CONTINUOUS EMISSION MONITORING

Third Edition

JAMES A. JAHNKE, PH.D.

This third edition first published 2022
© 2022 John Wiley & Sons, Inc.

Edition History
John Wiley & Sons, Inc., 2e (Continuous Emission Monitoring, 2000)
Van Nostrand Reinhold/co Wiley, 1e (Continuous Emission Monitoring: Theory and Practice, 1993)

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Library of Congress Cataloging‐in‐Publication Data

Names: Jahnke, J. A. (James A.), author.
Title: Continuous emission monitoring / James A. Jahnke.
Description: Third edition. | Hoboken, NJ : Wiley, 2022. | Includes bibliographical references and index.
Identifiers: LCCN 2021050361 (print) | LCCN 2021050362 (ebook) | ISBN 9781119433989 (cloth) | ISBN 9781119433996 (adobe pdf) | ISBN 9781119434023 (epub)
Subjects: LCSH: Continuous emission monitoring.
Classification: LCC TD890 .J34 2022 (print) | LCC TD890 (ebook) | DDC 628.5/30287–dc23/eng/20211115
LC record available at https://lccn.loc.gov/2021050361
LC ebook record available at https://lccn.loc.gov/2021050362

Cover Design: Wiley
Cover Image: © Cover illustration art by John M. Havel

To Gloria

PREFACE

This third edition to Continuous Emission Monitoring comes 20 years after the second edition was published. Over that period, more sources in more industries have been required to monitor a wider range of pollutants at ever‐decreasing emission levels. To meet the challenges of more stringent regulatory programs, both monitoring technology and the management systems necessary to maintain them have developed to the point where accurate and precise emissions data can be obtained at the lowest ranges specified by regulatory agencies. The evolution of monitoring regulation and the technology necessary to support it are based on programs initiated in the 1970s and 1980s. These programs were described in the first and second editions of Continuous Emission Monitoring, which have provided a foundation for those newly entering or those needing to gain perspective of the field. This third edition extends that foundation to later programs implemented in the 1990s and 2000s. In the 1990s, continuous emission monitoring (CEM) systems were applied to support the determination of emission “allowances,” in the U.S. acid rain cap and trade program. Later, in the 2000s, regulatory programs for NOx emissions, mercury, volatile and “air toxics,” semi‐volatile organic and inorganic compounds were instituted, leading to significant challenges for the monitoring community. This book focuses on continuous emission monitoring requirements promulgated in the United States, although monitoring rules developed in Canada and the European Union are addressed where appropriate.

Continuous emission monitoring involves the sum of activities associated with determining and reporting pollutant emissions from stationary sources. Coal‐ and oil‐fired power plants, municipal and hazardous waste incinerators, petroleum refineries, cement plants, Kraft pulp mills, and, now, many chemical process industries are required to monitor emissions on a continuous basis. The emissions data obtained provide a continuous record that can be used by environmental control agencies to support a variety of regulatory programs. First used to monitor the operation of air pollution control equipment, regulatory applications have extended in the United States to use CEM systems for determining the compliance of stationary sources with their emission limitations. For CEM data to be credible, one cannot rely only on instrumentation. The implementation of a plant‐level quality assurance program, based on routine quality control procedures, has been found essential for data credibility. As a result, CEM quality assurance and quality control have become integral to CEM regulation.

One of the purposes of this book is to provide an understanding of both the regulatory and technical issues that must be considered when making decisions about CEM systems. As regulatory applications are extended, CEM system data are being used increasingly for process control and optimization. Although the use of CEM systems for determining compliance with pollutant emission limits has been the driving force for their installation, the benefits of knowing what and how much of something is being emitted are becoming more widely recognized. Here, the adage that “if you can measure it, you can control it” has led to the acceptance of CEM systems by managers who understand that CEM systems can be used for more than just meeting environmental regulations – that a knowledge of emission rates can also be used to optimize plant operations.

The earlier editions of this book have continued to serve as a resource for training programs, the development of quality assurance plans, and the drafting of technical specifications for monitoring system purchases. It is a characteristic of U.S. environmental programs, that once written, regulations do not go away. In some cases they may be revised, but in others, they remain static. Continuous emission monitoring requirements have accordingly remained relatively unchanged over the past four decades. U.S. CEM requirements have remained basically the same since their inception in the 1970s, seeing only their greatest alteration with the allowance trading programs implemented in the 1990s. In terms of technology, extractive sampling methods, in situ monitoring, the principles of light absorption and light scattering, and other analytical methods applied in the monitoring instrumentation are fundamental; providing the basis for understanding the operation of instruments that typically remain installed from 15 to 30 years. However, much has been learned over the past 20 years and an update of the second edition is needed to provide a current perspective of the field. In particular, the U.S. Environmental Protection Agency institutes new rules and requirements as required by the periodic amendment of the Clean Air Act. These new rules are added to extend control over a wider range of industries for a wider range of pollutants. This edition of Continuous Emission Monitoring addresses these rules and the technology applied to meet them.

This book examines the interplay of technology and regulation as it affects the design, application, and certification of CEM systems. It describes new techniques employed in emissions monitoring, adds new knowledge gained on existing methods, but excludes instrumentation that is no longer available commercially. Chapters on the measurement of air toxics, mercury, and greenhouse gases have been added. The chapter on air toxics discusses monitoring instrumentation and methods used to measure hazardous air pollutants regulated under 40 CFR 63, the so‐called MACT (Maximum Achievable Control Technology) program. Monitoring for mercury is also required under this rule; however, due to the complexity of both the monitoring technology, calibration methods, and certification requirements, a separate chapter is devoted to this topic. A chapter on greenhouse gas monitoring has also been added. Monitoring greenhouse gases is relatively straightforward; however, data quality is paramount in this area of measurement. The role of CEM systems in greenhouse gas reporting is discussed in relation to the use of mass balance, emission factors, and other estimates to provide perspectives in reporting and certifying greenhouse gas information.

Due to the expanded use of CEM systems in regulatory programs both in the United States, Canada, Europe, and Asia, it is important for data comparability between nations that both the monitoring technology and regulatory standards used for system specification be technically sound. Additional emphasis is given to international approaches to continuous monitoring, particularly approval methods for the “automatic monitoring systems” (AMS) of the European Union (EU). Differences between the U.S. and European methods are discussed with regard to data equivalence and the implications for international agreements.

CEM technology can be considered to be mature for the continuous measurement of gases such as SO₂, NO, CO, O₂, and CO₂, in addition to the measurement of particulate matter, mercury, and flue gas volumetric flow. By mature, it is meant that sufficient knowledge has been attained over the past 50 years of CEM development so that when properly designed, operated, and maintained, these CEM systems can be used to measure emissions to within acceptable levels of precision and accuracy. Advances in the application of digital electronics have greatly improved monitoring instruments, as well as continuing the trend to smaller, more cost‐effective, and less maintenance intensive instruments. But CEM systems do remain application dependent. An instrument manufacturer's new analyzer or a CEM systems integrator's innovative design must still be evaluated with respect to plant‐specific requirements as well as the ever more demanding regulatory requirements. In terms of present realities, the first law of CEM systems that “there is no best type of system” may be rephrased more positively. The best system is one that (i) works in the plant application, (ii) can be purchased and operated at “reasonable cost,” and (iii) requires relatively low maintenance. It is, however, not always easy to obtain that one best system when confronted with marketing claims, conflicting performance histories, cost limitations, and installation deadlines.

This third edition is written in the same spirit as the first and second, presenting the principles by which CEM system technical and regulatory developments can be understood. This book is designed to be comprehensive in scope, to meet the needs of both the plant environmental engineer applying CEM systems and control agency personnel incorporating CEM systems in regulatory programs.

Although the chemical or physical basis of analyzer operation is given, the theoretical and technical details necessary for designing monitoring instrumentation and systems is beyond the scope of this book. Ample references are incorporated after each chapter should the reader wish to further pursue specific topics. This edition of Continuous Emission Monitoring, as the first and second editions, seeks to introduce the reader to this dynamic field and to point the way to the knowledge of today's CEM systems necessary to address the challenges of today's regulatory environment.

The author would like to thank the graphic artists who have contributed to the evolution of the figure illustrations presented in this book. These artists include Katherine Lindsay and Betsy Huber who initiated many of the original CEM system dimensional drawings, Sherry Stafford who prepared the graphics for the first edition, and John Havel who developed the new graphics for both the second edition and this third edition. The author is indebted to the instrument manufacturers and CEM system integrators who graciously furnished diagrams and technical information of their instruments and systems. Thanks are also expressed to Kata Kollath for assistance in editing, and the colleagues who offered suggestions for the development of this edition and pointed out errors in the second edition.

James A. Jahnke, PhD

CHAPTER 1
INTRODUCTION TO CEM SYSTEMS

In the early 1970s, a better way was needed to monitor stack emissions than by manual stack tests. In general, manual methods are conducted by inserting a probe into a stack, extracting a sample, and analyzing the sample in a laboratory, which is a time‐consuming process. Manual source tests also require a degree of preparation, and the coordination and prior scheduling of a test may result in source operations being highly tuned before such testing takes place. Manual test results, therefore, may not necessarily be representative of day‐to‐day emissions. Clearly, for monitoring plant emissions and the performance of pollution control equipment on a more realistic basis, alternative measurement techniques are needed.

A BRIEF HISTORY

Attempts were made in the 1960s to use ambient air analyzers and process industry analyzers to measure source emissions. Ambient air analyzers were not successful at that time due to the instability of dilution systems. However, process analyzers did prove to be useful, particularly those that employed ultraviolet and infrared photometric techniques. Then, in the late 1960s and early 1970s, successful developments emerged in instrumentation in Germany and the United States. Ambient analyzers were redesigned to measure gases at higher concentration levels, and the so‐called “in‐situ” analyzers were developed, which can measure gases in the stack without sample extraction. These methods, in addition to new German optical systems for opacity monitors and the development of luminescence measurement techniques in the United States, provided a technological base from which continuous emission monitoring (CEM) regulations could be established.

Continuous emission monitoring requirements in the United States were first promulgated in 1971. However, the CEM industry did not begin to develop until after 6 October 1975 when the U.S. Environmental Protection Agency (U.S. EPA) established performance specifications for CEM systems and required their installation in a limited number of sources. Since then, CEM systems have been applied to a wider range of sources, and over 50 years of experience has led to the evolution of analyzers and monitoring systems with ever‐improving performance The technology is considered mature, having a solid foundation in reliable instrumentation, procedures, and standards that can assure the quality of source emission data at specified limits of accuracy and precision.

The earliest focus of CEM technology was on the analyzer – the instrument that measures. However, it was soon found that the process of transporting the gas to the analyzer was a source of many problems. Such problems were addressed in a number of ways by CEM “systems” integrators. Those who understood the effects of corrosive stack gases on materials and the effects of pressure and temperature on gas transport were the first to design and successfully market systems that worked under severe sampling conditions.

The difficulties associated with extractive systems led to the idea of measuring the flue gases as they exist in the stack or duct, without conditioning. This idea was realized in the development of “in‐situ” analyzers, second‐generation source monitoring systems especially designed to avoid problems inherent in extracting gases. In‐situ systems have been designed to measure gas concentrations, flue gas opacity, flue gas flow, and particulate matter concentrations. Many present‐day CEM systems are a combination of extractive and in‐situ systems (Figure 1‐1).

Third‐generation systems emerged with the promulgation of the Clean Air Act Amendments of 1990 and the implementation of the acid rain allowance trading program. Requirements to report emissions in tons per year led to the demand for systems that could measure pollutant mass rate. As a result of this program, flow monitors and dilution‐extractive systems were added to the inventory of monitoring methods. It was in the acid rain program that CEM systems found their maturity. To assure the success of plant monitoring programs, both equipment and personnel resources were made available by corporate management. And here, it was found that for the success of monitoring programs, trained and experienced personnel can be equally important as the equipment.

A fourth wave of continuous emission monitoring applications came after 2000 with the delayed and piecemeal regulatory development of rules for hazardous air pollutants. The program to control hazardous air pollutant emissions was promulgated in the 1990 Clean Air Act Amendments along with the acid rain program; however, due to the enormity of the task of regulating 187 hazardous air pollutants from 174 source categories, the program was slow to start. It wasn’t until after 2000 that continuous monitoring requirements for air toxics began to come into effect, but the need to develop new and more sophisticated monitoring systems for measuring particulate matter, mercury, and hydrochloric acid was apparent before that time. A new generation of monitoring systems was developed, measuring a wider range of compounds and materials, at ever lower concentrations, by incorporating advanced measurement and miniaturization techniques developed in response to national military and security concerns.

The business of continuous emission monitoring is largely dependent upon environmental regulations and is almost cyclical with the ebb and flow of environmental rule‐making. As new regulatory programs are developed, it is found necessary that a means be provided to keep track of progress or lack of progress. When emission limits are mandated, enforcement programs require a measure of whether emission limits are met or not. Intermittent manual stack testing is clearly not adequate for this purpose, and it has been demonstrated that continuous emission monitoring systems can provide data of sufficient precision and accuracy to support enforcement programs and allowance trading programs. With emission limits becoming ever more stringent and the proper operation of pollution control equipment ever more critical, continuous emission monitoring systems have evolved where they can today, meet the most demanding applications.

Figure 1‐1 A continuous emission monitoring (CEM) system.

TYPES OF MONITORING SYSTEMS

A CEM system is actually composed of several subsystems: the sampling interface, the gas analyzer(s), and the data acquisition/controller system. The sampling interface is a subsystem that either transports or separates the flue gas from the analyzer. CEM systems are characterized in terms of the design of this interface. In extractive systems, the interface consists of a system that extracts and conditions the gas before entering the analyzer. In in‐situ systems, the interface is simpler, composed of flanges designed to align or support the monitor and blower systems used to minimize interference from particulate matter. The data acquisition/controller subsystem is integral to the proper operation of the total system. The control system controls automatic functions of the system, such as calibration, probe purging, and alarming. The data acquisition system receives the analyzer data, converts it into appropriate units, records it, and provides reports for both internal and external use. Today, CEM data acquisition systems are frequently networked to engineering, corporate, and even agency offices, where the data are used for a variety of operational and management purposes.

Both extractive and in‐situ systems operate in the source environment and must operate continually under changing stack and ambient conditions. Although this is not necessarily a problem for properly designed and maintained systems, alternative approaches have been sought. One of these approaches, remote sensing, has been applied with limited success, but has not been used widely. Another alternative, the correlation of stack emissions to process parameter data, has led to computerized “predictive emission monitoring systems” or PEMS. These systems have been employed successfully in a number of applications and have considerable potential if used in tandem with extractive or in‐situ monitoring hardware. The monitoring methods discussed earlier are classified in Figure 1‐2 and discussed further in the following sections.

Extractive Systems

Extractive gas monitoring systems were the first to be developed for source measurements. In these systems, gas is extracted from a duct or stack and transported to analyzers to measure the pollutant concentrations. Many of the early extractive systems first diluted the gas using rotameters, and then applied ambient air analyzers for measurements. However, frequent problems occurred in maintaining stable dilution ratios, so analyzers were subsequently developed to directly measure the flue gas at source‐level concentrations in the range of 100–1000 ppm or higher. These source‐level extractive systems were quite successful and received their widest application in the 1970s and early 1980s.

Many of the problems associated with the earlier dilution systems have since been eliminated by new techniques developed in the 1980s. The advent of the “dilution probe” made dilution systems viable for source measurements. Dilution systems are now relatively easy to construct and exhibit good performance. They are particularly useful for monitoring water‐soluble gases and provide a platform for the application of a new generation of analyzers that are able to measure part per billion concentration levels.

In order for an instrument to measure gas concentrations, the gas sample must be free of particulate matter. Often, water vapor is removed and the sample is cooled to instrument temperature. This requires the use of valves, pumps, chillers, sample tubing, and other components necessary for gas transport and conditioning. “Hot‐wet” systems, which measure hot gases without water removal, operate continuously at elevated temperatures, eliminating the need for water removal systems. Extractive systems use an umbilical line to transport the flue gas sample from the stack or duct to an analyzer cabinet or temperature‐controlled shelter. This line is heated in source‐level systems where the conditioning system is located in the shelter.

Figure 1‐2 Types of monitoring systems.

Dilution‐extractive systems became popular in the 1990s for determining pollutant mass emission rates at U.S. coal‐fired power plants subject to acid rain cap‐and‐trade regulations. Dilution‐extractive CEM systems measure on a wet basis, an advantage when required to report emissions in units of tons/year or kg/hr. Dilution‐extractive systems are available where the sample dilution takes place in a specially designed in‐stack probe or, alternatively, in a probe box outside of the stack, where a variety of dilution techniques are available. In either case, when the flue gas sample is diluted at the stack, a heated umbilical line is not always needed to transport the diluted sample to a CEM shelter.

Close‐coupled systems are extractive systems where the sample conditioning and analysis are conducted directly on the stack. In these systems, the analyzer is connected directly to the sample probe. These systems avoid sample losses for “sticky” or reactive gases due to gas transport and also reduce system costs by not requiring an umbilical line.

In‐Situ Systems

In‐situ systems consist primarily of an analyzer that employs some type of sensor to measure the gas directly in the stack, or projects light through the stack to make measurements. The opacity monitor and flow monitor illustrated in Figure 1‐1 are typical examples of in‐situ analyzers. There are two classifications of in‐situ analyzers: point and path. Point analyzers consist of an electro‐optical or electroanalytical sensor mounted on the end of a probe that is inserted into the stack. The point in‐stack measurement is usually made by a sensor over a distance of only a few centimeters. Path analyzers, on the other hand, measure along a path across the width of the duct or diameter of the stack. In these “cross‐stack” gas analyzers, light is transmitted through the gas, and the interaction of the light with the flue gas is used to obtain a quantitative value of the pollutant concentrations. In single‐pass instruments, light is transmitted from a unit on one side of the stack to a detector on the other side, making only one pass through the stack. In a double‐pass system, light is reflected from a mirror on the opposite side, doubles back on itself, and is detected back at the “transceiver.”

In‐situ analyzers are used to measure the concentrations of pollutant and combustion gases and particulate matter, flue gas opacity, and flue gas velocity (flow). Both point and path techniques are used to monitor gas and particulate concentrations. Opacity monitors (transmissometers) are path monitors and can be either single‐pass or double‐pass systems, measuring the transmittance of visible light through the stack. Flow monitors are designed in either point or path configurations, depending upon the analytical technique.

Using wavelength‐tunable lasers, in‐situ gas monitoring systems are experiencing renewed popularity, particularly for the measurement of reactive gases such as HCl and NH₃. More attention is being paid to verifying system calibration using NIST traceable calibration gases, an important issue in the United States. In‐situ point monitors using laser‐light scattering techniques have become popular for monitoring flue gas particulate matter concentrations. Light‐scattering particle sizing techniques are developing, but this technology has lagged behind in source monitoring applications for many years.

Remote Sensors

Remote sensing systems have no interface between the stack gases and the sensing instrument, other than the ambient atmosphere. They thus avoid problems associated with a stack or duct interface. These systems can detect emission concentrations merely by projecting light up to the stack (active systems) or by sensing the light radiating from the “hot” molecules emitted from the stack (passive systems). However, due to an inherent problem in defining the length of the measurement path in the plume, the accuracy of gas concentration data is poorer than that obtained by the extractive or in‐situ techniques. This problem is also an issue in making flue gas measurements using laser systems mounted on unmanned aerial vehicles (drones), a developing source monitoring technology.

The U.S. EPA has developed Method 9A for monitoring stack exit opacity, using a laser light detection and ranging technique (LIDAR). The method is particularly useful at night or under atmospheric conditions that are not favorable to a visible emissions observer (VEO) performing EPA test method 9. In a related development, a digital camera technique for measuring plume opacity has been standardized by ASTM in ASTM standard D7520‐16. Although not a continuous method, data using this method are being accepted by regulatory agencies for visible emissions compliance determinations.

Test methods and certification procedures have not been standardized for remote sensing systems used to monitor gaseous emissions. Since the regulatory applicability of remote pollutant gas measurements to stationary sources has not yet been established, these systems for source emissions monitoring are not extensively applied in commercial applications. They have, however, seen wider application in “fence‐line” monitoring, particularly at petroleum refineries and chemical plants. Attempts are frequently made to correlate emissions data with long‐path remote sensing data obtained along a plant perimeter. Such correlations typically devolve into research studies and have met with limited success as a regulatory tool.

Unmanned aerial vehicles (UAVs) (drones) offer significant potential in source monitoring applications (Villa et al. 2016). UAV systems can obtain grab sample for laboratory analysis, or, as part of an active remote system, incorporate a stationary mirror to reflect light projected from a ground‐based analyzer. Using lasers, two drones standing‐off from a stack exit can make cross‐stack gas measurements. Four drones could measure on two diameters. UAV platforms can carry simple miniature sensors, readily available from hand‐held monitors, to measure flue gases in real time using a stand‐off probe or by flying through the stack. For compliance measurements, a probe can be inserted from the UAV “down” the stack, as it hovers at a fixed position next to the stack. The availability, at present, of miniature and micro analyzers provides many options for analysis using UAV platforms. Flares and smaller process stacks with limited access or without sampling platforms are seen as potential applications for this technology.

Performance specification and certification procedures have not been developed for remote sensing systems or UAVs; however, this technology is relatively new. Calibration procedures and precision and accuracy issues relative to in‐stack measurements must first be standardized for UAV data to be credible. Standards developed by independent standards bodies such as ASTM or ISO may provide a basis for future agency requirements. Because the regulatory applicability of remote and UAV pollutant gas measurements to stationary sources has not yet been established, they will not be discussed further, but do bear watching in the technical literature.

Parameter Monitoring Systems

Alternative approaches to emissions monitoring have been developed that do not require the use of analytical instrumentation, but rely instead on inputs from process sensors, such as thermocouples, pressure transducers, and fuel flow meters. Data from these sensors can be used in a variety of ways in environmental regulatory programs. The parameter information can be either used directly as a surrogate to substitute for concentration‐based emissions data or it can be incorporated into a model to predict emissions.

U.S. regulatory programs have long used parameter data such as pressure drop or temperature to monitor the performance of emission control equipment. The parameter data has been used either as a regulatory trigger to initiate enforcement action directly or as an indicator of noncompliance with permit conditions. Control equipment and unit operational parameters can also be used directly in continuous parameter monitoring systems (CPMS) as part of a continuous monitoring system (CMS). This regulatory approach does not require the use of continuous emission monitoring systems although a CEM system can be a part of a CMS. The U.S. air toxics standards make extensive use of this method.

A more recent approach has been used to develop emission models based on process parameter data. Models are developed by first correlating parameter data to emissions data. An initial study is performed by varying and monitoring process and control equipment parameters while monitoring flue gas emissions using reference methods or CEM systems. One can then correlate the data using engineering calculations, least squares methods, or neural net techniques to develop a model that “predicts” emissions from parameter data. Such predictive emission monitoring systems (PEMS) employ from 3 to 20 input parameters and have been applied to a variety of sources. They are most successful on sources with minimal variation in fuels and operating conditions.

Analytical Techniques Used in CEM System Instrumentation

The analytical techniques used in extractive and in‐situ CEM systems encompass a wide range of chemical and physical methods. These vary from chemical methods using simple electrochemical cells to advanced electro‐optical techniques such as wavelength modulation and Fourier‐transform infrared spectroscopy. Table 1‐1 summarizes the analytical techniques that are used in currently marketed CEM systems for gases. Table 1‐2 gives a summary of analytical techniques used in continuous emission monitoring systems for particulate matter (PM CEMS).

Techniques used for laboratory analysis, as well as techniques applied specifically for emissions monitoring, have been incorporated into commercially marketed systems. New analyzers have been developed using established electro‐optical methods, but are beginning to incorporate new light sources and detectors, such as tunable diode lasers, quantum cascade lasers, and diode arrays and new techniques such as cavity ringdown spectroscopy. The incorporation of microprocessors into today's analyzers has added useful features such as data storage, troubleshooting diagnostics, and external communication.

To lower the cost of CEM systems, CEM system manufacturers are employing multi‐gas techniques to avoid subsystem duplication that occurs when using single‐gas dedicated analyzers. One approach is to use multi‐gas methods such as dispersive, FTIR, or photoacoustic spectrometry. Another approach is to incorporate discrete, multiple, and interchangeable sensors into a single chassis.

TABLE 1‐1 Analytical Techniques Used in Continuous Emission Monitoring Systems for Gases and Volumetric Flow/Velocity

Gases
Flow/Velocity

Extractive
In‐situ
In‐situ

Absorption spectroscopy:
Path:
Path:

Differential absorption

Differential absorption – IR/UV
Acoustic velocimetry

Photoacoustic

Second‐derivative spectroscopy
Time‐of‐flight

Gas filter correlation

Wavelength modulation

Fourier transform IR

Gas filter correlation

Luminescence methods:

Point:
Point:

Fluorescence (SO₂)

Differential absorption – IR/UV
Differential pressure

Chemiluminescence (NOx)

Gas filter correlation
Thermal sensing

Electroanalytical methods:

Polarography

Potentiometry

Calorimetry

Electrocatalysis (O₂)

Paramagnetism (O₂)

Methods for HAPS:

Differential absorption

Gas chromatography

Mass spectrometry

Fourier‐transform IR

Ion‐mobility spectrometry

Atomic emission (Metals)

Atomic absorption (Metals)

Atomic fluorescence (Metals)

TABLE 1‐2 Analytical Techniques Used in Particulate Matter Continuous Emission Monitoring Systems (PM CEMS)

Extractive | In‐Situ
Point | Point: | Path
Beta radiation attenuation | Light scattering | Transmissometry
Light scattering | Contact charge transfer | Light scattering
| Electrodynamic induction |

Succeeding chapters present details of both extractive and in‐situ systems – their advantages, disadvantages, and limits of application. The sampling interface is of particular importance in extractive system design and is treated separately in Chapter 3. Extractive system analyzers are discussed in Chapter 5. For in‐situ system design, the analyzer type is most important. In‐situ monitors for measuring gases are discussed in Chapter 6 and monitors designed for measuring flue gas flow, opacity and particulate matter in Chapters 7–9.

Mercury monitoring, a field in itself, has advanced significantly, within 15 years of research and development. This topic is treated separately in Chapter 12, to outline how a new generation of mercury monitoring systems has evolved to enable continuous monitoring of stationary source mercury emissions down to less than 1 μg/m³. Monitoring for hazardous air pollutants (HAPs) has developed along with increased concerns over their toxic effects. Monitoring requirements for these materials, implemented incrementally over the past 20 years, are discussed in Chapter 13.

Data Acquisition and Handling Systems

CEM system analyzers do not stand alone, but are part of a larger system as seen in Figure 1‐1. The assembly of analyzers is coordinated and controlled to provide emissions data that are subsequently recorded and reported. These roles were all originally considered part of the data acquisition and handling system (DAHS or DAS). Today, control functions are commonly separated from the DAHS by using data loggers, programmable logic controllers (PLCs), or separate microprocessor systems. This simplifies the CEM system by providing more flexibility for both system control and data acquisition and reporting.

Hardware used in CEM recording and reporting systems has evolved from the now archaic strip chart recorders to computer systems integrated into the plant distributive control system and the plant local area network, corporate wide area network, or intranet. In special cases, remote terminal units are used to provide emissions data to environmental control agencies either continuously on a real‐time basis or on demand.

CEM software has evolved significantly, principally due to the demands of the U.S. EPA Acid Rain Program. Requirements to report all emissions data plus plant operational data, on a quarterly basis, have led to sophisticated multitasking programs, having the capability of editing and back‐filling data according to prescribed algorithms. Today’s programs offer flexibility to both CEM system operators and environmental engineers in evaluating data quality and in preparing internal and external reports.

Programming tends to be customized to meet the demand of each plant installation with flexible and user‐configurable programs, making this task somewhat easier. The integration of CEM system data into plant distributive control systems and information networks has become a larger task. This requires considerable coordination between plant information technology personnel, plant engineers, the CEM system integrator, and the data acquisition system provider. This is often the most difficult job associated with the installation of a new CEM system.

THE ROLE OF QUALITY ASSURANCE

In the 1970s, industry frequently presented quite valid arguments that the performance of continuous monitoring systems was questionable. Two basic principles of CEM technology were soon learned:

There is no one “best” type of system for all applications.

A CEM system must be maintained if it is to operate.

During this period, aggressive CEM system vendors frequently sold their systems to anyone who could be convinced to buy their product. This resulted in misapplications of both in‐situ and extractive systems. The resulting poor performance led to unfortunate perceptions about the reliability of the technology and bankruptcy and absorption of several companies. This is a process that continues still today. From this experience, formal procedures for specifying and evaluating CEM systems have been developed and should be used by companies planning major CEM system purchases.

Errors in application have not been the only reason for poor CEM system performance. It is often assumed that after a CEM system is installed, it can generate data as routinely as a thermocouple or pressure gauge. It must be realized that routine maintenance programs are necessary for the continuing operation of extractive system plumbing and electro‐optical systems. Although this necessity is now well understood, awareness of this need did not develop in the United States until the early 1980s. A CEM specialty conference of the Air Pollution Control Association held in Denver in 1981 pointed out the need for established and effective CEM system quality assurance (QA) programs. By the time of a subsequent conference held in Baltimore in 1985, the U.S. Environmental Protection Agency proposed CEM system quality assurance requirements and many companies were reporting the success of their own QA programs in improving CEM system performance. In 1989, the U.S. EPA promulgated quality assurance procedures for CEM systems used for compliance determinations, specifying requirements for calibration and periodic audits. With this lesson learned, when new performance specifications are promulgated, quality assurance procedures specific to the pollutant are published concurrently. This can be seen in the almost concurrent publication of Appendix F quality assurance procedures for particulate monitoring systems, mercury monitoring systems, and hydrochloric acid monitoring systems with the publication of their respective performance specifications in Appendix B of Part 60.

Like an automobile, where the oil must be changed and the tires rotated, a CEM system requires routine checks and replacements. QA programs incorporating daily and weekly checks, periodic audits, and preventive maintenance procedures have been found to be the key to continuing CEM system operation. Systems with such programs today show better than 98% data availability.

APPLICATION

CEM systems were originally required by regulatory agencies in the United States for monitoring the effectiveness of air pollution control equipment in removing pollutants from flue gases. As indicators of control equipment performance, the data could be used to track plant performance and target sources that were not meeting their emission limitations. Manual source tests would then be conducted on targeted sources to determine if, indeed, they were failing to be in compliance with emission limitations.

However, the extension of CEM data to direct enforcement applications has grown in both federal and state programs. By stating specifically in a rule or permit that a CEM system provides enforceable data that determines if an emission limit is being met or exceeded, the earlier link to control equipment performance is not as important. In addition, the promulgation of the “credible evidence” rule now allows the use of CEM system data in litigation.

CEM systems also provide the basis for the U.S. EPA acid rain control program mandated in the 1990 Clean Air Act Amendments. Here, CEM systems determine the “allowances,” the number of tons per year of SO₂ emissions that are traded between the electrical utilities. This successful regulatory program has led to significant SO₂ reductions in the United States within two years of its implementation. The over 2000 utility CEM systems installed to track allowances have contributed much to this success, providing an accurate database necessary to instill confidence in the trading market.

Another trading program is found in the Cross‐State Air Pollution Rule, where NOx emissions are traded between electrical utilities and other sources in the northeastern states. These regulatory programs as well as economic forces led to an 89% decrease in SO₂ emissions and an 82% decrease in NOx emissions from 1995 to 2017.

Although emission monitoring systems have been applied principally to satisfy such regulatory requirements, CEM system data can also be used proactively by plant and corporate management by providing a base of information on compliance status or for consideration in legal issues. As a result of both agency environmental programs and proactive source monitoring, the CEM database provides assurance to the public that emissions are being monitored to address environmental concerns.

However, the essential purpose of CEM systems should not be forgotten when providing for the timely submission of emissions reports. That purpose is to use CEM system data to control plant operations to meet emissions limitations (Figure 1‐3). The continuous record of emissions data enables plant operators and engineers to optimize plant performance and control equipment operation. On a continuous basis, emissions can then be maintained within regulated limits. In some cases, operating costs can be reduced and data can be gathered for plant design and maintenance information. In sum, the focus should not be on the quarterly emissions report, but rather, on how to use the data to improve operational efficiencies to minimize emissions.

Figure 1‐3 Industry uses of CEM system data.

SUMMARY

The technology of continuous emissions monitoring has not been static. The use of CEM systems for allowance trading programs and emissions enforcement programs, the demands for increased system availability, and advances in data handling and reporting have led to more sophisticated systems with better reliability. CEM systems have advanced considerably over 50 years of development, with improved sampling techniques, analyzers, and data processing systems being integrated into today’s systems to meet the challenges posed by new requirements. Also, by implementing CEM system quality assurance programs and by properly managing the monitoring programs, high system availability can be achieved. This high availability is a necessity today, where inaccurate data or missing data can incur both regulatory and economic penalties.

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CHAPTER 2
CEM REGULATIONS

Environmental control agencies have been the driving force for the installation of continuous emission monitoring systems. The emergence of CEM regulation in the 1970s brought a new perspective to emissions monitoring by requiring a wide range of sources to install systems and by requiring the installed systems to meet specified levels of performance. Although instrumentation had been applied in the 1960s to monitor product loss in the process industries, it was not until environmental control agencies began implementing pollutant monitoring rules that the CEM industry began to develop. This development began almost simultaneously in the United States and the Federal Republic of Germany (FRG). Monitoring requirements have since extended throughout the European Union (EU), to Canada, Latin America, the Middle East, and Asia.

National environmental regulatory programs have been initiated to protect the health and welfare of their citizens. Ultimately, regulatory agencies establish limits for pollutant emissions from stationary, mobile, and area sources. This book addresses emissions from stationary sources, i.e., emissions from “smoke stacks.” By measuring the amount of pollutants emitted from stationary sources, assessments can be made as to their contribution to environmental problems. The data that they generate can also serve as a basis for future emission control regulations. Once in place, continuous emission monitoring systems provide a means of keeping score. Although measurements can be made manually and periodically as they were before the 1970s, continuous emission monitoring provides an ongoing record of how well emissions are being controlled and a means of determining at any time, the compliance status of an emissions source with its emission agency‐specified emission limits.

To be used effectively in any environmental program, CEM data must be representative, accurate, precise, and credible. In this regard, calibration, performance testing, certification testing, and periodic auditing are essential in maintaining credibility. An environmental agency monitoring strategy cannot be successful without including these elements.

Continuous monitoring requirements were first promulgated for fossil‐fuel‐fired steam generators in the United States in December 1971. In 1974, Germany passed the Federal Immission Control Act, which incorporated continuous monitoring requirements. Also, in 1974, pollutant emission limits and further monitoring requirements were published as “Technical Instructions on Air Quality Control” (TA‐Luft) in the Federal Republic of Germany. However, intensive monitor development did not begin until 1975 when the U.S. EPA published “performance specification procedures” for continuous emission monitors, and the German Federal Ministry of the Interior (BMI) published its corresponding “suitability testing guidelines.”

Since then, CEM regulations have expanded, affecting a wider range of sources and requiring a wider range of pollutants to be monitored. The basic CEM program elements established in the 1970s underlie most of the current regulations. The foundation of any regulatory continuous monitoring program incorporates three basic elements: (i) implementing rules, (ii) performance specifications, and (iii) quality assurance requirements. These three elements provide the necessary support for the application of CEM technology (Figure 2‐1).

When placed on uneven surfaces of a wide range of industrial applications, agency regulatory policies must be robust enough to enable CEM systems to produce accurate data. Continuing this analogy, when taking a photograph, a tripod serves to provide a stable base for a camera; the sharpness of the picture depends on the quality of the tripod as well as the quality of the camera. In the same sense, the quality of the data produced by a CEM system is dependent on both the system and the elements that support it.

Figure 2‐1 CEM program elements.

Implementing rules address the source categories and types of units required to monitor emissions, whereas performance specifications provide design, installation, and certification criteria. Quality assurance (QA) requirements specify procedures necessary for obtaining accurate data on a continuing basis. These elements support a CEM program, and a failure in definition of any one element can lead to an ineffective or failed regulatory program. Each of these elements incorporates a number of integral parts, which are illustrated in Figure 2‐2.

The regulatory development of implementing rules, performance specifications, and quality assurance requirements are discussed later in this chapter. Details of performance specification, performance specification test procedures, and quality assurance programs are discussed in the dedicated chapters that follow.

IMPLEMENTING RULES IN THE UNITED STATES

Implementing rules specify the type of source affected by the rule and may further specify types of process units required to monitor emissions. For example, a Kraft pulp mill recovery furnace may be required to monitor opacity and total reduced sulfur (TRS), or a petroleum refinery sulfur recovery unit may be required to monitor SO₂ and H₂S emissions through an implementing rule.

The rule should also specify why monitoring is required – its purpose. This may not always be stated or may be ill‐defined, particularly in permits. However, distinctions are important in the case of litigation. Purposes for which CEM systems are typically installed are as follows:

Control equipment operation and maintenance monitoring

Compliance monitoring

Emissions accounting

Public perception monitoring

The first U.S. Federal CEM implementing rules required the installation of CEM systems to monitor the performance of emissions control equipment. Since CEM systems provide a continuous record that shows if a source is either below or above its emissions limits (emissions standards), it was soon noted that the data could also be used for enforcement purposes. Implementing rules followed that required the installation of CEM systems to be used directly for enforcement. Another purpose for the installation of CEM systems is to provide the data necessary to support emissions accounting programs, such as the EPA acid rain program. Pollutant and flow monitoring data are used in these programs to calculate emissions in units of tons per year. A regulatory instrument called an “allowance” is equivalent to a right to emit one ton per year of a given pollutant and a source must have in its possession, the number of allowances equal its mass emissions expressed in tons/year. Here, CEM systems are the measurement tool used to track allowances.

Figure 2‐2 Elements of a CEM rule.

Public perception monitoring (or more euphemistically, “good neighbor” monitoring) refers to more stringent monitoring requirements established for sources such as municipal and hazardous waste combustors. In this case, extensive monitoring requirements are specified, coupled with plant operational interlock criteria where waste feed is shut off if emission limits should be exceeded. The continual oversight given by this instrumentation is intended to provide assurances to the public that environmental concerns associated with these types of sources are being addressed.

In addition to addressing source categories, operational units, and monitoring purposes, implementing rules also specify source specific monitoring details, such as instrument span requirements, data conversion equations, averaging periods, quality assurance, and reporting requirements. These details are important for using the data, but are often overlooked, particularly in state permits. Although there is a greater awareness of the need to specify such requirements in the implementing rules, when they are not incorporated, the rule may be too ambiguous to fulfill its regulatory intent. The variety of implementing rules that require the installation of CEM systems are examined further in the following sections.

U.S. Federal Implementing Rules

U.S. federal stationary source emissions standards and monitoring requirements are drafted by offices of the Environmental Protection Agency. The most important of these is the Office of Air Quality Planning and Standards (OAQPS), which developed the first CEM implementing rules and performance specifications in the early 1970s (U.S. EPA 1975). Other EPA offices have instituted CEM programs based on the original OAQPS regulations, modifying them for their own regulatory applications. Figure 2‐3 summarizes CEM regulatory programs that have been instituted.

In the United States, rules are first developed by the respective office and proposed in the Federal Register (FR), a document published on each government business day that includes regulatory proposals, promulgations, notices, and discussions concerning the rulemaking. After public hearings, comment, and revision, the regulations and requirements are promulgated and adopted into the U.S. Code of Federal Regulations (CFR). The CFR is a multivolume compendium of U.S. regulations for federal government agencies, which is revised annually to incorporate any new rules or changes in existing rules. It is the principle reference for environmental regulation in the United States.

Code of Federal Regulation citations are given in the format: (Title) CFR (Part). For example, 40 CFR 60 refers to the part of the code where the New Source Performance Standards (NSPS) are found. Performance specification test procedures for CEM systems are found in 40 CFR 60 Appendix B (U.S. EPA 2020c). Federal Register citations are given in the format: (Volume No.) FR (Page No.) (Date). As another example, the final performance specification test procedures 1–4 were published in the Federal Register in 1975 at 40 FR 46240 10/ 6/75. CFR publications can be found on http://www.ecfr.gov. Federal Register publications can be found on http://www.govinfo.gov/app/collection/fr. Federal Register publications can be useful by providing a background behind decisions that went into a final rule. Preambles to final rules include EPA’s responses to comments submitted on the proposed rule on which the final rule is based. Most of the rules do not stand alone and refer to other rules, test methods, monitoring specifications, and quality assurance requirements in other subparts and/or appendices of the Code of Federal Regulations.

Once promulgated, implementing rules may be amended or superseded by subsequent rules. This can create some confusion, particularly when rules overlap, as has been the case with the acid rain rules of 40 CFR 75 and the New Source Performance Standards of 40 CFR 60. Because the source‐specific standards are written at different times by different people, the formats, terminology, and specifications are sometimes inconsistent between the different standards. Although there are periodic attempts to harmonize the rules, inconsistencies often remain.

New Source Performance Standards, 40 CFR 60

U.S. EPA regulations concerning stationary sources are found under Title 40 Subchapter C of the Code. Newly constructed sources are required to meet New Source Performance Standards (NSPS), which are given in Part 60 of Title 40 (expressed as 40 CFR 60). Each source category, such as the electric utilities, municipal incinerators, or cement plants, is assigned a Subpart letter (Subpart Da, Eb, and F, respectively) by which it is referred to in the CFR (U.S. EPA 2020a).

The rules prepared by this office affect newly constructed sources. A “new source” is defined as one constructed after the date the rules are first proposed in the Federal Register. An “existing source” is a source constructed before that date. Rules for existing sources are given by the individual states, usually in facility operating permits, with federal guidance and approval. The Part 60 Subparts address primarily new sources, but also include subparts that provide guidance to the states to develop rules for existing sources. When meeting the federal guidance requirements, the rules for specific source categories can be incorporated into the State Implementation Plan (SIP) (U.S. EPA 2020b). Source categories required to install CEM systems under NSPS are given in Table 2‐1.

Figure 2‐3 U.S. Rulemaking requiring CEM systems.

Table 2‐1 shows the depth of CEM applications in U.S. industry and power production, but it should also be viewed as a guide to the Part 60 Subparts. The table gives applicability dates that distinguish “existing” sources from “new” and modified or reconstructed sources. The table lists those source categories required to monitor the concentration of gaseous pollutants, flue gas opacity, and/or particulate matter (PM). The table also lists the types of operational units on which a CEM system is to be installed. For example, Subpart BB for Kraft pulp mills may require monitoring on a number of devices, such as the recovery furnace, lime kiln, and digester contained within the plant. Sources such as the electric utilities or municipal waste combustors may have multiple boilers or combustors, all of which may require monitoring.

Note that most of the “effective dates” are old, and one might consider that “new” sources first affected by this program are now “old.” When Part 60 source requirements prove to be inadequate, new subparts are added to address newer “new” sources. This is the case for Subparts D and Da for electric utilities, Subparts Ea and Eb for municipal waste combustors, and Subparts J and Ja for petroleum refineries. The newer rules become more proscriptive and often require the installation of CEM systems not required in earlier subparts. Both new and existing stationary sources can be further regulated through programs such as the acid rain program of 40 CFR 75 and the air toxics program of 40 CFR 63, in addition to state permit requirements. Each of these programs can impose additional monitoring requirements.

TABLE 2‐1 Summary of New Source Performance Standards (NSPS) 40 CFR 60 CEM Requirements for Sources with Effective Dates 1971–1990

Source: Data from U.S. EPA (2020b).

Source Category
Part 60 Subpart
Affected Units
Effective Datea,b
CEM Requirementsc
CFR Monitoring Reference

Hospital/Medical/Infectious Waste Incinerators
(HMIWI)
Ce
SIP Guidelines
Combustor
6/20/96
3/16/98b
CO
60.37e

Fossil‐fuel‐fired steam generators
D
Boilers > 73 MW
8/17/71a ,b
SO₂, NOx, CO
O₂ or CO₂
Opacity
(PM CEMS option)
60.45

Electric utility steam‐generating unitsd
Da
Boilers > 73 MW
9/18/78a ,b

2/28/05a ,b
(IGCC)
SO₂, NOx, CO
O₂ or CO₂
Opacity
PM CEMS (Options for PMCPMS, Bag Leak Detector)
60.49Da

Industrial‐commercial‐ institutional steam‐generating units
Db
Boilers >29 MW
< 73 MW
6/19/84a ,b
SO₂, NOx, CO
O₂ or CO₂
Opacity
(PM CEMS Option)
60.46b
60.47b
60.48b

Small industrial‐commercial‐institutional steam‐generating units
Dc
Boilers > 2.9 MW
<29 MW
6/9/89a
SO₂
Opacity
60.46c
60.47c

Municipal waste combustors
Ea
Combustor
12/20/89
Opacity
SO₂, NOx,
CO
69.56a

Municipal waste combustors
Eb
Combustor
9/20/94
6/19/96b
Opacity
SO₂, NOx,
CO
(Options for PM HCl, Hg, D/F)
60.58b

Portland cement plants
F
Kiln and clinker cooler
8/17/71
Opacity
60.63

HNO₃ plants
G
Process equipment
8/17/71
NOx
60.73

HNO₃ plants
Ga
Process equipment
10/14/11b
NOx
60.73a

H₂SO₄ plants
H
Process equipment
8/17/71
SO₂
O₂, CO₂
60.84

Petroleum refineries
J
Catalytic cracker

Fuel gas combustor
Claus recovery plants
6/11/73
Opacity, SO₂, O2, CO
SO₂ or H₂S
TRS or SO₂
O₂
60.105

Petroleum refineries
Ja
Fluid Catalytic Cracking Units

Sulfur Recovery Units
Fuel Gas Combustion
Process Heaters
5/14/07
PM, Opacity
BLD
CO, CO₂, O₂
SO₂, NOx
SO₂, TRS, H₂S
O₂
SO₂ or H₂S
O₂
NOx,O₂
60.106a

60.106b

60.107a

Primary copper smelters
P
Roaster/Smelter
Cu convertor
Dryer
10/16/74
SO2

Opacity
60.165

Primary zinc smelters
Q
Sintering machine
10/16/74
Opacity
SO₂
60.175

Primary lead
smelters
R
Blast/Reverberatory furnaces
Sintering machine
10/16/74
Opacity

Opacity SO₂
60.185

Ferroalloy production facilities
Z
Submerged electric arc furnaces
10/21/74
Opacity
60.264

Steel plants
AA
Electric arc furnaces
Constructed between
10/21/74 and 8/17/83
Opacity
60.273

Steel plants
AAa
Electric arc furnaces
8/7/83
Opacity
60.273a

Kraft pulp mills
BB
Recovery furnace Lime kiln
Digester
Brown stock washer
Evaporator:

oxidation and

stripper system

9/24/76
Opacity, TRSe
60.284

Glass manufacturing plants
CC
Glass melting furnace
6/15/79
Opacity
60.293

Stationary gas turbines
GG
10 MBtu
Constructed between
10/3/77 to 7/8/04
Option:
NOx, O₂/CO₂
60.334

Lime manufacturing
facilities
HH
Rotary lime kiln
5/3/77
Opacity, or
scrubber Δp & supply P
60.343

Phosphate rock
plants
NN
Dryer and calciner grinder
9/21/79
Opacity
Opacity
60.403

Tire manufacturing industry
BBB

1/20/83
VOCd
60.544

Polymer industry
DDD
Carbon adsorbers
Constructed between
9/30/87 – 11/10/89
VOCd
60.563

Flexible vinyl and urethane coating and printing
FFF
Solvent recovery controls
Exhaust hoods
1/18/83
VOCd
60.584

Synthetic Organic Chemical Manufacturing Industry (SOCMI)
III
Air oxidation process controls
Absorbers, condensers, carbon adsorbers
10/21/83
VOCd
69.615
60.613

Onshore natural gas processing
LLL
Sweetening units
Constructed between
1/20/84 and 8/23/11
TRS, SO₂ Velocity
60.646

SOCMI
NNN
Distillation operations
12/30/83
VOCd
60.663

Nonmetallic mineral processing plants
OOO
Baghouses
4/22/08
Particulate
Matter
60.674

Petroleum refinery wastewater systems
QQQ
Carbon adsorbers
5/4/87
VOC
60.694
60.695

SOCMI reactor processes
RRR
Absorbers
Condensers
Adsorbers
6/29/90
VOCd
60.703

Magnetic tape coating
SSS
Carbon adsorbers
1/22/86
VOCd
60.714

Mineral industries
UUU
Calciners and dryers
4/23/86
Opacity
60.734

Polymeric coating
VVV
Carbon adsorbers
4/30/87
VOCd
60.774

a NSPS applies if construction commenced after this date.

b NSPS applies if modification or reconstruction commenced after this date.

c CEM requirements are as applicable when meeting the conditions of the subpart.

d  Rule applies if constructed before this date

e Organic monitoring device based on IP, photoionization, or thermal conductivity.

Not listed in the table are operational units or smaller sources that instead of installing CEM systems may alternatively be required to monitor process parameters such as pressure drops, temperatures, or fuel flow rates. Regulatory relief is applied to smaller sources where it can be a burden to purchase, operate, and maintain a CEM system. Here, the less stringent parameter monitoring requirements for low‐emitting sources may not be especially significant when considering their relatively smaller contribution to the atmospheric pollution burden.

The subparts tend to be complex. Accordingly, they should be referred to for detailed information concerning units of the emissions standards, monitoring requirements, reporting requirements, and exceptions.

General Provisions for the NSPS Subparts

General provisions pertinent to CEM systems required for sources regulated under the NSPS subparts are present in four sections of Part 60 of the Code. These sections are as follows:

§60.7 Notification and Recordkeeping

§60.8 Performance Tests

§60.11 Compliance with Standards and Maintenance Requirements

§60.13 Monitoring Requirements

Each of these sections gives important requirements regarding the opacity and gas monitoring systems mandated for source categories addressed by the subparts. These should be read in tandem with the subparts. For example, §60.7 gives requirements for Part 60 sources with installed CEM systems to submit excess emission reports and describes the information that is to be included in the report. In §60.8, requirements are given for conducting performance tests to determine whether the facility is within its compliance limits. Here, the performance tests conducted are those reference test methods of 40 CFR 60 Appendix A specified for the source category (e.g. acid plant, electric utility) (U.S. EPA 2020c).

Section 60.11 incorporates a requirement that has been central to U.S. EPA stationary source regulatory policy. This requirement [§60.11(d)] states:

At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator which may include but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source.

This policy, formulated in the early 1970s, is reprised in the compliance assurance monitoring and credible evidence rules that resulted from congressional concerns addressed in the 1990 Clean Air Act Amendments (which is discussed below).

Section 60.13 incorporates important requirements for Part 60 CEM systems. This section is sometimes forgotten after a CEM program has been implemented, but nevertheless, contains essential program requirements. Among these requirements are given as follows:

Performance Specification Tests. Part 60 installed systems must show that they meet performance specifications of 40 CFR 60 Appendix B (U.S. EPA 2020d) by conducting a performance specification test (Note: “performance specification tests” are used to certify CEM systems and are not the same as the “performance tests” of §60.8 conducted to determine source compliance with emission limits).

Quality Assurance Requirements. In the absence of other quality assurance requirements, as a minimum; the system must conduct a zero and span drift check once every 24 hours, zero and span adjustments must be made if the drift exceeds twice the value of the drift performance specification of Appendix B, and the zero and span check procedures must be written.

Representativeness. All CEM systems are to be installed such that measurements representative of actual emissions are obtained.

Alternative Performance Test Requirements. An alternative to conducting reference method tests for determining relative accuracy may be requested if the pollutant emissions are less than 50% of the emissions limit (60.13(j)(1)). When applicable, this allows conducting a cylinder gas test (audit) (CGA) instead of a relative accuracy test audit (RATA).

NESHAP, 40 CFR 61

The National Emission Standards for Hazardous Air Pollutants (NESHAP), formerly legislated under Section 112 of the Clean Air Act, require continuous monitoring for a limited number of sources covered under Part 61 of Title 40. As in Part 60, general monitoring instructions regarding notification, recordkeeping, etc. are given in the “general provisions” prior to the source requirements. Few pollutants were regulated under the NESHAP program due to uncertainties associated with risk assessments and scheduling mandates (Mohin 1992). Source categories affected by this subpart and monitoring requirements are discussed further in Chapter 13 on monitoring hazardous air pollutants.

The Air Toxics Program, 40 CFR 63

Title III of the 1990 Clean Air Amendments replaced the previous NESHAP program. Title III identified 189 hazardous air pollutants (HAPs) (later reduced to 187), to be regulated for sources emitting more than 10 tons/year of any one listed pollutant or 25 tons/year of a combination of listed pollutants. EPA has promulgated emission limits and engineering standards for the principal sources emitting HAPS (or “air toxics”). The sources must apply “maximum achievable control technology,” where MACT technology is the best control achieved in practice by 12% of the best controlled similar sources. However, MACT encourages process changes or other pollution prevention activities rather than the application of control equipment.

The air toxics, or “MACT standards,” also incorporate monitoring requirements to determine, on a continuous basis, whether emission limits are being met. Most MACT standards require parameter monitoring, in other words a “continuous parameter monitoring system (CPMS)” that is described in a “monitoring plan,” rather than the installation of CEM systems. However, where control devices are used that can be effectively monitored, such as carbon adsorbers and incinerators, CEM systems are either required or suggested as an alternative to parameter monitoring. The Part 63 Subparts give the emissions standards and monitoring requirements for HAPs emitted from 174 listed industries. Rather than requiring the monitoring of specific pollutants from the list of 187 HAPs, the use of surrogate analyzers is often allowed (such as a particulate monitor to monitor metal emissions or a total hydrocarbon monitor rather than a speciating instrument). Sources required to monitor HAPs and methods used to measure them are discussed further in Chapter 13.

Compliance Assurance Monitoring (CAM) 40 CFR 64

The compliance assurance monitoring program (CAM) was initiated from a congressional requirement included in the 1990 Clean Air Act Amendments (§702 (b) of the amendments). This amendment to Section 114 of the Clean Air Act states:

The Administrator shall in the case of any person which is the owner or operator of a major stationary source, and may in the case of any other person, require enhanced monitoring and submission of compliance certifications. Compliance certifications shall include (A) identification of the applicable requirement that is the basis of the certification, (B) the method used for determining the compliance status of the source, (C) the compliance status of the source, (D) whether compliance is continuous or intermittent, (E) other such facts as the administrator may require.

The amendment addressed the concern of Congress that the compliance status of most emission sources was determined only periodically by conducting manual stack tests. It was viewed that since source operations may be highly tuned during such testing, operations may not necessarily be representative of day‐to‐day performance. Congress gave EPA the task to devise a strategy that can assure Congress (and the public) that emissions standards and limitations are being met continually, not just intermittently.

The Compliance Assurance Monitoring (CAM) rule was developed as a response to the requirement that essentially places the burden back upon the source. The CAM rule applies to sources required to obtain a Part 70 or 71 air permit and having emission units with active control devices, whose potential pre‐control device emissions are at or above the emission thresholds that define a “major” source (such as 100 tons per year). Affected sources are to develop a “CAM Plan” that will provide assurance to the agency that they are meeting their emissions limitations (Neulicht et al. 1996). The CAM plan provides for the recording of work practice procedures, equipment monitoring, and inspection procedures related to pollution control compliance. CEM systems that measure pollutant emissions directly or by parameter monitoring techniques that provide indirect determinations may also be used. A guidance document on how to write a plan has been prepared by the U.S. EPA (OAQPS 1998).

Methods incorporated into the plan are to specify indicator ranges, within which the emission source is assumed to be in compliance. The range may be simply a range of pollutant concentration, or a range of pressure drops, temperatures, voltage settings, fuel flow, gas flows, and so on. Exceeding the range then triggers a requirement for initiating corrective action.

The CAM program emphasizes the use of plant sensors and parameter monitoring techniques to avoid the installation of CEM systems. This was due to public comment on an earlier “enhanced monitoring” rule intended to meet the requirements of §702 (b) of the 1990 CAA amendments. This earlier rule, viewed as a “CEM rule,” was withdrawn, due in part to outcry over assumed CEM system costs. However, the costs associated with developing CAM plans, modifying plans when plant operations change, and reporting parameter data may ultimately be comparable to the cost of CEM systems and process monitors. If a CEM system is already installed for compliance monitoring through a permit, NSPS, or other requirement, additional monitoring is not required.

Acid Rain Program (40 CFR 75)

The EPA acid rain program was the most significant program for CEM system implementation and development since the promulgation of the NSPS requirements in the 1970s. The program was responsible for the installation of over 2000 CEM systems in the electrical utilities in a relatively short period of three years. As a result of the program, dilution extractive systems were popularized in the United States, flow monitors were applied widely, and CEM system data acquisition systems improved markedly. Also, CEM systems achieved respectability. Being necessary to support the structure of the acid rain program, CEM system operation and performance came under supervision by engineers who report to upper management levels.

The acid rain program was established through Title IV of the 1990 Clean Air Act and is codified in Parts 72‐75 of Title 40 of the Code of Federal Regulations (U.S. EPA 2020f). Parts 72–74 deal with the programmatic issues of allowance trading, whereas Part 75 addresses the continuous emission monitoring requirements that support the program. The acid rain program is a “trading program” where the trading commodity is the “allowance.” An allowance is a trading permit, corresponding to the right to emit one ton of pollutant such as SO2, NOx, or CO₂ in any year. In the program, an affected facility must be in possession of the exact number of allowances corresponding to its annual emission of SO₂ in tons per year. If a coal‐fired power plant emits 30 000 tons per year of SO₂, it must have 30 000 allowances. If it has only 20 000 allowances, it must either reduce emissions by 10 000 tons during the year or it must purchase allowances to make up the difference. Allowances may be purchased, sold, banked, auctioned, or otherwise treated as negotiable securities.

The acid rain program differed from previous federal programs by applying to both existing and new electrical utilities greater than 25 MW capacity. In a trading program, a set number of allowances are initially issued to facilities affected by the program. To reduce emissions by 50%, only one‐half of the allowances necessary to cover annual emissions were provided by EPA. From SO₂ emissions level of 17.5 million tons annual emissions, in 1980 for the electric utilities, only 8.9 million allowances were distributed. When fully implemented by 2010, SO₂ emissions were expected to be approximately halved.

In contrast to “command and control” programs where certain control equipment or operating conditions are mandated, in trading programs a facility can choose how to comply with the rule. For example, a facility could add an SO₂ scrubber to reduce emissions; it could shut down intermittently; it could burn lower sulfur fuels, switch fuels, or buy allowances at auction, or could buy allowances from a company that had “overcontrolled” its emissions and had allowances to sell. This is illustrated in the example of Figure 2‐4. In the example, each plant emits 100 tons per year, but each plant is allocated only 50 allowances. To meet their allowance requirements, the plants adopt different strategies. Plant A decides to burn low‐sulfur coal and succeeds in reducing its emissions to 50 tons per year to meet the 50 allowances it was allocated. Plant B decides to install a wet scrubbing system and reduces its annual emissions by 70 tons down to 30 tons. It has overcontrolled its emissions, but now has 20 allowances available to sell. Plant C is an older plant and finds it too expensive to reduce its emissions by 50%. It decides to reduce them by only 30% down to 70 tons per year. To meet its allowance obligation at the end of the year, it then buys the 20 allowances available from Plant B.

The advantages of a trading program are that a source has choices instead of mandates and can change control strategies without notifying the agency. A trading program also changes the character of environmental management from spending money for compliance to possibly profiting by controlling its emissions more than it is required. Additionally, the similarity of an “allowance” to a “security” is understandable to corporate management and helps management to participate in a game with which it may be more familiar. Here, a strategy’s success or failure can be measured; and that measurement is made by CEM systems.

Figure 2‐4 Trading allowances.

Trading allowances requires a high degree of confidence in the negotiable instrument, the allowance. To calculate SO₂ mass emission rates, the flue gas volumetric flow rate must also be known. This is shown in Equation 2‐1.

(2‐1)p m r Subscript s Baseline equals c Subscript s Baseline upper Q Subscript s

where

pmrs = pollutant mass rate (kilograms per hour, tons per year)

cs = pollutant concentration (milligrams per cubic meter, pounds per cubic foot)

Qs = volumetric flow rate (cubic meters per hour, cubic feet per hour)

s = subscript denoting “stack”

For coal‐fired plants, flow monitors are specified for monitoring the flue gas volumetric flow. For gas‐ and oil‐fired plants, the fuel flow in conjunction with an O₂ or CO₂ “diluent” monitor can be used instead, to calculate the flue (stack) gas volumetric flow (see Appendix A).

Under the acid rain program, NOx emissions were not traded, but instead regulated under lb/mmBtu emission limits. Emissions are calculated using F‐factor methods, where the emissions in lb/mmBtu are determined from Equation 2‐2:

(2‐2)upper E equals c Subscript s Baseline upper F Subscript c Baseline StartFraction 100 Over percent-sign upper C upper O 2 EndFraction

where

E = emissions in units of lb/mmBtu (or ng/J)

cs = NOx concentration

Fc = carbon dioxide F factor

Here, a NOx monitor and diluent monitor measuring either CO₂ or O₂ are necessary to perform the calculation. F factors can be found in Table A‐2.

Since CEM systems are used to determine mass emission rates and, therefore, available allowances, it is essential that the CEM systems installed for this purpose meet high levels of accuracy and precision. Consequently, EPA established a new set of rules and performance specifications for CEM systems in 40 CFR 75, increasing the stringency of monitoring requirements from those originally promulgated in the New Source Performance Standards of 40 CFR 60 (U.S. EPA 2020g). As a result, CEM systems essentially became the “gold standard” by which the program operated. Because of the importance of the program and its potential costs, utility managers purchased new CEM systems, assigned engineers to oversee the monitoring programs, and provided financial and staff resources for their operation and maintenance. This led to a new generation of CEM systems and a new generation of CEM professionals. Close cooperation between utility professionals, regulators from the EPA Clean Air Markets Division (CAMD), and CEM system vendors contributed greatly to the overall success of the program (Schakenbach and Forte 2006).

Because of the more stringent monitoring requirements and incentives, Part 75 CEM systems typically achieve relative accuracies of <5%, in contrast to the minimum specification of <20% in Part 60 and <10% in Part 75 (Mangus 1997). Some utility managers initially installed redundant systems, concerned that CEM system downtime would incur allowance penalties. However, by instituting effective quality assurance programs and maintenance practices, availabilities of >98% became typical, negating the need for redundant systems, which were mostly removed and kept as spares. The key to these successes was in management providing the support and resources necessary to assure that the CEM data would be sufficiently accurate to back the allowance trades, where financial considerations could be substantial.

Allowance prices were relatively stable for about 10 years, hovering from approximately $150 to $200 per allowance from 1994 to 2004. Due to changes in regulatory policies (beginning with the Clean Air Interstate Rule and ending with the Cross‐State Air Pollution Rule), the closure of older coal‐fired facilities, and the increased usage of natural gas (which contains little sulfur), the market has essentially crashed, where SO₂ allowances are readily available and are priced today at less than $1. However, the acid rain program led to a decrease in SO₂ emissions in the power sector from 15.7 million tons per year in 1990 to below 1 million tons in 2019 (Figure 2‐5).

The acid rain program succeeded in meeting and exceeding its original program objectives sooner than mandated. However, factors other than trading also contributed to the program’s success (Schmalensee and Stavins 2013, 2015). The availability of low‐sulfur coal from Montana and Wyoming, the means to transport coal across the West and Midwest, and emergence of natural gas as an alternative fuel to coal led to SO₂ reductions that were not originally anticipated. Regardless of how the reductions were achieved, the constant factor in the program was highly accurate, reliable emissions data provided by the installed CEM systems. Accurate CEM data allowed the utilities to “keep score” with confidence, to weigh their operational and control options to cost‐effectively meet their regulatory obligations (Schreifels and Napolitano 2014).

The acid rain program serves as a template for other cap‐and‐trade programs, which is well documented by Schakenbach and Forte (2006). As viewed by Schakenbach et al., it is necessary that the monitoring and reporting procedures of the program be supported by effective quality control and quality assurance requirements. These requirements were at the time unique for a CEM regulatory program, incorporating elements such as the following:

Figure 2‐5 U.S. utility sector SO₂ emission reductions 1990–2019.

An implemented/effective CEM QA/QC plan

Incentives for good performance

Penalties for poor performance

Standardized electronic reporting formats and procedures

Electronic audits and data quality checking software

Targeted and random field performance and system audits

Flexibility for special circumstances and technical issues

Vigorous enforcement

These elements are further detailed in the Part 75 Subpart A – General Provisions (U.S. EPA 2020f). The Part 75 CEM requirements, for installation and certification, are found in Part 75 Appendix A (U.S. EPA 2020g), and quality assurance and quality control requirements are given in Appendix B (U.S. EPA 2020h). Other documents such as EPA’s Plain English Guide to the Part 75 Rule (U.S. EPA 2009), the Part 75 Emission Monitoring Technical Q and A document (U.S. EPA 2013), and the Part 75 CEMS Field Audit Manual (U.S. EPA 2003) are helpful in clarifying details of the Part 75 requirements.

The success of the acid rain program encouraged other cap‐and‐trade programs such as the EPA NOx Budget Program, the Regional Clean Air Incentives Market (RECLAIM) in California (discontinued), and the Houston‐Galveston HROVC (Highly Reactive Organic Compound) cap‐and‐trade program. In Canada, the province of Ontario has instituted a trading program for SO₂ and NOx (Government of Ontario 2020b).

Trading programs have also been established for the control of greenhouse gases. In the United States, the Western Climate Initiative (WCI) in California (with Quebec as a partner) and the Regional Greenhouse Gas Initiative (RGGI) in the northeastern states. A U.S. Federal greenhouse gas trading program had been considered at one time, but no longer appears likely due to political polarization regarding climate change issues.

Mandatory Greenhouse Gas Reporting Program (40 CFR 98)

Forty‐two source categories, ranging from stationary fuel combustion sources to electronics manufacturing, emitting more than 25 000 metric tons of CO2e per year are required as per 40 CFR 98 to report greenhouse gas emissions. Monitoring methods are specified in each of the 42 subparts; however, sources subject to Part 75 where CO₂ monitors are already installed must use CEM system data for reporting. Hazardous waste incinerators with installed CO₂ monitors must similarly report emissions using CEM system data. However, for most source categories, the reporting rule does not require the installation of continuous emission monitors, but allows the use of production data and emission factors instead.

Subpart C of Part 98 applies to stationary sources that combust fossil fuels. Here, a tier approach is taken, where each successive tier requires more measurements and the application of fewer emission factors, with the assumption that the higher the number of the tier, the higher the accuracy of the reported data. As an example of the use of emission factors, in Tiers 1 and 2, CO₂ emissions are calculated from the following equation:

(2‐3)upper C upper O 2 equals 1 normal x 10 Superscript negative 3 Baseline upper F u e l x upper H upper H upper V Subscript d Baseline x upper E upper F

where

CO₂ = annual CO₂ mass emissions (metric tons) for a particular type of fuel

Fuel = quantity of fuel combusted during the year (tons, scf, gal)

HHVd = default (Tier 1) or measured (Tier 2) high heating value of fuel (mmBtu per quantity of fuel)

EF = fuel‐specific default CO₂ emission factor (kg CO₂/mmBtu)

Tier 3 applies to sources larger than 250 mmBtu that have not been required to install a CEM system. In this tier, sources are required to monitor fuel use and the carbon content of the fuel instead of the fuel’s high heating value. CEM systems are used for Tier 4 reporting, where annual emissions are calculated as a pollutant mass rate times operating time. Methane and nitrous oxide emissions are reported using default emission factors for CH₄ and N₂O in Equation 2‐3. The CH₄ and N₂O calculate emissions data are combined with the CO₂ data to report greenhouse gas emissions as CO2e, carbon dioxide equivalents.

Greenhouse gas issues and reporting procedures are discussed in greater detail in Chapter 14.

Office of Solid Waste CEM Requirements (40 CFR 266)

Through the authority of the Resource Conservation and Recovery Act (RCRA), the EPA Office of Solid Waste requires CEM systems to be installed for incinerators designed to burn hazardous waste and for boilers and industrial furnaces (“BIF” sources) that burn hazardous wastes as supplemental fuel under 40 CFR 266 (U.S. EPA 2020i). This program under RCRA is delegated for management by the states. For hazardous waste incinerators, initial trial burns of hazardous pollutants are used to set operating criteria for the facilities. In many permits, the CEM system is tied into the operating system, where feed is cut off if CO or THC levels exceed the established trigger levels, or if the O₂ concentration decreases below the established limits. This is done, in part, to address the public's concern regarding emissions from such facilities.

BIF continuous emission monitoring requirements are found for CO in 40 CFR 266 §266.104(b)(2) and hydrocarbons (HC) in [§266.104(c)((3)]. In the BIF rules, performance specification for CO analyzers are given in Part 266 Appendix IX §2.1 and for hydrocarbon analyzers in §2.2. The performance specifications for CO are similar to those given in 40 CFR 60 Appendix B Performance Specification 4a. A relative accuracy test is not required for Part 266 hydrocarbon analyzers.

Quality assurance requirements for Part 266 CO and HC monitoring systems are found in Appendix IX of Part 266, where daily calibration checks, daily system audits, quarterly calibration error (linearity) tests, and an annual performance specification tests are required. Conducting an annual performance specification test for the CO monitoring system implies that a seven‐day calibration drift test, in addition to a response time test and a RATA, would be required, in contrast to Part 60 Appendix F where only an annual RATA is required (U.S. EPA 2020e).

Monitoring requirements have also been promulgated for hazardous waste combustors under the MACT standards of 50 CFR 63 Subpart EEE. Section 63.1209(a) (ii) requires that either a CO or hydrocarbon analyzer be installed, along with an oxygen monitor, to report emissions corrected to 7% O₂. Cement kilns burning hazardous waste are also required to install a continuous opacity monitoring system (COMS).

Sewage Sludge Incineration (40 CFR 503)

EPA regulations concerning sludge management programs are found under Title 40 Subchapter O – Sewage Sludge and Part 501: State Sludge Management Program Regulations. Regulatory authority is given under the Clean Water Act, which requires that states must develop sludge management programs. Part 501 specifies the requirements that a State program must meet for it to be approved by EPA. Sewage sludge can be disposed of in a solid waste landfill, applied to the land, or incinerated. For landfill or land applications, limits for metal concentrations, loading levels, and pathogen density are specified.

Monitoring requirements for incineration of sewage sludge are given in Subpart E of 40 CFR 503 – Standards for the Use or Disposal of Sewage Sludge If the sludge is incinerated, the concern shifts from releases to the soil and groundwater to the efficiency of combustion and releases to the air. Total hydrocarbons are required to be monitored as specified in §503.45(a)(1) of the Code. In addition, the carbon monoxide concentration must be monitored as an indicator of combustion efficiency, where a limit of 100 ppm corrected to 7% O₂ and zero percent moisture is specified. Total hydrocarbon concentration is similarly limited to 100 ppm corrected to 7% O₂ and zero percent moisture. Accordingly, an oxygen concentration monitor and an instrument used to determine the moisture content must also be installed to monitor the stack exit gas continuously along with the THC and CO analyzers. No other requirements are given for the monitoring system and analyzers, other than that a calibration and maintenance logbook shall be retained [40 CFR 503.47(n)]. Design and operational requirements are specified for the total hydrocarbon analyzer, where it must use a flame ionization detector (FID), be calibrated with propane, and have a heated sampling line maintained at a temperature of 150 °C.

New sewage sludge incinerators are also regulated under New Source Performance Standard Subpart O if the incinerator was constructed after 11 June 1973. The regulation requires the installation of an oxygen analyzer only. Here, the instrument specifications require a ±5% relative accuracy as certified by the manufacturer and a calibration every 24 hours according to manufacturer procedures. No reference is made to the Part 60 Appendix B or Appendix F CEM requirements, which are more complete.

State Programs and Federal Programs Administered by the States

State environmental control agencies are tasked with federal requirements to meet ambient air standards for SO₂, NOx, ozone, and particulate matter as PM2.5. The states receive federal funding for this purpose and institute programs to monitor ambient air concentrations of these ambient pollutants. Ambient air monitoring shelters housing analyzers that use many of the same analytical techniques as CEM systems are located across the country, providing a continuous assessment of ambient air quality.

A number of regulatory mechanisms can be used by the states to require the installation of CEM systems as a tool in meeting their goals. Because of the differences in state agency regulatory policies and work‐force capabilities and limitations, CEM programs vary greatly between the states. Several states have very stringent programs, based on CEM compliance monitoring for enforcement and public assurances. Other states, which have less stringent programs, accept EPA NSPS delegation for regulating new sources and have adopted minimum requirements for existing sources. Different types of programs delegated or otherwise employed by the states, where CEM system installations may be required, are listed in Table 2‐2.

By applying established regulatory procedures, CEM systems can also be required to be installed on other source categories or used directly for compliance. The development of such regulations typically proceeds through public hearings, combined with many approval processes. Under these procedures, it can often take several years before a regulation is issued.

State Implementation Plan Requirements (40 CFR 5l)

Each state is required by the U.S. Clean Air Act to have a State Implementation Plan, or SIP, that will lead to the improvement and maintenance of the air quality such that all areas of the state will meet national ambient air quality standards. Federal requirements for SIPs are given in 40 CFR 51 – Requirements for Preparation, Adoption, and Submittal of Implementation Plans and 40 CFR 52 – Approval and Promulgation of Implementation Plans (U.S. EPA 2020b).

Part 51 Appendix P – Minimum Requirements for Existing Sources. In Appendix P of Part 51, the U.S. EPA established minimum CEM requirements for existing sources (U.S. EPA 2020a). The rules, published in the 1970s, required state CEM requirements to be written by 1976 for only four source categories: fossil‐fuel‐fired steam generators, sulfuric acid plants, nitric acid plants, and petroleum refineries. Even so, these particular minimum requirements only applied to larger sources and allowed many exemptions, such as not requiring SO₂ monitoring unless SO₂ control systems are installed. The “existing sources” referenced in Part 51 were those built before 1971, many of which are no longer operating by having become subject to reclassification as a “new source” after modification, or are otherwise subject to acid rain, air toxics, and other rules written after promulgation of the 1990 Clean Air Act Amendments. Once in the Code of Federal regulations, rules, test methods, and procedures tend not to go away. They layer upon themselves; so, when reading them, attention must be paid to applicability and other conditions of the requirements.

TABLE 2‐2 State CEM Program Options

Federal Programs Delegated to States

SIP Rulemaking
Permit Programs
NSPS
Delegation
SIP
Rulemaking
Compliance Assurance
Monitoring
Waste
Incineration
Trading
Programs
Discretionary
Programs

Part 51
Part 52
Parts
70 & 71
Part 60
Part 62
existing
sources
Part 64
Part 266/503

Court Actions

Utilities
Pet. Ref.
HNO₃
H₂SO₄

PSD
NSR
Major
sources
NSPS categories (Table 2‐1)
Hazardous waste incinerators/
sewage sludge incineration
Major sources
Hazardous waste incinerators/
sewage sludge incineration
CSAPR
WCI (CA)
RGGI (NE States)
HRVOC (TX)
Variances
orders
agreements

Part 52 – Approval and Promulgation of implementation Plans Part 52.21 – Prevention of Significant Deterioration (PSD) For any source or a major modification to an existing source, located in an attainment area, where ambient air standards are met, a PSD permit must be granted. Once an area is in attainment, it is possible that the construction of a new source or modification of an existing source could lead to “significant” emissions that bring the area into nonattainment. To avoid this possibility a permit must be obtained by the source prior to the construction or modification. It must be shown whether a significant increase of emissions will occur, through a technical analysis and an air quality modeling, as specified in Part 52.21. One of the requirements of Part 52.21 is that the after construction or modification, the source must monitor mass emissions in tons per year of any pollutant designated under the New Source Review program for at least five years.

40 CFR Part 62 – Federal Requirements for Existing Units Not Covered by a State Plan

Part 62 gives requirements for existing sources that are not regulated by a state or tribal plan. The Subparts of Part 62 give Federal plans that can be delegated to the states for implementation by existing stationary sources. The applicable plan must be included in the Title V Permit for the affected source. Part 62 addresses a variety of incineration facilities listed in Table 2‐3. For a number of the sources, options are offered for using CEM systems instead of periodic performance testing.

40 CFR Part 70 – Title V Operating Permits

Congress established the Title V Operating Permit Program under the 1990 Clean Air Act Amendments. Under the program, major sources are required to obtain operating permits, operate in compliance with the permit, and certify annually that they are in compliance with the permit requirements. Most permits are issued by state and local agencies following the requirements of 40 CFR Part 70. Federal permits can be issued following 40 CFR Part 71.

TABLE 2‐3 Summary of 40 CFR 62 Monitoring Requirements for Existing Units Not Covered by an Approved and Effective State or Tribal Plan

Source Category
Part 62 Subpart
Affected Units
Effective
Datea,b
CEM Requirements
CFR Monitoring Reference

Large municipal waste combustion units
FFF
> 250 tpd
Constructed before 9/20/94
Opacity
As per
40 CFR 60.8b
Subpart Eb
62.14105
62.14109
60.58b

Hospital/Medical/Infectious Waste Incinerator (HMIWI)
HHH
Large
Medium
Small
Small Rural
Constructed before 12/1/08
Options for
SO₂, NOx, CO, HCl, O₂, D/F,
PM CEMS, Bag leak detector
62.14452

Commercial and Industrial solid waste Incinerators (CISWI)
III
Combustion Units
Constructed before 11/30/99
Bag leak detector if FF
62.14690

Small municipal waste combustion units
JJJ
>35 tpd < 250 tpd
Constructed before 8/30/99
4/6/10a
Opacity
SO₂, CO
NOx (Class 1)b
O₂ or CO₂
62.15170
62.15175

Sewage sludge incineration units
LLL
Combustion units
Constructed before 10/04/10
Bag leak detector if FF
Options for
SO₂, NOx, CO, HCl, O₂ or CO₂, D/F
62.15960
62.15980
62.16015

a Modification began before this date

b Units > 250 tpd capacity

States issue operating permits for both existing and new stationary sources.

An operating permit may include conditions that require the installation of CEM systems. States may prepare rules for existing sources that are more stringent than those promulgated by the federal agency (Kerstetter 1985). As a result, the stringency of state CEM rules may extend beyond those established for similar sources regulated under NSPS. Monitoring of gases such as HCl or volatile organic compounds may be required, or process cutoffs for excess emissions or real‐time telemetry may be required in the permit. Sources often agree to very stringent CEM requirements to expedite approval of the operating permit.

Federal Programs Delegated to the States

Most states have received delegation by the U.S. EPA to regulate the emission sources affected by the following federal rules:

Part 60 New Source Performance Standards

Part 64 Compliance Assurance Monitoring.

Parts 266 and 503 Hazardous and Municipal Waste Incineration

In implementing these programs, states have developed regulations to assure that affected sources have installed required CEM systems, to see that they are properly certified, and to receive and process excess emission reports and compliance data as required by the applicable rule.

Part 96 Cross‐State Air Pollution Rule (CSAPR)

The Cross‐State Air Pollution Rule, of 40 CFR 96, evolved from the Clean Air Interstate Rule (CAIR) and the NOx Budget Program (NBP). After the promulgation of Part 75 and the implementation of the acid rain program, significant progress was made in reducing SO₂ and NOx emissions. However, even with 50% reductions in SO₂ and NOx emissions, critical load was not being reached. “Critical load” is the level of emissions below which harmful effects to the environment do not occur. Studies indicated that reductions on the order of 75% on top of the previous 50% reductions would be necessary for SO₂ and NOx to meet ambient air standards for ozone and particulate matter, as well as reaching critical load requirements for acid rain. In the East, it was felt that part of the problem was due to the interstate transport of pollutants from the western to eastern parts of the United States. Thus, began the saga of rulemaking that extended from the NOx Budget Trading Program, to the Clean air Interstate Rule, and to the Cross‐State Air Pollution Rule, which is in effect today.

The NOx Budget Program (NBP)

To reduce the regional transport of ozone in the Northeastern United States, the U.S. EPA instituted a NOx control program, known as the NOx Budget Program, which was operated by the 20 eastern states plus Washington DC. The trading program began in 2003 and was discontinued in 2008. In the program, NOx emissions were capped for affected sources and NOx allowances were traded between sources under the program rules during the summer ozone season. The NOx Budget Program differed from the acid rain program in that it was administered by the states under State Implementation Plans, whereas the acid rain program is administered directly by the Federal EPA. In addition to the electric utilities, sources such as cement plants, petroleum refineries, and pulp and paper mills also participated in the program. The U.S. EPA provided guidance through the requirement of 40 CFR 96 to achieve consistency between the state programs (U.S. EPA 1998).

As in the acid rain program, an essential program component was the determination of the yearly NOx mass emissions. CEM systems incorporating NOx monitors, flow monitors, diluent gas monitors, and a DAHS provided the basis for these determinations. Because CEM systems for SO₂ and NOx had already been installed on fossil‐fuel electric generating units and other sources in the Part 60 and Part 75 programs, the primary impact on their monitoring requirements was in modifying CEM system software to accommodate the NOx Budget reporting requirements. NOx Budget CEM system certification and performance requirements referenced those of Part 75.

The Clean Air Interstate Rule (CAIR)

The NOx Budget Program was replaced by the Clean Air Interstate Rule in 2009 although the rule had been issued originally in 2005. The rule extended the NBP affecting 27 states plus Washington DC. CAIR included three interstate cap‐and‐trade programs: (i) the CAIR SO₂ trading program, (ii) the CAIR NOx annual trading program, and (iii) the CAIR NOx ozone season trading program. About 70% of the CAIR NOx ozone season units used CEM systems to measure NOx emissions (U.S. EPA 2010, 2014b). Lower‐cost monitoring alternatives were used for low‐emitting and infrequently operating gas and oil units.

After a training year in 2008, the CAIR NOx ozone season and NOx annual programs began in 2009 and the CAIR SO₂ program in 2010. This was after several court challenges that resulted in CAIR being vacated by the D.C. Court of Appeals in 2008, but remanded back to EPA until new rules could be developed to replace the program. CAIR was eventually replaced by the Cross‐State Air Pollution Rule (CSAPR), which was proposed in 2011, but was not implemented until 2015.

The Cross‐State Air Pollution Rule (CSAPR)

The Cross‐State Air Pollution Rule was proposed in 2011 as a replacement for CAIR, but was in turn vacated by the D.C. Circuit Court of Appeals in 2012 after judicial review. The U.S. Supreme Court reversed the decision of the Court of Appeals in April of 2014 and the stay was lifted in October 2014. Phase I of CSPAR began on 1 January 2015, but an update to the rule (the CSAPR Update) was finalized in September 2016.

CSAPR differs from CAIR in its level of stringency and trading restrictions. In CSPAR, allowance allocations are reduced from those in CAIR, and interstate trading is restricted. Despite the legal issues and shifting bases of the NOx control programs, using cap‐and‐trade policies as a tool, they have been successful in decreasing NOx emissions below the original target levels (Shouse 2018).

Ultimately, this history is not important to the CEM engineer, particularly since CEM requirements, based on Part 75, were not affected by the judicial issues. In the end, with the addition of control equipment and the increasing availability of natural gas over the decade, the electric utilities were able to meet NOx emission limitations.

Other Cap‐and‐Trade Programs

A number of other cap‐and‐trade programs have been initiated by the states. In California, the 1994 Regional Clean Air Incentives Program (RECLAIM) was one of the first programs to be implemented by a state (Lents and Leyden 1996). It established emission reduction targets for SO₂ and NOx, along with detailed protocols similar to those of Part 75. RECLAIM was discontinued in 2018; however, California currently participates in a Western Climate Initiative (WCI) CO₂ trading program. The northeastern U.S. states participate in the Regional Green House Gas Initiative (RGGI) CO₂ trading program.

A local trading program is active in the Houston‐Galveston area, where the numerous petroleum refineries and chemical companies have made it difficult to meet ambient air standard for ozone.

Here, the “Highly Reactive Volatile Organic Carbon (HRVOC)” cap‐and‐trade program requires the continuous monitoring of speciated volatile organic compounds, precursors to ozone formation. Flares, process vents, cooling towers, and fugitive emissions are affected by the program.

Discretionary Programs

Actions such as issuing permits give an agency a great deal of flexibility for achieving its goals. The ability of an agency to incorporate continuous monitoring requirements as part of these actions is within the agency's “discretionary authority.” Discretionary programs include:

Variances. Under special circumstances, a temporary authorization, called a variance, may allow a source to discharge pollutants in excess of the standard that would normally apply. A variance is generally issued for a specific time period, requiring that the source correct the problem and meet the standard by the end of the period. Special monitoring requirements are often included in the provisions of such variances.

Orders. Orders to comply with state agency requirements can be issued to a source under the enforcement authority given in Section 113 of the Clean Air Act. There are several types of orders: administrative orders, delayed compliance orders, and court orders. These orders differ with respect to the type of legal authority it takes to issue them.

Agreements. Agreements are often a result of bargaining between an agency and a source. Again, the purpose of any agreement is for the source to come into compliance with applicable regulations. As with orders, there are several types of agreements, each differing with respect to the level of authority or legal action exercised. Consent decrees, stipulation agreements, and court settlements are found in this group.

The use of discretionary authority allows fairness to be applied in regulatory programs. For example, a source may be able to gain time to install new control equipment by agreeing to the installation of a compliance CEM system. However, state discretionary authority can also result in arbitrary regulation since it does not have the extensive public oversight that rulemaking does.

PERFORMANCE SPECIFICATIONS

To this point, we have discussed implementing rules for CEM systems, rulemaking requiring the installation of a CEM system on a source category or a specific unit of a source. The implementing rule, however, is not complete unless it refers to some procedure that can be used to verify that the installed CEM system can provide data at a specified level of accuracy and precision. The level of accuracy can vary with the rule, depending upon the pollutant and the purpose of the rule. However, some verification procedure must be established so that the installed system can be shown to provide emissions data suitable to meet the purposes of the implementing rule.

In the United States, the verification or certification procedures established for CEM systems are given in standards called “performance specifications.” The performance specifications include requirements for the installation, design, performance, and testing of CEM systems. The installation criteria are regulatory guidelines for identifying measurement locations where representative measurements can be expected. Design specifications require that the instruments must be designed in a certain manner. These are important and specified in detail for opacity monitors, but are minimal for gas monitors.

The specifications for the performance of the monitoring systems are the most important part of these standards (except for opacity monitors, where the design specifications predominate). Specifications are given for drift, relative accuracy, and, in some cases, linearity. Basically, the design of a gas monitoring system is not relevant to the specifications. It does not matter whether the system is extractive or in‐situ or if the method of measurement is electro‐optical or electrochemical. It does matter, however, how the system performs. The proof of a system is in its performance as installed. The performance specification test procedures are applied to demonstrate that the installed CEM system meets “performance specifications.” If a CEM system meets these specifications, it is considered capable of providing quality data for the purpose of the implementing rule.

Sixteen sets of performance specification have been established for pollutant and diluent gas flow and particulate monitoring systems for sources subject to the New Source Performance Standards. Sources are required to meet these specifications after an applicable monitoring system has been installed or when otherwise called out by a rule. The NSPS specifications are found in Appendix B of 40 CFR 60. Other specifications are given for other implementing rules, and the states may write their own performance specifications (e.g. Pennsylvania and California). The Code of Federal Regulations citations where performance specifications for other implementing rules can be found are given in Table 2‐4.

As noted, EPA does not approve specific brands of instrumentation or specific analytical methods (in the case of gas monitoring) for source monitoring systems. This is in contrast to the policy of approving specific instrument models for continuous ambient air analysis. The procedure of meeting performance specifications provides latitude in continuous monitoring system design and application by allowing sources to handle individual monitoring problems. Since stack conditions vary from plant to plant, a CEM system found to work well at one plant may not work at another. Vibration, heat, or other conditions may necessitate a careful analysis of available monitors and systems before one can be chosen for the job. The performance specifications define the procedures to be used for checking the installed instrument's performance. It is the installed instrument system, operating on the stack, that is approved, not the model.

TABLE 2‐4 Performance Specifications for U.S. EPA Implementing Rules

Originating EPA Office | Program | Citation for Implementing Rule Performance Specifications
OAQPS | NSPS | 40 CFR 60 Appendix B
OAQPS | Air toxics | 40 CFR 63.8 monitoring requirements
OAR‐ARD | Acid rain | 40 CFR 75 Appendix A
OSW | Boilers and industrial furnaces | 40 CFR 266 Appendix IX
OWM | Sewage sludge incinerators | 40 CFR 503 Subpart E

U.S. CEM system certification procedures differ from those instituted in the European Union, where CEM system analyzers must undergo “type” testing, both in the laboratory and field, to show that they meet the design and performance specifications of the EU standard EN 15267. However, it has been found that a CEM system accredited under EN 15267 does not necessarily guarantee that it will pass a U.S. Performance Specification Test after installation.

QUALITY ASSURANCE REQUIREMENTS

The earliest applications of CEM systems in the 1970s were often met with frustration. Systems were installed and certified, but over a period of time began to fail. Either inconsistent data or no data would be generated. Often, the monitoring systems behaved so poorly that the data would not be accepted by control room operators. The problem was not so much in the instrumentation itself, but in misconceptions in how the systems operated. CEM systems were viewed as just another plant sensor, such as a thermocouple or pressure gauge – once installed, it would be expected to function for an extended period of time; failure could be corrected by a simple replacement. CEM systems, however, are more complicated than sensors. If not serviced periodically, serious corrosion and plugging problems can result, which can lead to a breakdown of the system. Failures cannot always be corrected through simple replacement, but instead may require expensive repairs and recertification.

The realization came quickly that in order to continue operating, a CEM system must be maintained continually (Jahnke 1986). Periodic inspections, a preventive maintenance program, and performance assessment procedures are all necessary for a CEM system to provide quality data on a continuing basis. These are the elements of a quality assurance program.

A quality assurance (QA) program requirement should be either part of an implementing rule or referred to in an appendix, as are the performance specifications in the NSPS requirements. QA requirements should include the preparation of a QA manual that describes the quality assurance and quality control procedures that will lead to optimum data quality for the CEM installation. Quality control procedures should detail the calibration methods, preventive maintenance activities, data back‐up procedures, and so on. Periodic audits such as systems audits and performance audits mandated by the regulatory agency should be part of the plan. Performance audits that use independent audit materials (e.g. calibration gases) or independent test instruments are recommended for providing quantitative assessments of data quality. Systems audits conducted by either internal or external auditors provide an assessment of whether the QA program has been implemented and is operating effectively.

Part 60 Quality Assurance Procedures

Quality assurance programs were not required for CEM systems in the implementing rules promulgated by EPA in the 1970s and early 1980s. After the initial certification was achieved by passing the performance specification tests, no further testing was required, unless requested by the agency for special circumstances. It was not until the 1980s that EPA proposed minimum quality assurance procedures for SO₂, NOx, and diluent monitoring systems in Appendix F to 40 CFR 60 (U.S. EPA 2020e). This rule was promulgated in 1987 and is today known as Procedure 1 of Appendix F. Other procedures were added to Appendix F as continuous monitoring requirements extended to the measurement of other pollutants, such as mercury and hydrochloric acid. However, quality assurance procedures for opacity monitors were not published until 2014 (U.S. EPA 2014a) although opacity monitors have been required at certain facilities since 1973.

Other U.S. QA Procedures

QA requirements for acid rain Part 75 CEM systems were promulgated along with the implementing rule and are found in 40 CFR 75 Appendix B (U.S. EPA 2020h). The requirements include procedures for SO₂ and NOx monitoring systems, O₂ and CO₂ diluent monitors, and flow monitors. The flow monitoring procedures are especially important because none are given in Part 60 Appendix F. It is obvious from Equation 2‐1 that the flow measurement is as equally important in pollutant mass emission rate determinations as is the gas measurement. The flow monitoring performance audit procedures such as the “flow‐to‐load ratio test” and semiannual/annual relative accuracy test audits are valuable, if not necessary for assuring accurate flow measurements.

The acid rain program, NSPS, and air toxics monitoring programs all include requirements for writing a plant‐specific CEM QA plan and periodic performance testing. Although Appendix F applies only to those NSPS sources that use CEM systems for compliance, many states have viewed CEM quality assurance as integral to their own programs and have patterned QA requirements after those of Appendix F. Even if not required to implement a QA program, a source should develop a QA plan if it wishes its CEM data to be legally defensible.

The Role of Calibration Gases

U.S. CEM programs have been written so that gaseous pollutant emission data are traceable to National Institute of Standards and Technology (NIST) standard reference materials (SRMs). Certified calibration gases, traceability back to SRMs, are used for this purpose when conducting the required quarterly cylinder gas audit of Part 60 Appendix F – Procedure 1 and the Part 75 daily calibration verifications and quarterly linearity tests. The traceability protocols are found in the document: EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards (U.S. EPA 2012).

In addition to the traceability protocol, the Clean Air Markets Division instituted the Protocol Gas Verification Program (PGVP) designed to ensure the accuracy of protocol calibration gases – a program that has done much to ensure the quality of CEM data [see 40 CFR 75.21(g)(6) and (7)]. To sell gases as “protocol” gases, gas suppliers must adhere to traceability protocol procedures and participate in the PGVP program. In the program, protocol gases are purchased by users, who instead of using them, send the gases to NIST for analysis against NIST standard reference materials. The results of the analyses are made publicly available, which provides an incentive for gas vendors to perform well on the blind audits. Failure to perform well can result in a loss of both credibility and customers in this competitive and lucrative business.

INTERNATIONAL RULES

Internationally, as in the United States, the implementing rules first require the installation of a CEM system, and then procedures for installation and certification are provided either in an appendix to the implementing rule or are given in a separate set of specifications. Either U.S. CEM Performance Specification Test procedures or the EU accreditation and calibration procedures are commonly adopted for CEM system certification by other countries.

Canada

In Canada, the Federal Government provides national guidelines, through Environment Canada, that are to be implemented by the provinces. For example, in May of 1993, National Power Generation Emissions guidelines for New Stationary Sources (N 305) were published to address acid rain control requirements agreed upon in the U.S.– Canada Clean Air Accords. Mercury monitoring requirements are given in the document Canada‐wide Standards for Mercury Emissions (CCME 2006, 2007).

Implementing rules are published separately by the provinces. For example, in Ontario, monitoring requirements for cement plants and smelters are found in Ontario Rule 194/05 (Government of Ontario 2020a). Monitoring requirements for electrical generation are found in Ontario Rule 347/01 (Government of Ontario 2020b).

In Alberta, CEM implementing rules are given in facility “approvals.” Approaches to emission monitoring requirements in other Canadian provinces have been summarized in a report submitted to the Canadian Council of Ministers by Marbek Consultants (Marbek 2009).

CEM system installation, certification, and quality assurance criteria are found in the Environment Canada document EPS/1/PG7 – Protocols and Performance Specifications for Continuous Monitoring of Gaseous Emissions from Thermal Power Generation (ENVC 2005), which is either adopted or modified by the provincial environmental ministries. In Alberta, a “CEMS Code,” based on EPS 1/PG/7, was developed to address petroleum industry and other sources (AEP 1998). The Alberta CEMS Code has also been adopted in Australia (WADER 2016).

Europe

In Europe, directives for installation of CEM systems are issued by the European Parliament and the Council. For example, the Industrial Emissions Directive (EU 2010) requires the Member States of the European Union to develop implementing rules for automated monitoring systems (AMS). CEM certification requirements were standardized by the European Committee for Standardization, i.e., (Comité Europeén de Normalisation [CEN]) in standards EN 15627 and 14181.

Asia

Both China and India are active in requiring the installation of CEM systems in major stationary sources. In China, an air pollution emissions standard for power plants, requiring the installation of CEM systems, was issued in 1997 (Qingfeng and Yuhong 1997; Sloss 1997). In 2007, China’s Ministry of Environmental Protection issued further requirements for all state‐controlled polluting facilities to install CEM systems by the end of 2008 (Zhang and Schreifels 2011). Certification procedures in China have followed those of U.S. Part 60 and 75, and over 10 000 systems have been reported as being installed (Zhu et al. 2010). The emissions data from these systems have been compared to satellite data (Karplus et al. 2018), a novel method of assessing data quality.

In 2014, the Central Pollution Control Board of India mandated 17 industrial sectors to install CEM systems (CPCB 2018a). This has created a large market in India for both particulate and gas monitoring systems. Certification procedures and data credibility issues are being resolved in this nascent program. Compliance reporting protocols for online continuous emission and effluent monitoring systems (OCEMS) were issued in 2018, which will require the submittal of CEM system design and installation details and real‐time data (CPCB 2018b).

Latin America*

CEM systems in Latin America are typically required to be installed through national emission control programs (Montoya 2020, Morrell 2020).

* The assistance of L. Montoya and S. Morrell in the writing of this section are greatly appreciated.

Mexico

Stationary source emissions in Mexico are regulated by the Secretaria del Medio Ambiente y Recursos Naturales (SEMARNAT – Secretariat of the Environment and Natural Resources). CEM systems were required in 1995 for glass manufacturing plants for monitoring NOx, CO, and O₂. CEM systems for monitoring NOx and O₂ were required for large thermoelectric plants in 1995, and SO₂ and opacity monitors were required in a 2011 revision of the standard. In 2002, CEM systems for CO and O₂ were required for waste incineration plants. In cement plants, if 15–30% of the fuels combusted are nonconventional fuels, continuous monitoring is required for CO, HCl, NOx, SO₂, THC, and O₂ (CMIC 2020).

It is only required to validate CEM systems in the incineration and thermoelectric plant regulations, where the U.S. performance specifications of 40 CFR 60 Appendix B are referenced.

Chile

In Chile, the Ministry of the Environment requires the installation of CEM systems at pulp mills, incinerators, thermoelectric power plants, and copper smelters. Lime kiln and recovery TRS emissions from pulp mills have been required to be monitored continuously since 1999 (MMA 1999). Thermoelectric power plants were regulated in 2011, where continuous monitoring systems for SO₂, NOx, and particulate matter are required (MMA 2011). Requirements to monitor SO₂ from smelter acid plants were established in 2013 (MMA 2013a). Monitoring requirements for PM, SO₂, and NOx emissions from incinerators were established in 2007 and 2013 (MMA 2013b)

Chile has applied a continuous monitoring protocol since 2011, which is based on U.S. Part 60 and Part 75 requirements and developed in collaboration with the U.S. EPA as part of the U.S.–Chile Environmental Cooperation Agreement (Chile 2003). Similar to the U.S. requirements, performance tests such as daily calibration verifications using certified gases, cylinder gas audits, and relative accuracy test audits are required for certification and after the systems are installed. This protocol was officially approved by the Superintendencia del Medio Ambiente (SMA) of the Government of Chile in 2019 (SMA 2019). For particulate matter monitoring systems, the correlation procedures of 40 CFR 60 Appendix B PS11 are followed. There are currently between 300 and 400 validated CEM systems in Chile (Montoya 2020).

Peru

In Peru, the Ministry of the Environment (Ministerio del Ambiente – MINAM) requires the installation of CEM systems for thermoelectric plants (MINAM 2014, 2020) and cement and lime manufacturing plants (MINAM 2016) for the measurement of particulate matter, SO₂, and NOx concentrations. Although a standard for copper smelters has not been published, CEM systems are installed in these plants. CEM system requirements are expected to expand to other industrial sectors in the future (Montoya 2020).

A CEM protocol (Protocolo Nacional de Sistemas de Monitoreo Continuo de Emisiones CEMS), based on the U.S. Part 60/75 requirements and similar to the protocol of Chile, was approved in 2016 (MINAM 2016).

Brazil

In Brazil, the national regulatory body responsible for setting emission limits and monitoring requirements is Conselho Nacional do Meio Ambiente (CONAMA). National emission limits were established for stationary sources in Resolution 382 (CONAMA 2006), complemented by Resolution 386 (CONAMA 2011). According to Resolution 382, Article 5, monitoring is considered continuous when the pollution source is monitored at least 67% of the operational time during a one‐year period. A valid day emission rate must have monitoring data for at least 75% of the day’s operational time.

There are no national protocols for CEM system certification or quality assurance. These are set instead by state licensing agencies (see Annex 6 Resolution 386). Accordingly, CEM validation and quality assurance vary between the states. As examples, the federal states of São Pablo and Rio de Janeiro require CEM systems for waste incineration plants and for larger combustion sources. In the federal state of São Palo, where CEM system installations are the most prevalent. A validation standard based on on the European standard EN14181 has been applied. (Environmental‐Expert 2020). Companhia Ambiental do Estado de São Palo (CETSB) is the regulatory body for source emissions in Sao Paulo.

Argentina

In Argentina, thermoelectric plants have been required to monitor particulate matter, NOx, SO₂, and O₂ since 2001 (Argentina Ambiental 2001, 2002). A national CEM protocol, based on the U.S. EPA Part 60/75 requirements, was published in 2012 (ENRE 2012).

Colombia

Regulations requiring CEMS for monitoring PM, SO₂, NOx, CO, HCl, HF, and THC were established in 2008 for various industrial sectors, including waste incineration plants, cement kilns that burn hazardous wastes (Ministerio del Ambiente Minambiente 2008). No protocol for CEM system validation or quality assurance has been published to support the monitoring requirements.

Ecuador

A regulation was implemented in 2019 for the installation of CEM systems in cement plants and thermoelectric plants for monitoring PM, SO₂, and NOx (Ministerio del Ambiente y Agua 2015). No protocol for CEM system validation or quality assurance have been published to support the monitoring requirements.

Developing a National Continuous Emission Monitoring Program

One would expect that because it has been over fifty years since the proposal of CEM systems for monitoring industrial emissions in North America and Europe, the accumulated knowledge on monitoring systems could be readily adapted to developing CEM programs in other countries. Unfortunately, all too often, the implementing rules come first and the certification and quality assurance criteria are either left ambiguous or are to be developed later. Figure 2‐1 emphasizes in all clarity that if the benefits from CEM technology are to be realized, the technology must be supported by clear implementing rules, accreditation/certification standards, and implemented quality assurance procedures. Failure to incorporate any of these three elements can make installed systems eventually fail to work or produce corrupted data lacking credibility. However, even if the three elements are extant, the enforcement of the rules (the subject of the next section) has been found necessary if CEM data are to be credible.

The CEM rules, protocols, and guidance documents developed in the past 50 years by the United States, Canada, and Europe can be used as resources for those environmental control agencies setting up their own monitoring programs, Also, standards and specifications available from ASTM International, the International Standards Organization (ISO), and the European Union (EU) Committee for Standardization (CEN) can be easily referenced without having to repeat the lengthy standardization processes that led to their publication. A number of CEM guidance manuals on CEM systems and regulations are referenced in the bibliography of this chapter and are readily available on the Internet.

ENFORCEMENT POLICIES AND CEM SYSTEMS

The most obvious impact of continuous data is that more information is available to environmental control agencies. By obtaining such data (or summaries of data), fewer on‐site inspections and manual reference method tests may be necessary to enforce emissions standards. Different approaches can be taken by an agency in applying CEM data to meet its goals of maintaining and improving air quality. Properly used, CEM data can expand an agency's enforcement capabilities. The CEM database can assist in negotiating the installation of control equipment or requiring process modifications, or the data can provide the basis for a supply‐and‐demand market‐based approach for improving air quality.

One would expect the regulatory application of CEM system data to be straightforward. If a source has a regulated pollutant emission limit and a monitoring system is installed to monitor the pollutant emissions, then it should be possible to determine at any time whether the source is emitting either under or over that limit. A source is said to be out of compliance if it exceeds its regulated emissions limits. A source is in compliance with emission standards if the emissions are under those limits. CEM systems do this and, by definition, provide emissions data on a continuous basis.

However, the use of monitoring data by air pollution control agencies with regard to enforcement issues becomes somewhat complicated. Technically, a continuous compliance determination method means:

a method specified by an applicable standard or an applicable permit condition which: (1) is used to determine compliance with an emission limitation or standard on a continuous basis, consistent with the averaging period established for the emission limitation or standard; and (2) provides data either in units of the standard or correlated directly with the compliance limit. (U.S. EPA 1997b)

Averaging periods, units, and the degree of correlation with the compliance limit all become issues in the application of monitoring systems to enforcement programs. These issues are readily resolved with the application of CEM systems, but resolution becomes more difficult when predictive emission monitoring systems (PEMS), continuous parameter monitoring systems (CPMS), or other such correlation methods are used. Problems can also arise from other areas. Arguments have been made that emission limits were established based upon EPA test (reference) methods such as those given in 40 CFR 60 Appendix A. Since a CEM system is not an EPA reference method, it has been argued that CEM system data cannot be used in enforcement cases. Also, early experience with CEM systems was somewhat less than satisfactory, and the lack of QA programs often made the CEM data less defensible in court. The conservative approach was to rely ultimately on the reference methods for enforcement issues.

The use of CEM system data for enforcement has grown as confidence has increased in the quality of the data. Specifying in a permit that a CEM system is the compliance method also helps to eliminate any ambiguity regarding compliance determinations. The EPA programs developed in response to the volume of data available have matured from the use of CEM systems from compliance indicating systems to compliance monitoring systems.

Compliance assurance monitoring (CAM) programs, the credible evidence rule, and periodic monitoring requirements for State Title V CAAA permits are also relevant to predictive and parameter monitoring methods, and fill in the monitoring gaps where CEM systems are not explicitly required (although CEM systems may still be used in such circumstances). As a result, EPA has put in place a regulatory framework that can be used to determine if a source is meeting its emission limits and standards at all times, as is required by the Clean Air Act of 1990.

Compliance Indicating Systems – Using CEM Systems for Reporting Excess Emissions

Federal CEM requirements were originally developed in 1975 to provide a means for sources and agencies to check the operation and performance of NSPS‐mandated control equipment such as bag houses and wet scrubbers. The intention was that the source could use the emissions data to track the control system performance, and that reports would be submitted quarterly to the agency. These reports, called excess emission reports (EERs), were to include data on the exceedances of emissions standards.

In 1975, new fossil‐fuel‐fired steam generators (FFFSGs), petroleum refineries, nitric acid plants, and sulfuric acid plants were the first source categories in the United States required to report such data on a quarterly basis. The excess emission reports can be used for the following:

To indicate if the source is using good operating and maintenance practices on its process and its control equipment to minimize emissions

To provide the agency with data on upset conditions or trend data indicating degradation of control equipment performance

To provide the agency with a continuous record of the source's ability to comply with standards

To provide a screening tool in inspection targeting programs

To provide the agency with sufficient data to issue a Notice of Violation (NOV) if the source is not complying with regulations or standards

Under U.S. regulations when CEM data are used for excess emissions reporting, the data usually have not been used alone as legally enforceable determinants of emission exceedances. Instead, the data have been used to show that a problem exists and, based upon the severity of the problem, the agency takes further action, which might include conducting reference method tests for determining compliance with emissions standards. The reference method test data would then determine if the source was complying with its emissions standards.

Using EER data to show that a system is not meeting emissions standards and then requiring an EPA compliance test to initiate legal action is cumbersome to some. The advantage, however, is that this method offers the agency significant negotiating power and provides flexibility in the enforcement program. The problem is that evaluating excess emission reports and following up with inspections and compliance tests can require more time and resources than an agency may have available.

Until 1997, many states adopted the position that excess emission report (EER) data would not be used to refer cases to the Department of Justice or to issue an order of noncompliance, unless other regulatory mandates specify the CEM system as the compliance method (as a compliance indicating systems). Actually, this position has not precluded the use of EER data in enforcement cases. Because an agency may review all available information when evaluating the compliance status of a source, the CEM data can constitute part of the record of an enforcement proceeding. Section 113 of the Clean Air Act states:

“Whenever, on the basis of any information available to him, the Administrator finds that any person is in violation of any standard of performance…he may bring a civil action in accordance with subsection 113(a).”

EPA can use EER data alone, as a basis for issuing a “finding of violation” (FOV) or a “notice of violation” (NOV) (U.S. EPA – OAQPS, 1984, Reich). If the source does not come into compliance after an FOV or NOV is issued, EPA must acquire compliance test (Reference Method) data before it can initiate litigation or issue a Notice of Noncompliance (NON). However, NOVs have been issued using CEM data on the basis of the Clean Air Act Section 113(a) to effectively enforce source compliance (McCoy 1985, 1990).

For agency personnel, a handbook providing procedures for reviewing excess emission reports is available (Quarles and Peeler 1986). A more recent review guideline, developed by the Commonwealth of Virginia Department of Air Quality (VADEQ), extends review procedures to predictive emission monitoring systems (PEMS) and continuous parametric monitoring systems (CPMS) as well as CEM systems (VADEQ 2018).

Enforcement Levels

The advantage of the “Excess Emission” (EER) approach for source enforcement is that it allows an agency discretion in its enforcement program. Based upon past source performance, agency resources, and so on, an agency may choose to follow up on or not to follow up on reported instances of excess emissions. A phone call may suffice to clarify a problem, an FOV or NOV may be issued, or, further, a site inspection or source test may become necessary.

An agency may take action on several levels after a review of an excess emission report. Depending on the agency policy, this determination may be either formalized or may be flexible. The approach illustrated in Table 2‐5 is typical although the action levels based on magnitude and periods of excess emissions or length of monitor downtime may vary.

Depending on the stringency of the program, the action levels may vary. For example, percentages for acceptable out‐of‐compliance periods could be <1% (more stringent) or <3% (less stringent) instead of <2% as given in Table 2‐5. Acceptable monitor downtime (in the absence of a percent availability requirement in the facility permit) might be specified in an agency policy as <1% (more stringent) or <3% (less stringent).

Level 1

On the first level, the agency evaluates the facility's quarterly EERs, by checking the following items:

Submittal timeliness and completeness

Reports of periods and magnitudes of excess emissions

Nature and cause of each period of excess emissions

TABLE 2‐5 Example Target Criteria and Agency Follow‐up Action Levels Based Upon a Review of the Excess Emission Report

Agency% of Time Compliance Response | % of Monitor Out of Compliance | Suggested Downtime Follow‐up | Action
Acceptable | <2.0% | <2.0% | If both cases exist, acknowledge receipt of EER
Request for corrective action | >2.0% and <5.0% | >2.0% and < 5.0% | If either or both cases exist, then send a letter requesting corrective action within 30 days
Warning letter | >5.0% and <10.0% | >5.0% and < 10.0% | If either or both cases exist, then warn by letter of unacceptable condition, request explanations of condition, and request corrective action plan to prevent condition from reoccurring
Notice of violation | >168 hrs >10% |  | If either or both cases exist, then issue NOV and require performance (compliance) test for monitored pollutant, monitor certification (PS) tests and request corrective action plan to prevent condition from reoccurring

Periods during which the continuous monitoring system was inoperative

Records of calibration checks, adjustments, and maintenance performed on the monitoring system

Problem areas in source operation and/or control equipment operation should present themselves on thorough evaluation of these items. When the documentation is unclear or incomplete, the facility should be contacted for clarification of the problem areas, perhaps avoiding more extensive agency action.

Level 2

On the second level, for more frequent exceedances or greater CEM system downtime, a request may be issued for corrective action to be taken within 30 days.

Level 3

If the EER reports are repeatedly late, indicate operational problems at the plant, or if emission levels are substantial, a warning letter requesting that the issues be resolved within 30–90 days may be issued. Alternatively, these deficiencies could be used to trigger an inspection by the agency that may include both an examination of the emission control system operation and the emission monitoring program. The inspection could take the form of a systems audit, not requiring the use of test equipment or gases.

Based on the findings and observations of the on‐site inspection, it may be necessary to conduct limited testing on the CEM system to check that it is operating properly. Performance audit procedures may be conducted, where the CEM system is challenged with certified audit gases and/or filters to check data validity.

Level 4

This level of activity determines the source performance with respect to the compliance test methods. If the tests show that the source is not in compliance with emissions limits, the test data can be used to support further legal action.

The following potential violations (among others) may be indicated from an excess emission report, supplementary information accompanying the report, or information requested upon the review (VADEQ 2018; U.S. EPA 2014c):

Exceeding the emission limit

Failure to meet emission control percentage reduction requirement

Failure to meet monitoring availability specification (as applicable in rule or permit)

Control equipment operation and maintenance deficiencies

Failure to conduct required, periodic CEM performance evaluations (RATAs, CGAs, Linearity Tests)

Failure to write or implement a CEM system QA/QC Plan

Failure to follow permit recordkeeping and reporting requirements

Compliance Monitoring Systems – Using CEM Systems for Direct Compliance

The use of CEM systems has evolved in other ways for enforcement purposes. The continuous record can be used directly to establish whether the source is in violation of the standard if a compliance CEM system is legally mandated. The CEM system becomes a “compliance monitoring” system, in contrast to a “compliance indicating” system. In this instance, CEM systems can provide an agency with legally enforceable data to issue fines or other penalties if the source is not complying with agency regulations or emissions standards (Hellwig 1980). Much like issuing a speeding ticket, if the source is over the limit, a fine is essentially automatic.

In the United States, individual states are allowed to develop regulations more stringent than the federal requirements and, as early as 1969 (McKee 1974), mandated CEM systems to be the compliance method. States have also used source operating permits, variances, compliance orders, and other regulatory tools to require the installation of CEM systems for this purpose. Data from CEM systems can be considered legally enforceable data by using these mechanisms.

The federal government has gradually instituted the use of CEM systems for compliance monitoring. The first of such regulations was promulgated for nonferrous smelters (copper, lead, and zinc smelters, Subparts P, Q, and R) in 1976. Continuous emission monitors were established here as the reference test method, but only during periods of time specified as a compliance test period. Only the data obtained during the scheduled period are considered compliance data; otherwise, the CEM system data are regarded as excess emission monitoring data. A much clearer use of CEM systems as compliance monitoring systems came with the promulgation of the NSPS for the Subpart Da Electrical Utilities (73 MW or larger utilities constructed after 18 September 1978). This promulgation (June 1979) requires the installation of SO₂ CEM systems to monitor both compliance with emission standards and the SO₂ removal efficiency of the emission control systems. Similar requirements have since been instituted for other source categories.

In one important ruling in 1987, EPA allowed the use of opacity monitors as a compliance test method, in lieu of the visible emissions observer, but only if the plant operator chose the option (52 FR 9778 26 March 1987 and 40 CFR 60.7. 60.11, and 60.13). Many states now specify the use of opacity monitors as the compliance method and do not offer such an election by the source operator. For specific applications, individual state requirements should be reviewed.

Continuous monitoring systems (CMS) required for sources in the air toxics standard of Part 63 are considered to monitor source compliance, or otherwise determined by the Administrator to be compliance monitors (§63.6). This includes continuous parametric monitoring systems used as the CMS.

COMPLIANCE ASSURANCE MONITORING AND THE CREDIBLE EVIDENCE RULE

The distinctions between compliance indicating and compliance monitoring systems are the result of environmental agency policy development since 1971. In the late 1980s, policy direction began to shift toward the use of CEM systems for compliance monitoring, with many new regulations specifically stating that CEM systems were to be used for direct enforcement. Then, in response to the 1990 CAAA requirement that major stationary sources submit certifications of compliance with pollutant emission limitations, the compliance assurance monitoring (CAM) rule was developed (U.S. EPA 2020j). As discussed earlier, the CAM rule focuses on monitoring the operation and maintenance of air pollution control equipment, with the assumption that this monitoring will indicate the compliance status of the source.

The CAM rule goes back to the concept of monitoring to indicate compliance or noncompliance. CAM data obtained from a continuous monitor or a parameter monitoring technique would not be used directly but would serve in further negotiations similar to those used in the evaluation of excess emission reports. But the question remains whether CAM data are enforceable data. The answer lies in the credible evidence rule, which was promulgated separately from the CAM rule, but is viewed by EPA (U.S. EPA 1997a, b) as complementing the rule.

The credible evidence rule is relatively concise, stating:

For the purpose of submitting compliance certifications or establishing whether or not a person has violated or is in violation of any standard, nothing shall preclude the use of any credible evidence or information relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. [emphasis added]

The rule allows CEM data to be used in litigation, whether the data comes from a compliance indicating CEM system, a compliance monitoring system, or a compliance assurance monitoring (CAM) system (Figure 2‐6).

The key to using the data for enforcement is the ability to show that a relationship exists between the monitoring data and the reference (test) method specified for the pollutant in question, for the source in question. A certified CEM system that has passed a relative accuracy test to meet performance specifications or a parameter correlated to performance test data would pass this relationship test. In other cases, arguments and further information might be required in the course of litigation.

Figure 2‐6 illustrates that data from a compliance indicating CEM system or a compliance assurance monitoring system used to monitor the operation and maintenance of air pollution control equipment can be used for enforcement through the credible evidence rule. Data obtained from a compliance monitoring CEM system need not invoke the credible evidence rule in enforcement cases. The credible evidence rule is a clarification of the position that many agencies have always maintained; in litigation, §13(a) of the Clean Air Act allows the use of any information available to the agency.

Figure 2‐6 CEM systems and enforcement policy.

Periodic Monitoring

The position of EPA has been that sources are obligated to comply with all permit emission limits and standards at all times. With regard to this position of EPA, in §§70.6(a)(3) and 71.6(a)(3) of 40 CFR 70 and 71, State and Federal Operating Permit Programs require that a source operating permit include a monitoring program. As stated in Section 70.6:

Where the applicable requirement does not require periodic testing or instrumental or noninstrumental monitoring, [the permit must still include] periodic monitoring [requirements] sufficient to yield reliable data from the relevant time period, that are representative of the source's compliance with the permit.

Also, a responsible official from the company must certify that the source is in compliance with all applicable requirements. The periodic monitoring should be of sufficient quality to provide a basis for the official to certify the compliance status of the source under all operating conditions.

Epilogue

Environmental control agencies have found CEM systems to be valuable tools in their regulatory programs. Whether used as control equipment operation and maintenance indicators, compliance monitors, or the basis for allowance trades, CEM systems today have become integral to achieving environmental goals. Requirements to install CEM systems at stationary sources arise from both federal and state regulatory programs. Whether state or federal, these programs specify pollutants that are to be monitored, emission limits, CEM system performance criteria, CEM quality assurance requirements, and reporting requirements. However, they are still incomplete if they do not include some mechanism for independently validating the data (Duflo et al. 2013).

Even with the best of intentions, CEM systems can be unsuccessful in supporting emission control programs. Analyzers, controls, computers, and associated equipment make up a CEM system, but just as an automobile’s odometer can be compromised, data from a CEM system can be falsified. If the environmental control agency has incentives to reduce emissions but no disincentives to prevent deliberate adjustments to data, the likelihood of data corruption is higher than if procedures are instituted to discourage such behavior. Especially problematical is the case when ethical personnel are requested by management to make adjustments they know to be wrong. It then often becomes a matter of either acceding to the request or being terminated. Although ultimately becoming a whistleblower may offer some sense of retribution, employees should never be put in such a position.

It is relatively easy to adjust and report CEM data to any value desired. It is also relatively easy to detect such adjustments. Given the daily calibration verification values, the emissions data record, maintenance logbook, and other records, an astute inspector can readily identify questionable data. Jumps in emission values, miscalibrated instruments, frequent instrument recalibrations, the introduction of correction factors, or CEM downtime during emission excursions are all situations that invite further investigation. A review of both calibration verification quality control charts and the analog emissions data are particularly useful in such an investigation. The problem is that someone has to do this. However, all too often, both the regulated facilities and/or the environmental control agencies either lack the foresight or lack the resources to institute procedures to make reality checks.

As an example of one solution to these issues, in the U.S. acid rain program, all calibration, emissions data, and performance evaluation results as well as plant operating data are submitted to EPA’s Clean Air Markets database. The data are checked for format and cross checked using various algorithms to evaluate whether they are internally consistent and whether they are consistent with plant operating conditions and past performance. Inconsistent data are flagged and requests are made to clarify and correct the data, as appropriate. In another example, the Canadian CEM Guidelines, EPS 1/PG/7, require that a facility’s CEM QA/QC program be evaluated annually by an independent inspector. In the United States, in the rare case that CEM data have been falsified, legal proceedings often ensue. In these proceedings, penalties are not civil penalties such as those incurred for having excess emissions, but criminal penalties – a significant disincentive.

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CHAPTER 3
EXTRACTIVE SYSTEM DESIGN

Analyzers used to monitor stack gases must be incorporated into a system – one that can protect the analyzer from the plant environment and provide a representative stack gas sample for analysis. Either in‐situ or extractive systems can be designed to perform this. Extractive systems were the systems first developed for continuous emission monitoring and are discussed in this chapter; in‐situ systems are discussed in Chapter 6.

Delivering and conditioning a hot, moisture‐saturated, particle‐laden flue gas to an analyzer can be a difficult process. Because the pollutant gases may be lost in this process, it is critical that the extractive system is properly designed and manufactured. Extractive system designs are associated with specific CEM system vendors, having been developed through years of industrial applications experience. Although it is possible and relatively easy to design and construct an extractive system from basic components, most systems purchased today are provided on a turn‐key basis; that is, the system is provided from start to finish. The two basic types of extractive systems that vendors offer are (i) fully extractive, source‐level systems and (ii) dilution systems. Each system has its own advantages and disadvantages in any given application.

This chapter describes both source‐level and dilution extractive systems and the components that are used in their design. Knowledge of these extractive techniques will assist in evaluating proposed system designs or systems that have already been installed.

SOURCE‐LEVEL EXTRACTIVE SYSTEMS

Source‐level extractive systems remove gas directly from the stack or duct, filter out particulate matter, and transport the gas for analysis. Three types of source‐level extractive systems are marketed commercially:

Hot/wet systems (Figure 3‐1)

Cool/dry systems with conditioning at the probe (Figure 3‐2)

Cool/dry systems with conditioning at the CEM system shelter (Figure 3‐3)

Hot/Wet Systems

The simplest type of extractive system uses a heated line to transport the flue gas to an analyzer that incorporates a sample cell heated above the flue gas temperature. The gas is delivered to the analyzer both hot and wet, but it minimally conditions the gas by removing particulate matter with a coarse filter located at the probe. The technique is useful when monitoring of water‐soluble gases is required, or when wet‐basis emission values are to be reported. Because water is not removed from the sample gas, problems associated with condensation systems are avoided. However, care must be exercised in maintaining the temperature of the sample above the dew point, from the probe to the analyzer exhaust. If the heating system should fail, moisture will readily condense and foul the system. This can lead to corrosion, plugging, or damage to the analyzer. Accordingly, a hot/wet system must be designed to shut down and flush with clean, dry air or nitrogen in case the system begins to cool down due to an event such as a power outage or heater failure.

Figure 3‐1 A hot/wet CEM system without sample conditioning.

Hot/wet systems are often used in association with ultraviolet analyzers designed for the measurement of SO₂ and NOx. When a wet‐basis pollutant measurement is obtained in conjunction with a volumetric flow measurement, the pollutant mass concentration can be obtained directly from the product of the two measurements (pollutant mass rate = concentration(wet) × volumetric flow rate (wet)). In contrast, when a cool/dry concentration measurement is obtained, a knowledge of the flue gas moisture content is necessary to calculate the pollutant mass rate. This adds both complexity and possible errors to such a monitoring system.

Hot/wet systems are also useful for measuring water‐soluble gases such as HCl, NH₃, and certain volatile organic compounds. The chiller in a cool/dry extractive system will remove these gases either in part or entirely, so either a hot/wet system or dilution extractive system would be necessary to deliver a representative sample to the analyzer. A hot extractive system and a hot analyzer can also minimize the adsorption of gases on the extractive system surfaces. Chemical reactions such as NO to NO₂ conversion (Sneek 1997) and ammonium sulfate (White 1995) or ammonium chloride (Peeler et al. 1997) formation can be minimized by using higher‐temperature extractive systems.

Cool/Dry Systems with Conditioning

In a more widely applied extractive system design, the gas is conditioned before it enters the analyzer. The gas temperature is reduced to ambient temperature and moisture is removed, so that the sample is both cool and relatively dry. The conditioning may be conducted either at the probe location (Figure 3‐2) or at the analyzer shelter (Figure 3‐3). Conditioning at the probe location offers the advantage of using unheated sampling line; however, preventive maintenance of the conditioning system at the probe may be inconvenient. Conditioning at the shelter or CEM room enables the CEM system operator to check the system performance conveniently. However, the necessary heat‐traced lines must be maintained at a proper temperature over their entire length.

Figure 3‐2 A cool/dry CEM system with conditioning at the probe.

Figure 3‐3 A cool/dry CEM system with conditioning at the CEM system shelter.

Extractive systems that condition the flue gas allow greater flexibility in the choice of analyzers and are commonly used when emission calculations are performed on a dry basis or when monitoring a number of different gases is required. Although this type of system is not as sophisticated as some others, it is flexible enough to accommodate engineering changes when application problems arise. In problem applications, the system components can be readily modified or replaced so that the system can meet performance specifications.

A source‐level extractive system is made up of a set of basic components: probe, sample line, filters, moisture removal system, and pump. Because the operation of an extractive system is dependent on the design and quality of each component, as well as on their arrangement in the system, it is necessary to review these characteristics.

Sample Probes

A sample probe (sometimes called a “stinger”) can be made by merely inserting an open metal tube into the stack or duct, or multipoint probes may be used to sample from several locations when the flue gas is stratified (Shahin 2016). This may be adequate in sampling situations where no particulate matter is present. However, flue gases free of particulate matter do not often occur in those sources that are subject to CEM regulation. An open tube can be easily plugged when particulate matter is present, especially if the flue gas has high moisture content. Also, water may condense and combine with the particulate matter to produce an agglomerated material that can plug the probe more readily. To minimize such problems, a filter can be placed at the end of the probe (Figure 3‐4a–c).

Filters made of sintered stainless steel and porous ceramic materials are commonly used to prevent particles from entering the sample tube. Sintered metal is made by compressing micrometer‐sized metal granules under high pressure and elevated temperatures. The metal fuses and acquires porosity depending on the compression pressure. Sintered stainless steel filters that are capable of filtering out particles of 5 to 50 μm have been used as probe filters. Some systems use filters that exclude particles greater than 1–2 μm in size, but the finer the filter, the more difficult it will be to draw the sample gas through the filter, and pump capacity will need to be increased.

Sintered filters or ceramic filters can become plugged by the particles impacting on and penetrating into the porous material. To minimize plugging, a baffle plate can be attached to the filter to deflect particles from the filter surface (Figure 3‐4b). Particles will then follow streamlines formed around the plate, whereas pollutant gases will still diffuse into the probe. Another way to minimize plugging is to attach a cylindrical sheath around the filter (Figure 3‐4c). Gas will still diffuse into the annular space between the filter and baffle, but most particles will not be able to make the 90° change in the direction to enter the space. If the end of such a sheath is partially closed off with a porous plate to provide for gas diffusion, the external filter probe can undergo a probe calibration check. Calibration gas can be injected into the sheath to flood out the stack gas during the calibration intervals.

In the probe designs shown in Figure 3‐4a–c, the coarse particulate filter is attached at the end of the probe. In another probe design, this filter is mounted externally, in a housing mounted outside the stack (Figure 3‐5).

In filter assemblies mounted outside of the stack, a heater either can be fitted into the assembly or placed around the outside of the filter holder. This allows the hot flue gas sample to remain hot as it is drawn through the filter and passed through to the heated sample line and the remainder of the conditioning system. The principal advantage of this configuration is that the coarse filter can be easily unclamped and inspected. The entire probe assembly does not need to be unbolted and removed from the stack to replace the filter, and if the probe becomes plugged with particulate matter, the plug can be pushed out with a rod. Also, if the probe is mounted at an angle (Figure 3‐5), water or acid condensed in the probe can roll back into the stack.

Figure 3‐4 (a) A simple probe filter. (b) Sintered filter with a baffle plate deflector. (c) Sintered filter with a deflector sheath.

Extractive systems designed with external filter housings can readily undergo a calibration verification at the filter housing. Calibration gases can be injected into the annular space between the filter and the housing to provide a check of system integrity from the filter back to the analyzer. This is difficult to do with in‐stack filters because the filter is constantly subject to the flue gas flow and excessive amounts of calibration gas may be needed to continually flood the area around the filter during a calibration verification.

Figure 3‐5 A course filter assembly mounted outside of the stack.

Other variations of the designs as shown in Figure 3‐5 are also used. One variation uses a coarse filter of 10–50 μm porosity at the probe tip, but incorporates a 1‐μm‐pore‐size external fine filter at the flange assembly. Another variant uses a bellows valve to close off the external filter from the probe to reduce the amount of gas necessary to perform a probe calibration check.

A major problem associated with the probes illustrated in Figures 3‐4a–c and 3‐5 is that the sintered filters still can plug with particulate matter. Another system, designed to minimize this problem, utilizes an inertial filter (Figure 3‐6).

In the inertial filter system, a pump (usually an eductor pump) pulls the flue gas through an internal cylindrical filter. The internal filter can be made of sintered stainless steel or porous ceramic, usually having a pore size of 2–5 μm. As the flue gas moves down the tube, a sample is pulled off from the filter at a direction perpendicular to the gas flow (radially) using another sampling pump. The gas velocity through the tube can vary from 70 to 100 ft/s, whereas the radial velocity of the gas pulled from the filter may be only 0.005 ft/s. Larger particles in the flue gas are swept through the tube because of their inertia in the gas stream and are exhausted back into the stack. Because of the low radial sample velocity, larger particles are also less likely to break from their streamlines and enter the filter. The 70–100 ft/s flow also aids in sweeping the particles off of the filter surface and back into the gas stream. An inertial filter can be incorporated as part of the probe inside the stack or in a system external to the probe, such as the one shown in Figure 3‐7.

Figure 3‐6 The inertial filter.

Conceptually, this system may appear ideal, but actually, submicron sized particles (<1 μm diameter) can follow the radial sample flow and enter the tubular filter. These embedded particles can further assist in the filtering action to reduce the filter pore size and remove particles down to 0.5 μm diameter from the sample stream. However, this also means that the filter can eventually become plugged.

Filter plugging can be a problem with any fully extractive system. Plugging can be minimized by “blowing back” on the filter using high‐pressure gas, plant air, or steam – air at pressures from 60 to 100 pounds per square inch (psi) is blown back through the filter, opposite to the normal direction of gas flow. The blowback can be pulsed by first pressurizing a surge tank and suddenly releasing the pressure to shock the particulate matter out of the pores of the filter. Depending upon particle characteristics and concentration, filters are blown back at periods of 15 minutes to 8 hours for durations of 5–10 s; 15‐minute blowback cycles are common. Care must be taken in the blowback system so that the blowback gas does not cool the probe to the extent that acids or other gases condense.

Umbilical Line

In a cool/dry system, a heated sample line is used to transport the sample from the probe to other elements in the conditioning system, or in the case of hot/wet systems, directly to the analyzer after particulate removal. The heated sample line (heat‐traced line) is generally incorporated into a tube bundle, or umbilical, which may contain electrical cables and additional tubing to transport zero air, blowback air, and calibration gases. Temperature sensors can also be placed at intervals along the line to monitor the temperature and warn of any reduction in temperature. A typical umbilical tube assembly with a heated wire coiled around the tube bundle is shown in Figure 3‐8.

Figure 3‐7 An externally mounted inertial filter.

Figure 3‐8 An umbilical assembly external to the stack.

In cool/dry extractive systems, heat‐traced line is used all the way from the probe to the moisture removal system. This distance can be as short as 2–3 ft for stack located systems, but is more commonly 100–250 ft. It is important to insulate and/or heat the junctions between the heat‐traced sample line and the probe and between the line and the moisture removal system; otherwise cold spots can develop that may eventually cause plugging and corrosion. If the moisture removal system is installed at the probe location, or if a dilution extractive system is applied, unheated sample line (or sample line with a lower temperature rating – freeze‐protection line) can be used to transport the sample to the analyzer.

Typical temperatures for extractive‐system heated sample lines are higher than 180 °C. Typical sample line materials are high‐density polyethylene (HDPE – maximum temperature 110 °C), polytetrafluoroethylene (PTFE – maximum temperature 260 °C), perfluoroalkoxy Teflon (PFA – maximum temperature 260 °C), and stainless steel (ss – either uncoated or treated coated with glass (SilcoNert®)). Heated umbilicals can be operated either at a constant power density or can be self‐limiting (self‐regulating). In self‐limiting lines, a specified minimum operating temperature will be maintained if the ambient temperature falls (e.g. sub‐zero conditions in winter) and will not exceed a specified maximum temperature if the ambient temperature rises. A cross section of a self‐regulated line for a dilution extractive system, with the heating element in the center of the bundle for freeze‐protection, is shown in Figure 3‐9.

This umbilical consists of the following components:

One 3/8″ O.D. PFA Teflon tube heated sample line

One 3/8″ O.D. PFA Teflon tube heated dilution air line

Two 1/4″ O.D. PFA Teflon tube (unheated calibration gas and purge air and spare)

Two 1/4″ O.D. PFA Teflon tube (unheated spares)

Two 3/8″ O.D. PFA Teflon tube (unheated spares)

Electrical lines in the umbilical include the following:

Sample line heater (120 self‐regulating heating cable)

Sample line Type K thermocouple

The low‐temperature self‐regulating heater in the line operates to maintain a temperature of approximately 50 °F, to guard against water condensation in the flue gas sample if the ambient temperature decreases below the dew point of the diluted sample gas (<−40 °C). The internal heated portion of the bundle is enclosed by a thermal barrier of an aluminum heat transfer tape. The outside of the bundle is enclosed by a flexible, black polyvinyl chloride insulation jacket. In this case, the calibration gas lines are located in the outer, unheated jacket of the bundle. Another option is to provide a separate, unheated umbilical to house the zero air and calibration gas lines.

Although much information has been cataloged on the relative chemical resistance of sample line materials to corrosive gases (McNulty et al. 1974; Podlenski 1984), 316 stainless steel or PFA Teflon are commonly used. Problems can occur with Teflon if the line temperature is too high since its softening temperature is near 250 °C. Efforts to increase sample line temperature to avoid condensation or adsorption sometimes melt the line and the umbilical cable. Furthermore, some gases (such as CO) can permeate through polymeric sample lines (Dunder and Stone 1995), especially at higher temperatures.

One solution to minimizing adsorption of volatile organic compounds has been the development of glass‐coated flexible stainless‐steel tubing (Gerhab and Schuyler 1996). This combination of fused silica and stainless steel can be heated to desorb gases from the tubing surface, if necessary. The company SilcoTek, (formerly, Restek) located in Bellefonte, PA, is the principal supplier of coating services for tubing, parts, fittings, chemical reactors, and process industry components. Proprietary materials such as SilcoNert®, Dursan®, and others are deposited by chemical vapor deposition to a depth of typically 2 μm (SilcoTek 2017).

Figure 3‐9 Umbilical line cross section for a dilution extractive system.

Chemical attack and wall adsorption effects can be a problem when sampling reactive gases. For example, Marshak (2015, 2019) and Hoard et al. (2014) have examined the problem of NH₃ retention in detail, using an FTIR spectrometer. At a flow rate of 3 l/min, they found that the time it takes for an NH₃ calibration gas value to stabilize at the analyzer can be significant, particularly when using untreated stainless‐steel sample lines. They also found that NH₃ adsorption of the sample system walls was dependent upon line temperature, flow rates, and the material. However, line length and diameter were not found to have a statistically significant effect. It was also found that PFA and SilcoNert® stainless steel lines work well for NH₃ with a flow rate of > 5 l/min, where 10–15 l/min may be preferable. Also, humidification of the sample and higher line temperatures reduced adsorption. SilcoNert® stainless steel was found to be the best for sample probes, and filters composed of borosilicate glass were found to be better.

Umbilicals are usually custom‐made and can contribute significantly to the expense of an extractive system. Umbilicals are usually priced per running foot and a total fixed price is generally not quoted by CEM system vendors unless the exact length is provided in a CEM system bid specification. Heated umbilicals are generally less than 250 ft in length, although longer lines can be installed if sufficient attention is paid to their construction. Freeze‐protect lines for dilution extractive mercury monitoring systems have worked well even at a length of 1000 ft; however, costs can be significant if, and when, they need to be replaced.

The time that it will take for gas to flow through a sample line will depend on the sample tube diameter, its length, and the flow rate. This lag can be roughly calculated from the expression (McNulty et al. 1974)

(3‐1)t equals StartFraction upper V Over upper Q Subscript s l Baseline EndFraction

where

t = the lag time (in minutes)

V = sample line volume (in liters)

Qsl = volumetric flow rate of gas through the line (liters per minute)

This expression is oversimplified since it assumes that there are no frictional wall effects restricting the flow. It shows, however, that if the sample line length is increased, the lag time will increase as the sample line volume increases. Typically, for a flow rate of 1 standard liter per minute (l/min), the lag time for a 100‐ft section of a 0.25‐in. internal diameter tube at a pressure drop of 152 mm Hg is only 30 s.

Hot spots should be avoided when installing a heated umbilical. Hot spots can be caused by the loss of temperature control through communication or temperature sensor failures or damages due to flexing problems. Hot spots can also occur if the bundle is clamped too tightly to a support, if the tubing makes contact with itself, or if multiple heated bundles are tied together, or if account is not taken for the temperature gradient between the inside and outside of a CEM shelter, in which case multiple heated zones may be necessary. The line should have a continuous downward slope from the probe to the conditioning system (5° is recommended) in case of condensation within the line, avoiding sags where condensate might collect, yet allowing for sufficient freedom for strain relief to allow for thermal expansion and contraction, especially when starting up or shutting down a unit. In the case of short circuits, damages may be minimized by incorporating ground fault circuit interrupter (GFCI) circuit breakers, tripping at 20 MA, into the system (Robinson 2010).

Condensation by water, acid, and other gases in cooler “pockets” can increase system corrosion or line plugging if fine particles are not adequately filtered at the probe. Sample lines can also become contaminated with reacted materials, which are difficult to remove. Plugs of particulate matter are difficult to remove in the heated sample line, and if a heater wire breaks or burns out, it is often difficult to find the break. On occasion, entire umbilicals will need to be replaced when these problems cannot be resolved (Bembe 2019).

Proper design and installation of the umbilical is important for its operation. This is not the area where costs can be cut. The use of inferior materials, installation by inexperienced personnel, and ad hoc supporting and fastening methods have led to numerous umbilical failures in the past (Robinson 2010). It is highly recommended that the umbilical manufacturer either supervise or be on‐site during installation. Lastly, the umbilical should be routed to avoid the possibility of damages by facility vehicles, cranes, forklifts, or other plant equipment.

Calibration Gas System and Cylinder Gas Pressure Regulators

A calibration gas delivery system is a component of any extractive sampling systems designed for meeting regulatory requirements in the United States and Canada. In North America, CEM systems are required to be calibrated against NIST‐certified calibration gases meeting established traceability protocols (Schakenbach et al. 2002; U.S. EPA 2012). Monitoring system calibration is required to be verified daily, and monitoring system linearity must also be audited quarterly using “protocol” gases injected as close to the probe as possible, passing through all components of the extractive system to the analyzers.

The calibration gas system typically extends from the calibration gas cylinders, through a gas pressure regulator, to an automated gas injection control system, through a dedicated line in the umbilical, and on to the injection port (Figures 3‐15 and 3‐21). The gas returns through the sample line to the analyzer(s). The calibration gas line may be either in the umbilical (which may be heated or unheated) or separated from the main umbilical in an unheated line. Components typically in contact with the calibration gas will be the calibration gas cylinder pressure regulator, calibration gas delivery line, the sample gas probe, the sample line, and the internal surfaces of the analyzer sample cell.

The use of cylinder gas pressure regulators is often taken for granted and can be a factor in the delivery of reactive calibration gases. Reactive gases such as HCl and NH₃ can stick to surfaces in the regulator as well as to the calibration gas delivery line, where the gas adsorption is dependent upon the materials of construction, flow rate, temperature, and the prior status of the delivery system. Moisture or other contamination in the regulator can have effects that may be difficult to uncover if proper precautions are not taken. Water in the air can condense in a regulator and regulators used for other purposes may have an unknown history that could lead to losses of the gas. Similar to calibration gas lines, regulators treated with SilcoNert® reduce surface absorption.

For reactive gases, calibration system problems are often blamed for the quality of the calibration gases. However, problems are more often due to the lack of consistent procedures used to deliver the calibration gas to the monitoring system. It is recommended that for reactive gases the regulator first be flushed with nitrogen for a half hour, installed on the cylinder, and then purged with the calibration gas. The regulator should remain on the cylinder and should be back‐purged when it is removed to exchange cylinders. Recommendations provided by Marshak (2015) are as follows:

Use new regulators – leave on the cylinder all the time.

Purge for 30 minutes prior to installing on cylinder.

Pressure purge with the cylinder gas 10 times.

Gas vendors are not always helpful on these issues, assuming that their purpose is to ensure the quality of calibration gases and not their usage.

Moisture Removal Methods

Moisture is usually removed before the hot flue gas enters a sample pump because water vapor and acid gases can easily condense in an unheated pump and corrode the interior. Cooling beyond the dew point (the temperature at which air is saturated with moisture) will cause moisture to condense, and many of moisture removal systems are designed to reduce the sample temperature below the dew point. Thermoelectric and compressor‐operated gas coolers are most commonly used for this purpose in extractive systems. Coolers should be correctly sized for the sample gas flow rates and stack‐gas moisture content; also, coolers must remove condensed water rapidly from the gas stream to minimize contact with dried gas.

Thermoelectric Coolers.

Hot flue gases can be cooled in thermoelectric Peltier coolers, which take advantage of the Peltier effect to chill the sample gas. The Peltier effect occurs when two dissimilar metals or semiconductors are joined in a loop and a voltage source generates a current through the loop. Because of the differing electron distributions in the dissimilar materials, a small voltage difference exits across their junction. The junction will heat up where the voltage difference opposes the voltage difference of the battery. At the other junction, thermal energy is absorbed from the surroundings and converted into electrical energy to balance the electron flow. This absorption, of course, reduces the temperature of the surroundings.

Semiconductor thermoelectric Peltier coolers are used in many commercial sample conditioning systems. Typically, impingers (laminar flow heat exchangers (Figure 3‐10)) are enclosed by a heat transfer block, which is contacted and cooled by a Peltier plate (Baldwin 1995). Radiator fins and a cooling fan dissipate heat from the hot side of the Peltier element.

In the impinger, the flue gas flows through the central tube, which is surrounded by a vacuum jacket. The flue gas remains above the dew point until it reaches the bottom where it is cooled rapidly. Water vapor condenses and is removed at the bottom of the impinger by typically using a peristaltic pump. The gas is cooled further by the cool impinger wall as it moves up to the impinger outlet. In a unique feature of the design, the gas is reheated by the unjacketed part of the central tube before exiting to the analyzer.

The effectiveness of this type of cooler is dependent upon the surface area and length of the impinger, gas flow rate, materials of construction, temperature of the ambient air, and the cold side temperature. The sizing of a Peltier cooler/impinger condensation system is dependent upon the demands of the total sampling system, so care must be taken in their proper application. The chillers normally operate to output a gas having a dew point of 4 °C (0.5% moisture concentration), but subzero coolers are available down to −25 °C to reduce the residual moisture concentration and to prevent the formation of acid gases such as SO₃.

Figure 3‐10 Impinger (laminar heat exchanger) used with a Peltier cooling system.

Compressor Gas Coolers.

Another approach to moisture removal is to use a compressor‐run refrigerator to cool the gas. Either laminar‐flow heat exchangers such as that shown in Figure 3‐10 or coils of Teflon, glass, or Kynar such as that shown in Figure 3‐11 are cooled by the refrigeration system. The condenser can be immersed in a liquid such as an antifreeze solution or water to facilitate better heat exchange. To avoid freezing condensate in the coil or impinger, temperature is typically not allowed to decrease to below 3 or 4 °C. Condensed water vapor is again continuously removed using a peristaltic pump. If condensate is removed only periodically or manually, failure to perform this operation may cause the trap to fill and overflow into the sample line. Most systems will incorporate a thermal conductivity detector or other means to detect or prevent moisture breakthrough into the sample line and analyzer.

Another condenser can be added to further reduce the water content, but a more efficient technique is to place the sample pump after the first coil and transport the gas from the chiller, under pressure, to a second chiller as shown in Figure 3‐11. A gas under pressure will condense more readily than a gas under vacuum. Since it is more difficult for water molecules to escape the liquid surface to vaporize when the gas is under pressure, this pressurization will, in effect, reduce the moisture content to a level lower than the content under atmospheric pressure.

Figure 3‐11 Refrigerated condenser moisture removal system with a secondary chiller under positive pressure.

In refrigerator systems, Freon sometimes escapes, pumps wear out, or algae start growing in the liquid. Another cooling option of using vortex coolers avoids these problems by using a counterflow of high‐pressure plant air to cool the sample gas. However, the power requirements necessary to generate the high flow rates of air needed may be excessive in some applications.

NafionTM Dryers.

Another method of removing water vapor from a flue gas sample is to use a material called “Nafion™.” Nafion™ is a copolymer of tetrafluoroethylene‐perfluoro 3, 6‐dioxa‐4‐methyl‐7‐octene sulfonic acid (Permapure 2019). The sulfonic acid group of the copolymer has high water‐of‐hydration, absorbing up to 13 molecules of water. Water vapor will transfer across the material by absorption as water‐of‐hydration if the partial pressure of the water vapor is different on each side of the membrane. Water molecules are initially bound on the material surface. However, unhydrated sulfonic acid groups deeper in the Nafion™ membrane will have higher affinity for water molecules and will absorb them and in turn pass them onto other unhydrated sulfonic acid groups, causing them to migrate into and through the membrane.

A typical dryer uses a bundle of Nafion™ tubes as shown in Figure 3‐12. In this dryer assembly, the wet sample gas enters the tubes and the dry purge gas flows in the opposite direction on the outside of the tubes to sweep the transferred water molecules away from the membrane. The driving force in this exchange can also be provided by either evacuating the shell side of the dryer or by back‐purging with dry gas taken from the tube exit. The dryer requires that the flue gas sampled be held above the dew point upon entering the dryer. The drying efficiency increases with the length of the tubes and is also dependent upon the sample inlet and purge gas pressures. Capacity can be increased by increasing the number of tubes in the bundle. In contrast to gas coolers, having an exit moisture content of 0.5%, gas exiting a Nafion™ drier is significantly lower, at 0.05% H₂O, corresponding to a dew point of −22 °C (Geary and Sinada 2018). When using a gas analyzer where water vapor interferes in the measurement, a Nafion™ dryer, or a Nafion™ dryer following a gas cooler, may help to minimize the interference.

The Nafion™ dryer offers a number of advantages over refrigerated chillers because no mechanical parts are incorporated into the system, no condensate trap is required, and the question of pollution absorption in condensed water is avoided. However, dryers using small‐diameter Nafion™ tube bundles can be prone to plugging, either from droplets of condensed material or from particulate matter introduced by improperly filtered samples or by the precipitation of salts. Problems of condensing liquids may be minimized by heating the entrance side of the dryer, whereas particulate plugging and precipitation can be resolved by using larger diameter tubing. When using large‐diameter tubing (1/4 in.), greater lengths of tubing must be used to achieve performance equivalent to that obtained from employing bundles of smaller diameter tubing.

Pollutant Losses in Condensation Systems.

One limitation of condensation‐type moisture removal systems is that pollutant gases can be absorbed in the condensate. This occurs readily for gases such as HCl and NH₃, which have high solubility in water and where, clearly, condensation methods are not applicable. NO has little solubility in water, but gases such as SO₂ and NO₂ can also be lost in the condensate. This issue has not always been recognized because SO₂ and NO₂ losses are less pronounced at higher concentrations (>100 ppm) and the losses can go undetected during a certification test if the source tester uses an apparatus that also incorporates a condensation moisture removal method. However, with the advent of more stringent emission standards requiring gas monitoring in the range of 50 ppm or less, more care must be taken to avoid biases due to analyte condensate losses.

Figure 3‐12 A Nafion™ dryer assembly.

Unfortunately, research on this problem has often failed to be sufficiently comprehensive in addressing a number of factors that affect analyte losses. McNulty et al. (1974) studied SO₂ losses at 1200 ppm, Freitag (1993) at 100–1000 ppm, and Baldwin (1995) at 300–400 ppm. Complicating the issue, the design and construction of the condenser can contribute to solubility losses, where poorly designed systems may allow too great a contact time between the dried gas stream and the collected liquid. Also, losses are dependent upon the inlet moisture concentration, sample gas flow rate, condenser temperature, and condenser material (glass, Kynar, PTFE, stainless steel). The most comprehensive, independent evaluation conducted to date is by Swaans et al. (2018), who studied SO₂ and NO₂ losses in four different coolers using glass, stainless steel, and PTFE condensers, at nominal concentrations of 25, 90, and 100 ppm for SO₂ and 10, 50, and 100 ppm for NO₂, at flow rates of 2, 3, and 5 l/min, and flue gas and moisture contents of 4, 11, and 20% H₂O.

Freitag (1993) found that for SO₂ at concentrations on the order of 100–1000 ppm, under a variety of conditions, 3–15% of the SO₂ could be lost in the chiller. Freitag also projected that at SO₂ levels of 20 ppm at 20% moisture, losses can be on the order of 30%. He observed that SO₂ losses increase with the increasing moisture content, decreasing SO₂ content, and decreasing trap temperature. In thermoelectric coolers at 380 ppm SO₂, Baldwin (1995) found losses of 1.7% of the SO₂ concentration at an inlet moisture concentration of 20% using glass impingers. Using stainless steel impingers and an SO₂ concentration of 245 ppm, he found losses of 4.1% SO₂ at an inlet moisture concentration of 20%. He also found greater losses at lower flow rates. In a comparison between thermoelectric coolers and permeation dryers, Dunder and Leighty (1997) sampled gases having SO₂ concentrations of 20, 50, and 100 ppm at moisture levels of 15 and 30%, at flow rates of 5 l/min. In the study, higher SO₂ concentrations were found using a permeation drier compared to a thermoelectric cooler, under all conditions. In agreement with these earlier studies and extending the work to lower concentrations while examining additional variables, Swaans and associates (2018) found, for SO₂ at a concentration of 25 ppm in a flue gas at 20% moisture content and a flow rate of 3 l/min, relative losses of 7–17% SO₂ using either Peltier or compressor coolers, depending upon the manufacturer of the cooler. The higher losses were seen in PFA‐coated heat exchangers relative to glass heat exchangers. At a lower SO₂ concentration of 17 ppm, Geary and Sinada (2018) found, at moisture levels of 6–9%, losses of up to 50% of the original sample concentration in a condensing cooler system compared to measurements using a permeation drier. Pellikka et al. (2019) have also demonstrated losses using a chiller in comparison to hot–wet and dilution extractive systems.

The primary conclusion from the work of Swaans et al. is that when monitoring SO₂ at low concentrations (<25 ppm) SO₂ losses are highly dependent upon the manufacture of the cooler, flue gas variables, and cooler operational variables. It is also apparent by comparing the work of others that the lower the SO₂ concentrations and the higher the moisture concentration, the greater will be the losses of SO₂ in gas coolers. To certify a CEM system in a RATA, comparing data with a source tester’s reference system operating under a different set of variables could lead to a failed certification, or where bias correction factors are required, inaccurate bias adjustments. At low SO₂ concentrations, it is recommended that instead of installing a source‐level extractive system with a gas cooler, a hot/wet extractive system, a dilution‐extractive system, or a source‐level extractive system, using a Nafion™ dryer, be considered for the application.

As a last resort in source‐level extractive systems using chillers, SO₂ absorption can be decreased by increasing the acidity of the condensate. One technique has been to acidify the gas stream with an unmonitored acid (such as HCl) to reduce SO₂ solubility during condensation (DeFriez 1992; Williams 1992).

Miscellaneous Drying Techniques.

Other drying techniques have been used or attempted in extractive monitoring systems. Cyclone‐type devices installed in or near the probe, coalescing filters, “knock‐out jars,” and other engineering afterthoughts are sometimes encountered.

The use of chemical desiccants (such as calcium chloride, CaCl₂; concentrated sulfuric acid, H₂SO₄; calcium sulfate, CaSO₄) to remove moisture is not common in CEM systems. Because desiccants have to be periodically regenerated or replaced, they are considered to present an unnecessary maintenance task. Also, to justify their use, it must be shown that the gases being measured do not react with, adsorb onto, or absorb into the material.

In cases where acid gas formation, such as SO₃, might occur, a “freezer” chiller designed to achieve a dew point of −25 °C can be used to reduce moisture levels to less than 650 ppm and minimize the loss of SO₂ by acid formation.

Sample Pumps

The sample pump is an important element of the extractive system and is used to transport the sample from the stack to the analyzer. A pump should be sized appropriately to meet the demands of gas analyzers and be designed so that no air in‐leakage occurs (i.e. around a rotary shaft seal) and that no contamination is introduced from pump lubricating oils. Two types of pumps meeting these criteria are (i) diaphragm and (ii) ejector pumps. These pumps are commonly used in source monitoring applications.

Diaphragm pumps operate by mechanically stroking a piston or a connecting rod to move a flexible diaphragm (Figure 3‐13). The diaphragm is circular and can be made of a flexible metal plate, Teflon, polyurethane, or other types of elastomer. The reciprocating action of the diaphragm moves the gas in short bursts. As the diaphragm is raised, the gas is drawn through the suction valve into the pump cavity. When the diaphragm is pushed down, the suction valve closes and the discharge valve opens. The gas is then displaced out into the sample line. Because only the chamber, diaphragm, and valves come into contact with the gas, contamination of the gas is minimized.

Figure 3‐13 A diaphragm pump.

Diaphragm pumps can be used before the sample gas conditioning system and can even be operated hot. However, particulate matter and condensed acid can weaken the pump head by particle abrasion or chemical attack. Unless the gas is properly filtered and the pump head adequately heated, it is better to locate the pump after the conditioning system. Eventually, the continual, rapid flexing action of the pump will cause the diaphragm to split or tear.

The flow rate of a diaphragm pump can be controlled by placing a throttle valve in the line on the discharge side of the pump or by installing a by‐pass line and valve from the suction side to the discharge side. If the pump is operating at less than its full capacity, controlling flow with the throttle valve will cause the pump to work against a high discharge pressure and pump life will be reduced. For this reason, it is better to control the flow using a bypass valve.

The ejector pump (also called an eductor or air aspirator) takes advantage of the Bernoulli effect to draw a vacuum through a sampling system (Figure 3‐14). In the Bernoulli effect, the moving jet of air reduces the air pressure normal to its flow. This is a common effect that is familiar in venturi flowmeters and jet carburetors. This reduced pressure pulls the sample gas through the sample line; if the jet velocity increases, the vacuum increases. Typically, the filtered plant air or compressed cylinder gas is used for the high‐velocity gas stream. The ejector pump is simple in its design and can be incorporated as part of an inertial filter probe system as shown in Figure 3‐7. Here, the pump draws in the sample through an inertial filter that would be installed in a heated cabinet located outside the stack. Another pump, usually a diaphragm pump, is used to pull the filtered sample to the analyzer. In the ejector pumps applied where the sample gas is not filtered, particulate matter can build up and dry out in the annular space of the pump. In such cases, it may be necessary to use steam instead of compressed air to provide the motive force for the pump action.

Figure 3‐14 The ejector pump or eductor.

Fine Filters

The coarse filter is used to remove larger particles from the sample gas. Because the majority of gas analyzers require almost complete removal of particles larger than 0.5 μm, additional filtration is necessary. This is accomplished by incorporating a fine filter before the analyzer inlet. The location of the fine filter is an important consideration in the CEM system design and is dependent upon the susceptibility of the other system components to the effects of fine particles. There are two types of fine filters: (i) surface filters and (ii) depth filters.

A surface filter can be simply a filter paper that excludes particles of a certain size. The filter material is porous to the moving gas, but the pores are of such a size that they prevent penetration of fine particulate matter. A filter cake can also build up on the filter, further reducing the size of particles passing into the gas stream. Because of the filter cake and developed electrostatic charges, surface filters can remove particles smaller than the actual filter pore size.

Depth filters collect particles within the bulk of a filter material. The filter may consist of loosely packed fibers of quartz wool or of filter material wrapped to a depth sufficient to remove fine particles. Such filters work particularly well for dry solids and moist gas streams containing aerosols. A depth filter can also be used as a probe filter, a technique that is used in some systems.

Assembling a Cool/Dry Extractive System

Designing and assembling a cool/dry extractive system is a relatively straightforward process. System components, such as probes, chillers, filters, and pumps are available from many suppliers and can be purchased individually to incorporate into a system design. Alternatively, several suppliers provide modular conditioning systems and modular calibration gas distribution systems that simplify the assembly. An example of a plumbing system for a cool‐dry extractive system is shown in Figure 3‐15.

Figure 3‐15 A cool/dry extractive system for monitoring CO.

The example shows a simple sample probe (stinger) attached to a heated, coarse filter external to the stack. Instrument air is provided for particulate blowback from the filter. Two sets of impingers, cooled with a Peltier cooler, condense moisture from the flue gas sample. The condensed water vapor is removed from the system using peristaltic pumps. A water break‐through detector is incorporated into the line after the first set of impingers and before the sampling pump. The sampling pump transports the dry sample gas to the analyzer after passing through a fine filter. The sample system control panel monitors vacuum, pressures, and flow rates at various points in the system. The control panel may provide for either manual or automatic control of the gas distribution although today most systems are automatically controlled. The system illustrated shows only one gas analyzer, but can be expanded to monitor multiple gases.

Although assembling such components to construct a CEM system may appear straightforward, it is important that the system design be appropriate for the application. If emissions need to be reported on a mass rate basis (kg/hr), if the pollutant is partially soluble in water and the emission limit is 10 ppm instead of 200 ppm, a hot/wet or dilution extractive system might be more appropriate. Other factors such as flue gas temperature, moisture content, and particulate concentration must also be considered in the system design. High temperatures and/or high levels of particulate matter or sticky particulate matter may limit the choice of probes and filters. Similarly, high moisture levels or the presence of acid gases may limit the choice of sample coolers. For challenging applications, experience in system design is important. It is this experience that distinguishes CEM system integrators from each other. It also may make a difference in the success of the system in passing its initial certification test and its success in operating continually without excessive maintenance demands.

Not shown in the diagram are the electrical and communication systems necessary for system control and data utilization. These aspects of the CEM system are the most difficult to accommodate into a CEM system installation because they must be integrated into existing plant networks. Most CEM systems do not stand alone, but are often used for control and optimization of the monitored operating unit. Alarms, emission values, calibration results, and real‐time as well as summary data are typically routed to the plant distributed control system, or separately to the environmental manager or corporate office. All of this takes coordination and collaboration with plant personnel and contractors to assure that CEM system electrical connections and communications are properly integrated into the existing systems of the plant. Compared to these challenges, assembly of monitoring system hardware is the simplest part of the installation program.

CLOSE‐COUPLED SYSTEMS

Many of the problems associated with source‐level extractive systems can be resolved by coupling the extractive and analytical system directly to the stack or duct. This technique minimizes problems associated with reactive, condensable, or adsorbing gases by essentially eliminating the sampling line. The method is especially appropriate for the extraction and measurement of volatile organic compounds. Close‐coupled systems have also been designed for monitoring criteria pollutants (Mandel and Gottlieb 1995), the most recent incorporating modular gas sensors with internal microprocessor control to regulate temperature, flows, and calibration sequencing (Jahnke 1997). A typical close‐coupled system is illustrated in Figure 3‐16.

Close‐coupled systems allow the use of analytical techniques that may need a more controlled sampling volume than is afforded in in‐situ measurements. By measuring the sample directly outside of the stack, sampling conditions can be controlled, while minimizing reactivity and sample line problems. Close‐coupled systems can be designed as either cool/dry or hot/wet systems.

Figure 3‐16 A close‐coupled extractive systems.

Costs of such systems are lower due to the elimination of the sampling line and the use of temperature‐controlled cabinets, which removes the need for a CEM shelter. However, challenges of the ambient environment, such as lightning, rain, ice, or extremes in temperature, may compromise its operation unless it is designed to accommodate such varying conditions.

DILUTION EXTRACTIVE SYSTEMS

The main problem associated with source‐level extractive systems is the need to filter and condition relatively large volumes of stack gas. This problem can be largely avoided by using dilution systems where gas is drawn into the probe at low flow rates, sometimes two orders of magnitude less than in a source‐level system (e.g. 0.05 vs 5 l/min.). This means that there will be less particulate matter to filter and less moisture to remove. Because the flow is relatively low, particles are more likely to follow the flue gas streamlines around the probe than to enter the probe.

Dilution systems are used in conjunction with ambient air level analyzers – a feature that can provide significant advantages to a source that has had previous experience with ambient air level analyzers or that is operating an ambient air network. In the case of analyzer problems, CEM system analyzers could be swapped for ambient air level analyzers or spares maintained for both purposes. Plant technicians already may be familiar with the operation and maintenance needs of the analyzers and may not require additional training.

There are two approaches to designing dilution systems. One approach is to dilute the stack gas in an in‐situ, “in‐stack” sample probe (Figure 3‐17). Here, the eductors and dilution orifice are contained in the probe itself. Another approach is to dilute the stack gas outside of the stack (Figure 3‐18) in a module containing the eductor and the dilution capillary or orifice. As with fully extractive‐system conditioning systems, using a dilution module outside of the stack, dilution can be performed at either the stack or the CEM shelter. If diluted at the stack, unheated sample lines can be used to transport the gas to the analyzers, but if diluted at the shelter, heat‐traced lines must be used.

Figure 3‐17 An in‐situ (in‐stack) dilution probe CEM system.

Figure 3‐18 An external dilution CEM system.

The dilution systems have seen widespread application in monitoring emissions from electrical utilities affected by EPA's acid rain program. In this program (U.S. EPA 2020a), emissions are reported in units of mass/time (i.e. lbs/hr or tons/year), calculated by multiplying a wet basis flow rate measurement and a wet basis pollutant gas measurement. Since dilution systems measure gases on a wet basis, the calculation is straightforward, not requiring a determination of flue gas moisture content. This feature, as well as the advantages inherent in sampling at low flow rates, has made it popular.

Dilution Probes

A dilution probe dilutes the stack gas in the probe to such a degree that the dew point of the diluted gas will be less than the lowest ambient temperature at the sampling location. This enables the CEM system to avoid the use of heat‐traced line and simplifies the gas transport system.

One of the first and most successful dilution systems uses a critical orifice coupled with an ejector pump designed into the probe body (Figure 3‐19). This probe, originally developed in the Netherlands (Bergshoeff and van Ijssel 1978), is unique in its design and construction.

This probe has also been known as the “EPM” probe named after the company that marketed it in the 1980s and 1990s.

Inside the probe, an ejector pump operates at flow rates of 1–10 l/min. A glass critical orifice (consisting of a glass tube drawn to a point, as shown in the figure) is chosen to limit the flow of sample gas to flow rates from 20 to 500 ml/min. The condition for obtaining a critical flow for the glass orifice is that the ratio of the absolute pressure at the venturi throat to the stack static pressure must be less than or equal to 0.53 (Brouwers and Verdoorn 1990). The dilution ratio, D, is calculated as follows:

(3‐2)upper D equals StartFraction upper Q 1 plus upper Q 2 Over upper Q 2 EndFraction

where

Q₁ = dilution air flow rate (l/min)

Q₂ = sample gas flow rate (l/min)

Data obtained from the gas analyzers measuring the diluted flue gas are converted into the source‐level concentrations by multiplying the analyzer response and the dilution ratio determined or adjusted at the time of initial calibration.

Dilution ratios of 50‐to‐1 to 300‐to‐1 are typical. The higher ratios are used for hot, saturated gas streams. In coupling a dilution system to an analyzer, attention must be paid to the measurement range of the analyzer. If the lowest instrument range should be 0–5 ppm, and it is required to measure a pollutant stack gas at a nominal concentration of 50 ppm of the pollutant, a 100‐to‐1 dilution ratio would provide a sample to the analyzer of 0.5 ppm. This would be at the low end of the range where the analyzer sensitivity is lowest. If the instrument noise or drift is high at this part of the scale, it could be difficult for the system to pass a relative accuracy test.

Figure 3‐19 The in‐stack EPM dilution probe.

Although the EPM dilution probe has been successfully applied, it is not the solution to all extractive sampling problems. In the cases of wet, caking, or sticky particulate matter, the probe can still become plugged even though it is pulling at a low flow rate. Dilution probes of this type have experienced difficulties when installed after wet scrubbers, where water droplets are entrained by the flue gas. If the droplets enter the probe, or water condenses in the probe from a highly saturated gas stream, the glass wool filter can become wet and the orifice can become plugged. Under normal conditions, when the probe is heated, water droplets should be vaporized and plugging should not be a problem. To avoid problems resulting from water droplets, adequate temperature control is required.

The dilution probe is sensitive to changes in stack pressures and temperatures (Jahnke and Marshall 1994; Myers 1986). In installations where the stack static pressure is highly negative (<−10 in. H₂O), the venturi vacuum may not be sufficient to overcome the pull of the stack negative pressure.

It should also be noted that air is used for dilution. This prevents the use of an oxygen analyzer in the CEM system because the contribution of stack gas oxygen to the sample would be swamped by the background 21% oxygen level of the dilution air. Most commercial oxygen analyzers are not designed to measure differences in oxygen levels at diluted values of 0.1–1%. If it is required to correct pollutant emission data for stack dilution air, a CO₂ analyzer is used in the system. When a regulation requires that pollutant concentrations be corrected to a specified oxygen concentration (such as the 6% O₂ correction specified in 40 CFR 60 Subpart BB for Kraft pulp mills (U.S. EPA 2020c)), the critical orifice can be incorporated into an assembly, which first splits the flue gas into two gas streams – one that passes through a critical orifice and is diluted and one that remains undiluted. This cannot be done when using an in‐stack dilution probe, but can be done when using external dilution systems.

Dilution Air Cleanup Systems

The air used for dilution must be clean and free of any of the gases being measured or else significant errors can occur. For example, 1 ppm of NO in the dilution air will give a response of 100 ppm in a dilution system having a dilution ratio of 100 : 1. Activated charcoal, sorbents, heatless dryers, and other gas scrubbing techniques are commonly employed to provide clean, dry air to the dilution system.

Because the dilution air cleanup system is central to the proper operation of the dilution extractive system, it is usually made redundant, with two equivalent systems. If maintenance is required, the system being serviced can be isolated, while the other system continues to provide purified air. A schematic of a redundant dilution air cleanup system is shown in Figure 3‐20.

In Figure 3‐20, manual valves are used to isolate air cleanup system for filters, scrubbers, or dryer maintenance, while the other system remains in operation. As instrument air enters, a coalescing filter is used to remove oil, water, and dirt from plant instrument air, in combination with a regulator to regulate the gas pressure. The air passes to a second‐stage coalescing filter backing up the filter/regulator and then to a soda lime scrubber, containing a mixture of Ca(OH)₂, NaOH, and KOH for the removal of CO₂. NOx and SO₂ are removed in a scrubber containing a material such as Purafil, a chemisorbent media composed of activated alumina impregnated with potassium permanganate. Water and CO₂ are removed in a heatless regenerative dryer, and SO₂ and other gases are removed in an activated carbon scrubber. The regenerative dryer is filled with chemisorption media to remove CO₂ and H₂O from the gas stream by adsorption, absorption, and chemical oxidation processes. The purifiers contain two columns packed with a desiccant material (such as activated alumina), where one column is drying the air and the other one is simultaneously being regenerated. If CO is being measured, another regenerative dryer and a heated catalytic CO scrubber can be included in the system, as shown in the figure.

Figure 3‐20 Example of a redundant dilution air cleanup system.

The dilution air pressure must remain constant. Variations in this pressure due to inadequate pressure regulation can significantly affect dilution ratios. Some systems integrators have installed mass‐flow controllers to maintain this pressure at a constant level. The air supplied to a dilution system may also serve as the air supply for the zero calibration cycles of the system gas analyzers, as well as an air supply for the ozone generator of an NOx analyzer.

Figure 3‐21 illustrates the plumbing associated with a typical dilution extractive system using an EPM probe. Note that the design differs from that of a source‐level extractive system shown in Figure 3‐15, by eliminating the sample conditioner and sample pump. In the dilution system, the motive, dilution air is used in the ejector pump to both dilute the flue gas sample and send the diluted sample under positive pressure to the analyzer. However, in exchange for a flue‐gas conditioning system in a source‐level extractive system, a dilution air cleanup system is required for dilution systems. Of course, either requires periodic maintenance. Dilution systems typically include a control unit that includes gauges and meters for monitoring the eductor vacuum, dilution air pressure, temperatures, calibration gas flow, and so on.

External Dilution Systems (Probes)

Another approach to diluting the flue gas is not to dilute it in the stack, but outside of the stack in a dilution assembly contained in a protective housing close‐coupled to the stack. External dilution systems can be more easily serviced and temperature controlled than an in‐stack dilution probe; however, in principle, their response time is somewhat slower due to the length of time necessary to transport the sample from the probe tip to the dilution orifice. External dilution probes do offer several advantages over in‐stack dilution probes. They can be heated relatively easily to maintain a more constant temperature. In wet scrubber applications, they can resolve droplet and aerosol condensation problems that may be more difficult to address with an in‐stack critical orifice. For example, by sloping the stinger of an external system, droplets can run off into the stack before they reach the critical orifice. The external systems also offer a significant maintenance advantage by not requiring the probe to be extracted to examine or replace the filter or critical orifice.

Figure 3‐21 An in‐situ dilution probe extractive system.

Several external dilution system designs are available. Each design is associated with a particular manufacturer and different industrial sectors, such as coal‐fired power plants or pulp and paper plants, tend to favor one particular design over others. In CEM system upgrades, external dilution systems often replace in‐stack dilution probes, not so much for any inherent faults in the in‐stack probes, but more often for not having to remove the probe from the stack for maintenance or because the designs are newer and “trendy.”

Cross‐Piece Fitting Design.

In a system designed by M&C Tech Group, an assembly, close‐coupled to the stack, is unique by cleverly incorporating both the dilution eductor and a dilution capillary within a Swagelok cross fitting (Figure 3‐22). This makes for a compact design where the temperature can be easily maintained.

In locating the dilution system outside of the stack at the end of the probe, the characteristic low flow rate of a dilution system would decrease the response time of the system to real‐time flue gas concentration fluctuations. This is in contrast to an in‐stack dilution probe, where the flue gas is diluted essentially at the probe tip and the diluted sample is transported relatively swiftly to the analyzers. A solution to this problem in external dilution probes is to add a venturi bypass eductor to transport the flue gas to the analyzer at a relatively high flow rate of 3–5 l/min. A slipstream from this flow is then extracted by the dilution eductor at a lower flow rate on the order of 30–50 ml/min. The flue gas sample is then diluted after the critical orifice (see the inset in Figure 3‐22) by mixing with the motive air flowing through the dilution eductor. It is necessary that the filter and other system components connected prior to sample dilution be heated to avoid condensation by flue gas moisture.

Using a bypass eductor solves a response time problem; however, by bringing the flue gas sample in at a high flow rate, the low flow advantage of the in‐stack dilution probe is lost. Higher flow rates will transport higher levels of particulate matter through the probe to the probe filter than the lower flow of the dilution eductor in transport of the flue gas. This will require that the probe filter and a probe be periodically inspected and cleaned, and may require the installation of a blowback system.

Modular Block Design.

Another M&C Tech Group external dilution probe design is shown in Figure 3‐23. This second‐generation design by M&C is more modular and robust than the design shown in Figure 3‐22. It is again compact and easily heated and has been successful especially in mercury monitoring applications. In this design, two modular heated blocks, located on the top of the assembly, enable the flue gas flow and sample dilution using two ejector pumps. In operation, the bypass eductor contained within the first block draws the sample through the probe filter. As in the external probe shown in Figure 3‐22, the dilution eductor in the second block draws a slipstream from the bypass eductor flow line at a lower flow rate. Again, clean, dry, conditioned air from the dilution air cleanup system provides the motive force for the pump vacuum and also serves to dilute the flue gas that it draws in from the slipstream. The flow rate of the sampled gas is controlled by a glass capillary serving as a critical orifice under the sonic flow conditions.

Figure 3‐22 External dilution system with cross‐piece dilution unit.

Figure 3‐23 Dilution system with modular block dilution unit.

In the daily calibration verification of the CEM system, the calibration gas is sent through the calibration/purge gas line (shown in Figure 3‐23 at the bottom of the assembly) at a flow rate sufficient to flood the annulus outside of the filter, expelling the flue gas. The calibration gas is then extracted by the CEM system similarly to the sample gas, being conditioned in the same manner as the sample gas.

The STI Probe.

The first external dilution probe was developed to address plugging of dilution orifices by water droplets in the EPM probe by Sampling Technology, Inc. (STI) and is available from STI and Thermo Fisher Scientific (Figure 3‐24). This external dilution system, made of Torlon, is shown in Figure 3‐24 (Fischer 1993). It again uses an ejector pump to extract the sample from the stack and has been popular in pulp and paper industry applications, particularly after wet scrubbers. The flue gas sample extracted at low flow rates is first filtered by a tubular filter, where particulate matter and aerosols not dropping out in the probe are collected. A quartz capillary serves as the critical orifice, which controls the sample gas flow rate. The sample gas combines with the ejector pump air as in other dilution systems described.

As mentioned previously, one advantage of an external dilution system is that an undiluted sample can be first sent to an O₂ analyzer before it proceeds to the dilution system. This provides an alternative to using a CO₂ analyzer for the diluent monitor. A separate sample line can be installed after the probe filter, but before the dilution orifice, to draw an undiluted sample. This sample can then be conditioned to remove water vapor and analyzed with an oxygen sensor.

An alternative approach to external dilution systems is to transport the gas from the stack in the traditional manner of a source‐level extractive system and to dilute the gas in the CEM shelter. This does provide for rapid gas transport, but a heated sample line must be used. This approach loses one of the principal advantages of dilution systems – their ability to deliver the sample to the analyzers with unheated sample line.

Enhancing the Operation of Dilution Systems

In today's applications for CEM systems, new demands have been made for dilution systems and CEM systems in general. For example, in the acid rain program, relative accuracy specifications became more stringent at 10%, daily calibration error (drift) is limited to 2.5% of span, and a 5% linearity criterion has been established. Although relative accuracy specifications are not difficult to meet, it is found that a clear understanding of the operating characteristics of dilution systems is necessary to achieve the optimum performance necessary for meeting the drift and linearity test specifications.

Figure 3‐24 STI external dilution system design.

In dilution systems, the flue gas concentration is calculated from the dilution ratio as follows:

(3‐3)c equals c Subscript m e a s Baseline upper D Subscript o

where

c = the calculated source‐level concentration of the gas (ppm)

cmeas = the analyzer response (ppm) to the diluted sample

Do = the dilution ratio at the time of calibration

This equation assumes that the dilution ratio remains the same while the reading cmeas is obtained as when the dilution system was calibrated initially. This is not always the case. If the absolute pressure changes from Po to P, the stack temperature changes from To to T, or the molecular weight of the sampled gas changes from Mo to M, the dilution ratio will change also. Pressure, temperature, and molecular weight all affect gas density, which affects the sonic flow of the gas through the orifice. A change in gas density will therefore affect the dilution ratio.

Problems arise when the original conditions at which the dilution system was first calibrated change for any subsequent measurements. Figure 3‐25 illustrates the principal factors that may cause a change in the dilution ratio.Consider the following scenarios illustrated in the figure:

Figure 3‐25 Principal factors causing changes in dilution systems.

Scenario 1 A dilution system is calibrated initially when the total stack pressure PT = Pbar + ps, the unit is on, the flue gas temperature = To, and the calibration gas has an average molecular weight = Mo. Typically, any variation from the nominal dilution ratio is adjusted out by setting the analyzers to the certified calibration gas concentration during calibration.

Scenario 2 A dilution system is calibrated at a stack absolute pressure of Po. A weather front moves in and the atmospheric pressure is reduced. A calibration check will indicate an upward drift in reading.

Scenario 3 A dilution system is installed on a cycling unit and is calibrated when the unit is off, at a temperature To. After the unit is turned on and the stack temperature increases, a calibration check will indicate a downward drift in reading.

Scenario 4 A dilution system is calibrated with an SO₂ in N₂ calibration gas. An auditor conducts a linearity test using a gas mixture containing SO₂ and 20% CO₂. The test gives a reading lower than expected.

These are all scenarios that may cause discrepancies in dilution system measurements. However, these discrepancies can be corrected (i) empirically or (ii) theoretically. Empirical corrections, based on experimental data from installed systems, have been used successfully in specific applications. Lacking experimental data, theoretical expressions can be used and have also been successful in correcting for the effect of gas density variation on the dilution ratio.

Empirical Corrections.

Empirical correction equations for pressure and temperature have been given by Jahnke and Marshall (1994) as follows:

Pressure Correction Equation.

Pressure changes may be caused by changes in either stack pressure or ambient pressure. It is not uncommon to observe an apparent reduction in pollutant gas concentrations when a weather front passes a CEM installation having a dilution system uncorrected for pressure. In one study, this pressure effect was noted as causing a 1% error for each 3.45 in. of water pressure change (Jahnke and Marshall 1994; see Figure 3‐26).

An empirical correction equation that has been used to account for pressure changes in the EPM dilution probe is given in Equation 3‐4:

Figure 3‐26 Pressure dependence of the critical orifice dilution system.

Source: Jahnke and Marshall (1994).

(3‐4)

where

∆P is the difference between the stack absolute pressure when the measurement is made and the pressure when the system was calibrated.

This equation appears to be general for dilution systems that do not use mass flow controllers for the dilution air. It would be prudent, however, to check the validity of the empirical coefficients on the installed system and adjust them for any system‐specific characteristics. Procedures for doing this are given in Jahnke and Marshall (1994).

Temperature Correction Equation.

Temperature effects contribute approximately 1% error for each 50 °F change in temperature from the initial dilution probe calibration setting (Jahnke and Marshall 1994). The temperature effect, however, is nonlinear. Temperature fluctuations of this magnitude do not usually occur in most operating units. However, for cycling units and other units that operate infrequently, a common practice has been to perform calibration adjustments to the dilution system when the unit is cold (not operating) and assume that the calibration holds during start‐up and when the unit is hot. This is not a valid assumption and can lead to measurement error greater than 10% due to the nonlinearity of the temperature dependence.

Probe temperature dependence can be minimized by heating the probe, although this has not always been successful during start‐up due to cooling of the heater by initially cool flue gas. A better approach, particularly for cycling units, is to use an external dilution system outside of the stack, where the temperature can be better controlled.

Alternatively, but not as satisfactory as maintaining probe temperature, empirical temperature correction equations can be developed. One equation developed for the EPM dilution probe is given in Equation 3‐5.

(3‐5)

This correction equation appears to be system specific (Jahnke and Marshall 1994) and should only be used as a first approximation for small changes in temperature (e.g. ± 50 °F). It is recommended that the user check the expression for his or her own installation and adjust it as appropriate. It does not appear to work well in cycling units where large swings in temperature are frequent.

Molecular Weight Correction Equation.

Since the flow through the critical orifice is dependent on gas density, molecular weight of the sample gas also affects the dilution ratio. Fluctuation of flue gas moisture and CO₂ concentrations can cause errors in the dilution measurements since their concentrations are respectively low (18) and high (44) relative to the usual combustion gas molecular weight of ~30. Also, with regard to earlier Scenario 4, the use of multi‐blend calibration gases containing CO₂ initially caused considerable confusion in conducting calibration error (drift) and linearity tests. The higher molecular weight of CO₂ increases the density and will cause lower readings if the dilution system was previously calibrated with a cylinder gas containing nitrogen (MW 28) only, as a background gas. Errors due to fluctuations in molecular weight have been calculated to approach up to 7%, depending upon the initial calibration conditions and measurement conditions (McGowan 1994).

This issue was first resolved by Miller (1994) who calculated relative sonic velocities for a variety of multicomponent gas mixtures. A molecular weight correction expression was developed by Appel (1994) for changes in flue gas composition valid under the condition that the dilution system is calibrated initially with single‐blend, nitrogen background cylinder gases:

(3‐6)

Combined Corrections.

If pressure, temperature, and molecular weight changes are affecting the dilution system response, the equations given above can be cascaded to obtain the following:

(3‐7)

Such an expression may not be necessary for all applications, but it does indicate that some insight must be put into the application and that more than one correction may be necessary.

Theoretical Corrections.

Although the theory of the critical orifice has been examined in detail, the construction and operation of dilution probe and its analogues may not satisfy all the underlying assumptions of the theory. Theoretical aspects of dilution systems were studied by Munukutla (1992) and Jahnke and Marshall (1994), Romero and Associates (1999), and Batug and Associates (2004). The extended formulation of Jahnke is provided here.

Dilution system theory begins from the theoretical equation for critical flow (see ASME 1971; Green and Perry 2007; Sadegh and Worek 2017; Shapiro 1953). This equation is used to obtain a corrected dilution ratio, D, from a new set of gas conditions that differ from the conditions under which the system was originally calibrated for the initial dilution ratio, Do (Jahnke and Marshall 1994; Munukutla 1992):

(3‐8)

Instead of using Equation 3‐3 (c = cmeasDo) to calculate the source‐level concentration from the measured analyzer data, the following equation can be used to correct the data to the actual conditions of measurement:

(3‐9)

This equation has been shown to adequately represent the effect of pressure and molecular weight changes on dilution system data (note: it is simplified by not incorporating changes in specific heat) (Jahnke and Marshall 1994; McGowan 1994; Miller 1994). Critical orifice theory predicts that the temperature variation f left-parenthesis upper T right-parenthesis equals StartRoot upper T EndRoot slash StartRoot upper T EndRoot Subscript o. However, this expression is incomplete since it does not account for changes in the dilution air temperature. Baugham (1996) has done this and has developed an instrument control method that corrects for both probe and dilution air temperature variations. In later work, Romero et al. (1999) and Batug et al. (2004) applied computational fluid dynamic techniques to develop a model for evaluating temperature, pressure, and molecular weight effects in the EPM dilution probe.

Equation 3‐9 is especially useful for calculating molecular weight corrections that would apply to changing flue gas composition or cylinder gas audits using different gas blends. One can simply input the molecular weight of the initial calibration gas, Mo, and correct subsequent readings if the molecular weight of the test gas, M, is known.

Note that these corrections may not be necessary if data are reported as an emission rate, E, in terms of lb/mmBtu (ng/J). If emissions are reported in units of lbs pollutant emitted/10⁶ Btu generated (or ng/J),

the F factor expression can be used (see Appendix A).

(3‐10)upper E equals c upper F Subscript c Baseline StartFraction 100 Over percent-sign upper C upper O 2 EndFraction

where

Fc = “F” factor in scf/10⁶ Btu

c = pollutant gas concentration

Because the pollutant concentration is divided by percent CO₂, any constant change in the dilution ratio cancels out in the concentration ratio. When reporting emission mass rates in pounds/hour, the pollutant mass rate equation is not expressed in a form where flue gas density effects on the dilution ratio cancel, and changes in the flue gas density must be taken into account.

Other Correction Methods.

In conjunction with Pennsylvania Power and Light (PPL), the Lehigh University Energy Research Center developed a dilution ratio calculation system called “DRCalc™” (Batug et al. 2004; Romero et al. 1999, 2002, 2005). After the dilution ratio is set initially, this system provides corrections for changes in the dilution air supply pressure, dilution air supply temperature, stack pressure and temperature, the sampled gas molecular weight, and the calibration gas molecular weight. Signals from temperature, pressure, and sensors, in addition to flue gas composition data, are sent to the DRCalc™ unit, where proprietary software is used to continually recalculate the dilution ratio. This system has been patented (Batug et al. 2004) and was successfully applied at PPL facilities (Sale 2000a, b). It also incorporates an algorithm for changes in the dilution probe flue gas temperature, f(T).

For the EPM dilution probe, an apparatus has been designed (Baugham 1996, 1997) that uses a regulator to adjust the flow of dilution air to maintain a consistent dilution ratio to compensate for gas density changes. The advantage of this apparatus is that it can easily retrofitted into existing systems without having to make computational changes in the data acquisition system. Atmospheric and stack pressure and sample temperature are monitored to provide inputs into the system. Equation 3‐6 is used to adjust for sample temperature changes. The system can also provide for changes in gas density as the flue gas moisture or oxygen concentrations vary.

The Electric Power Research Institute developed an algorithm for in‐stack and external dilution system corrections in their “CEMS Analyzer Bias and Linearity Effects (CABLE) study” (Berry 2000). The study was conducted to improve the accuracy of CEM systems used in the acid rain program and provided recommendations for the implementation of a correction algorithm based on Equation 3‐9. In this algorithm, the temperature dependence, f(T), was expressed empirically as fleft-parenthesis upper T right-parenthesis equals RootIndex x StartRoot upper T EndRoot slash RootIndex x StartRoot upper T Subscript o Baseline EndRoot when the study data were found not to follow the theoretical relation f left-parenthesis upper T right-parenthesis equals StartRoot upper T EndRoot slash StartRoot upper T EndRoot Subscript o. Here, x, is determined for each individual dilution system. Step‐by‐step procedures and a logic diagram for implementation of the dilution ratio correction routine can be found in an EPRI report of the study (Berry 1999).

Dilution Extractive Systems: Wet or Dry Measurement?

A question that frequently arises when considering the use of a dilution system is whether the emission values are given on a wet basis or a dry basis. Dilution systems that do not dry the diluted sample gas give concentration values (ppm) on a wet basis. If there is no moisture removal, there will still be moisture in the diluted sample. When the diluted concentration (measured with ambient air level analyzers) is scaled back up by multiplying it by the dilution ratio, the moisture content is scaled back up also. The concentration of the pollutant gas in the original wet sample is obtained.

Consider an example of 1 ml of flue gas that contains 0.1 ml of water vapor (10% H₂O), which is diluted with 99 ml of dry air (Figure 3‐27). In the diluted sample, the percentage of water vapor is reduced to about 0.1% of the total volume. Essentially, the analyzer is measuring SO₂ in a background gas containing 99.9% dry gas and 0.1% water vapor. Therefore, the flue gas SO₂ concentration obtained is given on a wet basis. When the diluted concentration is scaled back up by multiplying it by the dilution ratio, the concentration of SO₂ in the original wet sample is obtained.

Figure 3‐27 Example of a wet flue gas being diluted with dry air.

Consider again from Figure 3‐27 that the diluted SO₂ concentration is measured to be 3 ppm. This means that for every 100 ml of gas analyzed, the volume of SO₂ equals 3 × 10⁻⁶ × 100 = 3 × 10⁻⁴ ml. However, because no SO₂ is in the dry air used for dilution, this must be the volume of SO₂ gas contained in the 1 ml of flue gas drawn into the dilution system. A volume of 3 × 10⁻⁴ ml in 1 ml is equivalent to a flue gas concentration of 3 × 10⁻⁴ × 10⁶ = 300 ppm. Because, in this example, the 1 ml of flue gas sample also contains 0.1 ml of water vapor, the 300 ppm value is actually a wet‐basis value.

To report a dry‐basis SO₂ emission concentration, the moisture content must be known. It can be calculated by using Equation 3‐11:

(3‐11)normal c Subscript d Baseline equals StartFraction c Subscript w Baseline Over left-parenthesis 1 minus upper B Subscript w s Baseline right-parenthesis EndFraction

where

cd = dry‐basis concentration value (ppm or percent)

cw = wet‐basis concentration value (ppm or percent)

Bws = the moisture fraction of the flue gas

A value for Bws can be obtained by either installing some type of moisture monitor, using a value obtained by manual stack testing, or by estimating a value based on process parameters. Using a moisture analyzer is the most straightforward approach; however, this adds another analyzer to the CEM system. A common technique is to measure oxygen on both a wet and a dry basis and using the results to compute Bws. Also, various calculation approaches have been proposed (Aldina 1985; McGowan 1976) that involve the manipulation of combustion source F factors. But frequently, a moisture value obtained from manual stack test measurements is set as a constant factor to make the appropriate corrections. This approach assumes that variation in the value will be small under normal source operating conditions.

It is not necessary to convert dilution measurements into a dry basis if emission measurements are to be reported on an actual or wet basis. If the emissions are to be reported in terms of a pollutant mass rate (pollutant mass/unit time) as in the acid rain program, the wet basis measurement can be used directly. Also, if emissions are reported in terms of ng/joule or lbs/million Btu, a moisture correction is not needed if CO₂ is monitored along with the pollutant. This is due to the form of the F factor equation used to calculate emission rate in ng/Joule or lbs/million Btu as discussed earlier (see Equation 3‐10). When CO₂ is monitored as a diluent and the Fc factor equation is used, moisture content cancels out in the ratio between the pollutant concentration and CO₂ concentration. This is also discussed in EPA Test Method 19 (U.S. EPA 2020b).

Lastly, one should be aware of inadequacies associated with the use of dry calibration gases to check the performance of wet systems. Cylinder gases used for calibration or audit purposes are dry gases, containing no water. The molecular weight of a dry gas used to establish the calibration of a dilution system will be different than the molecular weight of a flue gas containing percent levels of moisture. As discussed earlier, this will affect the dilution ratio and introduce bias into the measurement. Also, some analyzers are subject to interference by water vapor. Here, a dry calibration gas may not truly establish the calibration function for the analyzer and the wet flue gas measurements will be in error. Additionally, water can adsorb onto sample tubing and internal instrument surfaces and subsequently reduce the adsorption of other gases such as volatile organic compounds (Peeler et al. 1997). Daily calibration with dry gases can disrupt this effect and cause some disequilibrium in the measurements for a period of time after calibration.

SAMPLING INTERFACE/MONITOR CALIBRATION

The entire extractive system sampling system and gas analysis system must be capable of being calibrated as a unit. In the design of the system, calibration gases should be able to be injected as close as possible at the probe – a recommendation made in fact by the EPA in its Appendix F quality assurance requirements and a requirement for cylinder gas audits and linearity checks. This is necessary to check for leaks or other operational problems in the system. In calibrating source‐level‐extractive systems, the analyzer should be calibrated at the same gas flow rate, pressure, temperature, and operating procedures that are used in monitoring the stack gas. In calibrating dilution systems, the calibration gas must enter the system before the critical orifice. Flooding the coarse filter or dilution probe with calibration gas at the inlet or using a check valve that allows calibration gas injection directly behind the coarse filter are the best methods for performing this check (Reynolds 1989). If the system is not pressurized by the calibration gas, this method can be used to determine if leaks, blockage, or gas adsorption are occurring in the system.

The system should also be capable of checking the calibration directly at the analyzer. A comparison between instrument readings from a probe calibration check and an analyzer calibration check is frequently useful in system troubleshooting.

The calibration gases are usually injected automatically every 24 hours although some operators prefer to perform calibration checks manually so that the system can be watched more closely.

EXTRACTIVE SYSTEM COMPONENTS AND ACCESSORIES

The design of an extractive system involves considering more than piecing together a probe, pump, and a conditioning or dilution system. The task is more complex since decisions must be made on at least the following minimum components:

Sample probe: construction and composition

Probe blowback: design and frequency

Sample line: composition, length, and diameter

Valves and fittings: construction and composition

Pressure and vacuum meters: quality

Moisture conditioning system: refrigerated, dilution, capacity, design, and construction

Filters: coarse, fine, or coalescing

Pumps: capacity, type, and quality

CEM shelters or cabinets: location, shelter HVAC requirements, enclosed space safety considerations, temperature stability

System controller: programmable logic controllers, datalogger, or microprocessor to sequence and control automatic functions

Electrical support: fuses, circuit breakers, regulating equipment, and uninterruptible power supplies (UPS)

Calibration gases: location, injection point, tubing requirements, regulators, and manifold, certified gases as appropriate, cylinder gas cabinet or weather overhang, cabinet heater/air conditioning as appropriate

Automatic calibration system: valves, injection sequencing, interconnections with the DAS and/or DCS

Issues associated with many of these components are discussed in further detail by McNulty et al. (1974) and Podlenski et al. (1984). The resistance of different materials to acid gases, flow rate, condensation requirements is particularly addressed.

Extractive CEM systems are most commonly housed in a temperature‐controlled room or a modular shelter. This adds significantly to the expense of a CEM system, but it does provide a centralized location to conduct system operations. To reduce costs, system manufacturers can also incorporate systems in temperature‐controlled National Electrical Manufacturers Association (NEMA) enclosures, a common practice in process monitoring applications. Alternatively, by close‐coupling the system to the stack, costs associated with sampling line and shelter are essentially eliminated.

To construct a working extractive system that delivers a representative sample to the gas analyzers is not something that can be done without experience, requiring an understanding of the interaction of gases, temperature, and materials. This experience is most often gained through trial and error and may require time to acquire.

MINI‐SYSTEMS

Compact miniature CEM systems advertised as mini‐systems or microsystems can be obtained at costs less than one quarter of the cost of traditional CEM systems that use discrete analyzers mounted in an instrument rack located in a temperature‐controlled shelter. Although these systems are often designed for relatively clean or specialized applications, such as gas turbine NOx monitoring, there are few technical barriers limiting system miniaturization for wider use. Increasing miniaturization in sensor design and microprocessor systems enables the compact construction of entire CEM systems that include extractive components, conditioning systems, and analytical systems (Josseau 2009; Koch et al. 2007). A single microprocessor can provide both system and analyzer control for multiple gas sensors. RS232‐RS485 outputs allow direct input into the plant distributive control system or environmental manager's computer.

MODULAR SAMPLING SYSTEMS

Miniaturization in extractive sampling system design has gone a step further through the development of modular, miniaturized sampling systems. Sponsored by the Center for Process Analysis and Control (CPAC), at the University of Washington, a consortium of equipment manufacturers and end‐users was formed for this purpose. Intended primarily for the process industries, refineries, and chemical companies, the “New Sampling Sensor Initiative” or “NeSSI” established the ISA standard, ISA 76.00.02‐002, for the design of modular sampling platforms (ANSI/ISA 2002). The goals of the program were to simplify and standardize sampling system design by using modular flow components that could be arranged like building blocks.

Derived from modular concepts developed in the semiconductor industry, functional components such as valves, gauges, regulators, sensors, and analyzers are mounted on interconnected building blocks. The standard specifies that each building block is to have a “footprint” of about one and a half square inches. The building blocks are machined with holes and passages in configurations that allow the functional components to be interconnected. Instead of stainless steel or Teflon tubing with nut and ferrule fittings, common in traditional extractive systems, the functional components (valves, gauges, regulators, and so on) are interconnected by the use of annular o‐ring slip‐fit pressure connectors or connecting tubes having specially designed o‐ring boss end fittings.

Parker‐Hannifin, Swagelok, and Circor have designed ISA 76–compliant sampling systems; however, each company uses their own approach to interconnecting the blocks (Figure 3‐28a–c).

In the Parker‐Hannifin system (Dudley and Cost 2012), the modular blocks are arranged on a pegboard, or other support, where they are interconnected by annular slip‐fit pressure connectors. The flow channels of the Parker‐Hannifin system are all in one plane, allowing for straightforward topology.

In the Circor system (Sherman 2005), the building blocks interlock, creating their own structure, which then may be mounted on a plate using a stand‐off support. The system utilizes a single building block in conjunction with various types of tube sets (“standard flow tube sets”). Flanges on the blocks allow them to be connected together as a “stick,” with the tube sets connected under the blocks to route the gases through the blocks to the functional components.

In the Swagelok design (Wawroski 2004), interconnecting tubes called “basic flow components” (similar to the Circor tube sets) are inserted in channels machined into a platform called a “substrate layer.” The building blocks are mounted on top of the substrate layer and are interconnected to the flow tubes from the bottom. A separate manifold layer, beneath the substrate layer platform, is used to connect the flows between the substrate channels. The building blocks joined with the valves, regulators, gauges, sensors, and other system components constitute the “surface‐mount” layer.

Figure 3‐28a Parker‐Hannifin NeSSI interconnection system.

Figure 3‐28b Circor NeSSI interconnection system.

Figure 3‐28c Swagelok NeSSI interconnection system.

Regardless of the platform, sensors and other system components are accessible from the top of the platform. Translating a traditional flow schematic into a NeSSI system may be challenging for someone unfamiliar with the manufacturer’s architecture. However, computer software has been designed to assist in the development of NeSSI structures from a given schematic. Figure 3‐29 illustrates a generic miniature modular CEM system.

Figure 3‐29 Example of a miniature modular CEM system.

These modular sampling systems have less dead space than the tube and fitting system and are less likely to leak than the traditional nut and ferrule fittings by using surface‐mounted o‐rings. However, if a leak occurs, it may be more difficult to find and resolve the leak.

NeSSI systems have seen the greatest application when multiple identical extractive systems are required. In other applications, NeSSI components may be substituted for part of an extractive system, such as the calibration gas distribution system for daily CEM system verifications, or calibration gas dilution systems. The size and modularity of the modular platforms make them ideal for the application of miniature and micro sensors and analyzers (Aquino 2003; Chon 2004). The University of Washington Center for Process Analysis and Control (CPAC) is the primary information resource for conference proceedings, publications, and current progress on NeSSI systems (Dubois 2009; Dubois et al. 2004; Marquardt et al. 2009).

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BIBLIOGRAPHY

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CHAPTER 4
INTRODUCTION TO THE ANALYTICAL METHODS

The heart of any CEM system, whether extractive or in‐situ, consists of the analyzers. An extractive system transports and conditions the flue gas, but the analyzers perform the job of measurement. The selection or evaluation of CEM system analyzers must consider both regulatory specifications and performance characteristics. Although most analyzers are advertised as meeting or exceeding required specifications, care must be exercised in their selection because an analyzer's performance in the field can differ greatly from its performance on a laboratory bench.

CEM system analyzers must measure gases without interference from other gases. They are increasingly being required to measure accurately in low‐concentration ranges, and they must perform well often in hostile environments. Current U.S. EPA, Canadian, and International Organization for Standardization (ISO) standards for CEM system analyzers do not specify analytical techniques that are to be used (except for opacity monitors), but rather provide performance‐based specifications. Therefore, it is left to the CEM system manufacturer or the user to determine the measurement techniques that would be the most appropriate for a given application. This chapter provides a basis for the understanding of several techniques employed in commercially available CEM system analyzers.

THE PROPERTIES OF LIGHT

The majority of instruments used in CEM systems are based on principles associated with the interaction of light with matter. Opacity monitors measure the effects of light scattering and absorption; a nondispersive infrared analyzer measures the amount of light absorbed by a pollutant molecule; and a chemiluminescence analyzer senses the light emitted in a chemical reaction. One could treat the operation of CEM system analyzers as “black boxes” that give out answers, but an understanding of their operation is necessary to properly apply an analyzer for monitoring at a source. Although some techniques will work well in a given application, other techniques will have problems in the same application. Also, for proper evaluation of system performance, a knowledge of how an analyzer works is essential to understand the effects of interferences, temperature, pressure, and so on. This understanding will be developed by first reviewing some of the basic properties of light and how these properties can be applied to measure pollutant gas concentrations.

The Wave Nature of Light

Light can be characterized as a wave composed of oscillating electric and magnetic fields. Light waves, or electromagnetic waves as they are better called, are distinguished by their wavelength or frequency. Figure 4‐1 illustrates the typical sinusoidal nature of an electromagnetic wave and its associated wavelength. The length between successive oscillations of a wave is called wavelength (λ). The period of time that it takes a wave to go through an oscillation cycle is called frequency (v). Wavelength and frequency are related by the following expression:

Figure 4‐1 An oscillating electric field and its wavelength.

(4‐1)v equals StartFraction c Over lamda EndFraction

where c is the velocity of light, 3.0 × 10⁸ m/s.

Literature describing continuous monitoring instruments often specifies the wavelength to characterize the spectral region used in the analytical method. Different units are often used for wavelength in different regions of the electromagnetic spectrum although the nanometer (nm) = 10⁻⁹ m has become the standard unit. Another unit, the Angstrom, Å = 10⁻¹⁰ m, has been used historically in the ultraviolet region. In the infrared region, both the μm = 10⁻⁶ m (also called 1 “micron”) and the wavenumber are commonly used by spectroscopists. The wavenumber is expressed as

(4‐2)v overbar equals StartFraction 1 Over lamda EndFraction left-parenthesis c m Superscript negative 1 Baseline right-parenthesis

Note that the units of v overbarare given in terms of the number of wavelengths per centimeter, called reciprocal centimeters or wavenumbers. The wavenumber v overbaris essentially a measure of frequency, differing from v by the constant factor of the velocity of light. The wavenumber is calculated by calculating the reciprocal of the wavelength expressed in μm and multiply by 10⁴ to obtain wavenumbers in units of cm⁻¹.

The wavelength of light used in CEM instrumentation ranges from 200 nm in the ultraviolet to 20 000 nm in the infrared. Figure 4‐2 shows the regions of the electromagnetic spectrum and the wavelength bands where molecules interact with light energy. Instruments are designed to measure the effects of these interactions.

The infrared spectral region is particularly important for the measurement of gaseous pollutants, and many instruments have been designed to operate in the infrared region. The infrared region is separated into the near infrared (NIR), mid infrared (MIR), and far infrared. Although an ISO standard does exist (ISO 2015), the boundaries of these regions are not universally agreed upon; there exists some ambiguity as to where the mid infrared ends and the far infrared begins, depending upon the usage by instrument manufacturers, spectroscopists, astronomers, or others.

Absorption of Light by Molecules

Light carries energy. Light has the properties of waves, but in some of its interactions with matter it behaves as if it were composed of discrete packets of energy called photons. In a beam of light having frequency v, each of these photons carries energy defined by the Planck‐Einstein relation of Equation 4‐3.

(4‐3)upper E equals h v equals h StartFraction c Over lamda EndFraction

where h is Planck's constant and has a numerical value of 6.62 × 10⁻²⁷ erg‐s. Clearly, the energy of a photon is dependent upon the frequency or wavelength of the light. Light (photons) of short wavelengths (such as in the ultraviolet) will carry more energy than light (photons) of longer wavelengths (such as in the infrared). Photons of different energies will have different effects. From a practical sense, sitting on the beach too long in bright sunlight can cause a severe sunburn. On the other hand, sitting under an infrared heat lamp will soothe sore muscles without causing sunburn. The effects of UV radiation are extremely severe under the Antarctic ozone hole, but less severe where the stratospheric ozone layer reduces the number of photons per unit time reaching Earth's surface. Light of different wavelengths (photons of different energies) will have a variety of effects on molecules. In a monitoring instrument, the manufacturer determines the best way to use these effects to make gas concentration measurements.

Molecules are made up of atoms and molecular electrons that are arranged in very specific patterns, which undergo unique and complex motions. If light of a given wavelength should resonate with one of these motions, it will have a high probability of being absorbed by a molecule. The light essentially alters the molecular energy, causing the molecule to act differently than it was acting before the light was absorbed.

Figure 4‐2 The electromagnetic spectrum for continuous emission monitoring analyzers.

If the absorbed light is of low energy (long wavelength, low frequency: [E = hv]), the molecule will rotate differently than it did before. This occurs typically for light wavelengths in the far‐infrared region of the spectrum, at wavelengths greater than 20 μm. Light in the range of 5–20 μm can cause changes in the vibrational characteristics of a molecule. In the range of 0.8–5 μm, the more complex overtones and combinations of fundamental vibrations give rise to light absorption. Figure 4‐2 illustrates the regions over the range of 0.8–20 μm (12 500–500 cm⁻¹) in the infrared spectrum where typical pollutant and combustion gases absorb light due to vibrational–rotational transitions. Figure 4‐3 illustrates some of the specific motions that occur when photons of the right energy (light of the right wavelength) are absorbed by an SO₂ molecule.

In the ultraviolet and visible regions of the spectrum, 180–700 nm, impinging light can cause the molecular electrons to change their energy states. Here, higher‐energy photons cause the electrons to become excited, and in the far ultraviolet may even cause the molecules to dissociate. SO₂ shows a particularly strong absorption centered at 280 nm, which is taken advantage of in several SO₂ analyzers, as we shall see in the next chapter.

Each of these absorption processes requires a precise quantity of radiant energy. The probability of light being absorbed and the transition occurring is greatest when the value of hv equals that energy. If light passing through a gas contained in a cell is changed over a range of wavelengths, a detector located on the other side of the gas cell would sense a dip in the light intensity it receives at the wavelengths where these transitions occur. This is shown in Figure 4‐4. This absorption can also be plotted directly as an absorption spectrum as shown in Figure 4‐5. The absorption spectrum offers some advantages for quantitative analysis.

Figure 4‐3 Example of normal vibrations of the SO₂ molecule.

Figure 4‐4 A typical transmission spectrum.

Each electronic state of a molecule will contain many vibrational energy levels and each vibrational energy level will contain many rotational energy levels. This is illustrated in Figure 4‐6, which shows the possible energy states in which a molecule can exist. The molecule's energy state can be modified by supplying a photon of proper energy that can cause a transition from one state to another. Because there are a large number of states, there will also be a large number of wavelengths at which light will be absorbed.

Figure 4‐5 A typical absorption spectrum.

The total energy of a molecule in a specific energy state can be summarized by the approximation

(4‐4)upper E Subscript t o t a l Baseline equals upper E Subscript e l e c t r o n i c Baseline plus upper E Subscript v i b r a t i o n a l Baseline plus upper E Subscript r o t a t i o n a l

The fact that transitions can occur between many of these states implies that energy will be absorbed at many different wavelengths. This gives rise to an absorption spectrum that typifies a molecule. As an example, Figure 4‐7 illustrates the vibrational–rotational absorption spectrum of SO₂ in the near‐infrared region. Such spectra are very important in the development of analytical techniques for gas monitoring.

Also, Figure 4‐2 shows that different molecules can absorb light in the same region of the spectrum. This can cause problems in developing an analyzer because it can be difficult to distinguish the relative amounts of absorption from each compound in the overlap region. Water vapor can be particularly troublesome because it absorbs in many regions of the infrared spectrum and is usually present at percent levels in the gas stream, whereas pollutant gases are present at ppm levels. Interfering gases can be removed before entering an analyzer, but this can be difficult and makes the monitoring system more complicated. An alternative to removing interfering gases is to select a region of the spectrum where there is no overlap. The wavelength‐specific light emitted by lasers has enabled a wide variety of instruments to be developed using this technique. High‐resolution instruments, once found only in the laboratory, provide another alternative. Advances in computerization along with advances in the science and technology of gas measurement have since made relatively sophisticated measurement techniques available to field instruments at reasonable cost. Different approaches to such problems are discussed further in the following chapters.

Figure 4‐6 Energy‐level diagram for a molecule.

To this point we have discussed the fact that molecules can absorb light energy. However, the question arises as to how this phenomenon can be expressed quantitatively. The answer lies in a mathematical expression known as the Beer–Lambert law.

The Beer–Lambert Law

When studying the absorption of light by gases, the Beer–Lambert law can be used to relate the amount of light absorbed to the concentration of the pollutant gas. First, consider the system shown in Figure 4‐8, which is composed of a light source, flue gas, and a sensor that measures light intensity.

The intensity of light passing through a stack (or sample cell) will decrease if gas molecules in the cell become “excited,” that is, if the light embodies wavelengths causing energy transitions in the molecule. Light transmittance, Tr, is the fraction of incident light passing through the cell. This can be expressed as the ratio of the light intensity transmitted through the cell, I, to the initial incident light intensity, Io, (or the intensity with no absorbing material in the stack or cell), or:

Figure 4‐7 Infrared vibrational–rotational transmittance spectrum for SO₂.

Figure 4‐8 Example system for measuring pollutant gas concentrations.

(4‐5)upper T r equals StartFraction upper I Over upper I Subscript o Baseline EndFraction

The Beer–Lambert law states that the transmittance of light through the medium decreases exponentially by the product α(λ) cL, or

(4‐6)upper T r equals StartFraction upper I Over upper I Subscript o Baseline EndFraction equals e Superscript minus alpha left-parenthesis lamda right-parenthesis c l

where

Tr = the transmittance of the light through the flue gas

Io = the intensity of the light entering the gas/s

I = the intensity of the light leaving the flue gas/s

α(λ) = molecular absorption coefficient (dependent on wavelength)

c = concentration of the pollutant

l = distance the light beam travels through the flue gas

The Beer–Lambert law relates light absorbance in a medium, A = α(λ)cl, to the distance the light travels in the medium and the concentration of the light‐absorbing (and or light scattering) species.

[Note: In the conventions of International Union of Pure and Applied Chemistry (IUPAC), the fraction of light not transmitted is termed absorbance, A, and is expressed as A = ɛ(λ)cl, where ɛ(λ) is the “molar absorption” coefficient in L/mol/cm, c is the concentration in mol/L, and l is the pathlength in cm, an expression commonly used for light absorption in liquid solutions. When applied to light absorption by gases, the absorption coefficient is often expressed as A = σ(λ)Nl, where σ(λ) is the “absorption cross section” in cm² and N is the number density of the gas being measured (no./cm³). In the field of continuous emission monitoring, the absorbance has traditionally been expressed as α(λ)cl, where α(λ) is termed the absorption coefficient [used instead of the IUPAC symbol ɛ(λ)], c is the concentration of the gas being measured, and l is the pathlength. [This convention has been used in this book.]

The absorption coefficient α(λ) is dependent upon the light wavelength and the properties of the pollutant molecules. The coefficient is a quantitative expression of the degree to which a molecule will absorb light energy at a given wavelength. If no absorption occurs, α(λ) will be zero, and the transmittance would equal 100%. If an electronic or vibrational–rotational transition occurs at some wavelength, the absorption coefficient will have some value, and the reduction of light energy across the path will also depend upon the pollutant concentration, c, and the pathlength, l.

Based on this principle, an instrument can be designed to measure pollutant gas concentrations. All that is needed is light having a wavelength that will cause some transition in the molecule of interest, a light path through the gas (either through a sample cell or through the stack or duct), and a light detector. Io is determined by taking a reading from the detector when no pollutant is in the light path of the duct or sample cell. The concentration can be obtained from the Beer–Lambert expression if α(λ) and l are known, but typically a calibration curve is generated with known gas concentrations, rather than using theoretical values for α(λ). Figure 4‐9 shows a calibration plot typical of an instrument designed to measure light absorption by pollutant molecules.

Here, ln(1/Tr) is plotted against concentration instead of plotting transmittance against concentration. This logarithmic plot gives a straight line, from which it is much easier to develop the calibration plot. In the example of Figure 4‐9, a calibration line is generated using three calibration standards of known concentration. Calibration gases are then injected one at a time into a sample cell to obtain values at the detector of I₁, I₂, and I₃. The ratios of I/Io are calculated, the logarithm is taken, and values of ln(1/Tr) are plotted against the concentration to obtain the line. Injecting an unknown gas into the sample cell gives a value, Iu, at the detector. The unknown concentration can then be determined by drawing a line from the calculated value of ln(1/Tru) on the y axis to intersect the calibration line. At the point of intersection, a line is drawn down to the x axis to obtain the concentration of the unknown gas.

Note that it is not necessary to know the value of the absorption coefficient to obtain the unknown concentration value. The use of gas calibration standards avoids that necessity in this type of instrumentation.

Note also that the instrument response can be given as the logarithm to the base ten instead of in Naperian logarithms. The conversion between the two is simply log₁₀(1/Tr) = (1/2.303)ln(1/Tr). Spectroscopists commonly use the base 10 logarithm, A, where absorbance is expressed as A = log₁₀(1/Tr).

LIGHT SCATTERING BY PARTICLES

There is another way that light energy is removed from a beam of light, other than by absorption from individual molecules. If particulate matter, aerosols, or droplets are present in the flue gas, light incident on these materials can be scattered in various directions. As a result, not all of the light will continue in its initial direction and its transmittance through the gas will be reduced. The mechanisms of light scattering are dependent upon the particle refractive index, the particle size (as defined by its radius, r) and the wavelength (λ) of light that impinges on it – different phenomena come into play, depending on how r compares to λ. Three basic types of scattering processes occur (see Figure 4‐10).

Rayleigh scattering. If the particle is smaller than the light wavelength, then the particle–light interaction can be characterized as “Rayleigh” scattering (Figure 4‐10a: r/λ ≤ 1), where the light is scattered isotropically equally in all directions.

Mie scattering. If the particle size and light wavelength are comparable, r/λ ≈ 1, Mie scattering occurs. In this scattering, electrons in the particle see varying electric fields from the impinging electromagnetic field. Electrons accelerated in an electromagnetic field will emit light, which combines constructively or destructively as it comes from different locations within the particle. The scattering pattern is somewhat complex as shown in Figure 4‐10b where r/λ ≈ 1.

Macroscopic scattering. When particles are very much larger than the light wavelength, r/λ ≥ 1, the concepts of geometric optics (such as reflection and refraction) can be used to explain how light scatters (Figure 4‐10c).

Figure 4‐9 Calibration plot for the Beer–Lambert relation.

Figure 4‐10 Three regimes of light scattering. (a) Rayleigh scattering r/λ ≤ 1. (b) Mie scattering r/λ ≈ 1. (c) Geometric optics r/λ ≥ 1.

In a typical flue gas, particle sizes may range from 0.1 to 10 μm or greater. When visible light ranging from 400 to 700 nm (0.4–0.7 μm) is directed through a gas, all of the aforementioned scattering processes can take place, with respect to the particle size distribution. These three scattering processes are described in the following sections.

Rayleigh Scattering: r/λ ≤ 1

Particles smaller than about 0.1 μm will scatter visible light by Rayleigh scattering. In this case, the electric field of light interacts with electrons within the particle molecules.

The electrons are correspondingly accelerated in their motion in the molecule. It is a phenomenon of nature that an accelerated electron will emit electromagnetic radiation in all directions. The net effect is that the oscillating electron scatters light out of the light beam. Due to this phenomenon, small particles (<0.1 μm) are very effective in scattering visible light.

Mie Scattering: r/λ = 1

As the particle size increases relative to the wavelength, the molecular electrons throughout the particle no longer see a uniform field. The intensity and field direction vary at different points within the particle and the electrons will accelerate in different directions, generating a complex scattering pattern. In fact, the scattered light waves can add together constructively or can subtract destructively as they come from the separate locations within the particle. This can lead to light scattering to the back, to the side, and to the front of the particle as shown in Figure 4‐11.

The size range of pollutant particles emitted to the atmosphere often corresponds to the wavelengths of visible light (400–700 nm). Bag houses and electrostatic precipitators used to control the emission of particulate matter will effectively collect particles that are greater than 1 μm (1000 nm) in diameter. It is more difficult, however, to collect particles in the submicron range (<1 μm). These are the particles that will have a higher probability of escaping into the atmosphere. Visible light scattering from these particles is, therefore, typically due to Mie scattering.

Figure 4‐11 Mie scattering. Destructive and constructive interference of light waves scattered from molecular electrons when the particle radius and light wavelength are comparable.

Geometric Optics: r/λ ≥ 1

Particles in the size range of 20 or more times the wavelength can be described by using concepts of geometrical optics. The incident beam of light can be thought of as being composed of separate rays that interact with the particle. This interaction can be in the form of reflection, refraction, or diffraction processes (Figure 4‐12).

Reflection is a surface effect in which, without entering the particle, the light ray changes the direction after striking it. Reflection will occur if the depth of particle surface irregularities is small relative to the wavelength of light. Light refraction occurs after light enters the particle. Its speed and direction change because of the change in the optical characteristics (refractive index) of the material. Once light has entered the particle, it can also reflect internally. Diffraction is the bending of light around an object caused by interference effects at the particle surface.

Figure 4‐12 Light scattering from large particles (r/λ ≥1) where geometrical optics apply.

Scattering phenomena have been emphasized here, but it should be noted that particles can also absorb light energy, as do gaseous molecules. When light of a specific wavelength resonates with the molecular electrons contained in the particle, it will cause the electrons to jump from one energy state to another. As stated earlier, only light wavelengths that correspond exactly to the molecular energy levels will be absorbed to impart energy to the molecule. As a result, light is again lost from the incident beam.

Opacity and Transmittance

Transmission of light through a flue gas that contains particulate matter will be reduced through a combination of scattering and absorption processes. Scattering and absorption of light by a stack plume gives rise to its opacity, its opaqueness to light transmission.

If light is not able to penetrate through a plume, the plume is said to be opaque – the opacity of the plume is 100%. Transmittance and opacity can be related as follows:

(4‐7)upper T r a n s m i t t a n c e left-parenthesis percent-sign right-parenthesis equals 100 minus upper O p a c i t y left-parenthesis percent-sign right-parenthesis

Therefore, if a plume or object is 100% opaque, the light transmittance through it is zero. If it is not opaque, but has zero percent opacity, the light transmittance would correspondingly be 100%. A stack gas or plume will rarely have either zero or 100% opacity, but will have some intermediate value. Opacity standards are typically set at 20%, but can range from 0 to 40% opacity, depending upon the policies of the regulatory agency.

Bouguer's Law

Particle scattering and absorption effects can be treated in a manner similar to that in the previous discussion on light absorption by gas molecules. Similar to the Beer–Lambert law, Bouguer's law is used when discussing particle scattering. Bouguer's law states that transmittance decreases exponentially by the product naQL, as shown in Equation 4‐8.

(4‐8)upper T r equals e Superscript minus n a upper Q upper L

where n = number concentration of the particles

a = projected area of the particles

Q = particle extinction coefficient

L = length of the light path through the flue gas

The expression was first stated by P. Bouguer in 1760 and later rediscovered by Lambert. In deference to the earlier work of Bouguer, it has become customary in the field of opacity monitoring to call it Bouguer's law (Middleton 1968).

Q is the particle extinction coefficient, which is dependent on the wavelength and expresses how the particle of size a scatters and absorbs light of wavelength λ. It is analogous to the absorption cross section σ(λ), discussed previously. Theoretically, it should be possible to calculate the opacity from first principles using Equation 4‐8. Because there are usually particles with more than one size in a flue gas, the particle size distribution and the Mie scattering coefficients need to be determined for each size particle. The data demands and calculation difficulties make this approach impractical although attempts have been made in the past (Ensor and Pilat 1971; Pilat and Ensor 1970; Thielke and Pilat 1978). Equation 4‐8 is overly simplified, being expressed for particles of only one size (see Jahnke (1984) for more detailed expressions).

Bouguer's law is an exponential relationship between transmittance and particulate matter concentration and is somewhat difficult to use in stack emission calculations. Another expression, called “optical density,” is used in opacity monitor specifications and calculations. It is related to opacity as follows:

(4‐9)

Optical density is useful in emission calculations because it is directly proportional to the particulate concentration, as shown in the following derivation.

First, taking the natural logarithm of both sides of Equation 4‐8 gives

(4‐10)ln upper T r equals ln left-bracket e Superscript minus n a upper Q upper L Baseline right-bracket equals minus n a upper Q upper L

and rearranging gives

and therefore

(4‐11)upper D equals StartFraction a upper Q l Over 2.303 EndFraction n

The expression can be written in terms of particulate concentration c, instead of the particle number density n:

(4‐12)upper D equals StartFraction upper A Subscript upper E Baseline l Over 2.303 EndFraction c

where

AE = πr²Q/m, the specific mass extinction coefficient

r = particle radius

m = particle mass

c = particle concentration

This expression merely states that optical density is directly proportional to the particulate matter concentration and also to the pathlength. It is a very useful relation, because if, for example, the pathlength should increase by a factor of 2, the optical density will increase by the same factor. If the particulate matter concentration is decreased by 1/2, D also decreases by 1/2. Applications of this expression are examined in Chapter 8 on opacity monitors.

COMPONENTS OF A SPECTROMETER: BUILDING AN INSTRUMENT

The types of analytical techniques used in today's commercially available CEM monitoring analyzers are listed in Table 1‐1 of Chapter 1. Of these techniques, absorption spectroscopy has been the most commonly applied technique in continuous monitoring systems. Spectrometers developed for pollutant and diluent gas monitoring typically incorporate four essential components:

Radiation sources

Wavelength selectors

Detectors

Optical components

These components differ depending upon the region of the spectrum in which the instrument operates and the analytical technique itself. The following sections give examples of these components.

Radiation Sources

Light sources used in CEM system analyzers emit in the ultraviolet, visible, and infrared regions of the spectrum. Advances in semiconductor electronics have led to the application of light emitting diodes (LEDs) and lasers in CEM analyzers. LEDs have largely supplanted the incandescent lamps once used in opacity monitors, and diode and quantum cascade lasers, alternatives to earlier broadband infrared light sources, have led to a new generation of extractive and in‐situ CEM system gas analyzers.

UV Light Sources.

For the ultraviolet region of the spectrum, hollow cathode gas discharge tubes, high‐pressure hydrogen or deuterium discharge lamps, xenon arc, and mercury discharge lamps have been used. UV lamps have shorter lifetimes than those operating in the infrared, and it is sometimes difficult to maintain stable UV intensities over the extended periods of time that they operate.

Visible Light Sources.

Visible light is used in opacity monitors, where the peak and mean spectral response is required to be between 500 and 600 nm, with less than 10% of the peak response below 400 nm and above 700 nm. This “photopic” region is established so as to be within the visual range of human observing stack exit opacity. Tungsten lamps, green light emitting diodes, and lasers have been used for this application, however green light emitting diodes are the most commonly used today.

Broadband Infrared Light Sources.

Heated materials will emit radiation in the infrared region of the spectrum. Among those used are Nernst Globars (fused hollow rods of zirconium and yttrium oxides, heated to about 1500 °C), Globars (heated rods of silicon carbide), carbon rods, and heated nichrome wire. These sources emit light over a range of wavelengths, from which the analyzer selects to make gas concentration measurements.

Light Emitting Diodes.

Light emitting diodes are semiconductors that emit light when an electric current is applied. Light is emitted from the recombination of the electron–hole pairs of semiconductor materials. The light wavelength emitted is dependent upon the energy bandgap between the valence and conduction bands of the semiconductor and can range from the infrared to the ultraviolet region as the energy of the bandgap increases. LEDs are not lasers. They do emit over a spectrum narrower than incandescent sources, but the light emitted is incoherent.

Tunable Diode Lasers.

Tunable diode lasers (TDLs) are now being used as infrared sources by a number of instrument manufacturers in North America and Europe for both extractive and in‐situ system analyzers in a wide variety of applications (Mettler‐Toledo 2017). Although first introduced for source monitoring applications in the 1970s (Hinkley 1972; Hinkley and Kelley 1971), diode lasers were not incorporated into CEM systems commercially until advances in communications lasers reduced costs for lasers emitting at wavelengths suitable for gas identification (Frisch 1996; Imasaka and Ishibashi 1990; Lerner 1998).

In a diode laser, an electron from the conduction band combines with a hole in the valence band to emit a photon. In the recombination of electron–hole pairs, some of the excess energy is converted into photons. The photon will stimulate further recombination and will reflect back and forth in the resonant cavity of the laser to emit a coherent beam of light. The laser wavelength is dependent upon the recombination energy, which is a function of semiconductor materials (such as InGaAsP/InP) and the laser design. Operating in the near‐infrared region of the spectrum from 0.5 to 2.5 μm, the wavelengths emitted can be tuned over a narrow range by varying the laser temperature or the injection current.

Quantum Cascade Lasers.

Quantum cascade lasers (QCLs), developed in 1994 (Faist et al. 1994), are another option for gas monitoring systems. Operating at room temperature, they emit light in the mid‐infrared region of the spectrum, from 2.5 to over 20 μm, a region where many pollutant molecules strongly absorb. In contrast to diode lasers, where the light emitted depends upon the bandgap of the semiconductor material constituting the laser, quantum cascade lasers incorporate dozens of alternating semiconductor layers. The electric potential varies over the length of the device, where the semiconductor layers form potential “wells.” In QCLs, the output light wavelength is dependent upon the layer structure constructed by design, whereas in tunable diode lasers, it is a function of the material.

The QCL relies on transitions between excited states in the conduction band (intersubband transitions) for photon generation. In operation, electrons tunnel through the “quantum wells,” generating photons as they cascade through different energy levels. One electron emits a photon in each intersubband transition within the quantum well and then tunnels into the next quantum well to emit another photon, cascading down the quantum wells of the structure to emit multiple photons.

The flexibility in manufacturing, their ability to emit light in the mid infrared, their high optical power output, and their ability to operate at room temperature have made QCLs increasingly attractive for gas monitoring applications (Kosterev et al. 2008).

Interband Cascade Lasers.

Interband cascade lasers (ICLs) operate in the wavelength range of 3–6 μm and fill the gap in wavelengths emitted between tunable diode lasers and quantum cascade lasers. ICLs are similar to quantum cascade lasers; however, in ICLs, light is emitted from electron–hole recombination in interband transitions rather than in intersubband transitions. In a sense, ICLs are a hybrid between tunable diode lasers and quantum cascade lasers, in that light is emitted by electron–hole recombination from electron injection. Due to the nature of these transitions, light emission can occur at lower electrical input power than in quantum cascade lasers.

Wavelength Selection

Lasers, of course, are used in gas analyzers to monitor at specific wavelengths. Before the advent of lasers, it was necessary to restrict or separate the wavelengths at which molecules absorb from the spectra emitted from broadband radiation sources. Optical filters and diffraction gratings were and still are used to do this in spectroscopic CEM system analyzers. To manufacture an analyzer, it is often easier and less expensive to utilize broadband emission sources, coupled with spectral limiters such as gratings and filters.

Optical Filters.

An optical filter allows light only in a narrow spectral region to pass through it. Interference filters, constructed by vacuum deposition of metallic films on glass or other materials, are commonly used in the infrared region of the spectrum. Neutral‐density filters are used to attenuate light of all wavelengths equally, being made of quartz or glass with a thin metal coating having a specified optical density.

Diffraction Gratings.

Diffraction gratings are commonly used in the ultraviolet and visible regions of the spectrum to select specific wavelengths. A grating consists of a reflective surface finely etched with a large number of parallel lines (on the order of 600 lines/mm). Each line will scatter light impinging on it, causing the light to interfere constructively and destructively to spread out a reflected spectrum.

Prisms.

Prisms disperse ultraviolet, visible, and infrared radiation due to differences in the wavelength‐dependent index of refraction in the prism material. Prism spectrometers are available in the UV and visible spectral regions; although they have been used in atomic absorption spectrometers for measuring metals, they are not typically used in pollutant gas monitoring applications.

Detectors

The type of detector used in an analyzer is very dependent on the energy of the light that it is sensing. Because light in the infrared region is relatively weak in the energy it carries, special stratagems are often devised to detect infrared intensity changes. Pneumatic, microphone‐type detectors (Luft detectors) traditionally have been used in infrared analyzers; however, solid‐state detectors, cooled with Peltier coolers, are common today. Sensitivity is often increased by not overly limiting the spectral region of the analyzer, but using a broader band of radiation to obtain more light for the detector. The special methods of gas filter correlation and Fourier‐transform infrared spectroscopy take advantage of this technique.

The most familiar detector in the visible region is the human eye, which is, of course, used as the detector in EPA Reference Method 9 for measuring visible emissions. Phototubes, photomultiplier tubes, photovoltaic cells, and photo‐diode arrays are used in instrumented systems. Photo‐diode arrays are being incorporated increasingly into CEM analyzers (Durham et al. 1990; Saltzman 1990). Diode arrays provide a simple way of measuring multiple wavelengths and are useful for monitoring several gases in one analyzer, rather than using a separate analyzer for each gas.

Multipath Gas Cells

Infrared and ultraviolet spectrometers, gas filter correlation spectrometer, Fourier‐ transform infrared spectrometers, and systems using tunable lasers make use of the Beer–Lambert law, either in a simple logarithmic relationship, or more complicated expressions. One characteristic in these instruments in which light energy is absorbed by targeted molecules is that when more molecules absorb the light energy, the greater will be the difference between the incident light intensity Io and the signal intensity, I. For low concentrations or small absorption coefficients, an instrument may not be sensitive enough to provide accurate measurements. In particular, weaker absorption bands in the near infrared make it difficult to apply tunable diode lasers for gas monitoring unless the pathlength is increased.

By increasing the measurement pathlength, more opportunities are provided for light energy to be absorbed before reaching the detector. There are several ways of doing this; the simplest is to just increase the length of the measurement cell. This was attempted in some early CEM instruments, but led to bulky, problem‐prone installations, most of which have since been replaced. Other approaches include using multipath cells (such as White and Herriott cells), using high sensitivity, ultralong pathlength, absorption techniques such as cavity ring‐down spectroscopy (CRDS) and integrated cavity output spectroscopy (ICOS), or by measuring across the stack in a double‐pass in‐situ system instead of using a sample cell in an extractive system analyzer.

White Cells.

A White cell is a type of sample cell developed by John White (White 1942) that increases the pathlength of the light beam by reflecting it from three spherical, slightly misaligned concave mirrors (Figure 4‐13). The cell shown in the figure shows the beam making eight traverses across the cell to increase the pathlength eightfold from that of a cell containing only windows. The number of passes can be adjusted by adjusting the mirror positions. White cells can be designed with pathlengths from less than a meter to hundreds of meters (Vidrine 2000; Doussin et al. 1999).

Herriott Cells.

The Herriott cell, named after Donald Herriott (Herriott and Schulte 1965), consists of two opposing concave spherical mirrors, with one mirror having a hole where the light beam enters and exits (Figure 4‐14). The cell can also be designed with an exit hole in the opposite mirror. In the Herriott cell, the number of reflections is changed by changing the separation distance between the two mirrors. More than one light source can be used in the Herriott cell by drilling more holes in the mirrors.

Figure 4‐13 A White multipath gas cell.

Figure 4‐14 A Herriott multipath gas cell.

Figure 4‐15 Integrated cavity output spectrometer (ICOS).

CRDS and ICOS.

The cavity ring‐down spectroscopic (CRDS) technique developed by O’Keefe in 1988 utilizes a sample cell with high reflectivity mirrors to achieve pathlengths on the order of kilometers in conjunction with a laser light source (O’Keefe and Deacon 1988). The off‐axis integrated cavity output spectroscopic (ICOS) method is a similar method; both methods are a breakthrough in trace gas analysis (Figure 4‐15).

Instruments using these methods are able to measure gases at part per trillion levels. The CRDS and ICOS techniques are discussed in Chapter 5.

Optical Components

In most electro‐optical analyzers, other components are used to direct and focus light. The following components can be found in gas monitoring instrumentation:

Neutral density filters

Lenses

Mirrors (concave and triple)

Beam splitters (half‐silvered mirrors)

Optical light fibers

Rotating shutters/window slits/irises

Lenses, slits, and diaphragms are used to focus light on through the system. Plain glass windows are used to separate the primary optical system from flue gases. Optical light fibers can be used to transmit light from the stack to a spectrometer or can route light in a spectrometer to simplify otherwise complex lens or mirror arrangements. Rotating shutters are used to reflect or block light to create oscillating signals.

Figure 4‐16 Constructing a spectrophotometer.

A half‐silvered mirror is a partially silvered mirror which both reflects and transmits light – essentially enabling two functions out of one component in an optical design. Half‐silvered mirrors may be more familiar in their application in mirrored sunglasses, or the “transparent mirror” seen in movies or amusement centers. Half‐silvered mirrors can be found in most double‐pass opacity monitors and in‐situ gas analyzers.

Constructing a Spectrophotometer

The components discussed above are used in various combinations in the construction of pollutant gas monitors. Putting them together, one can construct a spectrophotometer for gas measurements (Figure 4‐16), or a particulate monitor for light scattering or light transmission measurements. Different combinations of these components will be examined in the following chapters that discuss the many unique systems commercially available today.

REFERENCES

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Ensor, D.S. and Pilat, M.J. (1971). Calculation of smoke plume opacity from particulate air pollutant properties. Journal of the Air Pollution Control Association 21: 496–501.

Faist, J., Capasso, F., Sivco, D.L. et al. (1994). Quantum cascade laser. Science 264: 553–556.

Frisch, M.B. (1996). The spectra scan family of trace gas monitors based on tunable diode laser spectroscopy. Paper presented at the Air & Waste Management Association meeting, Nashville. June, paper 96‐TP26B.05.

Herriott, D. and Schulte, H. (1965). Folded optical delay lines. Applied Optics 4 (8): 883–891.

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Hinkley, E.D. and Kelley, P.L. (1971). Detection of air pollutants with tunable diode lasers. Science 171: 635–639.

Imasaka, T. and Ishibashi, N. (1990). Diode lasers and practical trace analysis. Analytical Chemistry 62 (6): 363A–371A.

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Saltzman, R.S. (1990). A process UV/VIS diode array analyzer for source monitoring. In: Proceedings – Continuous Emission Monitoring – Present and Future Applications (ed. J.A. Jahnke), 227–238. Pittsburgh: Air & Waste Management Association.

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BIBLIOGRAPHY

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CHAPTER 5
EXTRACTIVE SYSTEM ANALYZERS

The choice of gas analyzers for an extractive CEM system is important because some analytical techniques are more appropriate than others in a source application or system design. The total system must be considered; any system evaluation must be made on both the analyzers used and the extractive conditioning system itself. Chapter 3 reviewed methods for extracting, transporting, and conditioning flue gases for analysis. This chapter discusses the types of instrumentation used to determine gas concentrations after the flue gas has been properly conditioned for analysis.

Many problems occur when monitoring emissions from stationary sourceas; one of the major problems is that the pollutant gas must be analyzed among other stack gas constituents. The possibility of other gases interfering in the measurement process is great, and many approaches have been developed to avoid such interferences. As a result, a variety of spectroscopic and electroanalytical measurement techniques and new technologies that enable the measurement of gas concentrations at part per billion levels have been developed and applied.

Table 1‐2 summarizes the current commercially marketed techniques used in source monitoring analyzers. Table 5‐1 gives the major categories of methods used in extractive system analyzers. Extractive analyzers use techniques from all of these categories, whereas in‐situ monitors use only spectroscopic absorption or electrochemical methods. Extractive analyzers have been designed to monitor source‐level gas concentrations or ambient pollutant concentrations when used in conjunction with a dilution‐extractive system. It is important to understand the basic operating principles of these analyzers to evaluate properly the appropriateness of a technique in a system, effects of interferences, and levels of instrument maintenance required.

This chapter discusses absorption spectroscopic, luminescence, and electroanalytical methods used to determine the gas concentration of the criteria pollutants, SO₂, NO x , and CO and other gases, in addition to the diluent gases, CO₂ and O₂. Additional methods used for measuring hazardous air pollutants (HAPs) are discussed in Chapters 12 and 13.

SPECTROSCOPIC METHODS – INFRARED MONITORING INSTRUMENTS

Infrared analyzers monitor heteroatomic molecules such as SO₂, NO, CO, HCl, CO₂, as well as hydrocarbons and other gases. Nondispersive techniques that use optical filters or gas filters have been used in source monitoring applications for over 50 years and are well established. Fourier‐transform infrared (FTIR) spectroscopy was used primarily in research and analytical laboratories in the path, but is now applied routinely in both source and ambient monitoring programs for the range of gases that absorb light in the infrared region. More recently, with the advent of tunable diode and quantum cascade lasers, new measurement techniques have enabled gas concentration measurements down to part per billion levels.

TABLE 5‐1 Analytical Methods Used in Extractive System Gas Analyzers

Absorption Spectroscopic Methods | Luminescence Methods | Electroanalytical Methods | HAPS Methods
Infrared | Fluorescence | Polarography | Gas chromatography
Ultraviolet | Chemiluminescence | Electrocatalysis | Mass spectrometry
|  | Paramagnetism | Atomic emission spectroscopy
|  | Calorimetry | Ion mobility spectroscopy

Nondispersive Infrared Analyzers

Instruments designed for measuring molecular light absorption can be classified as spectrometers or spectrophotometers. Spectrometers are designed to vary the wavelength over a range of wavelengths to obtain the type of detailed wavelength‐dependent absorption information such as that shown in Figure 4‐7. Spectrophotometers, on the other hand, do not disperse light to scan the spectrum, but use filters or some other mechanism to measure light absorption over a relatively small range of wavelengths or “bands,” centered at an absorption peak of the molecule. Spectrophotometers used in the infrared region are commonly called nondispersive infrared (NDIR) analyzers. Having evolved since their earliest use in the 1930s, both the assets and limitations of NDIR analyzers are well understood. Because there exists a wealth of experience with their application, they are frequently used in extractive monitoring systems.

In Chapter 4, Figure 4‐2 illustrates the location of principal infrared absorption bands for a number of commonly monitored gases. Note from the figure that a number of gases have absorption bands that occur in the same region of the spectrum. In particular, water and CO₂ have broad bands that can interfere in the measurement of several important pollutant species. For a specific gas, the analyzer must measure in a region where such interference does not occur, remove the interfering species from the sample gas stream, or correct for the interference. Various stratagems have been designed to address interference issues, as will be seen in this chapter.

Spectrophotometers

In a simple NDIR analyzer (Figure 5‐1), infrared light is emitted from a radiation source such as a Globar (a silicon carbide rod heated to over 1000 °C), other types of infrared thermal radiators, infrared LEDs, or infrared lasers. In the example of Figure 5‐1, infrared light is transmitted through two gas cells: a reference cell and a sample cell.

The reference cell contains a gas, such as nitrogen or argon, that does not absorb light at the wavelength used in the instrument. As the transmitted beam passes through the sample cell, pollutant molecules will absorb some of the infrared light. As a result, when the light emerges from the end of the sample cell, it will have less energy than it did when entered. It also will have less energy than the light emerging from the reference cell. The energy difference is sensed by some type of detector, such as a solid‐state sensor [e.g. mercury cadmium telluride (MCT), lead sulfide (PbS), arsenic selenide (As₂Se₃)], or a pneumatic Luft‐type sensor (Luft 1943). The sensitivity of solid‐state sensors may be increased by cooling with a thermoelectric chiller. Thermistor‐ and thermocouple‐type detectors are usually not sensitive enough to measure the small energy differences that result in this type of gas monitoring instrument.

As seen in the previous chapter, the ratio of the detector signals from the two cells gives the light transmittance Tr = I/I o , which can be related to the pollutant gas concentration (see Equation 4‐5 and Figure 4‐9).

In the reference cell where c ref = 0 a value for I o can be easily obtained, since

(5‐1)

(5‐2)

The value of I o remains constant, so I sample can be related to it to obtain the transmittance (Tr = I/I o ) and a concentration measurement.

A common problem associated with analyzers that use a detecting arrangement as shown in Figure 5‐1 is that gases that absorb light in the same spectral region as the pollutant molecule will cause a positive interference in the measurement. For example, water vapor and CO₂ will interfere in the measurement of CO (see Figure 4‐2). When this happens, these gases must be removed by some scrubbing system before the sample gas enters the analyzer. Alternatively, sample gas scrubbed of the pollutant can be passed through the reference cell. In such a flowing reference cell, the level of interference will be the same as in the sample cell, but it will also be referenced to a zero level of the pollutant being measured.

Another solution to this problem is to use a pneumatic detector with absorption chambers arranged in series, as shown in Figure 5‐2. In this detector, two chambers are filled with gas of the species being measured. The front chamber is shorter than the rear chamber and both are connected to a sensor that can detect differences in gas pressure between the two cells or the flow of gas between the two cells.

Figure 5‐1 A simple nondispersive infrared analyzer.

To understand the operation of this detector, first consider that the infrared radiation is absorbed over a range of wavelengths corresponding to an absorption band such as that shown in the figure. Because the wavelength‐dependent absorption coefficients are greater at the band center, the energy absorbed in the front chamber will be greater at the band center than at the wings. As a result, less energy at these center wavelengths will be transmitted to the rear chamber. Absorption in the second chamber will be primarily at wavelengths at the wings of the band. The absorption is weaker at the wings (α wings < α center), so the rear chamber is made longer to allow for more overall absorption. Therefore, when no pollutant gas is present in the sample cell, the radiation absorbed in each detector chamber will be approximately equivalent.

In the infrared spectral region, molecules absorbing the radiation are excited to higher energy vibrational–rotational states, which means that they will vibrate and rotate more vigorously. However, the excited molecules soon collide with other molecules and this extra energy is transferred in the collision. The energy released causes the molecules to move faster, or heat up, increasing the temperature and pressure of the gas in the cell. If both chambers absorb the same amount of radiation, the pressures will be the same.

Now, if the pollutant being measured is present in the sample cell, there will be a loss of light energy before it reaches the pneumatic detector. The loss of energy will be primarily at the band center and the pressure in the first chamber will not be as great as before, when pollutant gas is not present in the sample cell. There will be more absorption in the rear chamber and a pressure difference will develop. This pressure difference can be detected by using either a capacitance‐type microphone detector or a flow sensor. In either case, an electrical signal is developed that can be related to the pollutant gas concentration.

Figure 5‐2 Operation of an NDIR analyzer using a pneumatic sensor with the detection chambers in a series arrangement.

If an interfering gas is present in the sample, it will generally exhibit broadband interference. If the absorption is sufficiently broad over the absorption band wavelengths of the pollutant, the degree of absorption due to the interferant will be approximately the same in the front and rear chambers. It will therefore not affect the pollutant measurement. This technique has been utilized to develop CO analyzers that minimize the effects of CO₂ and H₂O interferences.

With regard to the types of sensors used in pneumatic detectors, the micro‐flow sensor has been widely applied. The micro‐flow sensor consists of a thin‐film grid of heated nickel that is cooled as the gas flows past the grid, thereby changing the grid's electrical resistance (Ueda and Watanabe 1978). This change is correlated to the change in pressures in the chambers and therefore to the concentration of the pollutant gas in the sample cell. The micro‐flow sensor technique is similar to that used in thermal sensors applied in flue gas velocity monitoring. Another approach utilizes a microcantilever sensor between the two cells, where the change in pressure displaces a micromachined cantilever sensor. The displacement, measured by an optical interferometer, is proportional to the concentration of the gas in the sample cell.

In contrast, the microphone‐type detector is an older technology that correlates the change of capacitance between a metal diaphragm and a fixed plate to the pressure differences in each chamber. One of the problems with the diaphragm‐type detector is its susceptibility to vibration. Vibration from plant equipment can be transferred to the instrument, resulting in noisy and, sometimes, unintelligible signals.

Other instrument configurations have been developed using pneumatic detectors. As an example, NDIR analyzers have been designed using only a measurement cell, where the I o reference value is obtained when zeroing the instrument with gases. Multi‐gas analyzers have been developed by stacking detector chambers, each filled with a gas to be measured.

Differential Absorption Spectroscopy – Infrared Analyzers

Another nondispersive method measures light absorption at different wavelengths: those where molecules absorb energy and those that do not. Here, a reference cell where c = 0 is not used to obtain I o to determine light transmittance. Instead, a reference wavelength λref, where the Beer's law absorption coefficient α(λ) = 0, is used.

This particular technique is called differential absorption spectroscopy or differential optical absorption spectroscopy (DOAS) or “direct absorption” spectroscopy when contrasted to wavelength modulation and derivative techniques. It is applied using light sources emitting at infrared wavelengths or ultraviolet wavelengths and in in‐situ CEM systems as well as extractive CEM systems. The technique has become prevalent in‐situ instrumentation used for monitoring reactive gases such as HCl and NH₃. Although optical filters are commonly used to select light of appropriate wavelengths in these instruments, tunable diode lasers and quantum cascade lasers can provide for greater signal power and wavelength discrimination (Hinkley et al. 1976a, b; Laush 2010; Laush et al. 2012).

In a typical differential absorption system, using a broadband light source, light is emitted at many different wavelengths and transmitted it through a cell containing the sample gas (or through the stack) to a detector. The detector signal, at the light wavelength where no energy is absorbed, is used as a reference measurement for the signal obtained at the wavelength where energy is absorbed. The rationale behind this method again comes from the Beer–Lambert law.

In this technique, a narrow band is chosen where the molecule does not have any spectral features (it does not absorb the light at that wavelength) and therefore

(5‐3)alpha left-parenthesis lamda Subscript normal r normal e normal f Baseline right-parenthesis equals 0

Then the measured value at this wavelength, I ref, will give the I o value as follows:

(5‐4)

The ratio between I sample and I ref can then be taken to obtain a relation for the concentration.

(5‐5)

where α(λ) is the absorption coefficient of the compound being measured. Then,

(5‐6)

(5‐7)equals k log StartFraction 1 Over upper T r EndFraction

where l is a known value, the length of the sample cell, and α(λ) is either known or determined through appropriate calibration procedures and the transmittance, Tr = I sample/I ref, is measured by the instrument. From Equation 5‐8, the gas concentration is proportional to log 1/Tr as seen in Chapter 4, Figure 4‐9. This is a simplistic approach for determining the concentration from a differential absorption method.

Direct Absorption Fast Scan Spectrometers

One of the problems with the differential absorption technique is that the gas measurement results from the ratio or difference between two large numbers, I o and I, which limits sensitivity. Sensitivity can be increased by increasing the path length or by reducing the noise in the measurement. Sources of noise can include variations in laser output, electronic noise, or variations in alignment, mirror reflectivity, dust levels, or vibration in in‐situ systems.

One way of reducing the noise when employing a diode laser as a light source is to ramp the laser current to change the laser wavelength, scanning over the wavelength range of the absorption feature (Figure 5‐3). For tunable diode lasers, the temperature is first controlled for it to emit in the wavelength region corresponding to the absorption feature of the gas. The current is then changed to fine tune the wavelength of the emitted light. This change is in the form of a ramp, where the laser wavelength increases as a function of the injection current, which increases with time.

The absorption peak is scanned repetitively (on the order of a thousand times a second, kHz), so noise fluctuations between the time it takes to scan the spectrum from the absorption minima (λref) to the maximum absorption are reduced when multiple scans are averaged (Muzio et al. 2012). Conceptually, the laser begins scanning where there is minimal absorption to establish a baseline (I o ) reference for the transmission measurement.

Figure 5‐3 A fast scan of the absorption curve.

Wavelength Modulation and Derivative Spectroscopic Methods

Other methods that take advantage of the scanning capability inherent in lasers include signal processing techniques such as wavelength modulation and derivative spectroscopy (O’Haver 1979; Schilt et al. 2003). These have enabled the development of instruments with greater baseline stability, resulting in greater sensitivity and accuracy. Derivative techniques are particularly useful for separating out or eliminating underlying broadband interferences in the spectral region where a pollutant molecule is being measured.

As in the direct measurement, fast scan technique, in wavelength modulation methods, the laser current is changed to sweep the laser wavelength across the width of the pollutant absorption feature. In the wavelength modulation technique, as the absorption curve is swept, the laser wavelength undergoes a faster, sinusoidal modulation over a modulation interval, Δλ, by oscillating the laser current. The laser wavelength is modulated by applying a low‐frequency ramp and a high‐frequency sine wave (Wang et al. 2019).

This modulation results in an alternating current that can be isolated and measured. The signal contains harmonic components that are periodic with the modulation frequency. The first harmonic corresponds to the first derivative with respect to the wavelength of light intensity observed at the detector (Hager 1973; Hager and Anderson 1970; Linnerud et al. 1998). The second harmonic corresponds to the second derivative measurement of the absorption curve with respect to wavelength. The second derivative has a maximum at the absorption line center and does not have a DC component, a feature that can eliminate the effects of broadband absorption underlying the absorption peak. The second derivative can be obtained by using a lock‐in amplifier to tune the instrument to the second harmonic of the alternating signal, i.e. twice the frequency of modulation. The extracted signal is proportional to the second derivative of the absorption curve with respect to wavelength evaluated at the peak maximum. Correspondingly, by taking the second derivative of the Beer–Lambert equation with respect to wavelength and equating the two, it can be shown that the signal is proportional to the gas concentration (see Chapter 6).

Fast scan and wavelength modulation techniques are used in extractive system laser analyzers and are used in in‐situ laser systems, where they are more widely applied. The technique is discussed in more detail in Chapter 6 as applied to in‐situ analyzers. The signal processing methods vary between the different instrument manufacturers, who should be contacted for details.

Photoacoustic Analyzers

An optical filtering instrument using a photoacoustic detector, developed for ambient and industrial applications, has been used in conjunction with dilution systems to monitor hazardous air pollutants (HAPs) (Sollid et al. 1996). This detector monitors acoustic waves resulting from absorption of chopped light by targeted molecules in the sample cell (Innova 2020; Pedersen 1989). An analyzer design developed and marketed by the company Innova (now part of Advanced Energy) is illustrated in Figure 5‐4.

As discussed, when rotational–vibrational energy dissipates absorbed light energy into kinetic energy, the pressure will increase in the chamber where they are confined. If a chopper is placed in the light beam, its rotation will periodically block the beam and cause the pressure to alternately decrease and increase, producing a pressure pulse (acoustic wave). When rotating between 20 Hz and 20 kHz, the pressure pulse can be detected as sound waves by a sensitive condenser microphone (Innova 2020).

In this capacitor‐type microphone, a thin metallic membrane is placed close to a fixed plate where the membrane moves back and forth in response to acoustic pulses generated in the detector. Voltage changes across the capacitor are dependent upon the distance between the two plates. That distance varies with the sound pressure as the pollutant molecules heat up and cool down due to the motion of the chopper. The measured voltage, in turn, is dependent on the concentration of the target molecules in the cell.

The sample cell can be relatively small, on the order of a few cubic centimeters, in contrast to differential absorption systems where sample volumes may need to be several orders of magnitude greater to achieve comparable sensitivity. In a typical photoacoustic monitor, discrete samples are measured by closing off the sample cell. The time necessary to both purge the cell and make a measurement can vary from 30 seconds to a minute, depending upon the number of gases being measured. By incorporating different optical filters on the rotating chopper, a range of organic and inorganic compounds that absorb light energy in the infrared can be measured down to low part per million and part per billion levels. An analyzer can incorporate five different filters on the carousel to measure five different gases and water vapor. The sensitivity of the technique is not dependent upon the optical path, with detection limits being at ppb levels.

In the photoacoustic technique, light absorption is measured directly: If there is no absorbing gas in the cell, no sound is generated; if less amount of gas is present, less sound will be generated; if more gas is present, more sound will be detected. In the photoacoustic technique, the signal starts from zero, providing an alternative differential absorption technique discussed previously, where the gas measurement results from the ratio or difference between two large numbers, which limits sensitivity. As will be discussed in Chapter 9, this difference can also be seen in particulate monitors, where in light scattering instruments, the signal increases as the particle concentration increases, but in transmissometers, the signal decreases from 100% as the particle concentration increases.

With the ability to measure part per billion levels, or possibly lower, and the flexibility to use a broadband IR light source, a tunable diode laser, or a quantum cascade laser as the instrument light source, a wide range of monitoring possibilities for monitoring both organic and inorganic trace gases have been proposed for the application of photoacoustic spectroscopy (Rocha et al. 2010; Tittle et al. 2012). For example, photoacoustic analyzers developed by Gasera in Finland use a microelectromechanical system (MEMS) design incorporating a silicon‐on‐insulator cantilever pressure sensor instead of a capacitive‐type microphone (Kuusela and Kauppinen 2007). Here, the displacement of the cantilever is measured using a laser light beam reflected from the moving cantilever in an interferometer assembly (Saarinen 2010; Uotila 2009; Uotila et al. 2005).

Figure 5‐4 A photoacoustic analyzer.

Gas Filter Correlation (GFC) Analyzers

A different type of NDIR technique common to in‐situ monitors is also applied to extractive system analyzers. This technique, gas filter correlation (GFC), uses a reference cell that contains a 100% concentration of the pollutant, instead of the 0% concentration in the analyzers discussed earlier. This method has been used to measure SO₂, NO, CO₂, CO, NH₃, H₂O, and HCl in extractive system analyzers. The essential features of a GFC instrument are shown in Figure 5‐5.

In a GFC analyzer designed to measure CO, radiation from an infrared source passes through a filter wheel that contains a neutral gas, such as N₂, on one side and CO on the other. The light is then passed through a modulator that creates an alternating signal. The light enters the sample cell and reflects from the mirrors to make multiple passes through the gas. This increases the path length, l, of the system and improves the sensitivity of the instrument. A portion of the light will be absorbed by any CO molecules in the sample cell and the radiation then exits to be measured at the IR detector.

In the operation of the instrument, the filter wheel is continuously rotating. First, consider the difference in signals between the CO and N₂ sides of the wheel when the sample cell is flushed with zero gas. When light passes through the gas filter (the reference beam), it will be attenuated (Figure 5‐6a).

The gas filter contains enough CO to remove most of the light at the wavelengths where CO absorbs. The gas filter transmits light whose intensity cannot be further reduced by CO absorption. The wavelengths not absorbed by CO are not removed and are passed on to the detector. The net result is a reduction in light energy reaching the detector. Now, when the radiation from the infrared source passes through the N₂ side of the wheel, the intensity is not reduced. However, in practice, a neutral density filter (an optical filter that reduces the light intensity uniformly over the wavelength range) is placed over the N₂ side of the wheel. This filter attenuates the signal to the same level as the gas filter side attenuation due to CO absorption (Figure 5‐6b).

Next, consider the condition where sample gas containing CO is introduced into the sample cell (Figure 5‐6c). The infrared beam will be alternating through the N₂ and CO sides of the filter wheel and then will pass through the sample cell to the detector. CO molecules are now present in the sample cell and they will absorb light energy at the CO absorption wavelengths. Because the gas filter is chosen to absorb energy at these same wavelengths, absorption is already complete in the gas filter cell beam, and the detector will see the same signal as it did when the sample cell contained zero gas in Figure 5‐6a. The beam passing through the N₂ side, however, will carry less energy because light is absorbed by the CO in the sample gas (Figure 5‐6d). The difference in energy between the two beams is monitored and can be related to the CO concentration in the sample.

Other gases having spectral patterns in the same regions of CO will not affect the measurement if they do not “correlate” with the CO spectral pattern. If, however, the peaks coincide with the CO spectra, a positive interference will result. The interfering gas will reduce the light intensity when light passes through the N₂, but not when passing through the gas filter. Conversely, if the interfering molecule's peaks fall between the troughs of the CO spectra, a negative interference will result. The energy of the light passing through both the gas filter cell and neutral cell is now reduced. Because the energy through the gas filter is supposed to remain the same to use as a reference against the measurement beam (N₂ side), the interference will be negative.

Figure 5‐5 An extractive system gas filter correlation (GFC) analyzer for monitoring CO.

Figure 5‐6 Absorption principles in the GFC, NDIR technique. (a) gas filter cell beam – no sample. (b) neutral beam – no sample. (c) gas filter cell beam – CO in sample cell. (d) neutral filter beam – CO in sample cell.

In most cases, the interfering spectra will have some peaks that overlap and others that fall in the troughs of the CO spectra. As a result, positive and negative correlations will cancel to minimize the effect of the interference. Interference is further minimized by using a bandpass filter to select a region of the spectrum where the CO absorption is most specific. However, H₂O and CO₂ interference can still be a problem in some instruments. In cases where interference cannot be eliminated by the technique, one solution is to measure H₂O, CO₂, or other gases by using additional gas filter cells and subtracting their contribution to that of the gas of interest.

Another gas filter correlation instrument configuration can be seen in Servomex GFC CO analyzer (Figure 5‐7). In this design, a White cell is not used, but the path length is lengthened using a mirror configuration.

In Figure 5‐7a, the CO cell on the filter wheel is rotated in front of the IR source to provide the CO reference measurement, where light wavelengths absorbed by CO are removed from the beam by the CO in the cell. The light beam exiting the cell is composed of light wavelengths other than those that would be absorbed by CO. As in the previous GFC analyzer discussed, when the light passes through the sample cell, nothing further happens because all light having wavelengths at which CO will absorb are removed by the CO gas filter cell.

In Figure 5‐7b, the nitrogen gas cell is rotated before the IR light source. Here, the light is not attenuated by the N₂ gas filter and the two light beams shown exiting the N₂ cell signify the light wavelengths that are and are not absorbed by CO. Nitrogen does not absorb infrared light, so nothing is removed as the light passes through the nitrogen cell. As the light passes through the sample cell, the light wavelengths that CO absorbs are now present. Light energy will be absorbed by the CO molecules in the sample cell and the light intensity leaving the cell will be smaller than that entering. Again, the two alternating measurements, with the CO and N₂ cells in place, are compared to obtain the CO gas concentration.

The GFC technique offers several advantages over the more traditional zero‐gas reference cell methods. Because the method is not limited to one absorption peak, but can measure over a range of wavelengths, more energy will fall on the detector to produce a stronger signal. Also, because a ratio is obtained between a measurement beam and reference beam, variations in light intensity resulting from infrared source fluctuations or dirt accumulation on the optics will cancel out. For this reason, the GFC technique can be readily applied to measuring pollutant gases directly in the stack – an application that will be discussed later.

Figure 5‐7 Gas filter correlation CO analyzer with folded path.

The GFC technique can be used to monitor several gases at the same time in either cool‐dry or hot‐wet extractive systems (Baker et al. 2004) or even in point or integrated‐path in‐situ systems (see Chapter 6). By inserting gas filters corresponding to the gases desired to be monitored, up to eight different gases have been measured in a single instrument (Dillehay 1990, 1993). Both differential absorption and gas filter correlation techniques are applied in the instrument. Both optical bandpass filters and gas filter correlation cells are incorporated into a filter wheel that rotates through the light beam, providing sequential readings for each gas. Ideally, a multicomponent analyzer can lessen system costs by reducing the number of analyzers that are to be purchased and that need to be maintained. This can be an advantage for waste‐to‐energy and cement plant applications where more gases are required to be monitored than in fossil‐fuel‐fired combustion facilities (Baker et al. 2004, 2012).

Laser‐Based Analyzers

Cavity Ring‐Down Spectroscopy (CRDS)

The cavity ring‐down technique spectroscopy (CRDS) and the related technique of integrated cavity output spectroscopy (ICOS) represent innovations in gas monitoring that have enabled the measurement of gas concentrations in the part per billion range – an order of magnitude lower than that of traditional NDIR methods. The technique is applicable in both the mid and near‐infrared regions and has also been applied in the ultraviolet region of the spectrum.

Significantly, when incorporated in a dilution‐extractive system, the laser‐based CRDS and ICOS methods are capable of measuring water‐soluble gases such as NH₃ and NO₂ and acid gases such as HCl and HF, at parts per billion levels, with minimum detection limits (MDLs) at part per trillion levels (Bono et al. 2001). These analyzers extend the range of application of dilution‐extractive systems, which, as noted in Chapter 3, were previously limited to monitoring only a few gases, such as SO₂, NO x , and CO₂, due to the lack of suitable analyzers. As well as their application in CEM systems, the commercial availability of these part per billion level analyzers has triggered a revolution in gas monitoring for a wide range of applications from monitoring contaminants in clean‐room to determining CO₂ isotope ratios in greenhouse gas programs. Tiger Optics, LLC, and Picarro, Inc., currently provide CRDS analyzers for CEM applications.

The cavity ring‐down technique utilizes a laser coupled to produce a standing wave with one of the resonant modes of a sample cell equipped with mirrors having a high reflectance of typically 99.99–99.999% (Figure 5‐8).

The highly reflective mirrors employed result in light being trapped in the cell cavity to be reflected back and forth many times, far more than in the Herriott or White cells used in other instrumentation to extend the measurement path length (see Figures 4‐13 and 4‐14). This results in an effective path length of kilometers. When turned on, the light transmitted into the cavity builds up in intensity due to constructive interference. When the light trapped in the cell reaches a sufficient intensity, the laser is switched off. Because the mirrors are not totally reflective, some of the light leaks out upon each reflection, exponentially decaying to zero. Sensed by the detector, from Beer's law, it can be shown that the light decays in this “ring‐down cavity,” as a first‐order exponential [see for example Berden and Engeln (2009)], according to

(5‐8)upper I left-parenthesis t right-parenthesis equals upper I Subscript o Baseline e Superscript minus left-parenthesis t slash tau right-parenthesis

where

I = the light intensity at time, t, sensed by the detector

I o = the initial light intensity

t = time elapsed after laser is turned on

τ = the ring‐down time, a decay constant equal to the time taken for the light intensity to fall to 1/e of the initial intensity

This process is shown in Figure 5‐9 for two conditions: (i) where the cell is empty and (ii) where the cell contains the flue gas sample.

In the first condition, the sample cell can be either devoid of sample or the laser can be tuned to a wavelength, λ o , that the molecule being measured does not absorb (effectively, as if it were absent from the cavity). The ring‐down time, τo, in this case is determined from the following expression:

Figure 5‐8 Cavity ring‐down spectrometer.

Figure 5‐9 Build‐up and decay of light intensity in a cavity with high‐reflectance mirrors.

(5‐9)tau Subscript o Baseline equals StartFraction d Over c left-parenthesis 1 minus upper R right-parenthesis EndFraction

where

τ o = ring‐down time when light is not absorbed

  d = cell length

   c = speed of light

R = mirror reflectivity

In the second condition, the cavity contains the flue gas sample and the decay of the light intensity is measured with the laser tuned to a wavelength, λ, where light is absorbed by the molecule. Because the sample gas absorbs some of the light energy at this wavelength, this constitutes an additional loss mechanism to the light intensity. The ring‐down time will decrease as a function of both the wavelength‐dependent absorption cross section, σ(λ), and the number density of the absorbing gas in the sample, N. Accordingly, the ring‐down time can be expressed as

(5‐10)tau left-parenthesis lamda right-parenthesis equals StartFraction d Over c left-bracket 1 minus upper R plus sigma left-parenthesis upsilon right-parenthesis upper N d right-bracket EndFraction

where

τ(λ) = ring‐down time when light is absorbed at wavelength λ

σ(λ) = wavelength‐dependent absorption cross section

λ = wavelength

N = molecular number density, proportional to the gas concentration

Solving the two equations for the number density (concentration) gives

(5‐11)

The result depends only on the measured decay constant of the ring‐down, the gas absorption cross section, and the speed of light. Basically, the determination of τ o serves as a baseline measurement that eliminates the instrument‐specific design parameters from the calculation. In contrast to photometric gas monitors, which measure the change of light intensity under the two conditions, the operation of a cavity ring‐down spectrometer is based on the measurement of the relative decay rates. This eliminates problems due to fluctuation noise in the laser light source.

The optical cells are typically robust and can withstand vibration; however, mirror alignment is critical.

Although cavity ring‐down instruments are more expensive than infrared photometric or gas filter correlation methods, they can be easily incorporated into preexisting or new dilution‐extractive systems. They can offer a relatively easy solution to monitoring water‐soluble gases at low concentrations, even when diluted in dilution‐extractive systems. For example, HCl CRDS analyzers have been applied to meet the requirements of the electric utility mercury and air toxics standards (MATS rule), where the HCl emission limits are as low as 1.9 ppm.

Off‐Axis Integrated Cavity Output Spectroscopy (ICOS)

A similar method, termed “off‐axis integrated cavity output spectroscopy (OA‐ICOS)” is a long‐path laser technique developed subsequent to the CRDS method (O’Keefe and Deacon 1988; O’Keefe and Scherer 1999). Commercial analyzers using this technique for source monitoring applications have been designed by Los Gatos Research, an ABB company, through which they are marketed. In the ICOS method, a time‐averaged cavity output is measured instead of the ring‐down time. Similar to CRDS, the technique uses an optical cavity with highly reflective mirrors to extend the measurement path length on the order of several kilometers. Again, the light enters and exits the cavity through the mirrors, but in the OA‐ICOS method, the laser is aligned off of the cell axis (Figure 5‐10) rather than centrally aligned.

In the ICOS method, the direct absorption of the monitored species is measured by scanning the laser frequency over the molecular absorption spectrum. By using an embedded computer, the absorption line shapes over the scanning region can be resolved, and processed to correct for spectral overlap and pressure broadening effects (Baer et al. 2012). A typical scan will take on the order of 100 msec, where the laser is turned on, the absorption region scanned, and the laser turned off. Because the instrument can, in effect, scan an extended spectrum, more than one gas can be measured with a single laser.

Figure 5‐10 Off‐axis integrated cavity output spectroscopy (ICOS) sample cell.

In the ICOS method, because the laser is not optically coupled to the resonant modes of the cavity in the same manner as in the CRDS method, the optical alignment is not as critical as in the CRDS method. This is purported to reduce assembly costs, make the instrument more robust, and allow for field maintenance, in contrast to CRDS. The technique has been applied in both the near‐ and mid‐infrared spectral regions using tunable diode lasers as well as quantum cascade lasers.

Fourier‐Transform Infrared (FTIR) Spectroscopy

Although traditionally a laboratory technique, Fourier‐transform infrared (FTIR) spectroscopy is also applied to source monitoring. The advent of relatively inexpensive and powerful microprocessor systems has allowed the method to be applied in the field. One advantage of the method is that many gases can be monitored at the same time by a single instrument. FTIR instruments have found applications in monitoring combustion sources, cement plants, toxic waste incinerators, and industrial processes. In general, for stationary source monitoring, the method is best suited for measuring compounds with low molecular weights (i.e. <50 amu). For example, the FTIR technique has been used to analyze the complex spectra of combustion gas samples such as that shown in Figure 5‐11 (Vidrine and McIntosh 1993a).

Basically, the FTIR technique gives a “picture” (such as Figure 5‐11) of the total absorption spectrum of the sample gas over a broad spectral range – instruments typically having a range of 2.5–25 μm [4000–400 cm–1 (wavenumbers)]. However, the camera used to take the picture is an unusual one. A spectrum such as that shown in Figure 5‐11 is not obtained initially; instead, a picture, called an “interferogram,” shown in Figure 5‐12 is obtained.

Figure 5‐11 Infrared absorption spectrum of a combustion gas sample.

Source: Modified from Herget (1982).

Figure 5‐12 A typical interferogram obtained by an FTIR spectrometer.

Figure 5‐12 is a graph of the intensity, I, of the light seen at the spectrometer detector, plotted against the position, x, of a mirror moving back and forth in the instrument. Now, this picture is somewhat worse than a negative; not very much can be told about the sample by looking at the interferogram. Nevertheless, it contains practically all the information about the sample that is needed. This is where the Fourier transform comes in. The Fourier transform is an elegant mathematical technique that “develops” or “transforms” the interferogram, which is a function of moving mirror position x, into an absorption spectrum based upon the light frequency or wavelength with which we are more familiar, such as the frequency‐based spectrum shown in Figure 5‐11.

A microprocessor does the developing by applying the Fourier transform to the equations representing the interferogram. In addition, the system usually contains a library of spectra of the different gaseous species that are expected to be found in the sample. By comparing these library spectra to the sample spectrum, both qualitative and quantitative sample data can be obtained.

The “camera” in this method is based on the interferometer developed by Michelson and Morley in 1887 (Michelson and Morely 1887). This interferometer divides the light emitted from a radiation source in two, making two beams that traverse different paths, and then recombine. A schematic diagram of an FTIR spectrometer is shown in Figure 5‐13.

Light from an infrared source is transmitted to a half‐silvered mirror (beam splitter) that partially transmits and partially reflects the light. The system contains a moving mirror that can change the distance over which one of the beams travels. The helium–neon laser is used to determine the distance (x) of travel of this mirror. The light transmitted through the beam splitter is directed to the moving mirror, from which it is reflected, and goes back to the beam splitter. But this time, the light is reflected from the half‐silvered mirror to pass through the sample cell and to the detector.

On the other hand, the part of the light beam that is reflected initially from the half‐silvered mirror hits a stationary mirror and is sent back to the beam splitter, where it is transmitted through the sample cell and to the detector. The two beams recombine at the beam splitter before they proceed through the sample cell to the detector. The moving mirror will cause the two light beams to travel different distances, and consequently, when they recombine, they will constructively and destructively interfere, depending on whether they are in phase or out of phase. This interference yields the spectral information that is used to determine gas concentrations.

Figure 5‐13 Schematic diagram of the basic FTIR spectrometer.

Figure 5‐14 Reference measurement interference pattern. Intensity at the detector as a function of wavenumber at fixed x for a polychromatic light source. (Dashed line represents the intensity distribution of the light source).

Solid‐state detectors composed of materials such as HgCdTl (MCT) or deuterated glycine trisulfate (DGTS) may be used at room temperature or can be thermoelectrically cooled using Peltier coolers for increased sensitivity. In laboratory applications, detectors may be cooled to liquid nitrogen temperature (77 K) or other lower temperatures.

A reference cell is not typically incorporated into today's FTIR instruments; instead, a reference spectrum is first obtained by filling the sample cell with a gas that does not absorb light in the infrared, typically, nitrogen. The signal obtained after the light passes through the reference gas provides a reference or “background” measurement that can be compared to the sample measurements. The reference signal is stored in the system microprocessor and then serves as an I o reference for the subsequent calculations.

For a polychromatic light source in an interferometer, interference patterns are formed like those shown in Figures 5‐14 and 5‐15.

Figure 5‐14 illustrates an interference pattern for the reference measurement, using nitrogen gas. The pattern is given as a function of wavenumber for a fixed value of x, that is, for one position of the moving mirror. Note that the pattern is sinusoidal and is modulated by the intensity of the light at each wavelength. The total integrated intensity of the light of Figure 5‐14, I o (x), corresponds to one point on an interferogram. At each value of x, the moving mirror position, there will be a different pattern and a different I o value. The total reference cell interferogram is obtained by plotting similar I o values for the other values of x.

This analytical method is based on the Beer–Lambert law, as are the other infrared methods discussed in this chapter. When sample gas is placed in the sample cell, light will be absorbed by the gases in the cell, resulting in a reduction of the peaks shown in Figure 5‐14. Similarly, the I(x) value is obtained from Figure 5‐15 for the sample cell interferogram.

Figure 5‐15 Sample measurement interference pattern. Intensity at the detector as a function of wavenumber at fixed x with a sample gas present. Note reduced transmittance due to light absorption.

The integrated area under Figure 5‐14 can be expressed mathematically (Strong 1979) as

(5‐12)

where

(5‐13)

Similarly, the integrated area under Figure 5‐15 can be expressed as

(5‐14)

Note that the gas concentration, c, is part of the Beer–Lambert expression incorporated in I(x). However, a problem arises here. The integrals are given as a function of wavenumbers, but the interferometer does not scan wavenumbers, frequency, or wavelength. The interferometer simply measures the light intensity at the detector as the mirror moves (i.e. for each value of x). But now, the Fourier‐transform technique can be used to convert the interferogram (which gives the measured light intensity as a function of x) into a frequency spectrum (which gives the intensity as a function of nu overbar ).

When applied, the Fourier transform converts the integrals by switching the nu overbar 's and x's to obtain

(5‐15)

and

(5‐16)

which is the absorption spectrum when I(nu overbar ) is determined over a range of wavenumbers.

If the two are divided, the Beer–Lambert formalism for the concentration can be brought out of the integral:

(5‐17)

Now, by knowing x, by using the reference laser, and by detecting the intensities at each x as the infrared beam is passed through the reference cell, α(nu overbar )cl can be determined.

Once the dispersed absorption spectrum information is obtained, the analyzer microprocessor must then extract both the qualitative and quantitative information desired. To do this, “library spectra” of the compounds being measured must be stored in the computer and referenced against the test data. The library spectra are obtained by analyzing samples of the compounds at known concentrations with the FTIR spectrometer. Various mathematical techniques (typically, least squares techniques (Plummer and Reagan 1996)) are used in this process to obtain concentrations in parts per million.

The FTIR technique involves the application of numerous technical and mathematical “tricks”; however, its operation can be summarized simply as follows:

IR light is emitted over a broad spectral range

↓

Mirror moving over distance x, modulates light

↓

Modulated IR light is absorbed by molecules in the sample cell to create the “interferogram”

↓

The interferogram is converted by the Fourier transform to an absorption spectrum

↓

The library spectra are matched to the absorption spectrum to give the concentration in ppm for each compound being measured

The method can be relatively straightforward if the compounds in the sample do not absorb light in the same wavelength regions, i.e. if their spectral “fingerprints” are not similar. If these fingerprints are similar, or overlap, the method becomes more difficult to apply. This is the case when the sample contains hydrocarbons or other organic compounds of similar structure. Capable of measuring at low part per million levels, sensitivity can be increased to part per billion levels by using multi‐pass White or Herriott cells.

The attraction of the FTIR technique is that a new instrument need not be designed to measure a “new” compound for each new application. It will measure any compound if it absorbs light energy in the appropriate infrared regions. This does not mean, however, that the instrument does not have to be optimized for a given application. For new applications the instrument requires the incorporation of library spectra of the compounds of interest over the range of concentrations expected at the source. These spectra may have been already generated by the analyzer manufacturer for other or similar applications, or they may sometimes be obtained from other sources. If they have not been generated, individual spectra of the target gases, at known concentrations, must be obtained and put into the library.

The major differences between FTIR systems marketed for environmental applications are in the design of the optical bench and the method of moving the mirror to create the interferogram. The design goal for the moving mirror is to make it vibration‐insensitive for field use. Various unique methods have been developed to meet this goal in the commercial instrumentation available. Other differences between instrumentation exist in the mathematical techniques used to extract the concentration data from the interferogram and the Fourier‐transform‐generated spectrum.

FTIR analyzers were once thought to be too complicated for installation in CEM systems or for source testing field work. The name itself, “Fourier‐transform infrared spectroscopy,” is sufficiently imposing to suggest that special expertise is necessary for its use. That has all changed and today, FTIR systems are installed as continuous emission monitors in cement plants, municipal waste combustors, and coal‐fired utilities. Some cement companies in fact have standardized on the technology and require that their plants, worldwide, to use FTIR analyzers for monitoring applications. Source testing firms use FTIR systems for the measurement of a wide range of hazardous air pollutants and are at a competitive disadvantage when not having FTIR measurement capabilities (ICAC 2013). Although the optical systems and computer algorithms may be too difficult for most users to repair or modify, as with any instrument, FTIR instrument manufacturers can readily address service issues when they arise.

The literature associated with FTIR analyzers and their applications is extensive. For source emission monitoring, they were used as early as the 1970s in research applications (Herget 1982; Streiff and Claysmith 1972) and later were applied in a variety of source testing applications. Some early failures in their implementation as continuous emission monitors in the 1980s at first made industry wary of their use, but by the 1990s, source testing companies started using them in testing and contracted research programs (Bartak et al. 1996; Geyer 1996; Gray 2002; Kinner et al. 1995; Reagen and Wright 1996). Because of their ability to measure a wide range of compounds, FTIR analyzers are often the first method of choice used to characterize hazardous air pollutant emissions.

The trend over the past 20 years is to first use an FTIR to see if it can measure a gas species in the concentration levels normally encountered in a process or at levels specified in a regulatory agency emission limit. If successful, and if EPA Method 320 criteria can be met, an FTIR system may then be used as a test method for periodic compliance evaluations. Further, if an emissions control system is installed, and continuous measurements of the pollutant are required, an FTIR analyzer may be installed either for reporting emissions (Dunder et al. 1994; Vidrine and McIntosh, 1993a and McIntosh 1993b) or may be used as a process monitor (Reagen and Wright 1996; Seguin and Madden 2001; Stock and Eldridge 1996). More recently, FTIR analyzers have been applied to evaluate emissions from flares (Krnavek et al. 2012), emissions chemistry from ethanol plants (Dunder 2008; Spartz and MacPartland 2018), SO₃/SO₂/H₂SO₄ chemistry and low‐level HCl emission in coal‐fired power plants (Hall et al. 2002; Zemek 2014; Zemek and Marshak 2012), and greenhouse gas emissions (Heikkilä et al. 2009; Mosca et al. 2014). To illustrate the breadth of the method, gases monitored in the studies referenced above include formaldehyde, methanol, phenol, and carbonyl sulfide cyclohexane, ammonia, formaldehyde, methanol, carbon monoxide, methane, HCl, HBr, HF, and N₂O.

SPECTROSCOPIC METHODS – ULTRAVIOLET MONITORING INSTRUMENTS

Analyzers operating in the ultraviolet–visible region of the spectrum have been used for pollutant and process gas monitoring for many years. The characteristics of light in the ultraviolet region of the spectrum (shorter wavelength, higher energy) lead to molecular electronic transitions when light is absorbed. Because the energy associated with the absorption processes is greater than that in the infrared, it is easier to detect changes in absorption. Photomultiplier tubes have traditionally been used for this purpose; however, silicon‐based linear photodiode array detectors are now also applied in source monitoring instrumentation. One advantage of developing analyzers in the UV is that H₂O and CO₂ do not interfere in the spectral regions where pollutant measurements are made, which allows the use of hot‐wet extractive or in‐situ systems, and otherwise simplifying the analyzer design.

Nondispersive Ultraviolet Photometers

When analyzing for gases in the ultraviolet region, a common approach is to use one or more of the narrow absorption bands in the UV spectrum (Figure 5‐16). Different design options are available in commercial instrumentation – the most common being the single‐beam dual‐wavelength photometer, the dual‐beam multi‐wavelength photometer, or the dispersive diode‐array spectrometer.

Single‐Beam Dual‐Wavelength Photometers

The earliest instruments that were designed to operate in the UV region utilized the differential absorption technique. One of the first successful monitoring systems that met the EPA CEM performance criteria in the early 1970s was originally designed by DuPont Corporation to monitor process operations. Finding wider application in CEM systems, it was installed in smelters, coal‐fired power plants, and chemical plants to monitor SO₂ emissions at higher ranges (>1000 ppm) than currently allowed with lower emission values (Taylor 1981). The simple, single beam/design led to a robust instrument that saw over 30 years of operation in some applications until new regulations and technical advances warranted their replacement.

Figure 5‐16 The UV–visible spectrum of SO₂ and NO₂.

Source: Courtesy of DuPont Instruments.

Applied principally for monitoring SO₂, UV light absorption can be measured at a wavelength in the SO₂ absorption band centered at 285 nm and then be compared to the absorption at the wavelength region of 578 nm where there is no SO₂ absorption. Here, as in differential absorption infrared analyzers, a reference wavelength is used to determine the reference I o value, instead of a reference cell. The DuPont analyzer split the beam after passing through the sample cell, with one part passing through an optical filter to measure the reference I o value and the other part passing to the measurement detector. In a single‐beam dual‐wavelength differential absorption NDUV analyzer that evolved from the earlier DuPont instrument (Beamish 1981; Stenson 2000), a rotating filter wheel was employed to discriminate between the reference and measurement wavelengths (Figure 5‐17).

In this design, light from a mercury discharge lamp, hollow cathode, or other type of UV lamp passes through the sample cell to a set of bandpass filters rotating on a filter wheel and then to a photomultiplier tube. The measurement filter allows light centered in a narrow band at 285 nm to pass through to the detector. The other bandpass filter, the reference filter, allows light only in the region of 578 nm to pass through. Note from Figure 5‐16 the relative absorption of SO₂ in these regions. Light will be absorbed at 285 nm by the SO₂ in the sample gas, whereas no SO₂ absorption will occur at 578 nm. The resultant photomultiplier signals are amplified and the logarithm of the reciprocal of the transmittance (the absorbance) gives an output that is directly proportional to the SO₂ concentration, shown in Equation 5‐8.

Figure 5‐17 Operation of a single‐beam dual‐wavelength differential absorption NDUV analyzer.

Note that there is some interference by NO₂ at 578 nm, but there is also an equivalent NO₂ interference at the SO₂ absorption wavelength of 285 nm, so the net interference is negligible. Also, the concentration of NO₂ in a combustion gas from coal, oil, and incineration sources is small (approximately 5% of the NO level). Furthermore, the NO₂ absorption coefficient at 578 nm is small relative to that of SO₂ at 285 nm, which further reduces the effect of this interference.

The technique can also be applied for monitoring H₂S, which strongly absorbs in the region of 170–250 nm. Ammonia strongly absorbs at 170–220 nm, a spectral region utilized in commercial extractive and in‐situ NH₃ analyzers.

Problems associated with lamp aging, power supply fluctuations affecting light intensity, and temperature effects on hollow cathode gas discharge tubes can result in short‐term noise or long‐term drift. These problems can be minimized by modifying the basic system shown in Figure 5‐17 by adding a reference cell, splitting the UV beam to continually reference the lamp output, or using two lamps as shown in Figure 5‐18. Also, recent improvements in detectors and in some cases the use of solid‐state detectors such as gallium arsenide phosphide (GaAsP) have improved overall instrument performance. An approach taken AMETEK Land is discussed in the design applications that follows.

Design Application – SO₂, H₂S Single‐Gas Analyzer

A UV differential absorption instrument widely used in the petroleum processing industries was developed by Western Research, now part of AMETEK Land, to improve baseline drift stability and signal‐to‐noise ratios (Imbrogno and Harris 1996; Harris et al. 2010). The analyzer measures either SO₂ or H₂S using two ultraviolet light sources, two wavelength selective filters, a gas measuring cell and two matched photodetectors. When configured to measure SO₂, two magnesium UV lamps, emitting at 285, 309, and 383 nm, are used. When measuring H₂S, two cadmium UV lamps, emitting at 214 nm, are used. The wavelength‐selective filters block out wavelengths that might be absorbed by other gases to interfere in the measurement. The design of the analyzer is shown in Figure 5‐18.

In this design, light beams from two UV lamps are chopped so that at any one time, the detectors are exposed alternately to light from one lamp/filter combination and then the other.

Figure 5‐18 UV single‐gas analyzer measurement schematic.

The lamp/filter combination, shown at the bottom right of the figure, provides a light beam at a wavelength, λ, from which SO₂ will absorb energy. The light from the upper‐left lamp/filter combination is transmitted at a wavelength, λ o , at which SO₂ does not absorb. The light beams alternately transit through the monitoring system. Each beam first encounters a beam splitter, where it either reflects from or is transmitted on through to the reference detector. This measurement is used to correct for differences in the lamp intensities, differing optical paths, and mirror losses of the two beams. After the beam splitter, each beam alternately passes through the sample cell and then on to the measurement detector. As in the UV differential absorption instrument discussed previously, when SO₂ is present in the sample cell, light energy will be absorbed, and the intensity of the measurement beam at wavelength λ will be reduced. This intensity is compared to that of the reference beam at wavelength, λ, where no light energy is absorbed when it passes through the sample cell. The gas concentration can be determined from Equation 5‐8, after correcting for light losses due to differences in the two optical paths. In practice, from the application of Beer's law (Equation 5‐7), the ratio of the detector voltages for each beam is used to determine the SO₂ concentration, where

(5‐18)

and

normal c Subscript upper S upper O 2 = the SO₂ concentration of the conditioned gas

V o = the voltage at the Reference detector

V sample = the voltage at the Measurement detector

Differential absorption UV instruments have proven to be quite reliable in source monitoring applications and are typically applied as hot‐wet extractive systems, where a heated sample line and heated sample cell prevent condensation. Because water vapor does not absorb light appreciably in this region of the ultraviolet spectrum, little interference by water occurs. They are also used frequently by source testing firms in mobile vans SO₂ measurements because of their compact nature and relative freedom from interferences.

They operate well at higher concentrations (>100 ppm) found in coal‐fired power plants and smelters. They are not commonly applied at low ppm levels, where, as discussed in Chapter 3, SO₂ will be lost in the cool‐dry extractive system condensation units, particularly at lower concentrations. This, of course, will lead to SO₂ values lower than true. However, SO₂ losses might go unnoticed if source testers use the same type of analyzer in conjunction with a cool‐dry extractive system. In such a case, the two analyzers may agree, but both the results will still be wrong.

Design Application – SO₂/NO/NO₂ Multi‐gas Analyzer

The instrument discussed previously (Figure 5‐18) can be modified to incorporate a filter wheel containing up to five spectral interference filters as shown in Figure 5‐19. The monitor measures additional gases in the single analyzer as the filter wheel is rotated, where the individual filters allow the transmission of discrete light wavelengths, λ i , at which different gas species absorb.

The location of the filters in the wheel and the placement of the source lamps are chosen so that at any given time, light reaching a detector comes from only one lamp and filter combination. In a combination used to monitor total NO x and SO₂, two different hollow cathode source lamps are used. Optical filters selective for wavelengths at 284 and 309 nm are used for the measurement of NO and one for the measurement of NO₂ and/or SO₂ at 214 nm.

Depending on the choices of lamps and filters, other gases such as NH₃, H₂S, CS₂, COS, and Cl₂ can be measured in the UV with this analyzer. Minimum measurement ranges are on the order of 0–20 ppm to 0–500 ppm or higher depending on both the gas being measured and the cell length. Sensitivity can be increased by using a White multi‐pass cell to provide for a longer measurement path length. The instrument does measure ppm levels, but not at the ppb levels that would be necessary for application in dilution‐extractive systems. The use of these analyzers to monitor regulatory compliance may not always be appropriate when low emission limit values are mandated; however, they have seen wide usage as process monitors, particularly in hot‐wet extractive systems. Also, rack‐mounted versions of both single‐gas and multi‐gas designs of this instrument are often installed in mobile testing vans by stack testers.

Application of Linear Photodiode Array Detectors

Photodiode array detectors are applied in the UV region of the spectrum in both extractive and in‐situ systems typically for monitoring compounds such as SO₂, NO, and NH₃. With the advent of photodiode array detectors, a spectrometer capable of measuring multiple gases can be constructed with almost the same simplicity as a photometer. A photodiode array detector is composed of a series of silicon‐based photodiodes that are sensitive to light. A diode array can have from 128 to over 4000 diode elements, each separated by about 25 μm. The array is first set up by charging each diode element with a reverse voltage to establish a barrier to electron flow. When light strikes the n‐type silicon of the diode, photon‐generated electrons discharge the diode. Each of the diodes is then recharged – the voltage necessary to recharge it being a measure of the light intensity on the element.

Optical filters and diode lasers are used in both extractive and in‐situ analyzers. Relatively inexpensive analyzers can be designed using optical filters, although the expense of the filters increases as their discrimination increases between different wavelengths. Optical filters are commonly used for monitoring CO₂ in the infrared region. The technique is also widely applied in UV extractive analyzers, in‐situ analyzers, and remote‐sensing instruments

Figure 5‐19 Gas filter correlation multi‐gas analyzer with filter wheel.

By using the diode‐array detector in conjunction with a diffraction grating, an instrument can be designed to obtain a spectrum in a few seconds (Figure 5‐20). By using a diffraction grating, the light can be fanned out onto the diode array. The light from the grating can be focused so that each diode element senses an incremental region of the spectrum. In essence, each diode is looking at only a small range of wavelengths, but the whole array will look at a larger spectrum. Now, if the sample gas is placed in the sample cell, light will be absorbed at different wavelengths and the diode elements that monitor those wavelengths will sense that reduction. So instead of having a spectrometer that disperses the light and then scans each wavelength with one detector, with a diode array, the light is dispersed and the absorption at each wavelength can be measured simultaneously with over 1000 diodes on the array.

The technique has great potential and can be used in both extractive analyzers (Driver et al. 1996; Saltzman et al. 1989) and in‐situ systems (Durham et al. 1990; Scholz and Gilmour 1992). The method is obviously capable of measuring several gases at one time.

Figure 5‐20 A diode‐array spectrometer.

Figure 5‐21 Differential optical absorption techniques. (a) Optical filters. (b) Laser. (c) Diode array detector. (d) Moving slit.

Application of Diffraction Gratings and Moving Slits

A simpler method of applying the differential absorption technique is to use a diffraction grating and a moving slit. Figure 5‐19 shows that the UV light fans out in a spectrum over a range of wavelengths. In the instrument discussed earlier, the intensity of light at small wavelength intervals is measured on the photodiode array detector. Instead of using a photodiode array detector, a single detector can be used in combination with a moving slit to scan the spectrum, as shown in Figure 5‐21d. This technique is used by the Swedish company, Opsis, primarily in in‐situ monitoring systems for monitoring a variety of compounds as well as elemental mercury vapor.

Summary – Differential Absorption

Differential absorption spectroscopic techniques have been used for many years and were applied originally to determine the concentration of specific compounds in gas and liquid streams for the process industries. The earliest analyzers used optical filters to select the light wavelengths, but other techniques have since been developed to apply the principle. Methods used in the infrared and/or UV include among the following:

Optical filters

Tunable diode and quantum cascade lasers

Photodiode arrays

Diffraction gratings and moving slits

These techniques are illustrated in Figure 5‐21.

When there are appreciable interferences from compounds other than the one desired for measurement, advanced chemometric techniques are sometimes used to subtract out their effect, particularly in (3) photodiode array and (4) moving slit detection methods.

SPECTROSCOPIC METHODS – LUMINESCENCE

Luminescence is a phenomenon caused by the emission of light from an excited molecule. There are two types of luminescent processes that are used in source monitoring analyzers: fluorescence and chemiluminescence. Fluorescence in molecules is the release of light after a molecule has been excited by light of a different wavelength. Chemiluminescence is the emission of light from an excited molecule created in a chemical reaction. Analyzers utilizing the effects of luminescence can be very specific for a given pollutant and can have a greater sensitivity than some of the absorption or electrochemical methods.

Fluorescence Analyzers for SO₂ Measurement

Fluorescence is a photoluminescent process in which light energy is absorbed at one wavelength and emitted at a different wavelength. In this process, the excited molecule will remain excited from 10⁻⁸ to 10⁻⁴ seconds. Upon the loss of energy by vibrational–rotational energy relaxation processes (internal conversion), the molecule goes to a lower energy state. It will revert to its lowest energy state by emitting light, i.e. it fluoresces. An energy level diagram given in Figure 5‐22 illustrates the mechanism involved in fluorescence emission.

The molecule is in a high vibrational state after an electronic transition occurs (e.g. energy state S o  → S ₁). Upon loss of some of the energy by the vibrational relaxation, the molecule reverts to lower energy states by emitting light (e.g. S ₁ → S o ) of wavelengths longer than those originally absorbed. The fluorescence process can be expressed as

where upper S upper O 2 Superscript asterisk symbolizes the excited molecule. The fluorescence spectrum for SO₂, shown in Figure 5‐23, also illustrates this point.

To use this phenomenon to measure SO₂ concentrations, a sample is irradiated with light in the UV, in the range of 210 nm, and the emitted longer wavelength fluorescent radiation is measured.

Commercially available SO₂ fluorescence analyzers have been developed to measure ambient‐level and source‐level concentrations. A typical configuration is shown in Figure 5‐24.

Figure 5‐22 Energy levels and fluorescence emission.

Here, the light from either a continuous or pulsed ultraviolet light source is filtered to a narrow region, centered near 210 nm. The fluorescent radiation is measured at right angles to the exciting radiation, using a photomultiplier tube or other detector. A bandpass filter is then used to select a portion of the fluorescent radiation for measurement in the range of 310–370 nm, because interferences could occur over the full range of the fluorescence emission spectrum.

The application of this technique to ambient or source monitoring requires attention to the phenomenon of fluorescence quenching. In this process, the excited SO₂ molecule left-parenthesis upper S upper O 2 Superscript asterisk Baseline right-parenthesis may collide with another molecule before it can release its extra energy as light. Instead, energy will be lost in the collision and will cause the molecules to move faster after they collide. Water, CO₂, O₂, N₂, hydrocarbons, or any other molecule for that matter can quench the emission of radiation. The problem is, however, that each of these molecules has a different quenching efficiency (Jahnke et al. 1976). If the composition of the background gases changes (e.g. nominally 6% O₂, 12% CO₂ in a combustion gas), the SO₂ reading obtained would be different from that obtained if the background gas were ambient air containing 21% O₂. Because the analyzer is to be calibrated with SO₂ in air, errors due to the different backgrounds can range from 5 to 10% of the SO₂ concentration. It has often happened that a technician will take a convenient cylinder of span gas having SO₂ in nitrogen rather than in air. Spanning a source‐level instrument with such a mixture will cause the SO₂ readings to be approximately 30% lower than the true values.

Figure 5‐23 Fluorescence in SO₂.

Source: Adapted from Strickler and Howell 1968; Okabe et al. 1973.

Figure 5‐24 Operation of a typical SO₂ fluorescence analyzer.

Problems of quenching have been dealt with in a number of ways. In ambient air analyzers, hydrocarbon scrubbers or “cutters” have been added to minimize hydrocarbon quenching effects; UV light at lower wavelengths may be used to reduce the time for fluorescence to occur and reduce quenching probabilities; the sample cell may be held under a vacuum to reduce collision events. In source applications, the instrument can be calibrated with SO₂ mixtures contained in a gas having a background similar to that of the source; correction curves can be applied; or the best method and the most commonly one applied is to dilute the sample gas with air, to minimize the disparities in the background gas composition. The combination of a dilution system in conjunction with an ambient‐level SO₂ fluorescence analyzer has been successful in many CEM system applications, particularly those installed in the United States to meet the requirements of the acid rain program. In 2020, over 95% of the coal‐fired units participating in the Part 75 program were using fluorescence analyzers for measuring SO₂ (Norfleet 2020).

Chemiluminescence Analyzers for NO and NOx Measurement

Chemiluminescence results when light is produced in a chemical reaction. The phenomenon has been used in the development of NO x analyzers for ambient air monitoring, source monitoring, as well as diagnostic engine testing in the automobile industry.

The Chemiluminescence Analyzer

It has been known since 1949 (Greaves and Garvin 1959) that the reaction of NO and ozone, O₃, will produce infrared radiation from about 500 to 3000 nm:

Nitric oxide concentrations are determined by observing the chemiluminescent radiation over a narrow region of the total emission. A filter is used to select light in the region from about 600 to 900 nm (Figure 5‐25).

In an NO x chemiluminescence analyzer, O₃ is generated by the UV irradiation of oxygen in a quartz tube. The O₃ is provided in excess to the reaction chamber to ensure complete reaction and through dilution, to minimize quenching effects. Because the photomultiplier signal is proportional to the number of NO molecules, instead of the NO concentration, the sample flow rate must be carefully controlled. Figure 5‐26 illustrates the operational characteristics of an analyzer typical of this class of instruments.

Figure 5‐25 The chemiluminescent emission spectrum of NO₂*.

Source: Modified from Clough and Thrush (1967).

Nitrogen dioxide (NO₂) does not undergo this reaction and must be reduced to NO before it can be measured by this method. Most commercial analyzers contain a converter that catalytically reduces NO₂ to NO.

A heated stainless steel converter chamber will catalyze the NO₂ decomposition; however, this method is not characteristically used since at the high temperatures necessary, NH₃ will also be converted into NO (Fitz and Welch 2001). Instead, molybdenum chips, molybdate carbon, or vitreous carbon are used to reduce the NO₂ to NO at lower temperatures (Gluck et al. 2003). The NO produced is then reacted with the O₃ and the chemiluminescence is measured to give a total NO + NO₂ (NO x ) reading (Figure 5‐27).

Step 1 of a typical measurement sequence is for the sample gas to bypass the converter and react in reaction chamber:

In step 2 of the sequence, the sample gas is sent into the converter chamber and the NO₂ present is reduced to NO. The sample sent to the reaction chamber in step 2 is as follows.

To obtain the amount of NO₂ in the sample, the results of step 1 are subtracted from those of step 2:

Figure 5‐26 Operation of an chemiluminescence analyzer. Measurement of sample NO₂ concentrations.

Figure 5‐27 Operation of a chemiluminescence analyzer. Measurement of sample NO + NO₂.

The sample gas can be switched automatically in and out of the converter to give sequential readings for both NO and NO₂, but this is usually an optional feature. For low levels of NO₂, as is usually experienced in combustion source applications, a negative value will sometimes be obtained for the NO₂ concentration, particularly if the instrument is poorly calibrated.

Ammonia or other oxides of nitrogen can bias the NO x data. Ammonia will oxidize to NO in the converter, and other nitrogen oxides will reduce to NO. Using a molybdenum converter, which operates at lower temperatures, can minimize the problem. Also, because ammonia is very soluble in water, it will often drop out with the moisture in a conditioning system.

The chemiluminescent radiation also can be quenched, as in fluorescence analyzers (Gluck et al. 2003; Matthews 1977; Tidona 1988). The reaction chamber is commonly held under reduced pressure to lessen the quenching effects. Also, quenching can be reduced by flowing O₃ into the sample chamber at a rate greater than the sample rate. The resulting dilution gives a relative constant background gas composition. The use of a dilution‐extractive system instead of a source‐level extractive system can also reduce quenching effects. Through the incorporation of these techniques, the chemiluminescence method has been proven to be reliable and is often the method of choice for NO x measurements in source monitoring systems.

The practical application of these techniques differs between the various chemiluminescent analyzer manufacturers, and it is therefore difficult to generalize their effectiveness. Flaherty et al. (1998) have found that NO₂* chemiluminescence quenching by CO₂ is instrument dependent and can vary from −0.044% NO per %CO₂ to −0.132% per %CO₂. A typical quenching effect will lead to an NO reading approximately 0.5% low at a CO₂ concentration of 12%. These results are for source‐level monitoring systems. In dilution‐extractive systems, CO₂ concentrations are typically on the order of 3000 ppm and quenching effects will be minimal.

Low NOx Measurements.

The capability of CEM systems to measure NO x at low concentrations (on the order of 1–10 ppm) was studied by a number of institutions in the early 2000s. The studies were in response to the increasing installation of gas combustion turbines and stringent operating permits. Depending upon whether a gas turbine is an ozone nonattainment or attainment region, operating permit levels for NO x may range from as low as 2.0 to 2.5 ppm or 5 to 9 ppm, respectively (Eberhardt 2002). The lower limits can be achieved with the addition of catalytic reduction systems; however, the use of selective catalytic reduction (SCR) systems may introduce NH₃ into the flue gas exhaust as “ammonia slip.” The problem then is to measure NO x accurately, after SCR systems in the presence of ammonia at levels on the order of 2 ppm. Another problem arises if monitoring NH₃ in the range of 5 ppm is required.

Although chemiluminescence analyzers, and others, can measure accurately at these low levels, proving that a monitoring system is measuring accurately is “relative” to the measurements of a source tester, who must measure at least as accurately as the installed system. However, the variation of the exhaust gas flow trough the SCR grids can cause NO x and NH₃ stratification in the gas after the SCR system, and multi‐point sample probes and/or multipoint sampling may be necessary to obtain a representative sample. Other factors that enter into NO x measurements relate to the fact that after SCR systems, NO₂ concentrations can constitute 30–40% of the total NO x , whereas in coal‐fired plants, NO₂ concentrations are normally at 5% of the total NO x . Consequently, factors that can influence the accuracy of CEM system employing chemiluminescence analyzers are of concern (Clapsaddle et al. 2001; Gluck et al. 2003).

Stratification and sampling issues

Converter efficiency

Loss of NO₂ in the sample line

Loss of NO₂ in the sample conditioning system,

CO₂, H₂O quenching

Effects related to the calibration of the analyzer using a dry calibration gas in air or N₂, while sampling a wet gas containing CO₂. Quality of low‐level calibration gases

NH₃ interference, bias in the NO measurement

Many of these factors have been studied. However, the issues are confounding, and it has been difficult to assess their relative importance in the overall measurement. NO x analyzer converter efficiencies range from 83 to 97% (Fitz and Welch 2001; Franco 2001); however, for prolonged periods at high NO₂ levels, the long‐term efficiency of molybdenum convertors can be a problem, having a lifetime of approximately 12 000 ppm‐hours (Eberhardt 2002). CO₂ and H₂O quenching effects vary, depending upon on the analyzer manufacturer. These effects can be reduced by operating the analyzer under reduced pressure, in addition to diluting the sample by optimizing the flow of ozone (Jernigan et al. 2002) and/or by using a dilution‐extractive system.

Numerous studies on NO x quenching from the presence of CO₂ and H₂O have been conducted (Baldwin and Budd 2002; Fitz and Welch 2001; Gluck et al. 2003; Lanier 2001), and others. Although the results of these studies are inconsistent, it is generally considered that CO₂ and H₂O quenching can be minimized sufficiently in chemiluminescence analyzers designed specifically for source monitoring applications. The work by Fitz and Welch is the most extensive one, studying the effect of chiller type, type of sampling line, converter efficiency, and ammonia effects.

In general, it is considered that EPA performance criteria such as daily drift and relative accuracy can be achieved using chemiluminescence analyzers in the range of 2 ppm level (Baldwin and Budd 2002; Clapsaddle et al. 2001; Fitz and Welch 2001). However, care must be taken in the choice of materials, conditioning systems (if applicable), and the analyzer. In particular, if high NO₂ levels are present, the converter efficiency must be maintained and the CEM system design should minimize NO₂ losses in the conditioning system (Eberhardt 2002). To successfully pass a RATA at low levels, the source tester's apparatus must have an equivalent, or better, level of performance than the system being certified, with proper attention being paid to stratification and testing procedures during the certification process.

Measuring NH₃ Using Chemiluminescence NOx and Other Analyzers

To this point, this chapter has discussed methods for measuring the criteria pollutants, diluent gases, with the possible applicability of the methods to other gases. SO₂ and NO x have been major pollutants contributing to acid rain and photochemical oxidants in the atmosphere. They are now highly regulated and procedures for testing and certifying analyzers used to measure their emission are well established. This is not always the case for other pollutant gases. When new regulations are passed, such as those for the hazardous air pollutants, mercury and hydrochloric acid, resources are applied to develop monitoring criteria specific to them. In some cases (such as those for Hg and HCl), those resources can be appreciable; in other cases, resources applied may be minimal.

One such case is ammonia. There are few regulatory requirements for the installation of NH₃ CEM systems, although there is an active commercial market for monitoring the gas. Ammonia is not a regulated pollutant in the Part 60 New Source Performance Standards. At this time the U.S. EPA source reference test is a conditional test method CTM 027, or Method 320 can be applied. A performance specification for NH₃ has not been promulgated, although PS18 is recommended. However, ammonia does receive increased attention on the state level because it is viewed as a precursor to the formation of ammonium sulfate and ammonium bisulfate PM2.5 aerosols. In areas where air quality standard for PM2.5 deposition are not being met, requirements for monitoring ammonia emissions may be incorporated into plant operating permits on a case‐by‐case basis.

Ammonia is used as a reagent in NO x control systems, where excess, unreacted ammonia in the flue gas stream is known as “ammonia slip,” being indicative of the operating efficiency of the NO x control system. Excess ammonia downstream of the combustion system or the SCR system can react with SO₂ and SO₃ and form ammonium sulfates, which can plug or corrode downstream components of the unit such as air heaters, ducts, and fans. It can also contaminate collected fly ash, and cause stack‐exit opacity and odor problems. The higher the ammonia slip, the less efficient the NO x control system, consequently increasing the cost of reagents and system operation. Ammonia CEM systems have been installed on municipal waste combustors, process heaters, utility and industrial boilers, gas turbines, and other combustion sources, primarily as a means of optimizing the operation of NO x control equipment.

Using NO x analyzers, principally chemiluminescence analyzers, to measure ammonia was one of the earliest techniques applied for measuring ammonia slip. Two methods can be used: (i) the inlet–outlet differential NO x technique and (ii) the differential NO x /NH₃ converter technique.

Inlet–Outlet Differential NOx Technique (Mass Balance Method)

The method does not measure ammonia directly, but is a mass balance technique that requires four measurements: (i) the ammonia feed rate to the SCR, (ii) the inlet NO x concentration, (iii) the outlet NO x concentration, and (iv) the flue gas volumetric flow rate. Assuming that a majority of the NO x is NO reacting with NH₃ on a 1 : 1 basis and 100% converter efficiency, then the amount of NH₃ reacted in the converter will be

(5‐19)

If the amount of ammonia injected into the converter is known, then the amount of unreacted ammonia, or ammonia slip, can be calculated as follows:

Simply, in terms of emission rates in lbs/hr:

(5‐20)

This method requires monitoring of the ammonia feed rate, which is usually already monitored to operate the SCR; measurement of the NO x outlet concentration, which is usually required for compliance monitoring; determination of the NO x inlet concentration, which requires the purchase of an additional NO x CEM system; and determination of the volumetric flow rate. The NH₃ feed rate is usually given in pounds per hour. This can be converted into a volumetric part per million (ppmv) value by using the heat input calculated from the fuel flow and oxygen concentration (ICAC 2011).

Timing delays can be an issue in the application of this method, since it takes a finite amount of time for a parcel of gas to flow through the system from the process, through the control device, and to the control device exhaust or the stack. If the NO x concentrations or diluent gas concentrations (O₂/CO₂) vary at a rate faster than the flow rate through the system, the calculation may not be completely accurate.

In principle, any type of NO x CEM system could be used at either the inlet or outlet. For gas turbines, a source‐level extractive system would be suitable for measuring where the particulate concentration and NO x levels are low. Chemiluminescence analyzers can measure at ppb levels, but require that a cool‐dry extractive system be used to remove flue gas moisture. If there are high concentrations of NO₂ in the flue gas (which is sometimes the case in unit startups), there may be some absorption losses in the chiller. A dilution‐extractive system, which does not require the use of a chiller, could also be used in conjunction with chemiluminescence analyzers, especially when particulate concentrations are high. In‐situ NO x monitors may also be used at the inlet or outlet; however, care should be taken to assure that they can read low enough, especially at the outlet. The ability of an in‐situ NO x analyzer to measure accurately at low ppm levels (<5 ppm) should be determined before being considered as a monitoring option.

The inlet–outlet differential NO x technique was used in many applications before dedicated NH₃ analyzers became widely available. The technique is basically a “brute‐force” method taking advantage of existing technology. The problem is that by having to measure the NH₃ feed rate and two NO x concentrations, one increases the uncertainty of the end measurement, the ammonia slip. The two NO x analyzers may have different NO x convertor efficiencies, the zero and span drifts may vary, NH₃ may oxidize in the convertors, and so on. The NH₃ feed rate and volumetric flow rates have their own associated measurement uncertainties, which contribute to the overall uncertainty of the determination.

Extractive Differential NOx/NH₃ Converter Method

This method measures NH₃ downstream from an SCR, SNCR, or other NO x emission control unit. The analysis principle of this method is based on an extractive system differential NO x technique, where the flue gas stream is extracted and divided into two separate streams: one in which a catalyst is used to convert the NH₃ in the gas stream to NO and one where no catalyst is used (Figure 5‐28).

The NH₃ catalytic converter (consisting of precious metals such as platinum) can be located either in the probe (Top 2001) or outside of the stack, operating at about 700 °C and converting NH₃ to NO according to the following reaction:

The NO₂/NO converter outside of the stack, and before the moisture removal system, converts any NO₂ in the flue gas to NO to avoid wall losses of NO₂ due to absorption and because of its relatively high solubility in water, to prevent losses in the moisture removal system. The NO₂/NO converters can be placed either at the probe outlet or near the conditioning system and analyzer; however, a location near the probe is preferable if it is accessible and suitably protected from ambient environmental conditions. The ammonia slip, after the control equipment, is then given by the difference between the measurements made between the two legs of the sampling system, that is, between the total amount of the nitrogen compounds (NH₃ + NO x ) measured in the flue gas minus the amount of NO x present in the flue gas:

Figure 5‐28 NO x differential method.

(5‐21)

This method has been widely applied by Horiba in Japan, which by 2002 had installed over 200 systems in the power industry (Downey et al. 2002). However, the problem with the method is that if the ammonia concentration is low compared to the NO x concentration, by subtracting two relatively large numbers to obtain a smaller number, measurement accuracy may be compromised. It has been estimated than when the ratio

(5‐22)

the error in the NH₃ slip measurement will be greater than 5% (Marshak 2019). If the ratio is near 0.9, the error can be greater than 25%. Also, if two NO x analyzers are used instead of one, at low NH₃ levels, differences in calibration adjustments between the two NO/NO x analyzers may be greater than the ammonia concentration itself. The disparity might be minimized if only one analyzer is used, as illustrated in Figure 5‐28.

As an alternative, a dilution‐extractive system would eliminate the need to use a hot sample line, NO₂/NO converters, and hot sample cell. Using two out‐of‐stack dilution‐extractive boxes at the probe exit, the converted NO x sample and the unconverted sample could pass to the analyzers directly without having to remove flue gas moisture. The chemiluminescence analytical technique would be most appropriate here because of its ability to measure in the ppb range of the diluted sample concentrations. However, the use of two dilution boxes would introduce individual biases and errors associated with the dilution ratios of each box in addition to the biases and drift of the two analyzers.

Direct Ammonia Measurement Using Electro‐optical Methods

Ammonia absorbs light energy in both the ultraviolet and infrared spectral regions, and a variety of electro‐optical light absorption techniques have been developed for the direct measurement of ammonia over the past 50 years. In the ultraviolet region, this absorption is in the range from 190 to 230 nm. Sulfur dioxide also absorbs light in this region, so UV spectrometers operating here must select a region or multiple regions where interference is minimized or chemometric analysis can correct for it (Saltzman et al. 1989). In the near‐infrared region, absorption is principally at, 1450–1550 nm, 1900–2100 nm, and 2200–2400 nm.

A variety of techniques have been used to measure ammonia directly, ranging from nondispersive infrared photometry to Fourier‐transform infrared spectroscopy and wavelength‐modulated laser spectrometry. Newer techniques such as cavity ring‐down spectroscopy (CRDS) and off‐axis integrated cavity output spectrometry (ICOS), with the application of tunable diode lasers (TDLs) and quantum cascade lasers (QCLs), have led to a new generation of ammonia monitors that have greater sensitivities compared to some of the older techniques (Crabbe 2005).

Electro‐optical techniques that are used in commercially available ammonia analyzers are listed in Table 5‐2.

For source‐level extractive systems, analyzers based on any of the techniques listed in Table 5‐2 can be used to measure ammonia at levels of 1–10 ppm. If a dilution‐extractive system is used, the instrument should be capable of monitoring at ppb levels, which would require the use of a multipath sample cell, or a CRDS or ICOS analyzer.

ELECTROANALYTICAL METHODS

The instruments discussed in previous sections rely on spectroscopic, electro‐optical techniques to monitor gas concentrations. Another class of instruments based on electroanalytical methods of measurement has found great utility in source monitoring applications. Electroanalytical methods used in source monitoring include the techniques of polarography, potentiometry, and electrocatalysis.

Polarographic analyzers are relatively inexpensive and are portable being ideal for inspection applications. Potentiometric analyzers using ion‐selective electrodes have been successfully applied to measure hydrochloric acid (HCl) and hydrofluoric acid (HF). The electrocatalytic or high‐temperature fuel‐cell method, as it is often called, is used to monitor oxygen only. Both extractive and in‐situ monitors are available using this technique.

TABLE 5‐2 Electro‐Optical Techniques for the Direct Measurement of NH₃

UV Analyzer Techniques
IR Analyzer Techniques

Photometric – Differential Optical Absorption (DOAS)
Photometric (differential absorption):
Cavity ring‐down spectroscopy
Integrated cavity output spectroscopy
Wavelength‐modulated TDL/QCL

Gas filter correlation spectroscopy
Gas filter correlation spectroscopy

FTUV spectroscopy
FTIR spectroscopy

Photoacoustic spectroscopy

Polarographic Analyzers

Instruments have been developed that utilize the principles of polarography to monitor SO₂, NO, NO₂, CO, O₂, H₂S, Cl₂, HCN, NH₃, HCl, and many other gases. Polarographic analyzers (also called voltammetric analyzers or electrochemical transducers) select from a range of electrodes and electrolytes to provide this versatility.

The transducer in these instruments is usually a self‐contained electrochemical cell in which a chemical reaction with pollutant molecules takes place. Two basic techniques are used in the transducer: (i) a diffusion barrier (typically an orifice, capillary, or semipermeable membrane) allows the pollutant molecule to diffuse to an electrolytic solution, and (ii) the current change, produced at an electrode by oxidation or reduction of the gas at the electrode, is measured. For example, in a system designed to measure SO₂, the oxidation reaction that takes place is

where upper E 298 Superscript o Baseline equals 0.17 normal upper V is the half‐cell voltage potential.

Figure 5‐29 illustrates the operation of an SO₂ electrochemical transducer. The oxidation–reduction reaction occurs at the sensing electrode because the counter‐electrode material has a higher oxidation potential than that of the species being reacted. In the cell, the sensing electrode has a potential equal to that of the counter electrode minus the voltage drop across the resistor. The sensing electrode is electrocatalytic in nature and, being at a high oxidation potential, will lead to oxidation of the pollutant with a consequent release of electrons.

The reaction that takes place at the counter electrode is

where lead oxide (PbO₂) is converted into lead sulfate (PbSO₄).

The half‐cell potential of 1.68 V is greater than +0.17 V for the oxidation of SO₂ to sulfate (SO₄ ⁻²), so a net potential difference will develop. Similar oxidation–reduction reactions occur for different pollutants and electrode–electrolyte systems. Figure 5‐29 shows that the operation of these systems involves (i) diffusion of the pollutant gas through the diffusion barrier, (ii) dissolving of the gas molecules in the thin liquid film, (iii) diffusion of the gas through the thin liquid film to the sensing electrode, (iv) oxidation–reduction at the electrodes, (v) transfer of the charge to the counter‐electrode, and (vi) reaction at the counter‐electrode. The voltage drop across the resistor due to the current flow can be easily monitored and correlated to the pollutant concentration.

Figure 5‐29 Operation of an electrochemical transducer designed to measure SO₂ concentrations.

There are two reasons why this type of system may be termed as polarographic or voltammetric. In typical polarographic analyzers used in chemical laboratories, the electric current in the system is related to the rate of diffusion of the reacting species to the sensing electrode. It turns out that if the rate at which the reactant reaches the sensing electrode is diffusion controlled, the current will be directly proportional to the concentration of the reactant. This is known as Fick's law of diffusion:

(5‐23)i equals StartFraction italic n upper F upper A upper D c Over d EndFraction equals k c

where

i = current

n = number of exchanged electrons per mole of pollutant

A = exposed electrode surface area

F = Faraday constant (96 500 coulombs)

D = diffusion coefficient of the gas in the membrane and film

c = concentration of the gas dissolved in the electrolyte layer

d = thickness of the diffusion layer

k = constant

Fick's law is similarly used in laboratory polarographic analyzers.

The other reason why this type of system is called polarographic is that a retarding potential can be maintained across the electrodes of the system to prevent the oxidation of those species that are not as easily oxidized. The difference between the electrochemical transducers used for source monitoring and those used in the chemical laboratory is that in laboratory instruments, an external potential is applied to the system until the decomposition potential of a given species is reached and an oxidation–reduction reaction occurs. By varying the potential, both qualitative and quantitative information can be obtained about the composition of a solution.

The technique is temperature dependent, and any system, either permanent or portable, should be designed to maintain the cell at constant temperature. It is also extremely important that the sample gas be properly conditioned before entering the analyzer. Particulate matter and condensed stack gases will easily foul the cells, requiring the cells to be refurbished or replaced. When considering such analyzers for purchase, attention should be paid to the range specifications for each gas of the analyzers. The combustion analyzer ranges for the measurement of O₂ and CO₂ may be suitable; however, ranges for pollutant gases are often quite high unless low‐range sensors are requested. For example, a range of 0–2000 ppm for the measurement of SO₂, NO, or CO may not be useful for checking the performance of a CEM system installed on a gas turbine.

The cells themselves can come in a number of configurations, depending upon the manufacturer; see for example Figure 5‐30.

Analyzers using the cells tend to be small and portable compared to other source monitoring instruments. They are also relatively inexpensive. These two factors make them ideal inspection instruments or warning monitors. The so‐called “combustion analyzers” are widely available from over a dozen different instrument manufacturers for low‐cost combustion evaluation in small boilers and combustion systems. Simple electrochemical oxygen monitors used for detecting air in‐leakage in ducts and flues are also quite popular.

In addition to being used as an inspection tool, portable electrochemical analyzers can be used for regulatory testing purposes, including compliance testing (Coulson and McCarthy 2017; Juneau 1997; Juneau and McCarthy 1996). A protocol has been written by the U.S. EPA for the use of portable analyzers for testing reciprocal internal combustion engines (RICE). This is found in Appendix A of MACT standard ZZZZ in 40 CFR 63 (U.S. EPA 2020b). Other protocols, developed by the Institute of Clean Air Companies (ICAC), exist as EPA Conditional Test Methods OTM38 and OTM39 (U.S. EPA 2020c, d). These can be adopted by the states for their permitting programs (e.g. Oklahoma 2019). Also, a test method, written in conjunction with the Gas Research Institute, has been standardized by ASTM in ASTM D6522 for determining NO x , CO, and O₂ emissions from natural gas–fired reciprocating engines, combustion turbines, boilers, and process heaters (ASTM 2020).

Portable electrochemical analyzers can also be used to provide quarterly quality assurance checks on CEM systems that cannot accept calibration gases, such as certain integrated‐path in‐situ systems. They can also be used to perform monthly or quarterly reality checks on predictive emission monitoring (PEM) systems. When portable analyzers are calibrated against NIST protocol gases, traceability to NIST standards can be established for in‐situ or PEM system data. This is allowed by Environment Canada in its CEM Guidelines (ENVC 2005) according to the following alternative procedure for electrochemical analyzers meeting the requirements of EPS 1/RM/15 (ENVC 1990):

Calibrate the analyzer against Protocol gases in the field.

Sample at a point within 0.3 m from the sensing point of the CEM analyzer.

Sample a minimum of five minutes.

Check the low‐level calibration after the five minutes

Repeat at least six (6) times.

Check the high‐level drift.

Because only three comparison runs are performed, the relative accuracy for SO₂ and NO x Analyzers are given as specified to be ≤ 15% or 12 ppm absolute difference instead of ≤ 10% or 8 ppm for a nine‐run RATA.

The application of electrochemical analyzers in CEM systems on a long‐term basis is problematical. As with a battery, the chemicals in the cell will eventually be consumed and the cell will then have to be either refurbished or replaced. For 24 hr. operation in a permanent installation, replacement may be required every three to six months or less. This is a maintenance expense and requires careful attention by the instrument operator to note when degradation of the instrument performance begins to occur. It has been found that the cell lifetime can be increased by periodically cycling fresh air over the sensor. Here, two cells are needed; as one cell is being “refreshed,” the other will be measuring the flue gas sample until they switch.

Figure 5‐30 Construction of an electrochemical cell.

Electrochemical CEM systems have been applied for monitoring NO x at alcohol production facilities in the United States. However, O₂ electrochemical cells have been more widely applied in CEM systems installed in Kraft pulp mills. Here, they provide an economical means of correcting pollutant emissions data to 6% O₂, as required in Subpart BB of the Part 60 New Source Performance Standards (U.S. EPA 2020b).

Potentiometric Analyzers Using Ion‐Selective Electrodes

Potentiometric methods are used primarily to measure acid gases, where ion‐selective electrodes can determine the change of an ion concentration in a buffered chemical solution. The technique requires more attention compared to spectroscopic methods because of the recurring need to replace solutions and to maintain the analyzer plumbing. Although once popular in European countries, this method has, in the past, seen some application in the United States, particularly in ambient and source monitoring of HF at aluminum refineries.

In the potentiometric method, two electrodes are used to determine changes in the electromotive force of an electrolytic cell. One electrode serves as a reference electrode and the other serves as an ion‐selective electrode, sensitive to the ion of interest (such as Cl⁻ of F⁻). The reference electrode maintains a potential that is independent of the solution composition.

Various stratagems are employed to bring the sample gas into contact with the buffered absorber solution. The absorber solution can be atomized or injected into specially designed mixing chambers and then run continuously or cyclically past the electrodes. The potential difference across the electrodes will vary with the ion concentration (activity). Sample gas and absorbing solution flow rates are critical, as are requirements for maintaining a constant sample temperature and pH balance. One advantage of the method is that an analyzer can be calibrated or audited by injecting a standard solution rather than a calibration gas.

Electrocatalytic Analyzers for Measuring Oxygen

A method used for the determination of oxygen has been developed as an outgrowth of fuel‐cell technology. The so‐called fuel‐cell oxygen analyzers are not actually fuel cells, but simple electrolytic concentration cells that use a special solid catalytic electrolyte to aid in the flow of electrons. These analyzers are available in both extractive and in‐situ configurations. This versatility of design has made them popular for monitoring diluent oxygen concentrations in combustion sources as part of permanent CEM systems.

In this method, a ceramic material, zirconium oxide (ZrO₂), coated with a thin layer of platinum, serves as an electrolyte to allow the transfer of oxygen from one side of the cell to another (Figure 5‐31). In the cell, the oxygen concentration in the reference side is maintained at 21%. When sampling combustion gases, the oxygen concentration in the sample side will be less than that in the reference side (e.g. 3–6%).

When ZrO₂ is heated to >650 °C, oxygen ions can migrate through the material. The thin film of platinum will catalyze the process, allowing oxygen to hop through the structure as O–2 ions until they reach the other side. This hopping occurs because the zirconium ions form a relatively perfect crystal lattice in the material, whereas the O⁻² ions do not, resulting in vacancies in the structure. Heating the zirconium oxide allows the vacancies and O⁻² ions to move about. The oxygen ions migrate to the electrode on the sample side of the cell, release electrons to the electrode, and emerge as oxygen molecules.

Figure 5‐31 Operation of an electrocatalytic oxygen monitor.

This process continues until the concentration, or partial pressure, of oxygen becomes the same in both sides of the cell. In other words, the process continues until the chemical potentials become identical and the system comes into equilibrium. In practice, however, the sample side of the cell is continually flushed with new sample gas, not allowing the concentrations to become identical. As a result, a continual flow of electrons will occur across the resistor, as O⁻² ions continually move across the ZrO₂ in a vain attempt to establish equilibrium. The electromotive force (emf) of this process, expressed in terms of the oxygen partial pressures, is given by the Nernst equation as follows:

(5‐24)

where

R = ideal gas law constant

F = Faraday's constant

T = cell temperature

P ref(O₂) = partial pressure of O₂ in the reference side of the cell

P sample(O₂) = partial pressure of O₂ in the sample side of the cell

This emf can be measured. If the temperature is stabilized and the partial pressure of the oxygen on the reference side is known, the percentage of oxygen in the sample can be easily obtained. This phenomenon is used in some high‐temperature fuel cells, where oxygen in the sample side is kept at a low concentration by reacting it with some fuel. In this way, an electric current is produced directly by combustion, not by using a mechanical electric generator. However, this points out one problem with the method in gas analysis. When CO, hydrocarbons, or other combustible materials burn at the operating temperature of the device, this will lower the oxygen concentration in the sample cell and give readings lower than actual. However, in most combustion sources, such gases are present at ppm levels and will provide a negligible error compared to the concentrations of oxygen measured on a percent basis.

Paramagnetic Techniques for Measuring Oxygen

Molecules can be either attracted or slightly repelled by a magnetic field. When they are attracted, they are said to be paramagnetic in nature. When they are repelled, they are called diamagnetic. Most materials are diamagnetic, when placed in a magnetic field, but a few are paramagnetic. Paramagnetism arises when a molecule contains unpaired electrons. Most materials will have paired electrons (one electron spinning in a clockwise direction for every one spinning in a counterclockwise direction) and therefore will be diamagnetic. Oxygen molecules, however, are paramagnetic, having two unpaired electrons that spin in the same direction to give the molecules a permanent magnetic moment. When an oxygen molecule is placed near a magnetic field, the molecule is drawn to the field and the magnetic moments of the electrons become aligned with it. This striking phenomenon was first discovered by Faraday and forms the basis of the paramagnetic method for measuring oxygen concentrations.

The commercial paramagnetic analyzers are used only in conjunction with extractive systems. Water and particulate matter should be removed before the sample enters the monitoring system. It should be noted that NO and NO₂ are also paramagnetic and may cause some interference in the instrument if high concentrations are present.

There are three measurement techniques based on this phenomenon:(i) magnetodynamic (ii), thermomagnetic, and (iii) magnetopneumatic.

Magnetodynamic Instruments

The magnetodynamic method is based on the effect that oxygen will have on modifying the magnetic field in the vicinity of a permanent magnet. A specially constructed torsion balance, forming a “dumbbell” with diamagnetic glass spheres, is suspended in a nonuniform magnetic field (Figure 5‐32).

The dumbbell spheres, being slightly diamagnetic, are pushed away from the most intense part of the magnetic field. When the gas surrounding the dumbbells contains oxygen, the spheres are pushed further out of the field due to the change in the field caused by the paramagnetic oxygen.

The system is first set up without sample gas so that light will reflect off of a small mirror onto a photocell. In a feedback loop, a current is sent through a platinum wire that encircles the dumbbell to create a counter electromagnetic torque. This torque restores the mirror position so that the photocell will again detect the reflected light. The amount of restoration necessary (current through the wire), when oxygen is present, is related to the oxygen concentration.

The glass dumbbell systems are manually constructed in an expensive labor‐intensive process. In 2017, a silicon microsensor was developed by the company ABB to advance the technology where sensors can be manufactured efficiently and reproducibly (Harrison 2019a,b). Through semiconductor‐based production methods, multiple sensors are manufactured on silicon wafers from which they are extracted and automatically positioned onto the torsion balances. These “microwing” sensors are stated to have more resistance to the effects of moisture and acid gases than the traditional glass dumbbells.

Figure 5‐32 Operation of a magnetodynamic oxygen analyzer.

Thermomagnetic Instruments

Analyzers employing the thermomagnetic method are frequently termed “magnetic wind” instruments. They are based on the principle that the paramagnetic attraction of an oxygen molecule decreases as its temperature increases. A typical analyzer utilizes a cross‐tube type arrangement with a heated filament wire (Figure 5‐33).

A strong magnetic field covers one half of the coil. Oxygen contained in the sample gas will be attracted to the applied magnetic field and enter the cross tube. The oxygen then heats up and its paramagnetic susceptibility is reduced. The heated oxygen will then be pushed out by the colder gas just entering the cross tube. A flow of gas, or “wind,” therefore continuously passes through the cross tube. This gas flow effectively cools the following section of the heated coil and changes its resistance. The change in resistance can then be detected in a typical Wheatstone bridge circuit and be related to the oxygen concentration.

Several problems can arise in the thermomagnetic method. The cross‐tube filament temperature can be affected by changes in the thermal conductivity of the carrier gas. The gas composition should be relatively stable if consistent results are desired. Also, burned hydrocarbons or other combustible materials may react on the heated filaments and change their resistance.

Figure 5‐33 Operation of a thermomagnetic oxygen analyzer.

Magnetopneumatic Instruments

In the magnetopneumatic method (also called paramagnetic pressure or the “Quincke analyzer”), oxygen is again attracted to a magnetic field (Figure 5‐34). In this system, the sample runs through a flat cell and reference gas (nitrogen) flows at an equal rate through the channeling tubes. If oxygen is present in the sample, it is attracted to a pulsed magnetic field, creating a pressure imbalance in the flow. The resultant pressure pulse is detected by a micro‐flow sensor.

Thermal Conductivity Analyzers

Thermal conductivity analyzers operate based on the principle that different gases will conduct heat differently. When a sample gas flows over a heated wire, the wire will be cooled and the resistance of the wire will change accordingly. If the composition of the sample gas changes, the cooling rate and the resistance of the wire will change to give an indication of the gas composition. A simple circuit, such as a Wheatstone bridge, is generally used to detect the resistance changes in the heated wire.

Figure 5‐34 Operation of a magnetopneumatic oxygen analyzer.

Thermal conductivity analyzers have been used to monitor CO₂, SO₂, and other gases in process gas streams. A disadvantage is the flow of reference gas must always be maintained. Changes in the composition of the gas stream other than those due to changes in the pollutant level will interfere in the measurement. In such cases, scrubbing systems or other techniques will be necessary to obtain accurate data.

DEVELOPMENTS IN EXTRACTIVE SYSTEM GAS ANALYZERS

The science and technology of gas analysis is not static, but is continually evolving. Instrument manufacturers develop new techniques with the goal of capturing some segment of the monitoring market. CEM system vendors apply existing techniques and newly developed technologies in the hope of gaining a market advantage. These efforts are frequently not successful, because of technical problems, high cost, or the reluctance of CEM system users to try something new.

In this competitive field, CEM system integrators and instrument manufacturers often seek to develop alternatives to traditional approaches (Walker 1996). This has led to a number of analytical options, which are categorized in Figure 5‐35.

Traditional Approaches

The traditional approach to integrating CEM systems is to use either discrete analyzers or multi‐gas analyzers, such as FTIR or GFC instrument. External and internal multi‐gas modular analyzers utilize the analytical system of discrete analyzers and repackage them using a single set of electronics instead of multiple sets associated with using discrete analyzers.

Discrete Analyzers

In the typical extractive system, the flue gas is customarily directed to discrete analytical “boxes”: one box purchased for each gas monitored. Each box incorporates a sensor or analytical system, an electronics package, and, often, a pump and gas distribution system. If four or five gases are to be monitored, many subsystems are duplicated unnecessarily.

The use of multiple discrete analyzers offers several advantages for ongoing system performance. If one analyzer fails, others should still function to maintain availability for at least part of the system. Discrete analyzer systems are also readily maintained since analyzer malfunctions are compartmentalized. A malfunction, in most cases, can be identified easily and analyzer repairs can be performed without affecting the rest of the functioning CEM system. Also, when a particular analytical method or analyzer fails, a unit precertified for the system can be substituted relatively easily.

CEM system integrators favored this approach in the past since it afforded them to use either the “best” instruments for a given application or to bargain for the best price from the instrument manufacturers. The approach was used in both source‐level extractive systems and dilution systems.

Figure 5‐35 Multicomponent gas analysis – analytical packaging options.

As a box that fits into an instrument rack, extractive system analyzers are the same as those existed 30 years ago, outside of changes to the front panel, where touchscreen displays have since replaced switches, potentiometers, and other controls seen on older analyzers. Inside, however, lamps have been replaced by LEDs and TDLs; circuit board electronics have decreased in size and number. It is certainly possible to reduce the size of gas analyzers, but with the space available at most industrial facilities, there is often little reason to reengineer the instruments when a monitoring market is limited to the sale of only a few thousand units a year.

Multi‐gas Analyzers

A competing approach has been to employ analytical techniques that can measure more than one gas at a time, thus limiting the subsystem duplication. However, greater complexity of multi‐gas analytical techniques has, in general, counterbalanced any cost advantage to overall system simplification. This approach has been most frequently employed in in‐situ systems, using gas filter correlation or differential absorption spectroscopic methods for analysis. With the recent interest in monitoring air toxic compounds, laboratory techniques such as photoacoustic spectroscopy, Fourier‐transform infrared (FTIR) spectroscopy, and gas chromatography have seen increasing applications in this area.

An advantage with multi‐gas systems is that in case of system malfunction, it is only necessary to deal with one analytical system. It is not necessary to become familiar with different analyzers or to maintain multiple sets of replacement parts. They can gain a cost advantage by reducing the number of system components. However, if the monitor fails, monitoring for all gases will be lost, with the subsequent loss of availability.

The analytical techniques employed in multi‐gas analyzers tend to be unique to the manufacturer and its distinctive advantages are emphasized in the manufacturer's marketing efforts. Multi‐gas extractive analyzers are generic in application and can be readily incorporated into sampling platforms designed by CEM system integrators.

Multi‐gas Modular Approaches – External

One of the first techniques used to reduce the cost of CEM systems was to eliminate redundant analyzer electronic systems by using a single microprocessor system or computer. This approach separates the optical benches for the gas analysis from the electronic linearization and control circuits. The actual linearization and control is performed in the CEM system computer or microprocessor, which further reduces costs associated with the analyzer electronics (Mandel and Gottlieb 1995).

This approach to develop a modular system takes the sensing elements out of the analyzer boxes and repackages them in another box to achieve cost reduction, which shows the beginning of evolution of “sensor‐based” systems. The sensing element may be an optical bench, a zirconium oxide sensor, or electrochemical cell, depending upon the gas being measured. By separating these “elements” from the traditional analyzer box, a “plug‐and‐play” approach can be taken to building up a monitoring system.

Multi‐gas Modular Approaches – Internal

Another modular approach employs the traditional analyzer chassis, but redesigns it so that it can accept discrete, multiple, and interchangeable sensors. This approach has been used extensively in the so‐called “combustion analyzers” that incorporate electrochemical cells. The approach has also been followed in electro‐optical analyzers, where multiple electro‐optical and other sensors, employed traditionally in discrete analyzers are incorporated into single‐rack‐mounted multi‐gas instruments. As with the external modular system, a single electronics control package serves all the sensors. The multi‐gas modular chassis offer a greater degree of compactness than can be realized for an assembly of discrete analyzers or the assembly of microprocessor‐linked optical benches. Typically, two to five different gases can be monitored by the single analyzer, minimizing instrument rack space.

European and Japanese companies were the first to adopt this approach and have a wide variety of products available. U.S. companies have since followed this lead.

Developing Approaches

The trend in analytical system design has been to reduce both the size of gas sensors and the analytical system. Systems for monitoring gases and particles in ambient air and in workplaces, as well as for monitoring chemical warfare agents for homeland and military security, have benefited from these developments. Handheld commercial analyzers are available today for monitoring particulate matter and pollutant gases in the home, across fence lines, or in the air from drones.

Analyzer miniaturization began over 25 years ago, and significant advances have been made. The approach was first to miniaturize existing technologies, by just making things smaller. This approach changed by applying techniques established in the semiconductor industry by micromachining both sensors and analyzers. Semiconductor fabrication techniques might include the deposition of an array of sensors on a chip, the assembly of micromachined optical components on a chip, or micromachining a serpentine coil in a silicon chip rather than coiling tubing for a gas chromatographic column. The ABB “microwing” paramagnetic oxygen sensor, machined from a silicon wafer, is the first successful application of this approach in source monitoring. Trends in CEM analytical systems are illustrated in Figure 5‐36.

Figure 5‐36 Projected evolution of CEM analytical systems.

Miniaturized Sensors/Analyzers

The term “miniature” is somewhat relative. A miniature analyzer is one that can be handheld and transported, but maintains the same precision and accuracy specifications as a laboratory analyzer or a rack‐mounted process instrument. Today, miniature optical spectrometers, gas chromatographs, and ion‐mobility spectrometers are commercially available. In analyzers, miniaturization also involves using smaller components and microprocessors that can combine the functions of several circuit boards in addition to the use of a smaller sensor. The advantage is that the analyzer will take less power, generate less heat, and require less sample. For gas‐fired combustion sources, it may be possible to use miniature devices as an alternative to gas chromatography for determining fuel gas composition and Btu content. Advanced miniature FTIR analyzers could readily be applied on municipal waste combustors and in the petrochemical industry.

The basic work of miniaturization is typically done in university, government, or industrial laboratories. The degree of practicality increases from the university to industrial laboratories; however, most promising methods typically are introduced into the marketplace by entrepreneurs from the laboratory where the idea was originally conceived. These entrepreneurs may be a government laboratory scientist or university professor who develop the techniques and collaborate with commercial business partners. Their startup companies are funded by Small Business Innovative Research Grants (SBIRs), other government contracts, or private investors, until they become self‐sustaining, fail, or are purchased by a larger company.

Microtechnology

Silicon micro‐fabrication techniques have advanced to the point where sensors integrated with the electronics necessary to control them can be manufactured on a single chip. The resultant mico‐electromechanical systems (MEMS) have progressed to the point where spectrometers can now be manufactured on a semiconductor chip. The preparation of microsensors often requires research developments where individual components are micromachined, or metal oxides or other coating materials are deposited by programmed techniques. This process often results in change in the fundamental design, or architecture, of the analytical method from which it was derived. There exists significant potential to apply the results of these programs to CEM systems (Jahnke 1997; Jahnke and Evans 2005).

Economies of scale, promoted in the manufacture of microelectromechanical sensors and systems, may apply to the use of microtechnology for the military or homeland security, but do not necessarily apply to their application in CEM systems. “Scale” in the semiconductor industry is counted in terms of tens of thousands of units, which are at a level that would be difficult for the limited CEM market to reach.

Miniaturizing the CEM Systems

The incorporation of microsensors and/or miniature analyzers into a CEM system is largely irrelevant if traditional sampling systems are used to transport sample gas to sensors. In traditional CEM systems, space is not always an issue. The space occupied by the sensor, or even the analyzers, is relatively less than a sampling system, which includes valves, filters, pumps, and gauges. Gas must still be transported to the analyzer and without advances in sampling systems, little advantage is gained in miniaturizing the sensing system.

However, the New Sampling System Initiative (NeSSI™) discussed in Chapter 3 can be a key factor in the application of microtechnology (see Figure 3‐28a–c). The NeSSI™ sampling platforms provide a means for incorporating microsensors into either a process monitoring or a continuous emission monitoring system (Aquino 2003; Chon 2004). This has already been done for multiple monitoring systems installed at petroleum refineries to speciate organic compounds under the Houston/Galveston area HRVOC (highly reactive volatile organic compound) trading program (Gilmer et al. 2003).

Application

Miniature and microsystems are largely applied in pharmaceutical, chemical, petrochemical, and petroleum refining industries. They are widely applied as process monitors, where their purpose is to optimize process operations rather than reporting emissions. There are lower risks applying new technologies in process instrumentation, where costs of implementation, or even failure, may be justified as an attempt to improve plant efficiencies. With environmental monitors, the cost of failure cannot be justified in this manner and regulatory penalties can ensue in addition, so risks are consequently higher. Case‐by‐case evaluation is required to find whether such systems can meet daily calibration drift, relative accuracy tests, and other criteria of Part 60, 63, and 75. At this point, traditional systems are considered to provide fewer risks for monitoring and reporting flue gas emissions to meet environmental regulations.

In the world of CEM systems, it generally takes 10–20 years before a new technology is accepted, unless it can fill an immediate regulatory need. Instead, CEM system developments tend to focus on incremental improvements in packaging (such as analog to digital systems and internet ready communications) rather than modifications to the underlying analytical architecture. However, if low‐cost sensors and analyzers become readily available from the developing consumer market, there exists room for entrepreneurial efforts to seek innovative applications. Low‐cost miniature analyzers could allow for multiple measurements in stratified stacks or ducts or “like‐kind” replacement throw‐away analyzers. Lower‐cost miniature analytical systems could also allow for monitoring more parameters, at more locations, for optimizing process operations or validating the data quality of traditional CEM systems. The use of miniature analyzers on unmanned aerial vehicles also has considerable potential although standard procedures and validation methods need to be established in this application to assess uncertainties associated with such measurements.

REFERENCES

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CHAPTER 6
IN‐SITU GAS MONITORING SYSTEMS

Problems with extractive monitoring systems have led to the development of monitors that can directly measure source‐level gas concentrations in a stack. These so‐called “in‐situ” systems do not modify the flue gas composition and are designed to detect gas concentrations in the presence of particulate matter. In‐situ units are constructed to withstand environmental conditions at stack locations and have fewer subsystems than do extractive systems. In‐situ measurements can be made either over an integrated path across the stack or at a point within the stack, leading to two types of commercial designs: “integrated‐path” and “point” in‐situ systems – point monitors are also referred to as in‐stack or short‐path monitors and the integrated‐path monitors are also called cross‐stack monitors. As the terminology implies, point monitors measure essentially at point in the stack, whereas integrated‐path monitors measure the flue gas over a path extending from one side of the stack to the other.

In‐situ systems were developed in the late 1970s and were installed widely in electrical utilities and industrial sources. Although the systems performed relatively well at high concentrations, problems were found in measuring lower gas concentrations resulting from increasingly stringent emission control programs. Also, quality assurance requirements were established in the 1980s in the United States, specifying that quarterly assurance audits using certified gases are to be performed on CEM systems used for compliance monitoring (U.S. EPA 2020d). Since most integrated‐path in‐situ gas monitors could not provide a straightforward means to conduct these checks, they rapidly lost popularity. Problems with instrument drift, temperature and pressure compensation, and vendor service gradually eroded confidence in in‐situ measurement methods in the United States.

In the 1990s, European advances in electro‐optical design calibration procedures overcome a number of the earlier limitations. As a result, both point and integrated‐path monitors were reintroduced into the United States and began to be applied in Canada as well as in Europe and Asia. Because point in‐situ monitors can be checked readily with calibration gases, they became the preferred option for in‐situ monitoring, leading to the retirement of many integrated‐path (cross‐stack) designs.

The application of newer technologies now offers a wider range of in‐situ analyzers. In particular, tunable diode lasers have extended the list of gases that can be monitored in‐situ. More recently, integrated‐path systems have seen a revival in the United States due to the implementation of HCl monitoring requirements for U.S. coal‐fired electric generating units in the MATS rule (U.S. EPA 2020f). Several vendors have designed cross‐stack monitors using tunable diode lasers to monitor HCl or NH₃. To certify these systems, Performance Specification 18 was added to Appendix B of Part 60 (U.S. EPA 2020a, b). In addition, quality assurance Procedure 6 was added to Appendix F to address specific design and calibration issues associated with these systems (U.S. EPA 2020c).

The cross‐stack, or “integrated‐path” monitors (as termed by EPA in subsequent rulemaking), avoid sample loss problems associated with corrosive, condensable gases such as HCl, SO₃, and NH₃. By minimizing the corrosion and sample loss problems associated with extractive systems, in‐situ monitors offer significant advantages when monitoring reactive and condensable gases. They have also proven useful in process applications, particularly for controlling the addition of reagents, measuring ammonia slip after NOx emissions control systems. The terminology, techniques, and applications of these systems are discussed in this chapter.

POINT (SHORT‐PATH) IN‐SITU MONITORS

Point (short‐path) in‐situ monitors perform measurements at a single point in the stack, as do simple extractive system probes. Point in‐situ analyzers offer a means of measurement that is, in some respects, a compromise between extractive systems and the path monitoring technique. In a point in‐situ system, the measurement is made at a point or a path that is short relative to the diameter of the stack or duct so the length and placement of the probe must be considered, especially if gas concentrations are stratified in the stack (Figure 6‐1).

The “point” may extend over a few centimeters to 1 meter, or even longer, when low gas concentrations are to be measured. A more appropriate term for these systems would be “short‐path” rather than point monitors. There is always a practical limit for their length due to the mass of the probe and the possibility of the probe sagging in the hot flue gas.

Point in‐stack probes are more popular than integrated‐path systems because (i) they require only one port instead of two for installation, (ii) they avoid alignment issues associated with integrated‐path monitors, and (iii) the probes are amenable to calibration checks and audits using certified calibration gases. To address requirements for conducting cylinder gas audits, manufacturers of integrated‐path instruments will sometimes redesign them as point monitors by attaching a probe at the end of the path monitor transceiver. Point monitors have had many successful applications, particularly for measuring SO₂, NO, and O₂ in combustion sources.

Figure 6‐1 Point in‐situ CEM monitor.

Probe Designs

Various probes have been developed for point (short‐path) measurements, some of which are illustrated in Figure 6‐2. Figure 6‐2a shows an optical system common to most in‐situ probes. The instrument light beam passes through a protective window to the retroreflector and then back through the window to the detector in the transceiver. The measurement is made over the light path. Figure 6‐2b shows a slotted tube, allowing for the free passage of gas through the probe and a support for the retroreflector. For UV monitors having sufficient light levels, particulate matter may not have to be filtered, but the slotted tube complicates using calibration gas to verify the monitor calibration over the measurement path, when conducting cylinder gas audits.

The measurement path can be protected from particulate matter and/or water droplets by a ceramic or sintered metal filter (typically stainless steel or Hastelloy filter). Because particulate matter and water droplets will scatter light, a filter will help to reduce light transmission losses. An enclosing filter also allows for the direct injection of calibration gas to flush out flue gas for a calibration check or audit. The calibration gas line shown in Figure 6‐2a illustrates the most common method of injecting zero air and calibration gases into such systems.

Various approaches have been taken in designing filtered in‐situ probes. For short light paths, a ceramic thimble can be used to cover the optical system (Figure 6‐2c). For longer paths, a ceramic or sintered metal tube can be used (Figure 6‐2d) or the slots of a slotted tube can be covered by welding them over with a sintered metal plate (Figure 6‐2e). Another design uses stainless steel filter ports mounted on the probe tube (Figure 6‐2f).

For system calibrations or audits, for the filtered probes, calibration gas is injected into the cavity at a slightly higher pressure than the stack pressure to avoid diffusion of the flue gas back into the cell. This procedure is identical to probe calibrations conducted on extractive systems where the probe can be flushed with calibration gas. The gas is often heated by first passing it through a coil of tubing inside the probe or by using an auxiliary heater. Heating the calibration gas avoids cooling the measurement cavity, optical surfaces, or other components (Figure 6‐3). Because in‐situ measurements are dependent upon the temperature and absolute pressure of the sample gas, it is important that these parameters remain consistent between sampling and calibration, or are otherwise compensated.

In some situations, the filter may become “blinded” with particulate matter or coated with salts from a malfunctioning scrubber. The instrument may be “forced” to read zero and calibration gas values correctly if sufficient pressure is applied. However, if it takes an extended period of time for the system to come back to the stack value, the problem should become evident and the filter should then be replaced or cleaned. It should be noted that in the filtered probes, the gas diffuses (permeates) through the porous probe material; it is not sucked in as in an extractive system. As a consequence, particles are more likely to bypass the probe than be vacuumed into the probe and probe plugging may be minimal. For plugging problems, a deflection plate may be attached to minimize the direct impingement of the particles onto the filter. In the case of water droplet problems, a heater can be incorporated into the probe to vaporize any liquid entering the measurement cell.

Figure 6‐2 In‐situ point monitor probe configurations. (a) In‐situ probe optical system. (b) Open slotted tube. (c) Ceramic filter. (d) Ceramic or sintered metal tube. (e) Welded sintered metal filter. (f) Filter ports.

Both spectroscopic and electroanalytical techniques have been applied in point monitors. UV differential absorption, gas filter correlation IR, and second‐derivative (wavelength modulation) methods are the most common electro‐optical techniques used in short‐path in‐situ monitors. The most common electroanalytical technique is the zirconium‐oxide fuel‐cell method used for measuring O₂ (Chapter 5).

Point Monitor Analytical Methods

Differential Absorption

Simple point in‐situ differential absorption instruments can be constructed by attaching the retroreflector to the end of a probe, rather than placing it on the other side of the stack. In the Procal UV differential absorption instrument shown in Figure 6‐4, the retroreflector is protected by a sintered filter, which allows the flue gas to diffuse through it, but stops particulate matter from entering the measuring cavity.

Figure 6‐3 Performance check of an in‐situ point monitor using calibration gas.

UV light is projected down the probe through a protective window into the actual measurement cavity, which is approximately a half a meter in length. Light energy is consequently absorbed by the flue gas that has diffused through the filter into the cavity and is returned by the retroreflector to a diffraction grating, which splits the light onto a diode array. In this system, the diode array measures the relative absorption of flue gases in the measurement path. Gases such as NO, NO₂, SO₂, NH₃, and H₂S can be monitored, in principle, with this instrument. Zero gas or calibration gas can be sent into the cavity to purge the flue gas during a daily calibration check or a cylinder gas audit.

Figure 6‐4 Procal UV differential absorption point in‐situ monitor.

Figure 6‐5 Sick, Inc. point in‐situ monitor.

A similar instrument that uses a diffraction grating and diode‐array detector to distinguish between different light wavelengths is marketed by Sick, Inc. as the GM32 analyzer and is illustrated in Figure 6‐5 (Sick 2016; Exford 1997; Scholz and Gilmour 1993). In this instrument, a photo‐diode array is again used to measure SO₂ and NO. NO₂, NH₃, H₂S, and mercaptans can also be measured. In the instrument, a deuterium lamp projects ultraviolet light to a retroreflector in the measurement cavity. The beam is reflected back through a series of mirrors to a beam splitter, diffraction grating, and a silicon‐based photo‐diode array. Light absorption in the UV region from 200 to 250 nm is used for the measurements. A zero mirror can flip into the light path to obtain a zero condition and a calibration shutter containing reference filters and a gas cell filled with NO is used for internal calibration.

The optical configuration of this transceiver has also been made available in a cross‐stack version of the monitor. An earlier cross‐stack model, the Sick Optic GM30, was installed in a number of coal‐fired power plants in Alberta, Canada, in the 1990s. The GM30 instrument incorporated an adjustable mirror controlled by servo motors, to assure proper beam alignment between the retroreflector on the other side of the stack and the detector in the transceiver.

To conduct a cylinder gas audit in the point in‐stack version, it is necessary to use a gas permeable probe (GPP) probe, with a ceramic filter tube (as shown in Figure 6‐5) to flush out the flue gas for zero and upscale gas measurements. Here, the calibration gas flow rate should be greater than the flue gas diffusion rate into the probe. A slotted tube probe option is also available for this instrument, but does not provide the capability for conducting a cylinder gas audit.

Gas Filter Correlation Methods

The gas filter correlation technique has been applied by Procal in an infrared analyzer developed to monitor up to eight different gases, which include CO, NO, SO₂, NO₂, CO₂, and H₂O (Hutchinson 1998) (Figure 6‐6). Both gas filters and interference filters are used in the instrument – gas filters in the gas filter correlation mode and interference filters in the differential absorption mode of operation. The filters are placed on a rotating wheel, and the IR light passes through them sequentially to the retroreflector at the end of the probe. The light returns back to the transceiver, which contains the detector. A calibration port allows the injection of zero and calibration gases into the measurement cavity between the focusing lens and retroreflector.

Codel also manufactures a gas filter instrument similar to the Procal analyzer (Figure 6‐7). By using a mix of optical and gas filters, it can measure up to seven different gases using a filter wheel spinning at one revolution per second. Each gas filter filters out light emitted from the IR source at the wavelengths where the target gas absorbs but not where the background gases absorb. A nitrogen cell measures the total absorbance (background plus target gas), from which the difference in absorbance between the background and total absorbance is used to determine the target gas concentration. SO₂, CO, NOx, and CH₄ are measured over a relatively high range of 0–3000 and 0–1000 ppm for HCl with a stated accuracy of ±2% or 5 ppm. O₂, CO₂, and H₂O are measured at the normal percent levels. The instrument also provides for stack temperature and pressure measurements. The instrument can be zeroed, audited, or calibrated with cylinder gases by purging the probe with the appropriate gas. The inlet gas line is coiled on the probe to pre‐heat the calibration gas to stack temperature before purging the flue gas. The gas enters the probe through diffusion ports similar to those shown in Figure 6‐2f.

Figure 6‐6 Procal GFC point in‐situ monitor.

Intended for greenhouse gas control for industrial processes, Sick, Inc. designed an instrument to measure CO₂, H₂O, and CO or N₂O, the GM35 monitor (Sick 2015). N₂O and CO are measured by gas filter correlation and CO₂ and H₂O by differential absorption. The instrument design is shown in Figure 6‐8.

In the transceiver, infrared light from the lamp is reflected to pass through a half‐silvered mirror and through the probe (or across the duct or stack in a cross‐stack model) to the retroreflector. The light returns to the transceiver where the half‐silvered mirror now reflects it down to a mirror that directs it to another half‐silvered mirror at the bottom of the assembly. This mirror splits the light between two rotating wheel/detector assemblies. The light that is transmitted through the bottom half‐silvered mirror passes to a CO₂/H₂O optical filter wheel and detector. The rotating filter wheel contains four optical filters, one at a wavenumber of 1800 cm⁻¹ for absorption by H₂O, one with a wavenumber of 2000 cm⁻¹ for absorption by CO₂, and two reference filters, one of 1600 cm⁻¹ and the other of 2200 cm⁻¹. The CO₂ and H₂O concentrations are determined by the differential absorption technique when these filters are rotated through the light beam.

Figure 6‐7 Codel single‐pass gas filter correlation monitor.

Figure 6‐8 Sick, Inc. GM35 greenhouse gas monitor.

The light that is reflected from the bottom half‐silvered mirror passes to the gas filter correlation wheel containing two gas cells, one filled with nitrogen and the other with either CO or N₂O. CO or N₂O are determined by gas filter correlation. When a CO gas cell is used, the difference between light absorption by CO in the flue gas to 100% absorption by CO in the gas cell determines the CO concentration. The instrument can be configured to measure either CO or N₂O, but not both.

The instrument undergoes an automatic zero and reference check similarly to the Sick GM 32 SO₂/NO analyzer discussed earlier (see Figure 6‐5). Here, in a similar manner, a calibration shutter pivots into place after the zero mirror swivels into place to block transmission into the stack and reflect the light beam back into the instrument. A reference gas cell contained in the shutter is used to check the instrument operational stability.

Electrocatalytic In‐situ Method

Successful non‐electro‐optical in‐situ point monitors incorporate zirconium oxide oxygen sensors. The ZrO₂ electrocatalytic technique has already been discussed with respect to its application in extractive systems; however, the technique's greatest popularity has been in its application to in‐situ measurements. The method is used extensively for boiler control and monitoring.

The probe configuration of an in‐situ zirconium oxide O₂ analyzer is shown in Figure 6‐9. Here, the zirconium oxide solid electrolyte separates the sample gas from reference gas. A heater surrounds the measurement cell to maintain a constant temperature of typically 650 °C (or greater), which enables zirconium oxide to serve as a conduit for oxygen. The standard point in‐situ features, ceramic filter, and probe calibration are also incorporated in this system.

The zirconium oxide in‐situ analyzer has shown remarkable success in flue gas monitoring. Two factors contributing to this success are (i) the stability of ZrO₂ and (ii) its ability to operate at elevated temperatures. The system was initially developed by a division of Westinghouse (then Rosemount, now Emerson Process Management) and has been widely copied by other manufacturers. Today, the performance of the commercially available in‐situ O₂ analyzers depends on experience and quality control capabilities of the manufacturer, rather than on the method itself.

Figure 6‐9 Probe configuration of a zirconium oxide in‐situ point monitor for the measurement of O2.

Advantages and Limitations of Point In‐situ Systems

The idea of purchasing a box that can sit on a stack and deliver emissions data to the control room with just an electrical cable is very attractive to a plant operator. Monitoring emissions without the necessity of conditioning the flue gas led to the original development of in‐situ systems. In proper applications, O₂, NO, and SO₂ can be reliably measured with point in‐situ systems.

Point in‐situ systems may, however, experience problems in extreme stack or duct environments. Because the instrumentation is stack or duct mounted, the environment at the mounting location is very important. When stack or duct vibration is present, point in‐situ monitors may have problems in operating, particularly electro‐optical systems. Vibration can loosen or misalign optical components (as with integrated‐path in‐situ systems) and can loosen circuit boards and electronic components. For long probes, vibrations combined with varying flue gas velocities may cause oscillations in the probe itself and lead to cracks or other structural damage.

High ambient temperatures or widely fluctuating temperatures can also affect stack‐mounted electronics and optics. Acid gas in the ambient air can affect poorly constructed instrument housings, and condensed acid gases in the flue gas can rapidly corrode the sensing probes. The use of corrosion‐resistant alloys may be necessary in some applications. Lightning can be another factor. Improperly insulated or otherwise unprotected stack monitors can serve as lightning rods and are known to cause destruction to both CEM system analyzers and computers.

Particulate matter may be a problem in other situations. Sintered steel and ceramic filters do help in reducing the level of particulate matter entering the measuring cavity of a point monitor. However, submicron‐sized particles may still enter. The system must be able to compensate for such a problem (as most do). If the filter becomes plugged with particulate matter or condensed materials, the flue gas will no longer diffuse into the cavity. This problem should become evident in cylinder gas audits when purging the probe with calibration gases. However, if daily calibration verifications are performed using an internal gas cell or cuvette, the daily zero and calibration may still pass without indicating a problem. If probe plugging occurs frequently, the maintenance time required to clean or replace the filter may become excessive. Although blow‐back systems have been applied in some cases, they have not always been successful for ceramic thimbles. Deflection plates or deflector sheaths are commonly used to reduce the impaction of particulate matter onto the filter.

It must also be noted that measurements are conducted at stack temperature and stack pressure. To calculate emissions with reference to standard conditions (20 °C and 1 atm), stack temperature and pressure must be known. In most cases, an assumed value for stack pressure is used; however, stack temperature is a significant factor in performing a correction to stack conditions. For this reason, most point in‐situ systems also incorporate a temperature sensor. A malfunctioning thermocouple or thermistor can affect the corrected readings. Because temperature readings are generally not checked during calibration or an audit, discrepancies between audit gas measurements and emission measurements may, in some cases, be due to malfunctioning temperature compensation systems (McGowan and Karpinski 1995; Peeler 1981).

The capability of performing a cylinder gas probe calibration verification is a significant feature of point in‐situ analyzers. By injecting audit gas directly into the measurement cavity, the instrument performance can be assessed, which cannot always be made with integrated‐path monitors. If daily calibration verifications with cylinder gases are not required by regulation, as in Europe, time spent in inspection/maintenance activities is reduced accordingly.

INTEGRATED‐PATH MONITORING SYSTEMS

Integrated‐path (IP) in‐situ systems measure over a distance in a stack or duct that is usually equivalent to the internal stack diameter They are alternatively called “path” or “cross‐stack” monitors. In some cases, a pipe may be used for support or calibration purposes and may cut off part of the measurement path. Integrated‐path monitors use electro‐optical techniques, where light is transmitted across the stack to a detector, in “single‐pass” systems or “double‐pass” systems. Light energy is absorbed by target molecules at their signature wavelengths as light passes through the flue gas in its transit to the detector.

Single‐Pass Systems

Single‐pass systems locate a transmitter and a detector on opposite ends of the duct or stack (Figure 6‐10). Because light is transmitted through the flue gas only once, these systems are termed single pass. (Note: in remote‐sensing terminology, this arrangement is referred to as “bistatic” (Vaughan 1991).) Single‐pass in‐situ systems are used for the measurement of gas concentrations, flue gas velocity and opacity (velocity and opacity monitoring instruments are discussed in the following chapters).

Double‐Pass Systems

Double‐pass systems locate both the transmitter and detector on one end of the duct or stack (Figure 6‐11). To do this, a light beam is folded back on itself using a retroreflector. The light beam traverses the sample path twice, going from the transmitter‐receiver (“transceiver”) to the reflector and then back to the analyzer. (Note: in remote‐sensing terminology, this arrangement is referred to as a unistatic configuration.)

Figure 6‐10 Integrated‐path, single‐pass in‐situ CEM system.

Figure 6‐11 Integrated‐path, double‐pass in‐situ CEM system.

Optical Depth

By measuring over a path, a path‐integrated concentration is obtained. The term “optical depth” is applied to such measurements, where optical depth is the product of the gas concentration and the measurement path length:

(6‐1)upper O p t i c a l d e p t h equals c Subscript s Baseline d Subscript m

where

cs is the gas concentration and

dm is the distance the light beam traverses through the flue gas. Optical depth is essentially an expression that compresses the real measurement path length into a 1‐m length to give a normalized, equivalent concentration in units of ppm‐meters (ppm‐m).

Optical depth, expressed in ppm‐meters, is useful in discussing the measurement capabilities of gas‐monitoring path systems. For example, if a double‐pass instrument has a range of 5 000 ppm‐m, its full‐scale reading (span) on a 5‐m‐diameter stack will be 5 000/(2 × 5) = 500 ppm. Because optical depth is the product of concentration and path length, one could obtain an equivalent optical depth by decreasing the path length and increasing the concentration or vice versa.

For small‐diameter ducts or stacks, a path monitor may not be sufficiently sensitive to measure at low concentrations. For example, if a double‐pass CO analyzer has a range of 5000 ppm‐m and is installed on a 1‐m‐diameter duct, the minimum full‐scale reading of the analyzer will be 5000/2 = 2500 ppm. This range may not be appropriate if flue gas CO concentrations are normally on the order of 100–200 ppm. There are, however, several solutions to this problem. The measurement path length can be increased (or possibly reduced) by installing the path system in an alternative configuration, at an angle across the stack (Figure 6‐12a). In some installations, the gas can be bypassed through an external measurement tube, with a longer path length, to make the measurement (Figure 6‐12b).

Installing the path system at an angle can increase the path length to gain more sensitivity in the instrument. However, alignment may be more difficult, and moving parts, bearings, etc. may wear out unevenly when not placed in a horizontal position. A bypass installation can be used to increase or decrease the measurement path to tailor the optical depth to the measuring range of the instrument. Also, if water droplets are present in the stack gas, the external measurement ductwork can be heated to minimize interference or light transmission problems due to water droplets. However, this approach essentially converts an in‐situ system into an extractive system, thus losing some of the advantages of the in‐situ system.

Stratification Issues

In cases where the target gas concentration is stratified (Figure 6‐13), it is often assumed that a path‐integrated concentration will give a more representative value for determining stack emissions than a value obtained by a point monitoring system. This assumption may or may not be true, depending on the stratification pattern and the procedures used to define a representative sample. Both U.S. and European Methods (U.S. EPA Reference Method and ISO Standard – ISO 9096) specify that reference method measurements are to be taken at a minimum number of points located at centers of equal areas of the cross section.

Although, in many cases of stratification, a path‐integrated concentration will be more representative than a point‐determined concentration, the stratification patterns should still be characterized. When characterizing stratification patterns, effects on the patterns due to the variability of process operating conditions must also be considered. Only then can judgments be made on representative measurement locations for point or path monitoring systems (Brooks and Williams 1976; Kearney 1993; Zakak et al. 1974).

Figure 6‐12 Methods for increasing the measurement path of integrated‐path in‐situ monitors. (a) Installation at an angle. (b) Extractive system configuration.

Figure 6‐13 Gas stratification in a duct.

Integrated‐Path Analyzer Calibration Issues

Many of the integrated‐path systems have been developed for process control purposes, particularly those used for monitoring CO and NH₃. Process control instruments are not required to meet regulatory performance specifications, nor are routine calibration checks or periodic performance audits required to be conducted. Consequently, they typically do not incorporate a means for accepting cylinder calibration gases either for calibration checks or audits. These instruments may have internal mechanisms for maintaining their stability and may work well, but their ability to provide quality assured data is questioned when the data cannot be traced back to NIST standard reference materials by the use of calibration gases.

NIST traceability is important in the United States (U.S. EPA 2020a, c, d); however, in Europe, CEM certification criteria are based on correlation with reference methods and not calibration gases. As a result, in‐situ instruments installed for regulatory applications in Europe, are not required to provide a means to accept calibration gases. This has become a problem when instrument vendors outside of the United States have sought to market their instruments in the United States. Although in some cases agencies have been lenient in compelling the use of calibration gases, sources subject to Part 75 CEM requirements must use calibration gases for daily verifications and performance assessments.

This issue can be resolved in both single‐pass and double‐pass integrated‐path instruments by incorporation of a flow‐through gas cell somewhere in the analytical system. The use of flow‐through gas cells for calibration checks introduces some complexity due to the need for cell measurement temperature and pressure corrections.

Single‐Pass Systems

If a flow‐through gas cell is placed in the optical path of a single‐pass system, the light beam will pass through both the cell and the stack (or duct). The light energy reaching the detector will then be reduced by absorption by pollutant gas molecules in both the cell and the stack (Figure 6‐14).

Another option is to incorporate the light source and gas cell in an analytical unit away from the stack or duct as illustrated in Figure 6‐15. Here, light is transmitted through an optical fiber and launched through the duct to a detector on the other side. The detector signal is then sent to the analytical unit to produce the gas measurement. To determine the concentration of the gas in the flow‐through cell, the flue gas contribution to the total detector response must be subtracted. This creates a problem if the flue gas concentration varies appreciably during calibration or the audit period.

There exists another problem with the concentration of the audit gas. If, for example, an instrument response of 500 ppm is desired when flowing a certified gas at a concentration of 500 ppm, the length of the cell should be the same length as the optical path inside the stack. That will require a very long calibration cell. A smaller cell can, of course, be used, and the cell concentration can be increased to compensate for the decrease in the cell path length.

The appropriate gas cylinder concentration to be used in the gas cell can be simply calculated by using the optical depth expression. As an example, assume that the maximum expected SO₂ concentration, in a single‐pass path system installed in a duct of 1 m diameter, is 500 ppm. At this concentration, the optical depth of the SO₂ in the duct will be 500 ppm‐m. If the analyzer incorporates a 10‐cm‐long calibration cell, the SO₂ cell concentration required to give an optical depth equivalent to 500 ppm‐m can be determined as follows:

Figure 6‐14 Flow‐through gas cell in a single‐pass system.

Figure 6‐15 Single‐pass monitor with external analytical unit.

(6‐2)left-parenthesis upper O p t i c a l d e p t h right-parenthesis Subscript c e l l Baseline equals left-parenthesis upper O p t i c a l d e p t h right-parenthesis Subscript d u c t

This requires purchasing a cylinder gas of a concentration greater than 5000 ppm, but this technique does have its limits. If the cell length is too small, the gas concentration might have to be considerably higher to give the same response. For example, if dcell is equal to 0.01 m instead of 0.1 m, the concentration of an audit gas will be 50 000 ppm. This would be a problem if NIST traceable protocol gases are not available at this level.

Another problem arises when using integrated‐path instruments to monitor O₂ or CO₂ diluent gas concentrations. Again, if in the same system, it is desired to monitor CO₂ and the highest expected CO₂ concentration is 15%, the concentration of CO₂ required in the calibration cell to give the same instrument response as 15% CO₂ will be calculated as follows:

(6‐3)c Subscript c e l l Baseline d Subscript c e l l Baseline equals c Subscript s t a c k Baseline d Subscript d u c t

A CO₂ cell concentration of 150% would require that the gas in the cell be pressurized. This creates practical problems in sealing the gas cell at high pressures, the uncertainty associated with the cell pressure, and issues of traceability to known standards.

Double‐Pass Systems

In a typical double‐pass flow‐through gas cell calibration verification technique, a mirror moves in position to block the light from entering the stack and reflects it back to the detector. Inserting a gas cell into the path then provides a check of the active electronic and optical components of the monitoring system (Figure 6‐16). This is similar in principle to calibration checks in opacity monitors, where a mirror blocks the light beam from exiting the transceiver, and a neutral density filter falls in front of the mirror for the calibration check.

The advantage of a double‐pass system is that the light beam does not enter the stack in the calibration mode, so the flue gas does not affect the calibration check, as it does in a single‐pass system. The disadvantage is that although the technique checks the active electronic and optical components in the transceiver, the retroreflector assembly on the other side of the stack is not involved in the check. Any problems due to misalignment, contamination, or damage will remain undetected unless found by some other means.

Figure 6‐16 A double‐pass system with flow‐through calibration cell.

An option available for performing a cylinder gas audit, apart from incorporating an in‐line cell, is to attach a “filter box” to the transceiver assembly of a cross‐stack system (Figure 6‐17). The device shown is manufactured by Sick, Inc. and can be used on their product line of both integrated‐path and point monitors (Sick Maihak 2009). In use, the transceiver is swung away from the port, the filter box is bolted onto the front of the transceiver and heated up to a maximum of 140 °C. Light from the transceiver assembly enters the filter box, passes through three gas cells to a retroreflector at the end of this “simulated stack,” and then reflects back through the cells to the transceiver detector to give measurements for the reference gas in the cells. The gas cells have different path lengths of 50, 25, and 75 mm. By filling the cells in different combinations, six possible optical depths can be attained using a single calibration gas.

Obviously, because light does not pass through the stack with the box in place, any alignment, contamination, or other issues associated with the cross‐stack retroreflector are not addressed in the use of the box. Nevertheless, the filter box is useful in conducting an analyzer linearity check either for trouble‐shooting or for audit. Note also, that in principle, with proper conditioning, source gas could be flowed through the audit cell, to convert the in‐situ monitor into an extractive analyzer.

Figure 6‐17 Audit cell for a path monitor.

Integrated‐Path Analyzer Analytical Methods

Three principal techniques are currently applied in commercially available path analyzers: differential absorption spectroscopy, second‐derivative spectroscopy (wavelength modulation), and gas filter correlation spectroscopy. These techniques are also used in extractive system analyzers and point in‐situ monitors. The analytical configurations employing these techniques in in‐situ systems are found to be unique to particular instrument manufacturers.

Differential Absorption Techniques

Differential absorption techniques are easily adapted to in‐situ measurement. However, the measurement path length and the light absorbing characteristics of the many gaseous species present must be considered in the selection of measurement wavelength. In spectral regions where absorption is high, too much light may be absorbed over a long stack path length (>10 m in some cases, which could be doubled to 20 m if a double‐pass system is used). Some light energy does need to reach the instrument detector, so a weaker spectral band might be chosen over a band where the light energy is more strongly absorbed by the molecule.

For in‐situ analyzers, particulate matter and water droplets in the flue gas will scatter the light, reducing the amount of light energy that can pass through the optical path to the detector. This should not be a problem for opacities less than 20–30% if the instrument is properly designed. For opacities lower than 30%, opacity fluctuations should not affect the instrument measurements when using the differential absorption technique. If the intensity of the light energy at the measuring wavelength is the same as that at the reference wavelength, then the intensity measured at both measuring and reference wavelengths would be reduced by a constant factor and the reduction would cancel out as

(6‐4)upper I equals upper K upper I Subscript w p

(6‐5)upper I Subscript o Baseline equals upper K upper I Subscript o w p

where

I = measured light intensity at the measuring wavelength

Io = measured light intensity at the reference wavelength

K = fraction of light attenuated by particulate matter in the gas stream

Iwp = hypothetical light intensity at the measuring wavelength without particulate matter present

Iowp = hypothetical light intensity at the reference wavelength without particulate matter present

and taking the signal ratio (I/Io), we have

(6‐6)

where

T is transmittance.

This satisfies the prerequisite for all in‐situ analyzers, that is, particulate matter should not interfere in the analytical method. Interference caused by broadband absorption of water vapor or other molecular species should similarly cancel if the absorption of interferents at the measuring and reference wavelengths does not differ significantly.

UV Differential Absorption Techniques

A differential absorption technique employed by the Swedish company, Opsis, is used to perform either ambient or source pollutant measurements (Biermann and Winer 1990; Karlsson 1990), where a relatively large portion of an absorption spectrum is analyzed, not just a few wavelengths. The technique is a dispersive method utilizing a diffraction grating to separate a polychromatic light beam from the stack receiver into its component wavelengths. The Opsis instrument is a single‐pass monitor and can be used to monitor SO₂, NO₂, NH₃, Hg, H₂O, HCl, HF, CO, and CO₂ in source applications (Stenberg and Kamme 1999).

In one configuration, UV light from high‐pressure xenon lamp is projected through the flue gas (Figure 6‐18). A receiver at the opposite side of the stack transmits the light to the spectrometer through a fiber‐optic cable. In the spectrometer, the light is diffracted from the grating and the moving slit assembly is used to scan the spectrum, as shown in the figure. The light intensity associated with each wavelength is measured by the detector as the slits move over the diffracted spectrum. A computer collects the spectral data and compares them with stored reference spectra. The gas concentrations are calculated by matching library spectra to the source spectrum until the two correspond. In spectral regions where different gases may interfere, reference spectra from more than one compound may be necessary to reproduce the source spectrum. Alternatively, the lamp can be installed in the spectrometer box and a fiber‐optic cable can be used to send the light to the stack for transmission.

The instrument performs its own calibration through the use of the reference spectra, which are effectively reference standards. However, as mentioned earlier, the U.S. Part 75 requirements for a daily zero and span calibration and quarterly quality assurance checks require the use of protocol gases. Opsis has included flow‐through calibration cells in their systems when required, but they have been supplemental to their primary commercial products. As a consequence, the application of these integrated‐path systems in North America for regulatory compliance has been limited.

Figure 6‐18 Opsis single‐pass monitor.

Gas Filter Correlation Methods

The technique of gas filter correlation (GFC) spectroscopy was first applied for source emission measurements in in‐situ monitoring systems (Herget et al. 1976). The technique has undergone many developments since and is now successfully applied as well in extractive systems, as discussed in Chapter 5. In‐situ GFC optical configurations have been designed to employ the technique either in a single‐pass or a double‐pass mode. Single‐pass GFC systems continue to be marketed and perform successfully, although they suffer from the lack of suitable cylinder gas calibration techniques. Double‐pass GFC systems, however, do allow the use of flow‐through gas calibration cells. Integrated‐path GFC monitoring systems have had a checkered history, and many of the cross‐stack instruments popular in the 1980s are no longer manufactured. Today, the technique is more widely applied in point in‐situ and extractive system analyzers.

Single‐pass GFC monitors are manufactured by Sick, Inc., Land Combustion (Ametek), Siemens, and others, primarily for monitoring CO for combustion control. A gas filter placed on a wheel before the IR source on the transmitter side provides zero reference readings (100% absorption) at the detector. Instead of a rotating wheel, a stepper motor can be used to rotate a single gas filter correlation cell containing CO into the light beam. These monitors produce a rapid response and are suitable for the control of combustion processes, but may not be suitable for regulatory reporting due to calibration issues.

Diode Laser Systems in Derivative Spectrometers

Tunable laser systems (TDLS) have been incorporated into path in‐situ, point in‐situ, and close‐coupled monitoring designs using second‐derivative detection techniques. Tunable diode infrared lasers emitting light in pollutant gas spectral regions were first developed by Hinkley in the 1970s (Hinkley et al. 1976) and evaluated for SO₂ emission monitoring by EPA (Rollins 1977). However, monitoring systems were not practical at that time due to high cost associated with making custom lasers and the fact that both lasers and detectors had to be cooled with liquid helium to obtain sufficient sensitivity. With the advent of near‐infrared communications lasers and improvements in infrared semiconductor detectors, instrument companies in Europe, Canada, and the United States have developed laser‐based monitors for both source and ambient applications. Laser technology has extended with the development of quantum cascade lasers, and today, both tunable diode lasers and quantum cascade lasers are being used in emission monitoring systems.

Tunable Laser Systems

A simple diode laser system can utilize the differential absorption technique, tuning a laser to different wavelengths by changing the laser temperature or its driving current. However, greater sensitivity can be obtained by modulating the laser wavelengths over the wavelength range of the absorption peak. The second‐derivative technique is particularly applicable for enhancing the detection of weak absorption signals in the near‐infrared regions where lasers are available. There are different ways of doing this, but the net result is a signal that is proportional to the second derivative of Beer's law.

Since the method is dependent upon the shape of the absorption line, problems can occur due to line broadening effects. Temperature and pressure can affect the line shape, as well as collisions between other molecules, which lead to collisional broadening. Although lasers are very specific with respect to wavelength and can avoid spectral interferences, collisional broadening is dependent upon the flue gas composition, introducing a different type of interference, reminiscent of the quenching effects in fluorescence monitors. Advanced spectroscopic techniques and compensation methods have been developed to minimize line broadening effects (Linnerud et al. 1998). Laser frequency stability has also been a problem, being dependent upon the type of laser and the emission wavelength range. Distributed feedback (DFB) and distributed Bragg reflection (DBR) lasers are most widely applied (Mettler‐Toledo 2012; Wang et al. 2019).

Diode laser systems have been developed for monitoring HF NH₃, HCl, O₂, CO, H₂S, and NO (Bjoroy et al. 1998; Brand et al. 1996, 1997, 1998; Linnerud et al. 1998; Mills and Kasperson 1998; Mackay et al. 1997). Principal efforts have been devoted to the development of HCl, NH₃, and HF monitors due the ease of monitoring these gases in the near infrared, and the advantages in‐situ systems have in avoiding reactivity and adsorption/absorption problems associated with these gases in extractive systems (Arnold 2016). The Electric Power Research Institute (EPRI) has conducted a number of studies on TDL NH₃ monitoring systems, comparing the performance of commercial systems for measuring ammonia slip (Pisano and Durbin 2004; Shiomoto and Muzio 2000). EPRI has also prepared an applications guideline for these systems (Muzio et al. 2012).

Derivative Spectroscopy (Wavelength Modulation)

The technique of derivative spectroscopy (Hager and Anderson 1970; Hager 1973; Williams and Palm 1974), a form of wavelength modulation spectroscopy, has been used by analytical chemists to enhance the detection of weak absorption signals. In this technique, either the originating light from the light source is modulated, the light seen at the detector, or the subsequent signal is modulated. Derivative spectroscopy involves scanning a spectral absorption peak and obtaining its second derivative or higher derivatives with respect to wavelength at the peak maxima. Derivative techniques offer greater baseline stability, resulting in greater sensitivity and accuracy, particularly if underlying spectral interferences are present.

The second‐derivative method was first used in CEM applications by Teledyne‐Monitor Labs, Inc. in the 1970s (then Lear Siegler, Corp.), employed an oscillating lens to modulate the wavelength seen by the detector in the UV region of 218.5 nm in an in‐situ SO₂ point monitor (Polhemus and Hudson 1976). A later model used a diode‐array detector and employed mathematical techniques instead of the oscillating lens to obtain derivatives from the diode‐array spectrum (Teledyne Monitor Labs 2009, 2015). These monitors are no longer marketed. However, with the advent of lasers in gas monitoring, many instrument companies have developed both extractive and in‐situ analyzers that operate by modulating the wavelength of the laser light source.

To understand this technique, first consider an absorption spectrum such as that shown in Figure 6‐19a. When using a laser, the laser light wavelength is changed to sweep across the width of the pollutant absorption feature, by changing the laser temperature. As the absorption curve is swept, the laser frequency is modulated by changing the laser current. This is also illustrated in Figure 6‐19a.

Looking at the sloping first part of the absorption curve denoted as “a,” the signal seen at the detector would appear as the inset graph of Figure 6‐19b. Conceptually, the light wavelength changes from λi to λi ± Δλ, in increments – the light wavelength first increases, then decreases, then increases, and so on, in a sinusoidal fashion as it is modulated by changing the laser voltage. As the light wavelength is modulated, it also increases from λx to λy, as it scans the absorption curve. By following the dashed lines of each of the incremental modulations in this thought experiment, it can be seen that the sinusoidal nature of the modulation is reflected in the signal intensity. In other words, the frequency of the signal peaks will be the same as the frequency of the modulation.

However, when the absorption curve is scanned at the absorption curve minimum denoted as “b” on the curve, a different phenomenon occurs. As the sine wave modulation scans the valley of the transmission curve, the signal is first high when it starts off at λy, decreases at the minimum, increases at the other side of the valley, decreases again as it scans back across the minimum, and then increases as it scans back to λy (plus the increment the wavelength moves forward in time). In this case, the detector sees two peaks for every peak of the modulation. In other words, the frequency of the signal is twice that of the modulation.

Figure 6‐19 (a) Modulated laser intensity as a function of time and wavelength scanning a transmission curve. (b) Signal output for modulation over a curve segment where the output frequency equals the modulation frequency (c) Signal output for modulation over the absorption valley where the output frequency is twice the modulation frequency.

A derivative is just the rate of change of a function with respect to a variable. The inset graph of Figure 6‐19b shows the first derivative of the absorption curve, dI/dλ. The first derivative evaluated at a given wavelength will reflect the curvature of the absorption curve. The inset of Figure 6‐19c shows the second derivative, d²I/dλ². Here, the second derivative reflects the curvature of the first‐derivative curve. Scanning over the absorption spectrum produces the second harmonic of the absorption line. The amplitude of the second harmonic, the detector signal at twice the modulation frequency, is proportional to the second derivative of the intensity with respect to wavelength evaluated at λm, the valley minimum. Equation 6‐1 (Hager 1973) becomes

(6‐7)upper S proportional-to StartFraction d squared upper I Over d lamda squared EndFraction vertical-bar Subscript lamda Sub Subscript m

Now, if the Beer–Lambert expression characterizes the absorption curve, its second derivative is proportional to the gas concentration (Hager and Anderson 1970; Hager 1973). The second derivative can be taken from Beer’s law Equation 6‐2 with respect to wavelength, to obtain Equation 6‐8.

(6‐8)

Then, since the instrument signal, which is proportional to the second derivative of the intensity, will be proportional to the gas concentration

(6‐9)

Essentially then, the instrument gives a signal that is proportional to the gas concentration, which is, of course, what is necessary to make a monitoring instrument (Equation 6‐10):

(6‐10)upper S slash upper I equals upper K c

In practice, the instrument tunes into this frequency to extract this signal much like tuning in a radio. A strong signal indicates a strong absorption, in analogy to a radio station with a strong transmitter producing a clearer signal than a weaker station. A strong absorption can occur if there is a large value for α(λ), the absorption coefficient, and/or a high concentration of absorbing molecules, so this would imply that the signal is related to the pollutant gas concentration. By dividing S by I, problems caused by variations in the source intensity, broadband absorption from other gases, or scattering by particulate matter are avoided. This happens because a change in I by a constant factor will induce an identical change in S. Determining the ratio of the two cancels out the effect.

Advantages and Limitations of Integrated‐Path CEM Systems

Integrated‐path monitors originally appeared to be the solution to monitoring problems; however, as one set of problems is minimized by monitoring flue gases in‐situ, other problems arise. The first problem is related to access. An elevator or a series of squirrel‐cage ladders extending to the sampling platform provides relatively easy access. However, having to wear a safety harness when climbing an open ladder can discourage visits to the system.

Environmental effects are another problem. As with short‐path in‐situ systems, integrated‐path systems can be sensitive to elevated temperatures and lightning. Vibration can loosen circuit boards and components and misalign optical systems. High ambient temperatures may affect electronic circuit boards, necessitating a cooling or air conditioning system. High internal stack temperatures (greater than 260 °C (500 °F)) may result in radiative effects that interfere in infrared measurements. Lightning problems are again obvious because the transmitter and receiver on opposite sides of a stack can serve as two lightning rods that can damage the components in the control room. Insulation, lightning arrestors, and fiber‐optic signal transmission can be used as measures to minimize this problem.

Integrated‐path monitors, in particular, can suffer from beam alignment problems, signal strength losses, drift issues, and poor sensitivity at low concentrations. High flue gas opacities (>30%) due to either particles or water droplets may reduce the beam intensity to such a degree that too little light will reach the detector for analysis. In the past, integrated‐path monitors were viewed as appropriate for measuring pollutant gas concentrations on the order of several hundred ppm, with relative accuracies in the range of 10–20%. However, this view is changing. With newer systems, and even with older systems, excellent performance can be achieved (Arnold 2016). For example, Erwin Sick GM30 double‐pass cross‐stack monitors installed in Alberta coal‐fired power plants, at one time, routinely achieved relative accuracies on the order of 5–10% even after 30 years of operation (Hunting 2012).

Cost is always an issue with CEM systems, but with in‐situ systems, initial analyzer/system costs may lead to higher overall costs. Although daily operating costs can in principle be less than extractive system costs, if an in‐situ analyzer fails, it can be difficult to repair on‐site. If off‐site repair requires sending it back to the manufacturer, repair times can extend to a month or more, during which no reportable data would be available. Sending an instrument back to the vendor for repair can be costly, particularly if a regulation requires that, if a malfunction extends beyond 168 hours, either another certified system be installed or reference method testing be conducted. In such cases, to maintain high system availability, it is practically necessary to purchase a backup system, ready to swap out an installed system when it fails. This doubles the cost of the initial system although the relative cost is less if more than one system is installed at a facility. Although a well‐maintained in‐situ system can run well and maintain high availability, in‐situ systems by virtue of their on‐stack installation are more prone to risk and unforeseen events than analyzers enclosed in an environmental shelter.

Integrated‐path monitors do, however, provide advantages over extractive systems and point monitoring in‐situ systems. Daily operating costs can, in principle, be less than that for extractive systems if certified gases are not required for daily calibration checks. There are also fewer sub‐systems associated with in‐situ monitors, so problems occurring with chillers, heat‐traced lines, valves, and pumps are avoided. Performing cylinder gas audits can be resolved to some extent by using flow‐through gas cells as discussed.

Time‐sharing options are also possible for tunable laser systems by using multiple light sources transmitting light at multiple locations or multiple stacks. At each location, light transmitted across the stack or duct and received on the opposite side can be sent via the fiber‐optic cable to a single spectrometer. Also, one of the principal marketing features of in‐situ analyzer vendors is that a single instrument can monitor a number of gases, thereby reducing the cost of purchasing multiple analyzers.

Due to technical issues, regulatory issues, and market competition, in‐situ monitors, and integrated‐path monitors in particular, became unpopular in the United States in the 1980s. However, they were widely applied in Canada (where at one time, 50% of the CEM systems installed were in‐situ systems) (Jahnke 2006). Today, with the advent of tunable diode and quantum cascade lasers and the need to continually track and optimize the performance of emission control equipment, in‐situ monitors are undergoing a renaissance. Integrated‐path monitors have been increasingly used for process control and optimization, where laser systems are often applied to monitor CO and NH₃. Also, with greater experience in their application, integrated‐path monitors are now finding applications as regulatory compliance monitors for monitoring HCl.

Certification Test Criteria for Integrated‐Path Monitors

With the advent of tunable diode laser systems for monitoring HCl and NH₃ and the subsequent publication of Performance Specification 18 for HCl monitors, integrated‐path (cross‐stack) monitors are seen as a viable option for measuring highly reactive, soluble, and corrosive gases (U.S. EPA 2020b). Although PS‐18 is specific for HCl monitoring systems, it is also recommended for NH₃ CEM systems (EMC 2019), in lieu of a promulgated performance specification for NH₃. Performance Specification 18 presents an advance in the standardization of this maturing technology, by adding many requirements specific to integrated‐path in‐situ monitors.

The PS18 criteria include design and installation requirements, a beam intensity test, a temperature verification test, and a pressure verification test, among others. The PS18 certification criteria for HCl integrated‐path monitors are otherwise similar to those given in PS2 for SO₂ and NOx monitors. Location criteria are identical, and seven‐day zero and calibration drift tests, and relative accuracy test are required as in PS2 (see Chapter 11).

Additional criteria are included in PS18 for both extractive systems and in‐situ systems. These require determining the level of detection (LOD), conducting an interference test, and conducting a linearity (measurement error [ME]) test. The response time test was re‐instituted in PS18 after being dropped in PS2 in 1989. An alternative dynamic spiking procedure is included in PS18 for the seven‐day zero and calibration drift test. The PS18 performance specifications are summarized in Table 6‐1.

Design Criteria

Integrated‐path monitoring systems subject to PS18 must provide a means for introducing a calibration gas into the optical path. This is accomplished by incorporating in the optical path, a gas cell, such as that shown in Figures 6‐14 and 6‐15. The cell length must be known, and the cell pressure and temperature need to be monitored to make appropriate corrections to the cell gas concentration. Also, for cross‐stack systems installed in stacks or ducts having low flue gas velocities, there may be a concern that the system purge air might dilute the flue gas near the port or the end of an extension tube. PS‐18 specifies that the purge air velocity be less than 10% of the flue gas velocity to avoid this problem.

Interference Test

The interference test is conducted to demonstrate that an HCl monitor is not subject to interference by other gas species present in the flue gas. The test is performed by combining the HCl gas with a concentration approximately five times the LOD, with each interference gas listed in Table 1 of PS18 (for example, SO₂ at a concentration of 200 ppm, CO₂ at 15%, CH₄ at 100 ppm, and so on) and without other interferents. The test is done in triplicate for each possible interferent (10 different gases), and may be conducted by the instrument manufacturer on a “like‐kind” analyzer. An analyzer passes the interference test if the sum of the interference from each interferent tested is less than 2.5% of the instrument span, or within ±3.0% of the HCl gas concentration used to perform the test. The results are also acceptable if the sum of the interference responses does not exceed six times the LOD or 0.5 ppm for a calibration span of 5–10 ppm, or 0.2 ppm for a span of less than 5 ppm.

TABLE 6‐1 HCl Extractive and Integrated‐Path System Performance Specifications

Specification
Criteria

Level of detection (LOD)
≤20% of emission limit

Site‐specific LOD
LOD to be verified on‐site during certification

Interference test
≤2.5% of span or ±3% of test gas concentration, or
≤6 × LOD or 0.5 ppm for a span of 5–10 ppm

Response time
Reported – No criteria

Calibration drift (CD)
≤5.0% of span for each of 7 days

Measurement error (ME)
≤5% of span for low‐, mid‐, and high‐level reference gas concentrations

Relative accuracy (RA)
≤20% of Reference Method or
≤15% of Emission Standard

IP‐CEMS beam intensity
≤3% concentration difference at state attenuation

IP‐CEMS T sensor accuracy
≤1.0% f absolute difference from reference or
≤2.8 °C

IP‐CEMS P sensor accuracy
≤5.0% absolute difference

Beam Intensity Test

This test is conducted by introducing a calibration gas into the gas cell, making a measurement, and then inserting a neutral density filter, or filters, into the light path to attenuate the light intensity and making another measurement. The difference between the two measurements must be less than ±3.0%. After certification, and when the instrument is in operation, the beam intensity must be higher than the attenuated intensity at the time of the test. The instrument owner may conduct this test; however, it may be performed by the instrument manufacturer who will usually use a range of filters to determine the maximum attenuation that will still give a difference of less than ±3.0%. A test conducted by the instrument manufacturer must be on a “like‐kind” analyzer of the same make and model as the one being certified.

Temperature Verification Test

Because integrated‐path monitoring systems measure gas concentrations at actual conditions, ideal gas law corrections are necessary to convert measured values into standard conditions, when required. The test compares a calibrated temperature reference device against the monitoring system temperature sensor. The difference between the two sensors must be ≤1.0% of the reference sensor value or ≤ an absolute mean difference of 2.8 °C.

Pressure Verification Test

This test compares a calibrated pressure reference device against the monitoring system pressure sensor. The difference between the two sensors must be ≤5.0% of the reference sensor value or ≤ an absolute mean difference of 0.2 kPa or 0.5 in. of water column.

Level of Detection

The LOD is defined as the lowest level of pollutant that the CEM system can detect in the presence of the source gas matrix interferents with 99% confidence. For extractive systems, interference gases are injected directly into the inlet of the analyzer (not the probe inlet). For integrated‐path systems, the gas is injected into the gas calibration cell combining with an HCl gas having a minimum detectable concentration level, but no more than five times the estimated LOD. Seven measurements are made with each gas, where the LOD is defined three times the standard deviation. The LOD must be less than 20% of the HCl emission regulatory limit. The test may be conducted by the instrument manufacturer on a “like‐kind” analyzer.

The LOD must be verified on‐site during system certification by dynamic spiking (method of standard additions [SA]) for extractive systems; by spiking the native source concentration at an HCl concentration no more than three times the LOD determined in the laboratory. In this case the spike must be done at the probe and pass through the extractive system components. For integrated‐path systems, it may be done using the flow‐through gas calibration cell. The spike addition must be able to be determined above the native HCl concentration in the flue gas.

Response Time Test

No specification is given for response time; however, it must be determined. The response time is the time it takes for the measurement system to respond to a known step change in gas concentration. In PS 18, response times for the level of detection determination (LOD), measurement error (ME) test, and dynamic spiking (DS) are to be determined, as applicable. The response time is recorded as the time the monitoring system takes to reach 95% of the change to a stable value.

Measurement Error

This test similar to the linearity test of Part 75, where four references gases at 0, 20–30, 40–60, and 80–100% of span are injected into the system either at the probe or in the calibration gas cell of an integrated‐path monitoring system. A mid‐level dynamic spiking test is provided as an option for extractive CEM systems for the determination of measurement error.

Line Strength Factor

When using external gas flow‐through cells for calibration checks or cylinder gas audits, a “line strength factor” must be applied to temperature‐dependent spectral absorption characteristics of the molecule being measured if necessary.

Seven‐Day Calibration Drift Test

This test examines the zero and upscale calibration, using a mid‐level gas to determine the upscale calibration drift. The test verifies the ability of the CEM systems to remain in calibration for each of seven consecutive unit operating days.

Relative Accuracy Test

The test is the same as in other U.S. EPA performance specifications (see Chapter 11).

Quality Assurance for In‐situ CEM Systems

Quality assurance requirements for the continuing operation of CEM systems in the United States and Canada specify the performance of daily calibration verifications, quarterly audits, and a semiannual or annual relative accuracy test audit (RATA). The U.S. Part 60 rules and Environment Canada Guidelines allow the use of sealed internal gas cells for daily calibration checks in integrated‐path monitoring systems. In contrast, integrated‐path systems regulated under Part 75 are not allowed this accommodation and must use protocol cylinder gases for daily checks.

For quarterly audits, Part 60 and the Environment Canada CEM Guidelines do require that a cylinder gas audit (CGA) be conducted by injecting protocol gases into the system, or alternatively in Part 60, by conducting an abbreviated RATA (three runs instead of nine) in three quarters in the year. The Environment Canada Guidelines allow the use of portable monitors to conduct a five‐run RATA as an alternative to conducting a cylinder gas audit. Part 75 requires that quarterly audits using protocol gases be conducted in each of the four quarters of the year for all systems regulated under the program, in contrast to only three quarterly CGAs being required under Part 60.

The cylinder gas verification and audit requirements have limited the application of integrated‐path monitors in the United States since there has been reluctance to incorporate flow‐through gas cells. In‐situ systems have, however, seen wider application in Canada and, of course, in Europe where automated monitoring systems (AMS) are calibrated and audited according to the more lenient EN14181 procedures (CEN 2014) (see Chapter 11).

Procedure 6 of Part 60 Appendix F applies to HCl monitors and is the first of the Appendix F quality assurance procedures to provide requirements specific to integrated‐path monitors (U.S. EPA 2020e). Procedure 6 requirements are given in Table 6‐2.

TABLE 6‐2 Part 60 Procedure 6 Requirements for HCl CEM Systems

Requirements
Extractive Systems
Point In‐situ
Systems
Integrated Path Systems

QC Plan
QC Program
QC Program
QC Program

Daily Checks
Zero & Mid‐level CD check or Dynamic Spiking
Zero & Mid‐level CD check
Zero & Mid‐level CD check
Beam Intensity Record

Quarterly Checks
CGA
RAA or
Dynamic Spiking Audit (DSA)
CGA or
RAA
CGA or
RAA

Annual Checks
RATA
RATA
RATA
Temperature Sensor Audit
Pressure Sensor Audit

A quality control program must be developed and implemented for any extractive or in‐situ HCl monitoring system, meaning that step‐by‐step procedures must be written for the following:

Calibration drift checks and calibration adjustment

Integrated‐path temperature and pressure checks

Integrated‐path beam intensity check and recording

Routine maintenance

Preventive maintenance

Corrective action

Audits (RAA, RAA, CGA, Dynamic spiking audit (DSA), Temperature, Pressure – as applicable)

Data recording, calculations, and reporting

Daily zero and mid‐level calibration drift checks are required for any type of system installed for monitoring HCl. As discussed earlier, for integrated‐path systems, this is achieved by incorporating a flow‐through gas cell in the measurement path. For point in‐situ systems, the probe volume is flooded alternately with zero gas and a mid‐level gas for the daily check. For integrated‐path monitoring systems, it is required, in addition, to record the beam intensity. For integrated‐path systems, in addition to the relative accuracy test audit, annual audits of the temperature and pressure measurement sensors must be conducted against NIST traceable devices, or the sensors can be replaced with another certified sensor or instrument.

Quality control criteria for HCl monitoring system audits are given in Table 6‐3.

IN‐SITU SYSTEMS VS. EXTRACTIVE SYSTEMS

A continuing matter of discussion revolves around determining which system is the best system: extractive or in‐situ systems. The simplest answer is again, there is no “best” system since CEM systems are all application dependent. In fact, CEM system data quality is not as dependent upon the type of CEM system installed as it is dependent on the performance of maintenance at a level sufficient to maintain data quality. However, the most accurate CEM system will utilize methods that have the ability to measure the gas of interest without interference from other gases or materials found in the gas stream. Perhaps one of the greatest distinctions between extractive and in‐situ systems (both path and point) is that in‐situ systems typically require less inspection/maintenance time than do extractive systems (McGowan 1995; Payne and Christianson 1993). With these issues in mind, some of the principal differences between the methods are summarized in Table 6‐4.

There are also many differences between the types of CEM systems available commercially. As with any instrumentation, some systems are antiquated in design, others are poorly constructed, and others may require excessive maintenance (whether extractive or in‐situ). Similarly, vendors vary in quality and capability. Some CEM system vendors maintain well‐managed and well‐developed organizations, while others are made up of a few individuals without adequate service staff or financial resources. As in purchasing any product, it is left to astuteness of the buyer to choose the best system and vendor for his or her application.

TABLE 6‐3 Quality Control Criteria for HCL Monitoring Systems

Requirements
Requirement
Out‐of‐Control Criteria

QC Plan
Write QC procedures
Must be Implemented

Daily Checks
Zero & Mid‐level CD check, or
Dynamic Spiking + Zero Check
Beam Intensity Check (IP CEM)
> 10% of Span (zero, mid)
> 10% of Span (zero, mid)
> established low level

Quarterly Checks
CGA
RAA, or
Dynamic Spiking Audit (DSA)
> 5% of Span (zero, mid, high)
> 20% of RMavg
> 5% of Span (zero, mid, high)

Annual Checks
RATA
T Sensor Audit (IP CEM)

P Sensor Audit (IP CEM)
> 20% of RMavg
> 1.0% of T reference,
or > 2.8° C absolute dif.
> 5.0% of P reference
or > 0.12 kilopascals abs. dif.

TABLE 6‐4 Comparison of Features Between Extractive and In‐situ Systems

Features of Extractive Systems
Features of In‐situ systems

Point Monitors
Integrated‐Path Monitors

Can sample from point of average concentration
Can sample from point of average concentration
Linearly average concentrations
May loose light energy over path, requiring insertion tubes to reduce path length

Can easily audit with cylinder gases
Some probe types may be flushed with cylinder gases to conduct cylinder gas audits
Require internal or external gas cells to conduct cylinder gas audits or an RAA

May alter sample
Do not alter sample
Do not alter sample

Response time dependent on sampling system
Response time dependent on analyzer not sampling system

Do not require temperature compensation
Require temperature/pressure compensation

Analyzers located in environmentally controlled shelters, rooms
Analyzers may subject to rain, ice, snow, lightning strikes
Stack/duct flexing/vibration may affect alignment, noise levels

Installation may require major planning if have no preexisting CEM system
Installation may be relatively simple on duct/stack flanges

Have a large number of maintainable system components
Fewer number of maintainable system components

Systems components may be relatively easy to repair (pumps, valves)
System components may be relatively difficult or expensive to repair or replace (lasers, optics, electronics)

System problems usually readily resolved on‐site
Analyzer electro‐optical problems may be difficult to resolve on‐site

Maintenance may not require special training
Maintenance may require higher levels of training, call‐out for service, or return to factory

Availability dependent on extractive system rather than analyzer problems
Availability may suffer if unable to repair on‐site and spare analyzer not available

Costs approximately 2× in‐situ if require new shelter/extractive system
Costs may be comparable to extractive system if spare monitor is purchased

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CHAPTER 7
FLOW RATE MONITORS

Flow rate monitors were not widely applied in the United States until after 1993 when the acid rain program mandated their installation for the calculation of SO₂ allowances. The allowance is an emission rate, expressed in units of tons of a pollutant emitted per year, which is calculated from hourly emissions data. As discussed in Chapter 2, these allowances are allocated, banked, sold, and traded, or, otherwise, have commercial value. The U.S. EPA considered that flow monitors would be the most accurate means of determining allowances for coal‐fired units since, for these sources, analyzers can be certified, calibrated, and audited more uniformly. Although engineering calculations based on heat rate or process operations may also be used to determine flue gas flow rates, evaluation of the accuracy of these methods is more difficult, particularly where the fuel composition is variable. The U.S. EPA requirements for determining SO₂ mass emission rates using flow monitors led to the installation of over 1000 flow monitors at coal‐fired electric utility facilities in the early 1990s.

Emission standards that specify the continuous monitoring of pollutant mass emission rates imply that flow monitors are to be part of CEM systems. This can be seen by examining the following relation:

(7‐1)p m r Subscript s Baseline equals c Subscript s Baseline upper Q Subscript s

and

(7‐2)upper Q Subscript s Baseline equals upper A Subscript s Baseline v Subscript s

where

pmrs = pollutant mass rate (kilograms per hour, pounds per hour, tons per year)

cs = pollutant concentration (milligrams per cubic meter, pounds per cubic foot)

Qs = volumetric flow rate (cubic meters per hour, cubic feet per hour)

As = stack or duct area (cubic meters, cubic feet)

vs = stack as velocity (meters per second, feet per second

with the application of appropriate conversion factors (e.g. seconds to hours)

The first U.S. federal requirement for continuous pollutant mass rate determinations appeared with the promulgation of Subpart LLL (Standards of Performance for Onshore Natural Gas Processing: SO₂ Emissions) in 40 FR 40160 1 October 1985. However, as discussed above, the allowance trading policy of the 1990 U.S. Clean Air Act Amendments, Title IV provides greater impetus for the application of velocity monitors for the measurement of emission rates in the United States.

Instruments used to measure flue gas velocity are inherently in‐situ monitors because a dynamic gas measurement must be made. The analytical methods vary in complexity from the use of pitot tubes to transmitting ultrasonic signals across the stack (Table 7‐1). Pitot tubes and thermal sensors measure at one point only although averaging probes or arrays of sensors can be used to measure at centers of equal areas across a stack or duct. Alternatively, ultrasonic instruments measure velocity as a line average. Other instrumentation, such as orifice meters, venturi meters, vane anemometers, and flow tubes are more appropriate for air handling ducts or specialized gas streams free of particulate matter.

TABLE 7‐1 Flow Monitoring Techniques

Technique | Instrumentation/Sensor
Differential pressure sensing | Pitot tubes, averaging tubes
Thermal sensing | Heated sensor
Acoustic velocimetry | Ultrasonic transducers, audible sensors
Time‐of‐flight | Infrared sensors
Engineering/heat rate | Fuel flow meters, various

In practice, the volumetric flow, Qs, is first determined by averaging the velocity at at least twelve points located over the sampling cross section, at sampling points specified by conducting EPA Test Method 1 (U.S. EPA 2020a). Flow monitor readings are then adjusted to correspond to the EPA test method area average by incorporating an adjustment factor, called the “K factor.” This procedure is discussed further in this chapter.

This discussion of flow rate monitoring techniques is not intended to be exhaustive of all methods currently available and emphasizes those that have been or are currently being used for monitoring flow in industrial/utility stacks or flues.

REFERENCE METHODS FOR VOLUMETRIC FLOW

Pitot tubes have been used traditionally to measure the stack gas volumetric flow rate and are specified as EPA reference methods for measuring flue gas velocity. A pitot tube consists of two tubes: one tube, facing the direction of flow of the gas, measures the impact pressure and the other tube, either parallel to the flow or in the opposite direction of the flow, measures the static or wake pressure. The pressure differential between the impact pressure and wake pressure is the “velocity pressure,” ∆p. These components are illustrated in Figure 7‐1. The velocity pressure, Δp, is related to the flue gas velocity by the pitot tube equation:

(7‐3)v Subscript s Baseline equals StartRoot StartFraction upper T Subscript s Baseline upper Delta p Over upper P Subscript s Baseline upper M Subscript s Baseline EndFraction EndRoot

where

vs = velocity of the gas

Kp = dimensional constant

Cp = pitot tube calibration coefficient

Ts = absolute temperature of the gas

Ps = absolute pressure of stack gas

Ms = molecular weight of the stack gasΔp = velocity pressure

Figure 7‐1 Differential pressure monitoring.

To calculate the volumetric flow, differential pressure techniques require the measurement of the flue gas density. Therefore, several parameters besides the directly measured Δp must be assumed, calculated, or otherwise determined, to obtain velocity.

Type‐S Pitot Tube (Method 2)

A number of devices have been developed based on differential pressure sensing. The simplest one incorporates the Type‐S (Stausscheibe) pitot tube specified in U.S. EPA Reference Method 2 (U.S. EPA 2020a). The Type‐S pitot tube is typically calibrated against a standard pitot tube (L‐type), having a known calibration coefficient, in a wind tunnel at a single velocity (Figure 7‐2). The Type‐S probe calibration coefficient, Cp, is usually determined only once a year by source testers. However, the probe should be recalibrated or replaced any time it is damaged. The velocity pressure can be measured using an oil manometer, a Magnehilic® gauge, or an electronic manometer. Using a thermocouple to measure the stack temperatures, along with a measurement of the stack static pressure, the flue gas velocity can be calculated.

The Type‐S pitot tube is relatively simple to manufacture, calibrate, and easy to use – factors leading to its wide acceptance. The design of the Type‐“S” pitot tube is standardized in EPA Method 2 and also in the ASTM standard, ASTM D3154 (ASTM 2020a). Calibration procedures for the tube are given in both EPA Method 2 and ASTM D3796 (ASTM 2020b). The method has been long used in the United States as well as internationally and has been extensively studied. Method 2 does not include procedures for measuring yaw or pitch; nor does it take into account wall effects for measuring the volumetric flow. Although these issues were already recognized, they took on a new significance when air pollution control programs began to focus on the reporting of pollutant mass rates for emissions trading and taxing regulatory programs. When near the emission limit, or when emissions take on a monetary value, flow monitoring accuracy is as important as the accuracy of the pollutant gas concentration measurement, and can become a major concern.

Figure 7‐2 Standard and Type‐S pitot tubes.

As a result of this concern, the U.S. acid rain program conducted an extensive field program in 2001 to examine biases associated with the EPA reference methods and flow monitor accuracy (Lieberman 1998; Lieberman and Schakenbach 1997). The findings of this study led to the publication of test methods 2F, 2G, and 2H, introduced as options that can be used when optimal accuracy is desired in flow measurements. More recently, the U.S. National Institute of Standards and Technology (NIST) initiated an ongoing program for evaluation and improvement of flow measurement methods to increase the accuracy of CO₂ emission rates reported in greenhouse gas assessments (NIST 2018; Shinder et al. 2018).

Three‐Dimensional Pitot Tubes (Method 2F)

Three‐dimensional pitot tubes can compensate for the effects of pitch and yaw when measuring angular flow. Procedures for using and calibrating three‐dimensional pitot tubes are given in 40 CFR 60 Appendix A as Method 2F for the commercially available 5‐hole prism‐shaped probe and 5‐hole spherical probe (Figure 7‐3) (U.S. EPA 2020c). The method is specified for flows greater than 20 ft/s.

Figure 7‐3 Three‐dimensional pitot tubes: (a) prism probe (b) spherical probe.

Method 2F provides for a measurement of the pitch and yaw angles, which in turn are used to calculate the axial velocity. The method calibration procedures specify the design features of the wind tunnel to be used as well as the procedures used to determine the two probe calibration coefficients: the pitch angle coefficient, F₁, and the velocity coefficient, F₂. The expanded uncertainty for the spherical probe found by NIST ranges from 0.9 to 1.1% and for the prism probe from 0.9 to 1.25%, at pitch angles from −20° to +20° (Shinder et al. 2018). NIST found also that the prism probe has a strong Reynolds number dependence, whereas the spherical probe does not.

Yaw‐Nulling (Method 2G)

Method 2G utilizes the Type‐S probe to account for angular flow and provides a less expensive option in measuring the flow yaw angle than Method 2F (U.S. EPA 2020d). The method, however, does not measure the pitch. In the method, a digital inclinometer or protractor wheel is used to indicate when a null condition is reached as the pitot tube is rotated at a sampling point. A null condition exists when the pressure at the impact and wake pressure pitot tube ports are identical, i.e. the differential pressure is zero. The yaw angle is recorded and the probe moved into the axial direction of the flow. The axial velocity is calculated by multiplying the pitot tube equation (Equation 7‐3) and the cosine of the yaw angle.

Wall‐Effect Measurements (Method 2H and CTM‐041)

In Method 2, measurements are taken over the stack cross section at the sampling location. In practice, the traverse points are selected according to the procedures of EPA Test Method 1 – at the centroids of equal areas, divided over the cross section, (Figure 7‐4) (U.S. EPA 2020a). These points are located on two transects, perpendicular to each other, where the pitot tube measurements are made. A measurement at a centroid of each equal area is assumed to represent the average flow across that area. The stack flow is calculated as an area average from the velocities determined at each traverse point.

Due to viscous shear effects between the gas and the stack wall, the flow typically decays to zero at the wall. Measurements made at the centroids of the equal areas adjacent to the stack wall cannot account for this drop in the flow and will not be representative of the actual flow. The obvious solution to this problem is to make measurements closer to the stack wall and this is what Method 2H specifies. In the method, measurements are made at 1 in. increments from the wall (U.S. EPA 2020e).

Figure 7‐4 Method 1 sampling points used to determine an area average.

For circular stacks, Method 2H allows the use of a default factor to correct for flow decay near the stack walls. The factor is 0.99 for brick stacks and 0.995 for other stacks and ducts. When a complete wall‐effect traverse is made, the correction factor is limited to a minimum of 0.97.

Wall effects are more severe in rectangular ducts, and similar procedures are found for rectangular ducts in EPA Conditional Test Method CTM ‐041 (U.S. EPA 2003). Similar to Method 2H, measurements are made at 1 in. increments from at least four test ports (see also Norfleet 1998, 2000).

Vane Anemometers

The use of vane anemometers for low flows is acceptable as a reference method in the International Standards Organization flow standard EN‐ISO 16911‐1 (ISO 2013a), as is the use of tracer gases. Vane anemometers are also incorporated into U.S. EPA Method 14 for roof monitor flow rate determination. Anemometers can be useful for monitoring low flows, where the flue gas is relatively free of particulate matter. The method has been evaluated over a range of 0.5 to 40 m/s, where it is found that at higher velocities, mechanical stresses will increase, decreasing the instrument’s lifetime (ISO 2013a). Inserting a moving mechanical device in a flue gas is generally not advisable; however, in some applications the method might be useful for short‐term reference measurements.

Tracer Gas Dilution

Tracer gas injection is available as a reference method technique in EN‐ISO 16911 (ISO 2013a) but is not incorporated into any U.S. or Canadian source monitoring rules.

Tracer gas methods measure the transit time for a gas to travel between two measurement points in a stack or duct. The tracer gas chosen is not normally present in the flue gas, is easily measurable by a gas monitor, and does not react with other flue gas components. Radioactive tracers are typically used in the application of the method.

In this method, the gas is injected at a controlled and measured flow rate using a single pipe, or multiple pipes, preferably at a point of mixing (e.g. after a fan) or a point that does not lead to its stratification. The tracer gas should be well mixed with the flue gas. The gas is measured by the analyzer at a point downstream of the injection port using a single or multi‐port probe. The measurement location should again exhibit minimal stratification of the tracer gas.

The method gives the average stack gas velocity by dividing the length between the injection and measurement locations by the transit time of the tracer gas between them. Detailed procedures and an uncertainty analysis of the method are given in EN‐ISO 16911 (ISO 2013a).

CONTINUOUS FLOW MONITORING METHODS

A number of techniques have been applied for continuously monitoring flue gas flow. The methods vary from the installation of a single pitot tube at a fixed point in the stack to the use of ultrasonic flow monitors measuring across the stack. Each method has its advantages and disadvantages, and one can usually be selected that will meet regulatory performance specifications. However, and as will be discussed later, flow monitors are typically calibrated against a reference method (or methods), and their accuracy will depend greatly on how that calibration is conducted.

The techniques discussed in the following text are application dependent. Accordingly, when selecting a flow monitoring instrument, it is necessary to consider factors such as monitoring location and velocity stratification over the measurement cross section, flow pattern stability over the range of operating conditions, measurement points or path lengths, particle characteristics and particulate loading, flue gas temperatures, and stack vibration. Failure to consider these factors may result in significant maintenance issues or bias issues that may lead to overreporting or underreporting of mass emission rates.

Single Type‐S Pitot Tube

The simplest method of monitoring flow is to install a single pitot tube at a fixed point in the stack and to continuously monitor the velocity pressure, ∆p, using a transducer/transmitter. However, if daily calibration checks are required, as in EPA Part 75, plumbing will need to be added to check the daily operation of the transducer. If the probe is prone to plugging from particulate matter, a blowback system may also be necessary.

Numerous installations have utilized this method by installing the probe at a point representative of the average velocity. If the probe is calibrated against an area average determined by a suitable manual reference test method, representative measurements can be made as long as the velocity distribution pattern does not change from the time of initial calibration.

Averaging Differential Pressure Probes

A pitot tube obviously measures at only one point although multiple tubes can be used to average a flow distribution across the stack or duct (Figure 7‐5a). Here the impact and static pressures from two or more pitot tubes are combined to obtain a multipoint averaged velocity pressure.

A multipoint average can also be obtained by using an averaging differential pressure probe (Figures 7‐4b–7‐5e). Averaging probes are modified forms of the pitot tube, having multiple ports in a tube that can be located at the traverse points corresponding to the centers of equal areas of the stack cross section. The pressure ports face the direction of flow and give the average impact pressure over the stack diameter. The wake pressure is averaged using the ports drilled in a separate tube located 180° from the high‐pressure ports. The two tubes serve as manifolds to give the averaged pressures. Because the port locations will be different for each installation, stack dimensions must be carefully specified before the probe is constructed.

Several averaging probe designs are shown in Figure 7‐5b–e. The trademarked annubar probes of Emerson/Rosemount (formerly Rosemount and Dieterich Standard) are shown in Figure 7‐5b–d. The annubars shown in Figure 7‐5b and c are constructed as two tubes in one by welding two tubes at the center to provide impact and wake pressure manifolds. The patented Rosemount T‐shaped sensor shown in Figure 7‐5d utilizes slots in the front of the T to average the upstream impact pressure and holes at the back of the T to average the wake pressure (see Figure 7‐5d inset). This design is claimed to increase signal strength and reduce noise. In the Air Monitor design shown in Figure 7‐5e, the impact pressure tube and wake pressure tube are supported by a truss in a cantilever arrangement.

An averaging probe averages on only one diameter. If two probes are installed perpendicular to each other, the flow would be more completely characterized, or in rectangular ducts, in severe flow stratification, multiple probes can be used to average over the cross‐sectional area (Figure 7‐6).

Similar to the pitot tube, the accuracy of averaging probes is dependent on the constancy of its calibration coefficient (Cp) and assumptions associated with the stack gas density (molecular weight/composition). Also, cross‐flow existing in the annubar due to different port pressures can be an issue (Ginesi and Grebe 1987). However, the severity of such a problem would become evident when certifying the installation.

Figure 7‐5 Multipoint averaging techniques using differential pressure sensing systems.

Figure 7‐6 Multiple averaging probes in a rectangular duct.

The pitot tube and averaging probes are not as sensitive to low flow rates as they are to high flow rates since low pressure drops (∆p) are difficult to measure accurately. Agglomerating particulate matter, acid gases, and moisture droplets can cause system failures. However, using blowback techniques can minimize such problems. When there are substantial flow variations due to turbulence, the systems may also include a “ballast” tank to buffer, or smooth out, fluctuations in the Δp measurement.

Note from Equation 7‐3 that velocity is a function of the square root of the pressure differential ∆p. For multiple pitot tubes or averaging probes, average velocity should be calculated from the average of square roots of the ∆p values and not the average ∆p. Calculating average velocity from the average ∆p leads to a positive bias.

Thermal Mass Flowmeters

Thermal mass flowmeters are based on the transfer of heat from a heated body to the flowing gas. The flowing gas convects the heat away to cool the body – the greater the flow, the greater the cooling. Because the flue gas temperature will fluctuate, this technique requires two sensors, a sensor heated to 75°–100 °F above the flue gas temperature and a temperature sensor.

In a typical configuration (Figure 7‐7), a platinum resistance wire is wound on a ceramic cylinder, which is then protected by a stainless steel tube. In thermal sensing systems used for stack monitoring, the velocity sensor is not allowed to cool. Instead, more power is sent to the velocity sensor to maintain its original temperature. As the flowing stack gas passes over the velocity sensor, the current through the element is increased using a bridge circuit to keep the temperature differential between the velocity and temperature sensor constant. For heated wire sensors, the mass flow rate of the gas is proportional to the amount of power input (Kurz 1997; Olin 1994).

Figure 7‐7 Thermal sensor.

The current necessary to maintain a constant temperature differential is related to the heat loss of the velocity sensor due to the flue gas flow. The rate of cooling of the velocity sensor is dependent upon the thermal conductivity of the stack gas, which is, in turn, dependent upon gas viscosity and specific heat. Gas viscosity, in turn, is dependent upon gas velocity and gas density. As a net result of these effects, thermal sensing instruments produce an output that is proportional to mass flow and not volumetric flow:

(7‐4)

where

ρ = gas density

Tv = temperature of velocity sensor

Ts = stack temperature

f(heat loss) = an empirical function dependent upon the temperature differential, gas composition, and power input to the velocity sensor

vs = flue gas velocity

As = stack cross‐sectional area

When mass flow rates are calculated, the values for gas pressure and temperature do not need to be determined. However, when velocity or volumetric flow is needed (cubic meters or cubic feet of gas per hour), gas density (grams per centimeter or pounds per cubic foot) is required. Because gas density is dependent on its composition, changes in stack gas moisture content, CO₂ concentrations, and so forth will affect the calibration of the instrument. The theory of thermal anemometry has been discussed in detail by Olin (Webster 2000).

If particulate matter adheres to the sensors, it will cause some drift in calibration unless the coating equilibrates. Vendors recommend that the sensors be installed for at least a week to allow this coating to stabilize (Groce 1995). Coatings can be removed by flash heating the sensors similarly to that of a self‐cleaning oven. Air purging is also used for particulate removal. In general, however, thermal dispersion monitors are better applied to clean gases, rather than gases that incorporate “sticky” materials.

The method is not appropriate in applications where water droplets are present. Because it measures convective heat loss, the heat loss due to evaporation of water droplets will cause flow rates to be reported higher than actual.

Multiple thermal sensors can be easily combined in arrays to measure the average flow rate over the cross section of a duct or stack. Since each sensor makes an independent measurement, it is possible to monitor the gas flow distribution over the cross section. Such arrays are often useful in ductwork where the flow is severely stratified. Capital costs of an array of sensors will increase with increasing duct size because more sensors will be required and greater truss support will be needed.

Figure 7‐8 Acoustic measurement of flue gas velocity.

Ultrasonic Flow Monitors

Ultrasonic flow monitors measure the time that it takes ultrasonic sound pulses to travel with the flow direction of the stack gas and against the flow direction of the stack gas (Kleppe 1992; Meyer 2005). In this method, ultrasonic pulses in the range of 50 kHz are transmitted both upstream and downstream of the flow (Figure 7‐8). Two transceivers are located opposite each other on the stack at an angle of typically 45°. In each transceiver, a piezoelectric transducer transmits ultrasonic pulses over the path, L, to the opposite transceiver. The transducers both convert electric signals to acoustic signals and acoustic signals to electrical signals. The speed at which the pulse crosses the stack is dependent upon whether it is going with or against the flow:

Speed in the direction of flow:

(7‐5)v Subscript upper A normal Baseline equals StartFraction upper L Over t Subscript upper A Baseline EndFraction equals c plus v Subscript s Baseline cosine theta

where

L = path between A and B

tA = forward transit time from A to B

vA = speed from A to B

vs = stack gas velocity

c = speed of sound

θ = angle between stack and path L

Speed against the direction of flow:

(7‐6)v Subscript upper B Baseline equals StartFraction upper L Over t Subscript upper B Baseline EndFraction equals c minus v Subscript s Baseline cosine theta

where

tB = transit time from B to A

vB = speed from transceiver B to transceiver A

Note that ±vscosθ is the vector contribution in the L direction, of the stack gas velocity to the transit of the pulse.

If these two equations are subtracted, the stack gas velocity can be obtained.

(7‐7)

This expression is independent of the speed of sound, c, and when used with the stack cross‐sectional area will give the volumetric flow rate in actual cubic feet per minute. Note that the expression is independent of other gas properties such as density, pressure, or temperature.

If the expressions for the forward and reverse velocities are added, the speed of sound, c, can be obtained.

(7‐8)

Since the speed of sound is temperature dependent by the relation

(7‐9)c equals upper K upper T Superscript 1 slash 2

the stack gas temperature is then

(7‐10)upper T equals left-parenthesis StartFraction c Over upper K EndFraction right-parenthesis squared

where

K is a constant related to the specific heat ratio and the average molecular weight of the gas (Traina 1985).

The ultrasonic flow method provides a mechanism for an internal check of the system, where an internal zero can be obtained by electronically substituting the signal going with the flow, for the one going against the flow. This should result in tA = tB and vs = 0. An upscale system check can be obtained by introducing a known delay in the tone pulses and monitoring the delay.

Because the instrument is an in‐situ path system, it is not subject to corrosion and particulate fouling problems that may affect in‐stack, insertion‐type probes. However, particulate matter can foul the transducers, although purge air can be blown directly through or over them to keep them clean. High temperatures are found to affect the transducers; however, the purge air can help to keep them cool.

Although the ultrasonic method produces a line‐averaged measurement, the average does not necessarily correspond to an area‐averaged velocity. The sources of error in the method have been studied extensively by Lau (1997), Martz and associates (Martz et al. 1998), and most recently by the National Institute of Standards and Technology (Bryant et al. 2018). In particular, cross flow or swirl caused by an upstream bend in the ductwork can cause significant errors in ultrasonic flow measurements (Johnson 2017; Johnson et al. 2018). In pitched flow, where the flow is “pitched” toward the downstream transducer, the flow will read high, because of a larger differential in the transit times that would otherwise be seen if the flow were parallel to the walls of the stack or duct.

One option to address pitched flow is to install a single ultrasonic monitor perpendicular to the plane of the bend of two intersecting ducts (Traina 1992). This will eliminate the effect of the pitch on the downstream transducer and allow a flow determination that can be better correlated with a K correction factor and less dependent on unit operating conditions.

Another remedy is to minimize the angle between the transducers and the pitch. Yet another approach is to install two transducer sets configured, consistent with the flow characteristics, in an X pattern in the same plane, (Figure 7‐9a). Such a configuration can compensate for the flow errors caused by pitched flow and swirling (cross) flow (Johnson et al. 2018; Martz et al. 1998; Meyer 2005).

For nonuniform flow in which the velocity profile varies over the cross section, another set of X‐pattern ultrasonic flow monitors installed in the plane perpendicular to the other plane on crisscrossed diametrical paths (90° pattern) (Figure 7‐9b) can average out the variation in a manner similar to conducting Method 2 on two the stack diameters shown in Figure 7‐4. Where pitched or swirling flow is not present, a single transducer set on each plane may be sufficient. Martz et al. (1998) reported errors of less than 3% for utility stack installations for such configurations.

Figure 7‐9a Ultrasonic flow monitor planar X pattern.

Figure 7‐9b Ultrasonic flow monitor – a 90° pattern with crisscrossed X‐pattern transducer sets.

Other approaches are to install two monitoring sets either parallel to each other or in a 90° X pattern but with one being higher and the other lower in the duct. Depending upon the level of accuracy required and the expense one wishes to incur in research and design, multiple monitor sets (eight or more) installed in different configurations can be installed to provide optimal flow measurements (Drenthen et al. 2009; Johnson 2017; Lynnworth et al. 1992).

Time‐of‐Flight Methods

Time‐of‐flight instruments sense patterns in the flue gas as they move up the stack. These may be patterns in refractive index, infrared radiation, or particle distribution. Time‐of‐flight instruments, like ultrasonic instruments, have no components in the stack and have no moving parts. The methods can be used on both large stacks and small ducts, and because they calculate velocity by measuring the time‐of‐flight, they do not require ancillary measurements of stack temperature and/or stack pressure as do other flow monitors. However, particulate matter can foul the transmitter and detector lenses, so an air purge is usually necessary for stack‐mounted units.

Optical Scintillation

An optical time‐of‐flight technique developed by Wang and associates (Wang 2003; Wang and Buhr 2002; Wang et al. 1981) has seen wide application in petroleum refineries and other industrial sources in an instrument manufactured by Optical Scientific, Inc. (OSI). In the technique, a red light emitting diode is used to transmit a light beam from one side of the stack to the other side to two detectors, spaced a few cm apart (Figure 7‐10). The motion of flue gases moving through a stack or duct is turbulent, and turbulent eddies of the hot gases will form. As the beam passes through the flue gas, it “scintillates” (shimmers or twinkles) due to changes in the refractive index caused by the temperature gradients in the flue gas. These refractive index fluctuations create patterns that retain their configurations as the flue gas moves up the stack. A cross‐correlation signal processing technique is used to measure the similarity of the temperature gradient patterns between the two detectors. The time that it takes for a pattern to traverse the distance, d, between the two detectors is the time‐of‐flight, t, which then can be used to calculate the velocity, v = d/t.

Although the method can be applied for temperatures up to 1000 °C, it cannot measure accurately when thermal fluctuations are not present, such as at unit startup. In this case, a heated rod located approximately 1 meter below the monitor (see Figure 7‐10) has been used to develop artificial thermal fluctuations sufficient to measure the flue gas velocity.

Figure 7‐10 Time‐of‐flight optical scintillation method.

A similar technique described by Zhang et al. (2016) uses two diode lasers, emitting at 630 nm over parallel paths to two cross‐stack detectors. The optical scintillation caused by particle concentration fluctuations is also analyzed by a cross‐correlation technique.

Infrared Correlation

A cross‐correlation time‐of‐flight instrument developed by Codel (Kufta 1997) monitors patterns of infrared light emitted from a hot, turbulent flue gas, as they move up the stack. The method employs two broadband infrared detectors that are placed on the side of the stack in the direction of flow, at a distance of the stack diameter or less (Figure 7‐11). Lenses focus infrared radiation from hot flue gas molecules onto the detectors.

The motion of flue gases moving through a stack or duct is turbulent, and turbulent eddies of gases will form. These eddies can produce regions of higher levels of infrared radiation, which can then be tracked as they move up the stack. The two infrared sensors measure the time for these transient fluctuations to move between them to determine the eddy convection velocity, which can be related to the flue gas velocity. This technique has also been applied using UV and IR televisions for remote sensing of flue gas velocity at stack exits (Herget and Conner 1977).

OTHER METHODS

The Stack Venturi

A straightforward method for monitoring flue gas flow is to use the stack or duct itself as a meter. By designing a constriction between two tapered sections into the duct or stack, a rather large venturi meter can be constructed. A ring of pressure taps inserted before the venturi monitors the upstream static pressure, and a ring of pressure taps around the constriction measures the lower static pressure at that point (Figure 7‐12). The pressure differential between the two sets of taps measured by a transducer can then give the flue gas flow rate.

Arguments against this approach center about the cost of construction and costs associated with extra fan power needed to move the flue gas through the constriction. These costs may not necessarily be excessive, particularly in process industry applications. Excellent results have been shown with this approach compared to an ultrasonic monitor installed in the same stack (Thillman 1998).

Physical Models

Installing flow monitors in a stack may be expensive if access to a suitable measurement location is not already available. A duct installation might be considered instead, but it may be first necessary to determine whether the flow measurements at the alternative location would be biased relative to stack measurements at the stack. This can be accomplished by constructing a model of the ductwork out of plexiglass or other materials and then studying flow patterns under various flow conditions. Building physical models for flow studies can be significantly less expensive than providing access to alternative locations, installing ports, and testing at the facility. The method has been applied for a variety of industries and applications, particularly in installations where flow stratification may be problematical (NELS 2020).

Figure 7‐11 Time‐of‐flight infrared correlation.

Figure 7‐12 A stack venturi for monitoring flow.

Computational Fluid Dynamics

Computational fluid dynamics (CFD) can be applied for mathematically modelling flow distribution in stacks and ducts. The computer software necessary for computations has become widely available, enabling application to a broader range of source flow monitoring issues. Use of the models does require some expertise, and care must be taken in understanding model limitations; however, the CFD method can be useful in supplementing or validating a wider flow study.

Determination of Flow Rates from Engineering Calculations

Engineering methods using combustion stoichiometry, input–output relations, or correlations based on fan horsepower or steam flow rate can also be used for determining flue gas flow rates. Energy balance methods (Input–Output Methods) can also be used, where the heat input to the system is determined by difference, and stoichiometric or F‐factor calculations are used to calculate volumetric flow rates. This method requires a thorough understanding of the unit operation, and the procedures tend to be specific to the unit. Such calculations are frequently done for other purposes, such as optimizing process operations to increase operational efficiency.

Engineering methods can also be used to check measurements made by installed continuous flow monitoring systems. This may be done upon installation of the system or as an ongoing check, as required in the flow‐to‐load requirements of 40 CFR 75 Appendix B.

MONITORING FLOW IN PIPES

By monitoring the heat input rate to gas or oil‐fired boilers and gas turbines, the flue gas volumetric flow rate can be determined without the use of a stack gas flow monitor. Here, fuel flow monitors are installed in the fuel supply pipes and typically transmit the flow data to the plant distributive control system where the stack gas flow rate is calculated. F‐factor techniques (see Appendix A) can be used in this calculation by first determining the heat input rate, QH:

(7‐11)upper Q Subscript upper H Baseline equals upper R Subscript f Baseline times upper G upper C upper V

where

QH = combustion source heat input rate

Rf = fuel feed rate

GCV = gross calorific value (high heating value) of the fuel

(7‐12)

where

Qs = flue gas volumetric flow rate (dry basis)

Fd = dry F factor

QH = heat input rate

%O2d = percent oxygen (dry)

20.9 = percentage of oxygen in ambient airor

(7‐13)upper Q Subscript s w Baseline equals upper F Subscript c Baseline StartFraction upper Q Subscript upper H Baseline Over percent-sign upper C upper O Subscript 2 d Baseline EndFraction times 100

where

Qsw = volumetric flow rate (wet basis)

Fc = F sub c factor

%CO2w = percent CO₂ (wet basis), if the %CO₂ is given on a dry basis, a dry basis volumetric flow rate is obtained.

The gross calorific value (GCV) may be provided by the fuel supplier or measured by installing a gas chromatograph on‐site to continuously determine the fuel gas composition, from which GCV can be calculated. This technique is appropriate for gas and oil‐fired sources; however, for sources in which fuel may be variable ‐ such as incinerators and coal‐fired power plants, this method is not applicable since, in such cases, fuel sampling and analysis is difficult, resource intensive, and not sufficiently accurate. Fuel flow meter flow rates typically are required to meet a 2% accuracy specification where this method is allowed.

Methods for monitoring fuel gas flow in pipes are basically the same as those applied to stack monitoring: differential pressure, ultrasonic, time‐of‐flight, and other techniques. In addition, techniques using orifice and venturi meters are applied for monitoring fuel flow. The certification and quality assurance criteria for fuel flow monitors are specified in Appendix D of Part 75, which addresses their use in gas and oil‐fired units (U.S. EPA 2020j).

Orifice meters consist of a plate with a hole smaller than that of the gas pipe, restricting the flow (Figure 7‐13). By using the Bernoulli equation, the static pressure difference between the upstream and downstream side gives the gas flow rate.

Orifice meters are common at gas‐fired‐boiler and gas turbine facilities. Those facilities subject to Subpart D of Part 75 must conduct annual tests on differential pressure, static pressure, and temperature transducers and transmitters (U.S. EPA 2020j). Also, the orifice plate must be removed annually and checked for warping, nicks, or scratches. Mechanisms have been designed where the plate may be removed and inspected without unbolting the pipe flanges.

CALIBRATING FLOW MONITORING SYSTEMS

It is generally assumed that once an instrument is calibrated, it will be able to perform accurate measurements directly. For example, a gas monitor calibrated with independent certified calibration gas traceable to NIST standard reference materials (SRMs) will produce gas concentration data directly without further adjustment, or an opacity monitor calibrated with certified neutral density filters will report opacity data accurately. The calibration technique may be even an internal one, using reference spectra or reference gas cells, as done in some analyzers, to produce reportable emissions data. However, for flow monitors, calibration with independent traceable standards is not possible. The only means of calibration is in a wind tunnel having known flow characteristics monitored by another flow monitoring instrument.

The problem with monitoring velocity and volumetric flow in a flue gas is that factors associated with ductwork configuration, cross‐sectional geometry, stratified flow, swirling flow, changing flue gas composition, and other flue gas inhomogeneities will affect the flow measurement. A flow sensor can be calibrated in a wind tunnel having known flow characteristics, or the transducer may be independently calibrated, but ultimately, the flow measurements of an installed system must take into account the location and flue‐gas‐specific factors of the emission source.

Figure 7‐13 The orifice meter.

The “Pre‐RATA” and the K Factor

Due to the issues mentioned in the previous paragraph, to better approach the “true value” of the flue gas velocity or volumetric flow, the response of a flow monitor must be corrected to account for source‐specific variables.

This can be done by conducting a “pre‐RATA” (pre‐Relative Accuracy Test Audit), in which the flow monitor is calibrated against an EPA reference method (U.S. EPA 2020a–d). The pre‐RATA is performed similarly to a certification test by traversing the stack with a pitot tube, measuring the flow at a minimum of 12 points (Figure 7‐4) and averaging the subsequent measurements to obtain an area average for the volumetric flow according to EPA Method 1 (U.S. EPA 2020a).

A suitable correction factor (or correction factors, for different loads) is applied to the monitoring system so that it provides the same results as the reference method. The volumetric flow rate is then expressed as

(7‐14)

where

K is known as the flow monitor K factor, which corrects for flow variables for which the instrument itself does not account.

The idea here is that the reference test method provides the “true value.” It is performed over at least 12 points on the stack cross section at three loads, and is, after all, the “reference method.” This practice is not required, but was performed in the U.S. acid rain allowance trading program, for which the immediate goal was to certify the systems in a relative accuracy test audit (RATA) to under 15% or preferably less than 10%. Because a pre‐RATA is conducted the same manner as a RATA, a flow monitor corrected to Method 2 pre‐RATA data would obviously pass a certification test without problem. The practice was so successful that the original relative accuracy specification of 15% was eventually tightened to 10%.

Conducting a pre‐RATA to establish a correction factor is a simple correlation technique. However, detailed correlation procedures and specifications have not been established for flow monitors either in Part 60 or Part 75. This is in contrast to more rigorous correlation procedures used in Part 60 PS‐11 for the calibration of continuous particulate monitors. Note that although a flow monitor may pass a RATA after being corrected by a pre‐RATA, if conditions under which the K factor was developed change, the correlation may no longer hold. The technique therefore suffers from a limitation to all modeling or correlation methods – the dependency of the constancy on the underlying assumptions of the correlation.

This practice is similar to European calibration procedures, where installed gas, flow, and particulate monitoring systems are all required to be “calibrated” against reference test methods to within statistical limits specified in CEN standard EN 14181 (CEN 2014). Establishing a K factor or a K “function” where the factor changes with load is basically the same procedure as the method performed according to standards EN 14181, or Part 60 PS‐11 for particulate matter, except that it does not include the statistical criteria given in either standard.

Problems in Calibrating Against a Reference Method

Although flow monitors were successfully certified for application in the U.S. acid rain program, problems surfaced after a few months of operation. The pre‐RATA correlations seemed to hold well in most applications and retesting did not exhibit the need to radically alter initial correlations. However, when plant engineers began to contrast flow estimates based on engineering calculations to flow monitoring data, differences of from 0 to 17%, or higher, were noted (Kearney 1995). More seriously, flow monitors generally gave higher volumetric flow rates than the engineering calculations. The implication here is that if the engineering calculations are true, flow monitors are biased high, which results in potentially higher SO₂ emission rates (Equation 7‐1) and a potential loss of allowances or higher emission tax payments.

This problem led to much controversy. Differences from the engineering calculations were blamed on either the flow monitors or the engineering calculations, respective parties being certain that their data were correct. Others sought “the reason” for the problem, some single causal factor that created the discrepancies between the two methods, and once found, would resolve the issue. Michael Cashin and his associates (Cashin et al. 1996) approached this issue systematically by performing a detailed analysis of biases associated with both methods. One of the problems was that the CEM system operators were not always informed by flow monitor installers that the system was calibrated empirically through the pre‐RATA. Cashin showed that many of the biases were not due to the flow monitors, but due to the reference method (EPA Test Method 2) to which they had been calibrated. He also noted that most of the biases were positive, that EPA Method 2 tend to give results higher than true if the Type‐S pitot tube is not calibrated properly, if the direction of flow is not perpendicular to the face of the tube (non‐axial flow), if the actual flue gas density is not determined, if the drop in gas velocity at the stack walls is not addressed, and so on. He noted that biases can also occur in engineering calculations through the assumptions made in F‐factors, biases in heat input determination, and biases in CO₂ determination.

Experimental evaluations of these biases proved the findings of Cashin and his associates to be correct. In fact, by factoring out the biases, it was found that closure within 2–3.5% could be reached between the two methods (McRanie et al. 1997). Considering the nonuniformity problems associated with flow monitoring, this difference is within experimental error.

The USEPA has also addressed this issue by evaluating EPA Method 2 and pitot tube designs other than the Type‐S tube (Lieberman 1998; Lieberman and Schakenbach 1997). From this extensive laboratory and field study, three new methods were developed to resolve issues associated with non‐axial flow and wall‐effect errors (Cadmus 1997, 1999). Method 2F derives the flue gas axial velocity using a three‐dimensional pitot tube; Method 2G derives a “near‐axial” velocity through the “yaw‐nulling technique” using the Type‐S pitot tube; and Method 2H provides a means to correct for wall effects in circular stacks. These methods became effective in 1999. A conditional test method, CTM‐041, may be used for flow measurements in rectangular ducts (U.S. EPA 2003). Using the three‐dimensional spherical pitot tube in Method 2G and conducting wall‐effect measurements according to Method 2H or CTM‐041 have been found to give the most accurate results at NIST laboratories (Shinder et al. 2018). By performing these methods in a pre‐RATA, greater accuracy can be realized in the application of flow monitors and discrepancies in flow and heat rate determinations can be minimized.

Pitot tubes and flow reference methods have been studied exhaustively over the past 50 years in the United States and the European Union. These studies have varied in their quality, and many have added little that has not already been known. However, the work by the U.S. EPA in the late 1990s (Lieberman 1998; Lieberman and Schakenbach 1997), work conducted by CEN for the EU standard, EN 16911‐1, and, more recently, the flow studies by NIST are significant. Definitive work is being conducted by NIST with the construction of the Scale Model Smoke Stack Simulator (SMSS), and the development of a program designed to reduce uncertainties of flow measurements to less than ±1%. The aim of this work is to improve the accuracy of gas flue gas emission measurements used in greenhouse gas mitigation programs (Bryant et al. 2014; NIST 1998, 2018; Shinder and Johnson 2017; Shinder et al. 2018).

Where it makes sense, the utility industry in the United States readily applies the 2F, 2G, and 2H reference methods primarily because improvements in the methods will generally remove positive biases and tend to drive the flow values lower (Whitaker and Gentry 2019). Advances in flow monitoring, such as the application of computer‐driven automated probes at each of the four ports on the sampling cross section, are now offered as a commercial service. The use of the prism and spherical probes has become a frequently requested test method, despite of the increased costs with probe calibration. Because the reference methods are so important in establishing flow monitor K factors, it is now viewed that the most representative and accurate values possible are needed when reporting large volume emissions for carbon tax, carbon trading, or other programs.

PERFORMANCE SPECIFICATIONS FOR FLOW MONITOR CERTIFICATION

Several certification procedures have been published for flow monitors. The first was published in 1988 as Performance Specification 6 in Part 60 Appendix B. More detailed specifications are provided in Appendix A of Part 75, to meet the special requirements of the acid rain program. Internationally, the International Standards Organization (ISO) and European Committee for Standardization (CEN French: Comité Européen de Normilisation) issued a joint ISO‐European Norm (EN) as EN‐ISO 16911 in 2013.

The performance specifications or standards used to certify a flow monitor may be designated either in the rules of a national, state, or provincial regulating body or in the monitoring requirements given in the plant operating permit or license. A flow monitoring requirement given without designating the applicable performance specification for certification is deficient.

Part 60 Appendix B Performance Specification 6

Performance Specification 6 was derived from PS‐2 for gas monitors in 1988, at a time when flow monitoring issues were not well understood. The intent of specification PS‐6 of Part 60 Appendix B is to certify continuous emission rate monitoring (CERM) systems, i.e. systems where emissions are reported as a pollutant mass rate (PMR) in units of pounds per hour, kilograms per hour, or tons per year (see Equation 7‐1). A calibration drift test at low and high levels (0–20% of FS and 50–100% of FS) and a relative accuracy test are required to be conducted in this specification.

The calibration drift test is conducted for both the pollutant and flow monitors and calculated and reported independently. Low‐ and high‐level drift for the flow monitor is required to be ≤ 3% of the high‐level value used in the drift test.

The PS‐6 relative accuracy test may be conducted using an applicable test method for the pollutant monitor and either EPA test methods 2, 2A, 2B, 2C, or 2D for the flow monitor. Relative accuracy in PS‐6 is calculated using the combined pollutant–flow monitor system in the units of the pollutant mass rate standard and is required to be ≤ 20% of the reference test method or ≤ 10% of the applicable emissions standard. The relative accuracy of the flow monitor with reference to test Method 2 is not calculated or reported independently in PS‐6.

Part 75 Appendix A Specifications.

Design and certification procedures for flow monitors are found in Appendix A of Part 75 (U.S. EPA 2020i). Part 75 specifications are more evolved than those of Part 60. In contrast to Part 60, Part 75 specifies how the span value of the monitor is to be determined and requires interference checks for certain types of monitors.

Spanning the Instrument

The span value for combustion source flow monitors is calculated from the maximum potential velocity (MPV) as follows:

(7‐15)

where

Fc = dry basis F factor

Hf = maximum heat input

A = inside cross‐sectional area of the flue at the flow monitor location

%O2d = maximum oxygen concentration, percent dry basis, under normal operating conditions

Alternatively, the Fc factor can be used instead of the Fd factor as follows:

(7‐16)

where

Fc = carbon‐based, CO₂ F factor

%CO₂ = minimum CO₂ concentration, percent dry basis, under normal operating conditions

The “calibration span” value is determined by multiplying the MPV by a factor of between 1.0 and 1.25 and rounding up to at least two significant figures. However, the range of the instrument should be selected such that the majority of the readings are between 20 and 80% of the range. Note that as with gas monitors, the “span” is not necessarily the “range,” which is somewhat awkward, considering that most technicians and engineers use the terms “span” and “range” interchangeably. If not regulated under the Part 75 requirements, Equation 7‐15 or 7‐16 may nevertheless be useful in estimating a flow monitor range when purchasing a new flow monitoring system.

Interference Checks

As a design specification, Part 75 requires that flow monitors, where applicable, provide a means for detecting interference from particulate matter or condensation in the performance of the instrument. Differential pressure systems are required to incorporate a blowback system to purge sensing ports and pressure lines at least once each day. Thermal flow monitors are to provide a means of ensuring that the sensing element remains clean, such as by using flash heating. Similarly, ultrasonic flow monitors are to keep the transceivers free of particle buildup. Blowers are typically used for this purpose, which also serve to keep the transceivers cool.

Calibration Error Test

A seven‐day calibration error test is conducted where the instrument probe tip or transducer reference signal is introduced for each of seven days to a value 0–20% of span and a value 50–70% of span (as defined above). The calibration error must be ≤ 3% of the span value (as defined above).

Relative Accuracy Specifications

In contrast to Part 60, in Part 75, relative accuracy is not calculated in conjunction with the pollutant monitor, but is calculated for the flow monitor itself. The relative accuracy test is conducted at three unit loads for units that produce electricity: low (30% of the range of operation), mid (30–60%), and high (>60%).

In the original specifications published in 1990, the flow monitor was required to meet a relative accuracy of ≤ 15%, but if the relative accuracy was ≤ 10%, future relative accuracy tests would only need to be repeated annually instead of semiannually as part of the Part 75 quality assurance requirements. As with gas monitors, the more stringent specification was meant to serve as an incentive to enhance flow monitor performance. Later in 1995, the relative accuracy specification was changed to 10% and the incentive requirement as 7.5%. The monitor must pass these requirements at each load level at which the relative accuracy test is conducted (low, mid, and high).

Environment Canada Specifications

Guidelines for flow monitors in Canada are specified in the Environment Canada continuous monitoring protocols and performance specifications of document EPS 1/PG/7 ( ENVC 2005). Here, specifications are given for the full‐scale value, calibration drift, orientation sensitivity, and relative accuracy.

Full‐Scale Value

The operating range is recommended to extend from zero to approximately 100% of the maximum potential flow rate, to cover the range of velocities expected. If flows vary widely, multirange monitors are recommended.

Calibration Drift

Flow monitors are required to pass a calibration drift test at three levels: low (0–20% FS), mid (40–60% FS), and high (80–100% FS). The calibration drift specification is unusual, in that it is not determined with the flow monitor internal calibration system but at three‐unit operating loads (low, mid, and high). Reference method (RM) measurements are made at each load, and the calibration drift is calculated as the difference between the monitor response and the RM value as a percentage of full scale. This test is conducted for seven days and can be quite expensive for a base‐loaded unit required to change load three times a day for seven days.

The 24‐hr calibration drift must be ≤ 3.0% of FS or 0.6% absolute difference for all three levels determined over the seven‐day period.

Relative Accuracy

When conducting the relative accuracy test, the flow monitor measurement must be made concurrently with the pollutant gas reference method concentration measurements. The monitor must meet a relative accuracy specification of ≤ 10% or 0.6 m/s avg. absolute difference at a minimum safe and stable load, mid load (40–60%), and full load (90–100%). The instrument bias must be ≤ 5.0% of the full‐scale value or 0.6 m/s avg. absolute difference.

Orientation Sensitivity

This test is required for flow sensors sensitive to orientation, such as Type‐S pitot tubes. The sensor is rotated ±10° from the zero position, where the readings at 5° intervals must not differ from the zero‐orientation reading by more than 4.0%.

EN‐ISO 16911 Specifications

The EN‐ISO flow monitor specifications were standardized after the Part 75 rules were published and draw from much of the experience gained in the U.S. acid rain program. The EN‐ISO standard is more thorough than the Part 75 requirements because they address issues such as the effects of skewness and swirl in more detail and address directly how the “K” factor, or calibration function, is to be established. In addition, criteria for the acceptability of the “calibration function” are given (ISO 2013a,b). The European procedure of developing a “calibration function” is common to gas monitors as well as flow monitors in Europe and is detailed in the EN‐14181 procedures for automatic monitoring systems (AMS).

The Pre‐investigation

Before installing a flow monitor to meet the conditions of the ISO‐EN standard, it is recommended that flow profiles be investigated with regard to the plant operating conditions. This is especially important if different duct inlets are brought into operation or dampers are operated since the calibration function established under one set of conditions may not characterize the flow under another set of conditions.

The standard also recommends that the flow profile be characterized either by computational fluid dynamics or by testing at the intended monitoring location. Test measurements are to be made, at at least two different plant operating conditions – one where the flow profile is expected to be the most uniform (fully developed flow) and one where the flow rate is low, combined with changes in dampers or inlet flows. “Crest factors” (ratio of the peak value to the cross‐section sample line average flow) and “skewness” (a measure of flow asymmetry along a cross‐section sample line) area are to be calculated at both high and low flow unit operating conditions. These are then used in the selection of an optimal location and the type of monitoring system (point or cross‐stack).

Type‐Testing

As per European procedures, instruments must first meet the requirements EN:15627, type‐testing for the instrument model (CEN 2009). The type approval is conducted by an independent laboratory and includes both laboratory and field tests. The repeatability (analogous to calibration drift or error) is limited to ≤ 2% of the upper limit of the range (full‐scale value) at both lower and upper reference points. Linearity (lack of fit) should be less than 3% of the range.

The Calibration Function and Validation Criteria

In Part 75, the flow monitor K factor is determined at three loads from which a calibration function can be developed. As discussed above, this is similar to the procedure given in ISO‐EN 16911, which in turn references the procedures for developing calibration functions in EN 14181 (see Chapter 11). The calibration function is expressed as a linear equation:

(7‐17)y equals a plus b x

where

y = the calibrated value of the flow monitor

x = the measured signal of the flow monitor

a, b = constants

The equation must meet certain conditions for its variability and is to be determined over “the complete range of concentrations encountered during normal operations.”

FLOW MONITOR QUALITY ASSURANCE

Quality assurance procedures are addressed for flow monitors in Appendix B of Part 75 but not in Appendix F of Part 60. Part 75 requires that flow monitors subject to the rule perform daily calibration checks, interference checks, flow‐to‐load ratio tests, and a semiannual/annual relative accuracy test audit. If the K factor(s) is changed, the relative accuracy test must be repeated at three‐unit operating loads (low, mid, and high).

Daily Calibration Checks

Part 75 requires that the calibration of a flow monitor (calibration error) be checked at least once each unit operating day (U.S. EPA 2020f). Checks are to be conducted at values in the range of 0–20% of span and 50–70% of span. In effect, such flow monitor calibration checks are merely self‐tests; they are electronic or pressure checks of system components and not checks of the total measuring system (Shigehara and Peeler 1998). The checks do not verify the calibration of the instruments to a known fluid flow rate. No system has been designed that can auto‐calibrate itself in a flue gas where the velocity is not determined by some other means A periodic check of the monitoring system in a wind tunnel, where the volumetric flow is known accurately, would be ideal for this purpose, but this is neither practical or cost effective for installed continuously operated systems.

The self‐checks are specific to the type of monitor. As discussed, in ultrasonic monitors, a zero check is conducted by transposing the signal from one transceiver to the other. If the flue gas velocity is zero the transit time will be the same in both directions. If both receivers receive the same signal, the system should be fooled into reading zero. To check the upscale value of an ultrasonic monitor, a time delay that corresponds to a known increase in velocity can be introduced into the signal.

In differential pressure systems, low‐ and high‐level checks are conducted typically by closing off the sensing element (the pitot tube or averaging tube) and zeroing and pressurizing the pressure transducer. This adds greater complexity to the differential pressure sensing systems and has, in some cases, created more opportunities for leaks and valve malfunctions. Checks in thermal sensor systems are typically electronic stability tests, doing little to validate the response of the thermal elements themselves.

Daily Interference Checks

Flow monitor systems subject to Part 75 are required to perform daily “interference” checks. In ultrasonic monitors, it implies the system must check daily that the blowers keeping the transducers clean are operating. For differential pressure systems, a blowback system is essentially mandated to ensure that pressure ports are not plugged. Differential pressure sensing systems must be checked quarterly for leaks. Thermal sensing systems must provide some means for ensuring that the sensors remain clean enough to avoid interference.

Quarterly Leak Checks

A quarterly leak check of the pressure lines is recommended for differential pressure monitoring systems and is required under Part 75.

Flow‐to‐Load Ratio Test

Due to limitations of the flow monitor daily calibration drift tests to quality assure flow monitoring data, EPA requires conducting a flow monitor performance test, called the “flow‐to‐load ratio test,” where hourly performance data are summarized and reported quarterly (U.S. EPA 2020g,h). A similar test is specified in the Canadian continuous monitoring guidelines (ENVC 2005). The test involves correlating flow data to plant load data. In combustion sources, the flue gas volumetric flow rate increases proportionally to the load. The flue gas flow rate at a given load should therefore remain relatively constant. Accordingly, the ratio of the flow to load should be relatively constant at a given load. Hourly values of the flow‐to‐load ratio are calculated and compared to a reference ratio determined at normal load during a relative accuracy test. Sources having flow monitoring systems subject to Part 75 must summarize and report the average of the flow‐to‐load ratios that are determined at loads within 10% of the normal load at the time of the relative accuracy test.

The flow‐to‐load test is surprisingly sensitive to changes in both flow monitor and plant performance. For example, unexpected changes in the ratio have led to the discovery of sagging pitot tubes and boiler tube leaks. The test supplements the daily calibration drift checks in an important way, in that it provides an independent assessment of the flow monitor performance. The flow monitor drift checks are basically internal checks that monitor the stability of the instrument, but do not compare the measured results with an independent flow value. The flow‐to‐load ratio provides such a comparison.

In the flow‐to‐load ratio test, a “reference” flow‐to‐load ratio, Rref, is first determined when a normal‐load flow RATA is performed. The reference value is calculated as follows:

(7‐18)upper R Subscript r e f Baseline equals StartFraction upper Q Subscript r e f Baseline Over upper L Subscript a v g Baseline EndFraction times 10 Superscript negative 5

where

Qref = the average stack gas volumetric flow rate (in scfh) measured by the reference method during the normal‐load RATA

Lavg = the average unit load during the normal‐load flow RATA (MW)

Then, when the unit is operating at the normal load, the hourly flow‐to‐load ratios, Rh, are calculated:

(7‐19)upper R Subscript normal h Baseline equals StartFraction upper Q Subscript h Baseline Over upper L Subscript normal h Baseline EndFraction times 10 Superscript negative 5

where

Rh = the hourly value of the flow‐to‐load ratio, in scfh/megawatts or scfh/1000 lb/hr of steam load

Qh = the hourly stack gas volumetric flow rate (in scfh) as measured by the flow rate monitor

Lh = the hourly unit load in megawatts or 1000 lb/hr of steam; must be within ± 10.0% of Lavg during the most recent normal‐load flow RATA

The hourly error is then calculated as the absolute percentage difference between the hourly average flow‐to‐load ratio and the reference value of the flow‐to‐load ratio at normal load from Equation 7‐20:

(7‐20)

The arithmetic average of all hourly Eh values obtained when the unit load was within ±10% of the reference load over a quarter, is then calculated as Ef and reported in the Part 75 program. In this program, the results of the flow‐to‐load evaluation are acceptable if Ef does not exceed the following limits:

15% if Lavg for the most recent normal load flow RATA is ≥60 MW and if bias‐adjusted flow rates are not used in the calculations

10% if Lavg for the most recent normal load flow RATA is ≥60 MW and if bias‐adjusted flow rates are used in the calculations

If Ef exceeds the applicable limit, the facility must troubleshoot the monitor to identify the problem causing the failure to meet the limits. If a problem cannot be identified, a normal‐load RATA is required to be conducted to determine whether the instrument is reading accurately.

An abbreviated flow‐to‐load test may be performed after repair, component replacement, or corrective maintenance by averaging 6–12 hourly flow‐to‐load ratios and seeing if the error is within ±10 or ±15% as appropriate. However, an astute technician can readily recognize if the flow‐to‐load ratio is trending away from the reference ratio, without waiting to take action before calculating such an average.

Semiannual/Annual RATA

Part 75 requires that flow monitor relative accuracy be ≤10%. If in the last RATA, the relative accuracy is >7.5% and ≤10%, the test must be conducted twice a year, where the test may be conducted at a single level (normal operating load) and two levels (most frequent operating load and second most frequent operating load) in alternate years. A flow RATA may be conducted once a year at the two most frequently used load levels if the relative accuracy for the last RATA is ≤7.5% at each load. Also, the test can be conducted at a single load if the unit operated at that load 85% of the time. A three‐load RATA must be conducted every five years or whenever the K factor is changed.

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CHAPTER 8
OPACITY MONITORS

By placing a light source on one side of the stack and a detector on the other side and determining the intensity of light on both sides of the stack, the amount of light transmitted can be measured. The amount of light transmitted is the fraction of light from the light source that is measured at the detector. The term “opacity” relates to the fraction of light that is not transmitted. Instruments have been designed to measure light transmission and are in the general sense termed “transmissometers.” Transmissometers can be optimized to provide a signal that correlates to particulate mass concentrations, as we shall discuss in the next chapter. They can also be designed as an “opacity monitor” where the transmissometer is optimized to provide a measurement that can be correlated to the observations of a visual emissions (VE) observer (Conner and White 1980). In this chapter, the term “opacity” monitor is applied to transmissometers used for measuring in-stack opacity, or more fully:

An opacity monitor includes a transmissometer that determines the in-situ opacity, a means to correct opacity measurements to equivalent single-pass opacity values that would be observed at the path length of the emission outlet, and all other interface and peripheral equipment necessary for continuous operation.

Source: ASTM (2021a)

Opacity monitors are required to be installed in most of the larger stationary sources in the United States and Canada. Transmissometers are applied as particulate monitors in Europe and elsewhere.

As discussed in Chapter 4, scattering and absorption of light by particulate matter will reduce the transmission of light through a flue gas. The more particulate matter present in the flue gas, the more opaque the medium will become to the transmission of light. In terms of percentage, transmittance and opacity are related as

(8-1)upper T r a n s m i t t a n c e left-parenthesis percent-sign right-parenthesis equals 100 minus upper O p a c i t y left-parenthesis percent-sign right-parenthesis

In terms of fractions, the expression is

(8-2)upper T r equals 1 minus upper O p

where

Tr is the transmittance and

Op is the opacity.

Transmissometer measurements are performed in-situ and can be used to monitor the performance of air pollution control equipment, compliance with particulate mass emission standards, or compliance with opacity standards. Transmissometers can produce an output in units of mg/m³ after the instrument response is correlated with manual isokinetic sampling test data.

In the United States, federal opacity standards are based on visual determinations made by trained observers (EPA Test Method 9 (U.S. EPA 2020a)). Observers view the opacity at the stack exit after having been trained and certified in the procedure. In this test, the plume at the stack exit is viewed from an appropriate location with respect to the sun, and averages of a series of 24 observations are taken at 15-second intervals to determine opacity. EPA Test Method 9 was derived from the Ringelmann method (Stern 1968), in which a “smoke chart” was used to obtain a comparative opacity. If the method is performed properly, most readings (>95%) will have positive errors of less than 5% opacity. The method has withstood numerous court challenges and has been an essential tool in the support of agency particulate control programs. The direct use of in-stack opacity measurements by an opacity monitor is not precluded from compliance determinations in state programs, if the state control agency adopts requirements in this form. In contrast, in Europe, particulate emission standards are based on mass concentration units of mg/m³. There, flue gas opacity is not regarded as a viable regulatory parameter.

One of the problems associated with Method 9 is the subjective nature of measurement, which is dependent on the capability of the VE observer and the ambient conditions. Some of this subjectivity is removed when using a digital camera to apply the digital camera opacity technique (DCOT). This method was developed under U.S. army and air force programs with the intent of reducing costs associated with VE observer recertification. It was standardized by ASTM International (ASTM 2021b) and has been published by the U.S. EPA as alternative test method ALT 082 (U.S. EPA 2012; EMC 2020b). Various approaches have been taken with this method – from its initial intent in providing specifications and procedures for digital cameras, to its extension for smartphone applications (Du et al. 2007a, b; Yuen et al. 2013), and as a basis to support commercialization of the digital technique.

An alternative method for measuring stack-exit opacity senses laser light backscattered from plume particulate matter. This LIDAR technique (Light Detection and Ranging) is not dependent upon ambient lighting conditions and can measure plume opacity at night, if necessary. The method has been standardized and designated as an EPA test method, Method 9A – Determination of the Opacity of Emissions from Stationary Sources Remotely by Lidar (U.S. EPA 2020b). However, the method is rarely used, due to the instrumentation cost and the necessity of having skilled operators to apply the method.

If a transmissometer is intended to correlate with the visible emissions observer, it is required to meet certain design requirements, of which the most important one is the instrument must determine opacity using visible (photopic) light. If the data are to be correlated with particulate mass emissions, the use of photopic light is not required, and red or infrared light may be more appropriate. Other design features can be incorporated into a transmissometer to enhance overall system performance for monitoring mass emissions or opacity. This chapter discusses such design criteria for opacity monitors and shows how they are incorporated into a number of commercially available systems. Because of the importance of optical density calculations in transmissometer applications, calculation techniques are also reviewed.

BASIC COMPONENTS OF TRANSMISSOMETERS

In a transmissometer, the optical system is designed so that the transmittance is determined from two principal measurements: the measurement of Io (a reference measurement of light intensity) and I (the intensity of the light beam measured after light passes through the flue gas). The ratio of the two intensities, I/Io, is the fractional transmittance (Tr), which, from Equation 8-2, is equal to (1.0 − Op) where Op is fractional opacity.

As with in-situ path gas monitoring systems discussed in Chapter 6, transmissometers may be constructed using either a single-pass design (Figure 8-1) or a double-pass design (Figure 8-2). In the single-pass design, a lamp, light-emitting diode, or laser projects a light beam across the stack or duct leading to the stack, and the amount of light transmitted through the flue gas is sensed by a detector. Such instruments can be constructed rather inexpensively and are often used as baghouse monitors. However, they generally do not satisfy regulatory design criteria required for their use as opacity monitors.

The double-pass system shown in Figure 8-2 houses both the light source and light detector in one unit, the transceiver assembly. By reflecting the projected light from a retroreflector mirror housed on the opposite side of the stack, systems can be easily designed to check the electronic circuitry, including the lamp and photodetector, as part of the operating procedure. Most transmissometer systems include some type of air purging system or blower to keep the optical windows clean. In stacks with positive static pressure, the purging system must be efficient or else the windows will become dirty, leading to spuriously high readings. Shutters or flaps are often used to seal off the flue gas from the windows in case of blower failure. It is generally assumed that the blower air is sheared off at the stack wall by the flue gas and that the air does not penetrate further into the stack.

DESIGN SPECIFICATIONS AND MANUFACTURER’S PERFORMANCE SPECIFICATIONS FOR OPACITY MONITORS

For the monitoring of opacity, design specifications have been established for the manufacture of transmissometers that can provide in-stack opacity readings that correspond to out-of-stack visible emissions observations. These design specifications also set standards of construction so that the commercially manufactured instruments will function similarly. Opacity monitor design specifications are given in ASTM Standard Practice D6216 (ASTM 2021a) and are adopted by reference in U.S. EPA Performance Specification 1 (U.S. EPA 2020c).

The ASTM specifications are an extension of EPA Performance Specification 1, promulgated in 1975 (U.S. EPA 1975) and revised in 1983 (U.S. EPA 1983). By the 1990s, considerable experience had been gained by instrument manufacturers in the design and operation of opacity monitors. Both manufacturers and the U.S. EPA considered that the instrument design specifications could be tightened to improve precision, accuracy, and quality control. A majority of opacity monitor manufacturers met with ASTM International, a consensus standards body, and over a period of several years agreed on design standards that led to a new generation of opacity monitors. Published as ASTM D6216, the standard added design specification verification procedures, which include tests for instrument response to ambient light, effects of ambient temperature fluctuations, and the effects of supply voltage fluctuations. Previous EPA verification procedures for the determination of instrument calibration error, response time, and the effectiveness of optical alignment indicators could previously be determined by either the manufacturer or the owner/operator. ASTM D6216 establishes these verification tests as the responsibility of the manufacturer. A summary of the ASTM specifications is given in Table 8-1. For opacity monitoring, the most important of these specifications are those related to opacity-specific design and calibration. These are discussed further here. Details of the specifications and verification methods can be found in ASTM D6216 (ASTM 2021a).

Figure 8-1 Single-pass transmissometer.

Figure 8-2 Double-pass transmissometer system.

TABLE 8-1 Opacity Monitor Design and Performance Specifications

Opacity Monitoring Specific Design Criteria
Design Requirements for Calibration and Audit

Spectral response (peak and mean)
Angle of view and angle of projection
Insensitivity to ambient light
Path length correction factor security
Upscale calibration check device
Automatic zero compensation indictor
External audit filter access
Alignment indicator

Electronic Specifications
Manufacturer’s Performance Specification Tests

Supply voltage variations
Thermal stability
Status indicators
Resolution
Measurement recording frequency
Calibration error
Response time
Misalignment indication
Spectral response performance
Calibration device repeatability

Opacity Monitoring Specific Design Criteria

Spectral Response

An opacity monitor designed to provide data corresponding to visible emissions observations must project a light beam that has wavelengths in the visible or photopic range of the electromagnetic spectrum. ASTM specifications require that: “The peak and mean spectral responses must occur between 500 and 600 nm. The response at any wavelength below 400 nm or above 700 nm shall be less than 10% of the peak spectral response.”

Figure 8-3 shows a possible spectral response curve for a green light emitting diode (LED) (Traina and Myers 1990). The peak response is the wavelength where the monitor is the most sensitive and is the wavelength that corresponds to the highest value of the relative instrument response on the curve. The mean spectral response is the wavelength at which the instrument shows its mean or average sensitivity. There are three basic reasons for specifying opacity monitors to measure in the visible range (400–700 nm) of the spectrum.

Figure 8-3 Spectral response for a green LED.

Emissions observers determine flue gas opacity in the visible region of the spectrum. To make a comparable measurement, an opacity monitor must also be sensitive in this spectral range.

Water vapor and CO₂ absorb light energy in the near-infrared range of the electromagnetic spectrum (Figure 4-2). If a transmissometer projects light in this range, water vapor or CO₂ can absorb some of the light energy by molecular absorption processes, resulting in a higher opacity reading than that obtained using an instrument that projects light at shorter wavelengths in the visible range. Tungsten lamps emit light in the infrared region, but can still be used in opacity monitor systems if appropriate optical filter-detector combinations are employed to eliminate the detection of light at higher wavelengths. However today, most commercial opacity monitors use green light emitting diodes.

Light scattering is very dependent on the particle size relative to the wavelength of light impinging on it (as discussed in Chapter 4). For example, light at 450 nm has a maximum Mie scattering coefficient for particles in the range of 0.2 μm diameter, whereas light at 1000 nm has a smaller scattering coefficient for 0.2-μm-diameter particles and exhibits maximum scattering for particles having sizes of 0.5 μm and larger (Cashdollar et al. 1979). In industrial plants controlled with baghouses and electrostatic precipitators, most of the larger particles are removed. Because the stack-exit plume opacity results from the scattering of visible light from the uncaptured small particles, it is essential that monitors be designed to measure the loss of transmittance due to small-particle scattering.

Figure 8-4 (a) Angle of projection. (b) Angle of view.

The wavelength criteria for opacity monitors do not address the problem of NO₂ interference (Lindau 1991). NO₂ absorbs light in the visible region of the spectra as evidenced by the brown plume sometimes seen at the start-up of gas turbines or in photochemical smog. At high concentrations, NO₂ will be seen by opacity monitors as opacity caused by light absorption rather than by light scattering.

Angle of Projection/Angle of View

In Chapter 4, it was noted that light will scatter in many different directions after it impinges on a particle. If a transmissometer has a large detector or a lens that gathered light over a wide angle, it might measure the light that would ordinarily be lost to its field of view. As a result, the measured opacity will be lower than it should be, The transmittance will be too high; the detector sensing the scattered light, which will be counted as transmitted light.

Similarly, if the lamp and lens system project a cone of light at a wide angle, light could be scattered into the view of the detector instead of out of view of the detector. This will increase the measured transmittance and decrease the opacity. Because of the importance of these effects, design specifications have been established for the observation cone of the detector and for the spread of the cone of projected light. These specifications are expressed as (i) the angle of view and (ii) the angle of projection. Definitions given for monitor assemblies in ASTM 6216 are as follows:

Angle of projection. The total angle that contains all of the visible (photopic) radiation projected from the light source of the transmissometer at a level greater than 2.5% of its peak illuminance

Angle of view. The total angle that contains all of the visible (photopic) radiation detected by the photodetector assembly of the transmissometer at a level greater than 2.5% of the peak detector response

Measurements are usually made from the transceiver window or from the windows or lenses of the transmitter and receiver units of the monitor (Figure 8-4a shows the angle of view and Figure 8-4b the angle of projection). ASTM 6216 requires that these angles be less than or equal to 4°.

Insensitivity to Ambient Light

Because opacity monitors are designed to be sensitive to photopic light, sunlight reaching the detector either directly or by particle scattering will cause an increase in the transmission signal with a corresponding decrease in the opacity reading. Ambient light can enter through the top of the stack, from open ports in the stack, or openings or cracks in ductwork. In general, a stack is not dark inside.

To avoid this problem, the ASTM Standard Practice requires that the instrument exhibit no more than ±2.0% single-pass opacity when exposed to ambient sunlight over the course of a day. In the ASTM verification test for this specification, the instrument is set up at a flange-to-flange path length of 3 m, and a halogen lamp spotlight is used to illuminate the transceiver (or detector for a single-pass unit) on the optical axis of the opacity monitor.

Path Length Correction Factor Security

It is obvious from Bouguer's law Equation 4-6, that, for a fixed particulate concentration, light transmission will decrease as the path length of the light increases. In most cases, the measurement path of an opacity monitor is different than the diameter of the stack exit. Because the visible emissions observer reads opacity at the stack exit, to be comparable, data from the opacity monitor data must be corrected as if the instrument were measuring across the stack-exit diameter. A correction factor called the “path length correction factor” (PCLF) is used for this purpose. Other terms such as the “optical path length ratio” (OPLR), stack taper ratio (STR), or other such expressive terms are used, depending upon the manufacturer. The PLCF is the ratio of the emission outlet path length, lx, to the single-pass monitoring path length, lm.

(8-3)upper P upper L upper C upper F equals StartFraction l Subscript x Baseline Over l Subscript m Baseline EndFraction

l x , = emission outlet path length; the internal diameter of the stack at the stack exit

l m = the monitor path length, the effective single-pass depth of the effluent between the transmitter and receiver of a single-pass transmissometer

The monitor path length is not the flange-to-flange distance, but is defined by the ASTM as the single-pass optical path length of the opacity monitor through the flue gas, most typically being the inside stack or duct diameter at the installed monitor location.

The PLCF is used to calculate the equivalent single-pass opacity that would be observed at the stack exit. Expressions using the PLCF are given in the discussion of the stack-exit correlation equation.

In many of the early opacity monitors manufactured in the 1970s and 1980s, the correction factor could be “dialed” into the instrument using a potentiometer, thumbwheel switches, or keypad entries. Changing the correction factor also changes the opacity reading. Unfortunately, operators sometimes found it convenient to adjust the correction factor to bring an opacity monitor out of an alarm condition. In other cases, it became a convenient means to lower reported opacity values. Such practices are, of course, not permitted and can lead to civil and criminal penalties.

Newer monitoring systems now embed the correction further into the system programming. It is often accessible only through several layers of security or is set by the manufacturer at the factory, using owner-supplied stack and mounting dimensions. The ASTM Standard Practice now requires that the value of the path length correction factor be certified by the manufacturer and that

the PLCF cannot be changed by the end user; or

the PLCF is recorded during each calibration check cycle; or

the system must provide an alarm when the PLCF value is changed from the certified value.

Design Requirements for Calibration Check Devices

Opacity monitors meeting ASTM specifications are required to incorporate an automated mechanism that checks the instrument calibration daily, after it is installed on the stack. The result of the calibration check is reported typically as “calibration drift.”

Depending on the design of the calibration mechanism, the calibration drift reported can be the sum of both the dust accumulation on the monitor windows and electronic drift, or merely the electronic drift, if the system compensates for dust accumulation. To perform a calibration check, a method is needed to provide a “simulated zero” or “pseudo-zero” as a reference to an upscale calibration filter or reflector. The simulated-zero device produces a simulated clear path condition or low-level opacity condition that checks the operation of the active internal optics electronics and electromechanical systems of the analyzer. Two methods are used to perform this function. One method uses a “zero mirror” and the other uses reflectors of differing reflectance.

In the zero-mirror approach, a mirror is mounted on the transceiver assembly and flips into the path of the light beam to reflect the light back into the transceiver to the detector. The reflected light does not go through the stack, so it should provide some constant reference value that is indicative of the instrument stability. While in place, an upscale attenuation filter can flip into the light beam to give an upscale calibration value. The upscale calibration filter may be either a screen, a series of metal slats, or an optical filter.

In the reflectance approach, two reflectors, located on the outside of the transceiver box, sequentially reflect the light back to the detector. Reflectors with high and low reflectance (reduced reflectance) provide two reference points for the calibration check. This technique does not actually produce a zero value, but generates a greater than 10% opacity value as one point of what is essentially a two-point calibration curve.

External Audit Device

When opacity monitors are used for compliance purposes, it is important that they be auditable. Data that are supported by successful periodic audits are more credible when subjected to the tests of litigation. An opacity monitor must incorporate a method or be able to utilize a device that provides an independent assessment of the instrument performance when using independent audit filters. Filters traceable to the National Institute of Standards and Technology (NIST) standards are typically used in these audits.

The monitoring system may include a slot within the mounting flange air plenum or other location or may use an external, removable device (or “audit jig” as they are often called) in which audit filters can be inserted. Audit jigs were developed to check the performance of double-pass transmissometer systems (Cohen and White 1980; Hamil 1980). Basically, the devices consist of a slot for holding calibration filters and a short-range retroreflector assembled into a holder that can be attached onto the transceiver. The device and transceiver basically constitute a “mini-transmissometer” that can accommodate audit calibration filters. Figure 8-5 shows such an audit device.

Figure 8-5 Opacity monitor audit jig attached to the transceiver assembly.

A reflector mirror at the end of the device serves as a reflector intermediate in position between the simulated-zero reflector and stack retroreflector. Certified filters can be placed between this retroreflector and the transceiver head to check the “calibration error” of the instrument over a range of opacities. The device also contains an iris, which allows the reflectance of the mirror to be adjusted so that it will correspond to the true, stack zero. The device must be designed so that the entire beam received by the detector will pass through the calibration attenuator, minimizes interference from reflected light, and when in the zero-measurement mode without filters, must return the same energy (within ±5%) to the detector as the instrument would at clear path conditions over the installed measurement distance. Procedures for conducting these audits are given in 40 CFR 60 Appendix F Procedure 3 and are discussed later in this chapter (U.S. EPA 2020e). See also Plaisance and Peeler (1988).

Alignment Indicator

A well-designed transmissometer system or opacity monitor will incorporate a method to indicate optical misalignment. In a stack- or duct-mounted double-pass monitor, temperature changes, vibrations, or poor maintenance procedures may cause the retroreflector assembly to shift with respect to the transceiver, resulting in a different portion of the beam hitting the reflector and returning to the detector at the transceiver. In a single-pass monitor, the projected beam may move over or stray from the detector. When the beam intensity is not uniform over the projected area, optical misalignments can change the value of the signal at the detector, independent of flue gas opacity. The filament in a tungsten or quartz halogen lamp can project a pattern of the filament, or the electrical contact of an LED can produce a dark spot in the middle of the beam (Hovan et al. 2004). If a small amount of light hits the detector due to a “shadow” in the beam, the opacity will read higher than it actually is in the stack.

An alignment indicator meeting the criteria of D6216 shows that the system is misaligned when a movement of the transceiver both laterally and rotationally in the vertical and horizontal planes leads to a > ±2% error in the opacity reading. For opacity monitors applied for opacity standards <10% opacity, misalignment must be indicated if the misalignment error is > ±0.25% opacity for a ±2.5° rotational misalignment. This is a significant increase in stringency for low-level opacity monitors. The alignment indicator provides an inspection point that can be checked periodically by the CEM technician or by a corporate or agency auditor.

Electronic and Other Specifications

Electronic specifications related to supply voltage variations, thermal stability, status indicators, resolution, and measurement recording frequency are also given in ASTM D6216. These specifications are typical of those given in industry standards, but are not always incorporated in regulatory standards. Their inclusion in the ASTM Standard Practice adds to the set of design criteria intended to enhance the overall quality of opacity monitors used for compliance reporting.

Manufacturers' Performance Specification Tests

These tests are performed by the manufacturer on each instrument before it is shipped to the user. The data recording system is not evaluated in the manufacturer's tests; however, additional field tests are still required to evaluate the complete opacity monitoring system after it is installed. The manufacturer must conduct tests for response time, calibration error, alignment, spectral response, and reproducibility of the calibration device.

For the manufacturer's tests, the monitoring system is set up in a clean, smoke-free environment, with the transceiver and retroreflector assemblies separated by a distance equivalent to the distance between their points of attachment on the stack or duct on which they will eventually be installed (the flange-to-flange distance). The instrument is configured so that it will produce an output that is correlated to the stack-exit opacity (lx) by setting the value for the path length correction factor.

The instrument is then turned on, aligned, and calibrated. Because the monitor is now measuring only laboratory air, it should read zero opacity. At this time, the simulated-zero system of the transceiver assembly is adjusted so that it corresponds to the measurement of zero over the smoke-free test path. In systems using an external audit jig, this also requires that an adjustable or selectable aperture, such as an iris, in front of the zero reflector of the jig be adjusted to provide a response equivalent to that of the zero obtained by the instrument at the installation path length.

The Response Time Test

The response time is the amount of time it takes the opacity monitoring system to display, on a data recorder, 95% of a step change in opacity. The test is performed to demonstrate that an opacity monitor can make a measurement at least once every 10 seconds, the minimum response time specified in both ASTM D6216 and PS1.

In this test, a high-level calibration attenuator (screen or other neutral density filter) is placed in the beam path, and the time it takes for the instrument to go from its zero value to 95% of the attenuator value is measured and recorded. This is the upscale response time. After the attenuator value is reached, the attenuator is removed. The time it takes for the monitoring system to go from the attenuator value down to 5% of the value is measured and recorded. This is the downscale response time. This procedure is repeated until five upscale times and five downscale times have been logged. The five upscale response time values are then averaged and the five downscale values are averaged. Both the upscale and downscale average response times are required to be less than 10 seconds.

TABLE 8-2 Calibration Error Attenuator Values

Applicable Standard | 10–19% Opacity | ≥20% Opacity
Low level | 5–10% opacity | 10–20% opacity
Mid level | 10–20% opacity | 20–30% opacity
High level | 20–40% opacity | 30–60% opacity

The Calibration Error Test

The calibration error test is performed by placing three different neutral density filters (calibration attenuators) in the light path of the monitor. Using the appropriate path length correction factor and the opacity standard of the intended installation, ranges for single-pass values for the optical filters are given in Table 8-2:

The attenuators must be calibrated against a laboratory spectrophotometer or be certified that they are calibrated by an independent laboratory.

The actual calibration error test is very simple. First, a low-range attenuator is placed between the transceiver (transmitter) and retroreflector (receiver) to obtain a monitor reading. Next, a mid-range filter is placed in the path, followed by a high-range filter. The measured opacity is recorded on a data sheet, and the procedure is repeated until five separate measurements are obtained for each filter. The measurements for each filter are taken nonconsecutively. After the 15 measurements are taken, the calibration error is calculated from the difference between the measured value and the certified filter value. The calibration error for each filter is the sum of the mean difference of the five tests and the confidence coefficient (a measure of the variability of the measurement), Equation 8-4.

(8-4)upper C upper E equals StartAbsoluteValue x overbar EndAbsoluteValue plus StartAbsoluteValue c c EndAbsoluteValue

where

(8-5)

(8-6)

and,

xi = Opacity monitor response – Attenuator value for ith measurement

n = number of measurements made with each attenuator (t0.975 = t − value t0.975 = 2.776 for n = 5)

The calibration error is required to be less than 3% opacity for each filter.

The Spectral Response Performance Test

This performance check is a simple way of assuring that each opacity monitor conforms to the spectral response design specifications. Here, a transmission filter is used, having a transmission of greater than 80% at 500 nm and a 50% transmission point between 550 and 575 nm. After placing the filter into the beam, the manufacturer is required to calculate the expected opacity for the filter and also the expected values if the opacity monitor’s wavelength is shifted by ±20 nm. The measured opacity must fall within the range of the ±20 nm shifts.

Calibration Device Value and Repeatability

This test is also performed after the calibration error test and relates the calibration error results to the reference value obtained by the instrument reference light attenuator. In the test, the reference attenuator is placed into the light path five times. The instrument response (plus confidence coefficient) is then compared to the responses of the calibration error filters. Using Equation 8-6, the confidence coefficient must be less than 1.5% opacity. A value is assigned to the reference attenuator, based on the certified values of the filters used in the calibration error test.

The Manufacturer’s Certificate of Conformance (MCOC)

Verifying that opacity monitors are properly designed and meet required specifications is time consuming and requires the use of special equipment. Because analyzers of a given model are designed and manufactured in the same way, there is little purpose to check each instrument. The ASTM Standard Practice requires that one analyzer, randomly selected from each month's production or one from each group of twenty opacity monitors, whichever is more frequent, be tested according to the design specification verification procedures given in ASTM D6216. Only one monitor must be tested each year for conformance with the spectral response specifications, thermal stability, and insensitivity to ambient light. The purchaser of an opacity monitor must then obtain a “Manufacturer’s Certificate of Conformance” (MCOC) which states that either the analyzer or an analyzer manufactured during the month in which the purchased analyzer was produced, passed all of the verification tests specified in ASTM D6216. The certificate should be obtained from the instrument vendor and must include the results of each test performed on the sampled analyzer. The plant environmental engineer should either file or retain a copy of the MCOC so that it will be available when an agency inspector wishes to verify that the monitoring system meets the ASTM D6216 specifications.

Design Specifications For Low-Level Opacity Monitors

When ASTM D6216 was first published in 1998, the ASTM task group preparing the standard practice considered that the design specifications were not stringent enough to assure that opacity monitors could read accurately at opacity levels below 10% opacity. However, an opacity emission limit of 3% opacity had been established for steel industry electric arc furnaces in 40 CFR 60 Subpart AAa (U.S. EPA 2020d). For an opacity limit of 3%, a calibration error specification of ≤ ±3 is clearly inadequate. In the late 1990s, several manufacturers developed monitors with tighter specifications and marketed them as being capable of measuring opacity at levels lower than 10%.

Subsequent work established criteria for opacity monitors at opacity levels of less than 10% (Stuart 2008). Values for these criteria and revisions to D6216 were published in 2003 as D6216 with the addition of Annex A – Addition or Alternative Specifications for Certifying Opacity Monitors for Use Below 10% Opacity (Low-level Opacity Monitors). Differences between the D6216 and Appendix A requirements are summarized in Table 8-3.

An uncertainty analysis was conducted for each class of opacity monitor, by first estimating uncertainties of individual parameters that are associated with overall opacity measurement. The combined uncertainties were determined by taking the square root of the sum of the square of the individual uncertainties (variances) in the standard uncertainty analysis. Although this calculation may not consider all contributing factors and assumes the factors to be uncorrelated, the root sum-square error for a monitor manufactured according to the original specification was ±5.8% opacity and for a monitor manufactured according to the more restrictive criteria of Appendix A was calculated to be ±1.8% opacity (ASTM 2021a).

OPACITY MONITOR INSTRUMENT DESIGN

It was mentioned previously that transmissometer optical systems are designed so that two principal measurements can be made: the measurement of Io (the intensity of a reference light beam) and the measurement of I (the intensity of a light beam that has passed through the flue gas). The ratio of the two intensities, of course, gives the transmittance.

Several methods are used to obtain this ratio in commercially marketed opacity monitors. These methods incorporate beam splitters, reflectors, and optical fibers. Other techniques were used in the past, but many of them were discontinued due to either market competition or upgrades to newer designs. Also, instrument manufacturing companies are bought and sold over time, resulting in discontinuation of products or their rebranding. Descriptions of some of the discontinued products may be found in earlier editions of this book. The optical systems tend to be unique to each manufacturer and are therefore discussed here with respect to current manufacturers. The most widely used monitors in 2020 are included in this edition.

TABLE 8-3 Summary of Manufacturer’s Specifications and Requirements (shaded boxes show more restrictive criteria)

Specifications
D6216
Requirements
D6216 Annex A
Requirements

Spectral response
500–600 nm
500–600 nm

Angle of view, angle of projection
≤4°
≤4°

Sensitivity to supply voltage variation
1.0% opacity
0.2% opacity

Thermal stability
2.0% opacity
0.3% opacity

Insensitivity to ambient light
2.0% opacity
0.2% opacity

External audit filter access
Required
Required

External zero device repeatability
1.0% opacity
0.3% opacity

Thermal drift of external zero device
—
0.4% opacity

Automated calibration checks
All active components
All active components

Simulated zero check device
90–110% of energy reaching detector under clear path conditions
90–110% of energy reaching detector under clear path conditions

Upscale calibration check device
Between 10% opacity and highest audit filter value
Between 2% opacity and highest audit filter value

Status indicators
Manufacturer selected
Manufacturer selected

PLCF security
3 options
3 options

Measurement output resolution
0.5% opacity
0.1% opacity

Measurement and recording frequency
10 s
10 s

Instrument response time
≤10 s to 95% of final value
≤10 s to 95% of final value

Calibration error
3% opacity
1% opacity

Optical alignment indicator
Indicate ±2% opacity
Change due to misalignment
Indicate ±0.5% opacity
Change due to misalignment

Indication of optical misalignment in transmitter or transceiver
2% opacity
≤0.5% opacity

Effect of optical misalignment in receiver or retroreflector
2.0% opacity
≤0.5% opacity

Calibration device repeatability
1.5% opacity
≤0.5% opacity

Beam Splitter Techniques

Beam splitters are made from coated optical glass so that they both transmit and reflect a portion of the incident light. They are useful in electro-optical instruments for directing light through an optical assembly, as we have seen in several of the gas monitors discussed earlier. Beam splitters are applied rather ingeniously in transmissometer systems to measure transmittance using a minimum number of components. Opacity monitors manufactured by Teledyne-Monitor Labs, Sick Inc., and AMETEK Land fall into this group.

The Teledyne-Monitor Labs Light Hawk 560 Opacity Monitor

The Light Hawk 560 opacity monitor measures transmittance using two detectors (see Figure 8-6).

Tracing the path of a light beam projected from the green LED in the bottom left-hand corner of the figure, the light passes through an aperture to a beam splitter that transmits a portion of the light to a reference detector. This detector provides the reference, or Io value for the transmittance measurement. The first beam splitter, in addition to transmitting light to the reference detector, reflects light to the principal beam splitter, which, in turn, reflects the light out of the transceiver to cross the stack or duct to the retroreflector. The light returning from the retroreflector enters the transceiver and this time passes through the beam splitter to reflect from another beam splitter to the measurement detector to give the measurement signal, I. The ratio of I/Io gives transmittance, which can be converted easily into opacity or optical density. Light is also transmitted through the third beam splitter to provide for an alignment check of the monitor.

Figure 8-6 Light Hawk 560 opacity monitor schematic.

The relative responses of the two detectors must be determined, since it is usually difficult to obtain identical responses from different detectors. This is done when the zero reflector is in front of the beam. The upscale calibration check is performed when the neutral density reflector is moved into the beam.

The light from the light emitting diode is pulsed, to code the transmitted light so that the detector will be insensitive to ambient light. The instrument detector and electronic system are designed to detect only the pulsed or modulated light. Unmodulated light that reaches the detector from the stack-exit or stack openings will not be detected.

The Sick OMD-41 Opacity Monitor

The Sick, Inc. OMD 41 opacity monitor is a double-pass system that performs a transmittance measurement by using beam splitters and two detectors. These components are shown in Figure 8-7, which illustrates the instrument light paths in the measurement mode of operation. Here, light is projected from a light emitting diode through a beam splitter and then on to the primary beam splitter. At the primary beam splitter, the light is both transmitted through the splitter and reflected from it. The reflected part continues to a mirror which reflects it back to the splitter. This time, the beam is transmitted through the splitter to a reference detector. The reference detector measures the incident light as the Io value (reference zero value).

The light that passes through the primary beam splitter continues through a lens on the transceiver housing, through the clear portion of a swinging disk, and through the stack. The light passes through another disk and is reflected back by a retroreflector. When it reenters the transceiver, it reflects from the primary beam splitter to impinge on the measurement detector and give a value for I (the measurement value). Again, the ratio of I/Io, gives transmittance. The relative response of the two detectors is determined, by swinging the zero-point reflector in front of the transceiver lens. This gives a “pseudo-zero” condition at which the measuring detector and reference detector should give the same response. Any differences can then be compensated electronically in this calibration cycle.

The alignment between the transceiver and retroreflector assemblies is checked by the light returning from the retroreflector being reflected off of a beam splitter to a “bull's-eye” alignment sight on the side of the transceiver. A small circle of light can be observed, which should be centered in the bull's-eye to indicate proper alignment. Adjustments to the instrument mountings are necessary if the alignment is found to be unacceptable.

Figure 8-7 Measurement mode of the Sick double-pass opacity monitor.

This instrument is one of the few opacity monitors designed to check both the transceiver and retroreflector assemblies for particulate matter accumulation on the optical surfaces that are potentially exposed to flue gas. The swinging disks contain windows that in normal operation are placed in position in front of the transceiver or retroreflector lenses. The windows of the swinging disk are periodically and alternately swung away from the lenses of the assemblies. A discrepancy in response with the windows in front of and away from the lenses indicates that particulate matter has fouled the assembly. The instrument will automatically correct reported opacity values up to a specified level (typically, 4% opacity). For “dirty window” corrections greater than this level, an alarm will register, and cleaning may be required.

This instrument design also provides a calibration system for obtaining an upscale opacity reading. When the zero reflector is moved into the path of the light beam, an upscale calibration attenuator can be moved into the path of the light beam. This produces an opacity value that checks the electrical and optical components of the transceiver.

The AMETEK Land 4500 MKIII Opacity Monitor

The AMETEK Land 4500 MKIII opacity monitor operates similarly to the Sick, Inc. instrument. Light from a light emitting diode is projected to a primary beam splitter, where it is split into a reference beam and a measurement beam (Figure 8-8). The reference beam is again reflected from a mirror to a reference detector (to give the reference value, Io). The measurement beam passes through the stack and returns from the retroreflector to reflect from the beam splitter to a measurement detector (to give the measurement value, I).

The relative response of the two detectors is checked by flooding them with light when the zero mirror is in place. Again, a calibration filter is used to check upscale light attenuation and the lamp is pulsed to produce a response insensitive to ambient light. The optical alignment sight is located on the side of the transceiver, where light returning from the retroreflector and transmitted through the beam splitter, impinges on the bull's-eye alignment sight.

The company has developed a homogeneous light source by arranging a number of LEDs in conjunction with an optical diffuser to meet the alignment requirements for low-level opacity monitors (Hovan et al. 2004).

The Durag DR-20 Opacity Monitor

The optical design of this instrument is shown in Figure 8-9.

In the measurement mode, a broadband diode light source reflects light from a beam splitter to project it across the stack to a retroreflector and then back through the beam splitter to a detector where the beam intensity is measured to produce the measurement signal (I). Light from the diode also passes through the beam splitter to a reference reflector to reflect the light off of the beam splitter and then to the detector to produce a reference signal (Io). The ratio of the two signals is again transmittance (T), used to determine the flue gas opacity.

Figure 8-8 Beam splitter function in the measurement and flood mode of the Ametek double-pass opacity monitor. (a) instrument measurement mode. (b) detector calibration flood mode.

A control cycle is initiated periodically to check the zero and calibration of the system. During this cycle, the instrument automatically measures and displays the zero-point, window contamination, and upscale calibration value. With the zero-mirror moved in place to block the beam from entering the stack, a zero reading is obtained. By rotating the filter wheel to move the reference filter in front of the zero mirror, an upscale calibration reading is obtained. If the contamination is >4% opacity, a warning signal will be generated. If the reading is less than 4% opacity, the subsequent measured values will be corrected for window contamination.

Figure 8-9 The Durag D-R 290 opacity monitor.

The MIP Opacity Monitor

Single-pass units can meet calibration requirements that check the active electronic and optical system components by using either fiber-optic cables or a zero pipe. By placing a pipe across the stack and either flushing it with clean air or sealing it to be free of particulate matter, zero values can be obtained; however, this is a maintenance-intensive activity. A more practical method is to use a fiber-optic cable, running it around the stack from the light source to the detector on the opposite side. Such a system originally designed by the Finnish company, MIP, is unique in using a helium–neon laser as a light source (Hovan and White 1996) (Figure 8-10).

In this system, a low-power laser emits light at 543 nm and is, of course, highly collimated, so that it easily meets specifications for angle of projection and view. No windows or lenses are incorporated into either the transmitter or receiver assemblies of the system, and either plant instrument air or blowers can be used for air purging at the ports. The instrument incorporates a double chopper assembly that uses two calibration reflectors and two detectors. In the measurement mode of operation, light from the laser is reflected from a mirror, passes through the double chopper assembly and through the stack to the main measurement detector to produce the flue gas measurement. The chopper then rotates so that the light reflects off of the mirrored lobe of a large shutter of the double chopper. The light is reflected into the optical fiber and is transmitted through the optical fiber to the main detector on the opposite side of the stack to provide a zero reference measurement (see also, Jahnke 2000).

The double chopper next rotates into a position where a smaller shutter with a mirrored surface moves into position to reflect the laser light up to the reference detector contained within the transmitter. (Note that this smaller shutter is positioned so that light is reflected up to the reference detector and not into the optical fiber.) The large calibration shutter next swings into place to reflect the laser light into the optical fiber and to the main detector. A further rotation brings the smaller calibration shutter into place to reflect the light up to the internal reference detector.

In total, a zero measurement and upscale calibration measurement are made for each detector. Light transmitted over the optical fiber checks the zero baseline and calibration response of the main detector. A change in the zero value when the shutter is in the zero position for this detector can indicate dust accumulation on the main detector surface. Signals from light reflected to the reference can check for changes in laser light intensity. Compensation to the instrument calibration can be made by using this performance check. An audit slot (not shown) allows audit filters to be placed between the double chopper and detectors to provide an independent filter check of the instrument response.

Low-Cost Units

Several companies manufacture simple single-pass units that can be zeroed and calibrated only under clean-stack conditions. These units consist of a light source on one side of the stack and a detector on the other side. These monitors may be perfectly adequate for specific applications, such as baghouse monitoring, but in general will not meet the ASTM design criteria. The advantage of using them is that they are lower in cost, weigh less, and are easier to install compared to double-pass units.

Figure 8-10 Single-pass laser opacity monitor using fiber-optics for calibration checks.

Older Units

Opacity monitors have evolved over years, particularly after the original publication of ASTM D6216 in 1998. Several monitors described in earlier versions of this book are no longer available because companies discontinued their manufacture or upgraded their instruments to meet the design specifications of D6216. See Jahnke (1984, 1993, and 2000) for descriptions of instruments previously manufactured by Rosemount, Inc., Thermo Environmental, and Dynatron.

Probe-Type Opacity Monitors

Probe-type opacity monitors are basically in-situ point monitors consisting of a transceiver assembly and a probe. Probes of fixed lengths are designed to attach onto the transceiver, where the probe body serves as a support for a retroreflector located at the end. The retroreflector is usually a glass corner-cube designed to withstand flue gas temperatures. Probes vary from 1 to 2 m in length.

These transportable units may at first appear useful for inspection and auditing; however, there are several drawbacks to their use. First, they only measure a small portion of a stack diameter, a portion that is closest to the stack wall and more subject to particulate stratification. Second, standards and procedures have not been established for these systems. These two issues of unrepresentativeness and unstandardized procedures limit their application for both technical and regulatory purposes.

LIDAR

An alternative method for measuring stack-exit opacity measures laser light backscattered from plume particulate matter. The light ranging and detection (LIDAR) technique is not dependent on ambient lighting conditions and can measure plume opacity at night. The method has been standardized by EPA and designated as EPA Method 9A (U.S. EPA 2020b). Significant research studies were conducted using the method in the 1970s and 1980s for stack monitoring (Dybdahl 1981; Johnson 1969; Uthe 1983). Although the method is finding many new applications in fields such as ecological modeling, agricultural and forest studies and archeological mapping, interest in source monitoring applications has waned despite of the possibility of conducting useful research in this area (da Costa et al. 2011).

OPTICAL DENSITY/OPACITY CALCULATIONS

Although the relation between opacity and transmittance is quite straightforward, opacity and transmittance are not parameters that change in a linear fashion with respect to changes in path length, particle density, or the degree of light absorption and scattering from particles. As we have seen from the Bouguer equation (Equation 4-8), the relation between these parameters is logarithmic:

(8-7)upper T r equals left-parenthesis 1 minus upper O p right-parenthesis equals e Superscript minus n a upper Q upper L

where

n = number concentration of the particles

a = projected area of the particles

Q = particle extinction coefficient

L = length of the light path through the flue gas

To provide a greater degree of flexibility in calculation, the optical density expression, introduced in Chapter 4, is often used. To review from Chapter 4, Equation 4-9, the optical density, D, is simply the logarithm to the base 10 of the reciprocal of the transmittance, or

(8-8)

In Chapter 4 Equation 4-12 it was also shown that the optical density is directly proportional to the particle concentration and also to path length:

(8-9)upper D equals StartFraction n a upper Q l Over 2.303 EndFraction equals left-bracket StartFraction upper A Subscript upper E Baseline Over 2.303 EndFraction right-bracket c l

where

AE is called the specific mass extinction (with units of m²/g), a function of the particle scattering characteristics, volume, and density. For most purposes, AE can be assumed to be constant.

Again, n is particle number density, a is the particle area, Q is the particle extinction coefficient, and l is the path length of the light through the sample. Note from the expression, that if AE is constant, the optical density is directly proportional to the concentration

The antilog of Equation 8-8 can be taken to express opacity in terms of optical density as follows:

(8-10)upper O p equals 1.0 minus 10 Superscript negative upper D

Most commercial instruments will have an optical density scale on the meter panel, or can provide the optical density as part of the instrument output along with the opacity readings.

Optical density is useful in a number of calculations necessary for correcting and reporting opacity monitor data. These include (i) calculating stack-exit opacity, (ii) calculating audit filter values, (iii) calculating combined opacity readings, and (iv) correlating opacity measurements to mass emissions, as discussed in the following sections.

Stack-Exit Correlation

A visible emissions observer determines the flue gas opacity at the stack exit; however, opacity monitors are installed further down in the stack or in a duct leading to the stack. To obtain some consistency between these observations and opacity monitor readings, the data are corrected to a single-pass stack-exit value.

If the diameter of the stack differs from the opacity monitor path length, a relationship between the two can be derived from the optical density expression (refer to Figure 8-11). Assuming that the concentration of the particulate matter is the same at the stack exit as it is at the monitor location, consider that the optical density Dx at the stack exit is

(8-11)

where

lx = the monitor path length.

Similarly, for a single-pass opacity monitor, the optical density of the flue gas at the monitor location is

(8-12)

Figure 8-11 A tapered stack.

where

lm is the inside diameter of the stack at that location.

By dividing the two expressions, the optical density at the stack exit can be obtained:

(8-13)upper D Subscript x Baseline equals StartFraction l Subscript x Baseline Over l Subscript m Baseline EndFraction upper D Subscript m

Taking the antilogarithm of Equation 8-14 and solving for opacity, the stack-exit path-length-corrected opacity value can be obtained:

(8-14)

And the path-length-corrected stack-exit opacity for a single-pass opacity monitor will be

(8-15)

For a double-pass system, the light traverses the stack twice; therefore the monitor path length is two times lm, and

(8-16)upper D Subscript x Baseline equals StartFraction l Subscript x Baseline Over 2 l Subscript m Baseline EndFraction upper D Subscript m

and

(8-17)

In terms of the path length correction factor, PLCF, for a single-pass system, Equation 8-16 becomes

(8-18)upper O p Subscript x Baseline equals 1 minus left-parenthesis 1 minus upper O p Subscript m Baseline right-parenthesis Superscript upper P upper L upper C upper F

and for a double-pass system, Equation 8-18 becomes

(8-19)

Another term called the “optical path length ratio” (OPLR) which is equal to one half the PLCF for double-pass systems, resulting in the expression

(8-20)upper O p Subscript x Baseline equals 1 minus left-parenthesis 1 minus upper O p Subscript m Baseline right-parenthesis Superscript upper O upper P upper L upper R

A useful form of the expression can be obtained by combining optical density and opacity values in the same formula. Starting from Equation 8-17 for a double-pass system,

(8-21)upper D Subscript x Baseline equals StartFraction l Subscript x Baseline Over 2 l Subscript m Baseline EndFraction upper D m

(8-22)

(8-23)

and

(8-24)

These derivations may not be necessary, but it is often difficult to determine how a vendor calculates the stack-exit opacity from the stack and opacity monitor path length measurements. Equations 8-13 through 8-24 have given five possible expressions that can be used in correlating the stack-exit opacity to the in-stack opacity monitor readings. These are summarized in Table 8-4. The calculation method used by the instrument vendor should be checked before installation to verify whether the appropriate single-pass or double-pass path length is used in the instrument setup.

For a tapered stack, the flue gas is not appreciably compressed at the outlet of a tapered stack. The velocity increases at the stack exit, but the particulate matter concentration and the volumetric flow rate will be the same at both locations. Therefore, if the diameter of the stack at the stack exit is less than the distance the opacity monitor light beam traverses at the monitor location (OPLR < 1), opacity will be smaller at the stack exit than at the monitoring location.

The expressions are, of course, derived from theory. In practice, they are valid only if various conditions are met. Generally, if the opacity monitor is located so that it is monitoring representative stack emissions, the correlation expression will give the correct stack-exit values. If, however, the opacity monitor is installed at a stratified location, seeing inconsistent or abnormally high or low particulate concentrations across the path length, the stack-exit opacity may not agree with the readings of a visual emissions observer. Also, condensation, particle agglomeration, or chemical reactions at the stack exit could create difference between in-stack and stack-exit readings. Connor and McElhoe (1982) have evaluated observer opacity monitor data and have found that, in general, observer readings at the stack-exit and in-stack opacity monitor readings will agree to within ±10% opacity.

TABLE 8-4 Equations for Calculating the Stack-Exit Opacity

| Single-Pass | Double-Pass
1 | upper D Subscript x Baseline equals StartFraction l Subscript x Baseline Over l Subscript m Baseline EndFraction D m | upper D Subscript x Baseline equals StartFraction l Subscript x Baseline Over 2 l Subscript m Baseline EndFraction D m
2 |  |
3 | upper O upper P Subscript x Baseline equals 1 minus 10 Superscript minus StartFraction l Super Subscript x Superscript Over l Super Subscript m Superscript EndFraction upper D Super Subscript m | upper O upper P Subscript x Baseline equals 1 minus 10 Superscript minus StartFraction l Super Subscript x Superscript Over 2 l Super Subscript m Superscript EndFraction upper D Super Subscript m
4 | upper O upper P Subscript x Baseline equals 1 minus 10 Superscript minus upper D Super Subscript m Superscript upper P upper L upper C upper F | upper O upper P Subscript x Baseline equals 1 minus 10 Superscript minus upper D Super Subscript m Superscript StartFraction upper P upper L upper C upper F Over 2 EndFraction
5 | upper O upper P Subscript x Baseline equals 1 minus 10 Superscript minus 2 upper D Super Subscript m Superscript normal upper O upper P upper L upper R | upper O upper P Subscript x Baseline equals 1 minus 10 Superscript minus upper D Super Subscript m Superscript normal upper O upper P upper L upper R

Calibration Filter Selection

The expressions given above can also be used for selecting opacity monitor calibration and audit filters. For example, if an inspector wishes to check the performance of a double-pass instrument using an audit filter, consider the following:

A double-pass opacity monitor has been adjusted so that all opacity readings are corrected as if the instrument were measuring across the stack exit, using a stack-exit correlation function (see Table 8-4).

Given a neutral density filter having a certified opacity or optical density value, what will the opacity monitor read when it is used either in external audit device or used in the transceiver to conduct the daily calibration drift check? Consider, that if

(8-25)upper O upper P Subscript c a l left-parenthesis k n o w n right-parenthesis Baseline equals k n o w n o p a c i t y v a l u e o f t h e f i l t e r

or, alternatively, the optical density of the filter for light passing through it once will be

(8-26)

But actually, light passes through the filter twice in a double-pass system because it reflects off either the pseudo-zero mirror of the transceiver or the mirror of the external audit device. The opacity monitor would measure the filter value as

(8-27)upper D Subscript m e a s u r e d Baseline equals 2 x upper D Subscript c a l left-parenthesis k n o w n right-parenthesis

Therefore, for a double-pass system, the filter value corrected to stack-exit conditions is

(8-28)

The double-pass form of the stack-exit correlation expression is used since most double-pass instruments employ this expression to produce a single-pass meter reading.

(8-29)

On the other hand, consider the example of an operator who needs to purchase an audit filter that will produce a reading of 20% opacity (D = 0.0969) when it is inserted into the audit jig. If the monitor path length lm = 5 m and the stack-exit diameter lx = 4.0 m (single-pass values), the value of the filter would be calculated as follows:

or

A filter having a nominal value of 24% opacity would then be purchased.

Combiner Equations

The optical density expression is also useful in situations where two or more opacity monitors are placed in ducts that lead to a single stack such as that shown in Figure 8-12. This arrangement is quite common because it enables the plant operator to monitor the performance of the separate control equipment that exhaust to a common stack. Although the arrangement may be useful for plant control, air pollution agencies usually require that the opacity be reported as if an opacity monitor were located at the stack exit. Such data can be obtained by taking the readings from the individual opacity monitors and using them in a combiner equation (Rasnic 1990). Again, care should be taken in their application since a number of assumptions need to be satisfied to obtain accurate values for the combined opacity at the stack exit. In Figure 8-12, the optical density at the stack exit can be obtained using the following combiner equation for double-pass opacity monitors:

(8-30)

where

A₁ and A₂ are the cross-sectional areas of each duct at the point of measurement,

l₁ and l₂ are the monitor path lengths, and v₁ and v₂ are the flue gas velocities in each duct.

The opacity at the stack exit can then be obtained from the optical density, Dx, using Equation 8-11.

If the duct areas and flue gas velocities of each duct are identical, Equation 8-18 can be simplified accordingly. However, the condition of the flue gas velocity being equal in each duct may be difficult to verify without the installation of velocity monitors or the application of other methods for determining the duct velocities. In some installations, the ratio of the duct fan speeds is used rather than installing flow monitors.

Opacity–Mass Correlations

Light scattering and absorbing properties of particles in a flue gas are related to their concentration in the gas. In fact, particulate concentration data in units of mg/m³, obtained from manual particulate traverses (EPA Reference Method 5, 5i, 17, the ISO Standards ISO 9096 (ISO 2017), or ISO 12141 (ISO 2002), or the European standard, EN13284-1 (CEN 2017)), can be correlated with transmissometer data. Standards have been prepared that detail both test procedures and methods for developing these correlations (ISO 1995). The original procedures were developed and published in Germany (VDI 1980), modified in the international standard ISO 10155, and again modified in U.S. EPA Performance Specification 11.

Figure 8-12 Two ducts entering a common stack.

Figure 8-13 Particulate mass–opacity correlation.

Equation 8-10 shows that optical density is proportional to particulate concentration. A plot of Method 5 or Method 17 data should, therefore, yield a straight line (Figure 8-13). A semi-log plot of the source test data against opacity produces a similar result.

The relationship between particulate mass concentration and extinction depends on the basic assumption that the particle characteristics remain the same as when the correlation was obtained. If the particle size distribution changes, the light scattering behavior may also change. This will cause a spread in the concentration-extinction data. However, the technique may still be used if the spread is not too great (as determined by the width of the confidence and tolerance intervals). Experience has shown that:

Correlations are not general. They apply only to the source on which they are made and cannot be transferred to other sources, even if the processes and/or fuels are similar.

Scatter in the data will primarily depend on (i) methods used to vary the particulate mass concentration when the correlation is developed, and (ii) the competence of the source testing team performing the manual sampling.

The opacity–mass correlation technique is valid only so long as the conditions under which it was developed are representative of the source operation. Changes in operation that lead to significant changes in particle characteristics or the particle size distribution may greatly affect the slope of the correlation line. Changes in fuel, control equipment, or process operation may contribute to this problem. A new correlation should be developed in such situations and such guidance should be provided in any regulatory specification. By checking single points on a routine basis, the continuing validity of the correlation can be assessed. These issues will be discussed further in the next chapter.

Since the 1970s and 1980s when this correlation technique was applied to transmissometers, particulate emission limits have become more stringent. Flue gas opacities have decreased substantially to the point where, in many cases, a transmissometer is not sensitive enough to meet the statistical criteria of PS-11 or ISO 10155. As a result, the more sensitive light scattering and beta gauge instruments are more commonly used today to continuously determine particulate emissions on a mg/m³ mass concentration basis.

OPACITY MONITOR PERFORMANCE SPECIFICATIONS

Performance specifications for opacity monitors are found in 40 CFR 60 Appendix B Performance Specification 1 (U.S. EPA 2020c). The specifications differ from those for gas monitoring systems because gas monitors can be readily checked using manual or instrumental reference test methods. Performance Specification 1 does not include a relative accuracy test because the opacity reference method, Method 9, using the human visual emissions observer, has a stated uncertainty of ±7.5% opacity, which is too imprecise for evaluating an instrument measuring in the range of 10–20% opacity. Method 9A using LIDAR is not reasonably convenient and is a too costly method to be used for checking the accuracy of stack-mounted opacity monitors.¹

Design specifications have, therefore, been used instead to guide the manufacture of opacity monitoring instruments used to provide defensible data of sufficient accuracy for monitoring control equipment performance and adherence to opacity compliance limits. The ASTM D6216 design specifications, which are incorporated in U.S. EPA Performance Specification 1 by reference, were prepared for this purpose. As mentioned previously, each opacity monitor can be tested to verify that it meets these specifications, or a certificate of conformance to the specifications can be obtained from the manufacturer.

Before an opacity monitor is installed, the Manufacturer’s Performance Specification Tests (ASTM 2021a) are conducted by the manufacturer for each instrument. These include a calibration error test, a response time test, and a spectral response performance test. Also, the simulated zero is adjusted to the true zero when the monitor is set up in a clean environment. By the ASTM Standard Practice, these tests are conducted and certified by the manufacturer.

Installation Requirements

Installing an opacity monitoring system should consider two important factors – representativeness and accessibility. A representative monitor location is one where the measured opacity will correspond to the actual opacity of the emitted flue gas. In strict regulatory terms, “the measurements are to be representative of the total emissions from the affected facility” (U.S. EPA 2020c Section 8.1).

Particle Stratification

Particles may not be uniformly distributed in a flue gas. Because of their momentum, particles may not be able to change direction as rapidly as the flue gas flowing through the plant exhaust system. This will cause gradients in particle number concentrations to develop in the ductwork (Figure 8-14).

In long, horizontal ducts, gravitational settling can lead to the stratification of larger particles toward the bottom. The problem of stratification can be compounded by low flue gas velocities because the carrying capacity of the gas for large particles will be reduced. Particle stratification depends largely on four factors:

Figure 8-14 Particle stratification in ducts and stacks.

Size of the particles

Flue gas velocity

Distance between the point of interest and a disturbance

Nature of the disturbance

The disturbance can be a bend in the ductwork, air in-leakage, a control device, internal support structures, or a disturbance caused by the stack exit. Also, a helical flow pattern (cyclonic flow) can be produced from the tangential entry of gas from one flue into another (Figure 8-15) or the entry of gas from multiple ducts into a single stack. The swirling pattern of gas flow may make it difficult to find an opacity monitor path that will produce an average opacity “representative of the actual emissions.”

Another problem occurs when the location being sought is to be representative for the determination of mass concentration instead of opacity. If an opacity–mass correlation is to be developed, reference method sampling is conducted at traverse points located at the centroids of equal areas over the stack or duct cross section (U.S. EPA 2020e). However, a good location for measuring opacity might be an area of high turbulence where particles of all sizes are well mixed. Such an area might be a good monitor location, but may be poor for manual sampling because of reverse and fluctuating gas flows.

Figure 8-15 Helical flow patterns due to tangential entry.

Monitoring Location

To simplify decisions regarding opacity monitor location, EPA has defined a number of conditions that are deemed representative for the purposes of specification. The criteria for proper measurement locations are that the sampling location is to be

at least four duct diameters downstream from all particulate control equipment or flow disturbance;

at least two duct diameters upstream of a flow disturbance;

where condensed water vapor is not present; and

accessible in order to permit maintenance.

The four and two duct criteria are rather arbitrary since particulate stratification is dependent upon both the size of the particles and flue gas velocity. The larger particles will be the ones to break through flue gas streamlines and to stratify. However, the small particles, which do tend to follow gas streamlines, are the most effective in attenuating light projected from an opacity monitor. The implicit assumption in the first criterion – the effect of the disturbance dissipates after four duct diameters – will also depend on the flue gas velocity and may not necessarily be valid. Alternatively, an area of high turbulence, where there is sufficient time for mixing both large and small particles, might not follow the four and two duct criteria but may provide for a more representative monitoring location. In this sense, the four and two duct criteria are an accommodation to practicality, where otherwise, extensive testing might have to be conducted to assure the adequacy of a sampling location.

The third criterion is obvious because water droplets attenuate light just as do solid particles. Wet scrubbers are widely used in industry to control both gaseous emissions of pollutants such as SO₂ and particulate emissions. In large fossil-fuel-fired steam-generating units, particulate control devices such as electrostatic precipitators and baghouses typically precede a wet scrubber. This arrangement helps to optimize the scrubber design for pollutant gas removal. The droplets that may be formed in a wet scrubber system are usually removed before the scrubber exhaust gas is emitted to the atmosphere. Cyclonic separation and mist eliminators are commonly used for this purpose. However, these droplet removal systems are not always perfect, and locating an opacity monitor after the scrubber will sense any droplets not removed. The monitor opacity readings then would not accurately represent the flue gas opacity attributable to pollutant particles. In such situations, it is recommended that the monitor be located between the particulate control device and the wet scrubber. On the other hand, a wet scrubber can either remove additional particles or add particles in the case of slurry entrainment, so the measurement may, in either case, be unrepresentative of stack emissions.

The issue of water droplets is more problematical than one might expect. On occasion, when a unit is down for maintenance and exhaust gas is not flowing, the opacity monitor may produce unusually high opacity readings. An investigation of this effect may indicate a correlation with local weather conditions. Rain falling down a stack can contribute to these upscale readings. Also, for relatively low-temperature exhaust gas stream (<200 °F), subzero ambient temperatures can cause the water vapor in the exhaust to condense. This is particularly true for metal and non-insulated stacks (Jaye et al. 1978). Because water is not a pollutant, it is somewhat disconcerting to be issued a notice of violation by the control agency in such situations.

Accessibility

Accessibility is as important a factor in opacity monitor installation as representativeness. If the monitor is not accessible for maintenance, representativeness becomes irrelevant. Consequently, the choice of location often results in a compromise between location and servicing constraints.

The Measurement Path

Performance Specification 1 addresses two aspects of the installation site: the actual location and the measurement path at the selected location. After a measurement location is selected, the question remains: over what path is the instrument to measure? The path chosen for the monitor must be considered with respect to the distribution of particulate matter over the location cross section. This becomes especially important when particulate matter is stratified at the location. There are a few guiding principles. First, the path must pass through a “centroidal” area that is no greater than 1% of the stack or duct cross-sectional area, which basically means that the path must pass through the center of the stack or duct.

Another guiding principle in selecting a path is that if particle gradients exist in the flue gas, the measurement path should pass through those gradients. If particulate matter is forced to the outside wall after a bend, the path should be in the plane of the bend, not perpendicular to it. An optical path that is not in the plane of the bend, but the plane perpendicular to the bend, may pass through a region of lower particle concentration if the particles are stratified over the cross section. In this situation, a path through the plane formed by the bend would be more representative of the total emissions.

On this basis, PS1 specifies monitor paths in terms of how far they are located from horizontal and vertical bends in a duct. The distances are expressed by the number of duct diameters that the site is located from a bend, where, as a minimum specification, if the monitor is located less than four equivalent diameters upstream or downstream from a bend in a vertical stack or duct, then the light beam path must be in the plane defined by the bend (Figure 8-16).

In a horizontal duct, particulate matter may stratify, with larger particles being forced to the top or bottom of the duct, depending on the flow pattern. Mounting a monitor in the plane of the bend of an upward or downward incoming duct would require that the monitoring system be installed vertically.

Figure 8-16 Path criteria for a location (a) downstream from a bend and (b) upstream from a bend.

Although possible, this would be impractical due to accessibility and maintenance issues. Instead, the installation guidelines of Performance Specification 1 compromise the issue by allowing the monitor to be installed between 1/3 and 1/2 of the distance from the bottom of the duct if the monitor location is greater than four duct diameters from a bend or the monitor location is less than four duct diameters from a down-coming duct (Figure 8-17a). For an upward incoming duct, and a monitor location less than four duct diameters from the bend, the monitor is recommended to be installed between 1/2 and 2/3 of the distance from the bottom of the horizontal duct (Figure 8-17b).

Because the location and path criteria are based partly on regulatory compromises and partly on technical considerations, it is best that plant and agency representatives agree on the monitoring site before installation. Alternative locations and light beam paths are allowed if it can be shown that the average opacity measured at the alternative location or path is equivalent (e.g. within ±10% of reading) to a location or path meeting the criteria.

The Installation

Prior to installation, ports, flanges, access platforms, electrical power, and so on should all be in place at the site selected. Upon installation, blower connections are made; the blowers are turned on; and then the transceiver and retroreflector assemblies are mounted. Preliminary alignments and adjustments are made and the instrument is turned on so that the light beam can cross the stack. The system can then be optically aligned. An optical alignment sight or telescope is used to help adjust the transceiver and retroreflector assemblies. When the appropriate light pattern is observed on the alignment sight, one can assume that the system is optically aligned. Ideally, this alignment procedure is to be done when the facility is not operating and no particulate matter is present in the optical path.

Figure 8-17 Optical path requirements for horizontal ducts (a) greater than four duct diameters from the bend. (b) Less than four duct diameters from the bend.

After the facility is started up, alignment is checked again. Heated stack walls may cause some misalignment, or vibration may cause problems that were not present when the facility was not operating. If the instrument becomes misaligned under these conditions, it should be realigned. It is assumed that the simulated zero/true zero adjustments made in the laboratory will remain the same after the instrument is mounted on the stack. However, at the first opportunity the alignment and zero adjustments should be verified. This may be during a scheduled outage period for maintenance, or it may be done when the facility is otherwise out of service.

Field Audit Performance Tests

Field audit performance tests are conducted after the monitor is installed. These tests are not difficult to perform and do not require the services of a source testing company since a relative accuracy test is not conducted. The instrument is aligned and shown that it can operate on the stack or duct. The following procedures and tests are performed:

Optical alignment assessment

Calibration error check

System response time check

Averaging period calculation and recording check

Zero calibration drift test (24-hour)

Upscale calibration drift (24-hour)

Operational test period

The performance specifications that are to be met are listed in Table 8-5.

Optical Alignment Assessment

The optical alignment is required to be verified before conducting the field audit performance tests. The optical alignment is part of the monitor installation as discussed above.

Calibration Error Check

A calibration error test is conducted by placing three different neutral density filters (calibration attenuators) into the external audit device. This test is the same as the calibration error test conducted as part of Manufacturer’s Performance Specification Tests discussed above, where three low, mid, and high-level attenuators are alternately placed into the external audit device. Again, this is done five times and the results averaged for each of the three filters.

The single-pass calibration attenuator values, corrected to the stack-exit conditions, are subtracted from opacity monitor responses. The calibration error is calculated as the sum of the mean difference plus confidence coefficient, using Equation 8-5. The calibration error is required to be less than 3% opacity for each filter and is to be reported for each filter.

TABLE 8-5 Performance Specifications for Opacity Monitor Field Tests

Specifications | Parameter
Optical alignment assessment | Verify alignment with respect to reference marks
Calibration error check | ≤3% opacity for each of three filters
System response time check | ≤10 s
Averaging period calculation and recording check | ≤2% of attenuator response
Operational test period | ≤68 h
Zero drift (24-hour)a | ≤±2% opacity
Calibration drift (24-hour)a | ≤±2% opacity
Data recorder resolution | ≤0.5% opacity

a Expressed as the sum of the absolute value of the mean and the absolute value of the confidence coefficient.

System Response Time Test

This test is the same as the response time test conducted as part of Manufacturer’s Performance Specification Tests discussed above. Again, a high-level calibration attenuator is inserted and removed five times from the external audit device. The mean of the five upscale measurements and mean of the five downscale measurements should be ≤10 seconds, respectively.

Averaging Period Calculation and Recording Check

After the calibration error check is completed, the monitoring system’s six-minute average is calculated. This is the required averaging period for reported opacity monitoring data and should be verified. Here, the low, mid, and high-level attenuators are each placed into the external audit device for 13 minutes (twice the averaging period plus 1 minute). The average obtained from the data recording system must be within ≤ ±2% opacity of the certified attenuator value.

Operational Test Period

After completing the four field audit tests discussed above, the opacity monitoring system is to be operated for a 168-hour test period during which the source is operating normally. Over the 168 hours, unscheduled maintenance, repair, or adjustment should not be made to the monitoring system although intrinsic adjustments that are made automatically without operator intervention are allowable at any time. If the 168-hour test is interrupted because of an instrument failure, the system must be restarted.

For opacity monitors, instead of conducting a RATA, Performance Specification Test 1 requires that a seven-day drift test be performed. All that has to be done is to obtain normal 24-hour zero and upscale calibration verification readings and perform the PS-1 drift calculations. The plant environmental engineer or instrument operator usually performs these calculations without having to hire a source tester or contractor.

Zero and Upscale Calibration Drift Test

The test is carried out on the first day of the 168-hour period, by recording the simulated zero reading and the upscale attenuation reading. After 24 hours, the readings are taken again. This is continued for seven days until seven simulated zero readings and seven upscale attenuation readings are obtained.

Zero Drift Calculation,

Zero drift is determined by initiating the simulated-zero device. The response of the opacity monitor to the simulated device is recorded for each 24-hour period. The opacity monitor value is subtracted from the nominal value of the simulated-zero device to calculate the 24-hour zero drift.

(8-31)

(8-32)

Note that it is necessary to keep the plus or minus sign for each xi value when performing the summation. The zero drift, ZD, is calculated by adding the value of the confidence coefficient to the absolute value of the mean difference.

(8-33)upper Z upper D equals StartAbsoluteValue x Subscript z e r o d r i f t Baseline overbar EndAbsoluteValue plus StartAbsoluteValue c c EndAbsoluteValue

where the confidence coefficient,│cc│, is calculated using Equation 8-7.

Upscale Calibration Drift Calculation.

The upscale calibration drift is determined from the response of the opacity monitor to the internal upscale calibration device recorded for each 24-hour period. The opacity monitor value is subtracted from the nominal value of the device to calculate the 24-hour zero drift.

(8-34)

(8-35)

Again, note that it is necessary to keep the plus or minus sign for each xi value when performing the summation. The calibration drift, CD, is calculated by adding the value of the confidence coefficient to the absolute value of the mean difference.

(8-36)upper C upper D equals StartAbsoluteValue x Subscript c a l d r i f t Baseline overbar EndAbsoluteValue plus StartAbsoluteValue c c EndAbsoluteValue

The opacity monitor passes the drift test if both the zero and calibration drift are ≤ ±2% opacity over every 24-hour period of the seven-day test.

The drift equations for opacity monitors differ from those given in PS 2 and PS 3. In these specifications, calibration drift is expressed as a percentage of the full-scale value of the analyzer and does not include the confidence coefficient. Here, the full scale of the opacity monitor is assumed to be 100%, and in a calculation for percent of span, 100 in both the numerator and denominator cancels out to give Equations 8-33 and 8-36.

OPACITY MONITOR QUALITY ASSURANCE

Methods for assuring data quality from opacity monitors are given in 40 CFR 60 Appendix F as Procedure 3 (U.S. EPA 2020f). These were deemed necessary by ASTM in 1998 when the D6216 Standard Practice was prepared. The U.S. EPA assumed the responsibility of standardizing these procedures and specified the frequency at which they should be performed in a proposed rule published in 2003. The ruling was held in abeyance until 2014, when it was finally published (U.S. EPA 2014).

Procedure 3 is required for sources using opacity monitors to demonstrate continuous compliance with opacity standards in federally enforceable regulations. Requirements for daily instrument zero and span checks, quarterly performance audits and annual zero alignment checks are included in Procedure 3. Also, a quality assurance plan (manual) that incorporates these checks and audits must be developed and implemented. The plan must also include corrective maintenance procedures that address diagnostic tests required after repairs are made to the monitoring system. The following list summarizes Procedure 3 requirements:

Quality assurance plan

Daily system checks (zero and span calibration verifications, status indicator check)

Quarterly three-point calibration tests

Annual primary zero alignment

Quality Assurance Plan

A quality assurance plan is required for opacity monitors just as for any gas monitoring system. It is easier to incorporate the opacity monitor plan and standard operating procedures into the overall CEM system QA plan, rather than preparing a stand-alone document. The plan must include standard operating procedures for the daily zero and upscale drift checks, procedures for the quarterly audit, procedures for the annual zero alignment check, and a program for preventive and corrective maintenance, including diagnostic testing after repairs.

Written quality assurance procedures for opacity monitors are often forgotten when writing a CEM system quality assurance plan. Routine preventive maintenance programs tend to be lacking and audit procedures are often improvised or abbreviated rather than being conducted as specified in Procedure 3 or Performance Specification 1. Part of this problem is due to the reliability of opacity monitoring systems and well-running instruments that typically experience few maintenance problems. However, this does not relieve one from the responsibility of writing an opacity monitor QA plan.

Daily Zero and Upscale Calibration Drift Test

A zero and upscale calibration drift test is required daily. This is an automatic function of opacity monitors mandated for regulatory compliance. Various instrument designs, using mirrors, attenuators, or reduced reflectance devices for this purpose have been discussed earlier in this chapter. If the daily zero drift or upscale drift exceeds ±4% opacity (twice the PS-1 drift specification of 2% opacity), corrective action must be taken. In addition to verifying the status of the daily zero and span drift check, status and diagnostic indicators and data acquisition system error messages must be checked daily.

Quarterly Audit – Three-Point Calibration Error Test

An audit of the opacity monitoring system is conducted quarterly. Three activities are performed: (i) an optical alignment check, (ii) a zero-compensation check, and (iii) a calibration error test. Because the monitor must be visited to conduct the audit, the audit provides an opportunity to inspect the system and perform preventive maintenance, such as cleaning windows and surfaces, exchanging blower filters, and checking blower hoses and electrical connections.

Optical Alignment

Sometime during the audit, the alignment of the instrument should be checked, checking the functionality of the bull’s-eye sight or alignment screen on the transceiver case. The stack or duct must be operating at the time of the check to assess whether elevated stack temperatures caused distortions in the stack that might have led to misalignment of the optical system. Obviously, any misalignment must be corrected.

Zero Compensation

The value of the zero compensation, corrected to stack-exit conditions, is recorded at the time of the audit.

Calibration Error Test

The calibration error test performed for the PS 1 certification is essentially repeated quarterly for opacity monitoring systems subject to the requirements of Appendix F, except the filters are inserted a minimum of three times instead of five. The test is conducted using three certified neutral density filters (hence called the three-point test), which are to be recalibrated every six months (Cohen and Ross 1989). However, if two annual calibrations agree within 0.5%, then the attenuators may be recalibrated only once every five years (Appendix F Procedure 3 §10.2(2)).

The opacity monitor performance audit calibration error check does not test the absolute accuracy of the monitoring system. There are many other factors involved in the opacity measurement, such as system alignment and the viability of the cross-stack zero. The calibration error check is, nevertheless, a useful quality control procedure and can be done relatively rapidly at other times to increase confidence in the opacity data. The procedures of the performance audit do check internal transceiver problems that might affect the opacity measurements and are particularly useful in assuring unit operators that the opacity monitor is functioning properly, allowing them to concentrate on process operations or failures in particulate control equipment that may be the cause of an opacity excursion.

Before the three-point calibration error test is conducted, the instrument zero compensation must first be checked. This is recorded as corrected to stack-exit conditions. Although it is not required to clean the instrument windows unless the correction is greater than 4% opacity, doing so is good practice before attaching the audit jig and conducting the test. Also, preliminary to installing the jig, fault indicators, the stack-exit correlation value, and the internal zero and span values should be checked.

The actual performance part of the audit is relatively simple. The zero value with the audit jig in place should be the same as the simulated “pseudo-zero,” established with the transceiver zero mirror. Each of the three filters is then placed into the jig for two minutes. Stable values are recorded for each filter from the instantaneous (unaveraged) response of the monitor. This procedure is repeated a minimum of three times. Detailed guidance for conducting an opacity monitor performance audit can be found in 40 CFR60 Appendix B Performance Specification 1, §8.1(3)(ii). The calculations for calibration error are similar to those used for calculating calibration drift, where the calibration error for each filter is the sum of the mean difference between the instrument response to the filter and the certified value, plus a confidence coefficient:

The calculations are the same as those given in Equations 8-4 to 8-6 when the instrument vendor first conducts the calibration test, or when the instrument undergoes the same calibration error test for certification under Performance Specification 1. Again, the difference between the certified filter value and the opacity monitor response, x Subscript upper C upper E Sub Subscript i, for each filter inserted into the external audit device is

(8-37)

the mean difference, StartAbsoluteValue x Subscript upper C upper E Baseline overbar EndAbsoluteValue, for each filter is then:

(8-38)

and the calibration error for each filter, CE, is the sum

(8-39)upper C upper E equals StartAbsoluteValue x Subscript upper C upper E Baseline overbar EndAbsoluteValue plus StartAbsoluteValue c c EndAbsoluteValue

where

CE is the confidence coefficient calculated according to Equation 8-6.

The opacity monitor system is viewed as passing the performance audit if the calibration error (Er) for each filter is less than 3% opacity. If the calibration error for any one filter is greater than 3% opacity, the test calibration error test fails and the monitor is considered to be out-of-control until problems are resolved and the test is repeated and passed. In a functioning monitor, the difference values, x Subscript upper C upper E Sub Subscript i, are usually small and reproducible, varying from zero to 0.1–0.2% opacity. When the differences are small, it sometimes viewed as unnecessary to calculate the value of the confidence coefficient,│cc│. However, if the results need be reported, the calibration error must be calculated as required in Equation 8-39 in order to be defensible.

Sources that meet Procedure 3 quality assurance requirements for three consecutive quarters are allowed to reduce the audit frequency from four quarters a year to two.

Annual Primary Zero Alignment

The annual primary zero alignment requires that the opacity monitor be moved from the stack to a room free of any suspended particulate matter. This is a major activity and with the system removal, alignment, reattachment, and subsequent checkouts, will take a day or more to perform. Accordingly, managers should be aware of the requirement and the effort it will take so that adequate resources can be allocated to the instrument technicians involved.

Setup

First, both the transceiver and retroreflector are removed from the stack to a clean room. A laboratory, control room, or any other reasonably clean and convenient environment free of circulating or suspended particulate matter and cigarette smoke and large enough to accommodate the path setup requirements is usually adequate. Tables, tripods, or other stable supports are used for this purpose (Figure 8-18). Setting it up on the floor is not a good idea.

The transceiver assembly and retroreflector assembly are separated by a distance equivalent to the distance between their points of attachment on the stack or duct. If possible, this distance should be determined by direct measurement rather than from engineering drawings. The flange lengths are included to obtain the flange-to-flange distance.

Figure 8-18 Setting up the clear path in the laboratory.

The instrument is then turned on and aligned using the alignment sight. The retroreflector (or receiver unit) is adjusted until the maximum response is reached by the system. Because the monitor is now measuring only laboratory air, it should read zero opacity. The monitor response is then recorded before any other adjustments are made. Any difference from zero is recorded as the zero-alignment error.

Primary Alignment

In a primary alignment, the simulated (pseudo) zero system of the transceiver assembly (for double-pass monitors) is adjusted so that it corresponds to the measurement of zero over the clear, laboratory path. In systems with zero mirrors, the primary alignment requires that the iris on the zero mirror be adjusted such that the energy reaching the detector is within 90 and 110% of the energy reaching the detector under clear path conditions (Figure 8-19).

After the zero adjustments are made, the internal upscale calibration value is determined. This usually involves actuating the calibration cycle of the instrument and noting the instrument signal produced when the upscale filter or reflector is in the path of the light beam. The value of this filter must be in the range that is required for the particular installation.

External Zero Device

After the pseudo-zero mirror is correlated to the clear path zero from the retroreflector, the external audit device is adjusted to produce a zero that correlates with that of the transceiver pseudo-zero mirror. This may likewise require the adjustment of an iris; however, instrument-specific procedures from the instrument manufacturer’s operation and maintenance manual should be referenced.

Figure 8-19 Adjusting the iris. (a) Stack zero. (b) Transceiver zero.

Corrective Maintenance and Diagnostic Tests

Opacity monitor maintenance and repair was addressed in detail in the version of Procedure 3 published in the Federal Register in 2012 (U.S. EPA 2012). This discussion was eliminated in the 2014 final rule which redirected it to an unreferenced guidance document. It provides some useful perspectives on maintenance and diagnostic testing and can still be found in the 2012 draft and also on the EPA Emission Measurement Center website (EMC 2020a). This earlier document can be especially useful in writing the maintenance component of the quality assurance plan as required in Procedure 3 §9.0(4)

Routine/Preventive maintenance

Noncritical repairs

Critical repairs

Routine/Preventive Maintenance

Routine maintenance on an opacity monitor consists mainly of cleaning the transceiver and retroreflector windows and to periodically replace blower filters. Windows are cleaned usually at least quarterly, or more frequently if needed to respond to dirty window alarms. Particulate levels in the ambient air will determine the replacement frequency for blower filters, which may be quarterly or longer.

Noncritical Repairs

Noncritical repairs are associated with electronic components, machined parts, cabling, and other elements of the monitoring system that may fail, but when replaced with a like-kind component, will not affect the instrument performance.

Critical Repairs

Critical repairs are necessary when a component that may affect the accuracy of the measurements fails or is damaged. These components include the light source, detectors, lenses, optical filters, reflectance coatings, and so on.

After repairs are made, whether critical or noncritical, diagnostic tests should be conducted to determine the success or failure of the repair. These could include a simple zero and span check or a calibration error check using the audit jig.

REFERENCES

American Society for Testing and Materials International (ASTM) (2021a). ASTM 6216-12. Standard practice for continuous opacity monitoring manufacturers to certify design conformance and monitor calibration. 2018 Annual Book of ASTM Standards. Volume 11.07. West Conshohocken, PA: ASTM.

American Society for Testing and Materials International (ASTM) (2021b). ASTM 7520-16. Standard test method for determining the opacity of a plume in the outdoor ambient atmosphere. 2018 Annual Book of ASTM Standards. Volume 11.07. West Conshohocken, PA: ASTM.

Cashdollar, K.L., Lee, C.K., and Singer, J.M. (1979). Three wavelength light transmission technique to measure smoke particle size and concentration. Applied Optics 18: 1763–1769.

Cohen, J.B. and Ross, R.C. (1989). Use of Precalibrated optical density filters in the in-situ calibration of opacity monitors. Paper presented at Air Pollution Control Association Meeting, Montreal, paper 80-42.4.

Committee for European Standardization (CEN) (2017). EN13284-1 Stationary Source Emissions – Determination of Low Range Mass Concentration of Dust - Paart 1: Manual Gravimetric Method. Brussels, Belgium: European Committee for Standardization.

Conner, W.D. and McElhoe, H.B. (1982). Comparison of opacity measurements by trained observer and in-stack transmissometer. Journal of the Air Pollution Control Association 32: 943–946.

Conner, W.D. and White, N. (1980). A Comparative Study of Plume Opacity Measurement Methods. EPA 600/2-80-001.

da Costa, R., Seffens, J., Lanulfo, E. et al. (2011). Real-time mapping of an industrial flare using Lidar. In: Proceedings Volume 8182 Lidar technologies. Techniques ad Measurements for Atmospheric Remote Sensing. SPIE.

Du, K., Rood, M.J., Kim, B.J. et al. (2007a). Quantification of plume opacity by digital photography. Environmental Science and Technology 41 (3): 928–935.

Du, K., Rood, M.J., Kim, B.J. et al. (2007b). Digital optical method to quantify the visual opacity of plumes in the field. Journal of the Air and Waste Management Association 57: 836–844.

Dybdahl, A.W. (1981. The Use of Lidar for Emissions Source Opacity Determinations. EPA-330/1-79-003-R.

Emission Measurement Center (EMC) (2020a). Suggested Continuous Opacity monitoring Systems (COMS) Diagnostic Tests. U.S. Environmental Protection Agency Emission Measurement Center. www. epa.gov/sights/production/files/202-08/documents/suggested_coms_diagnostic_tests.pdf.

Emission Measurement Center (EMC) (2020b). ALT-082 approval of method 9 alternative revised. Broadly Applicable Alternative Test Methods. Air Emission Measurement Center (EMC). https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods

Hamil, H.F. (1980). The Development of Performance Audit Devices for Optical Transmissometers. Unpublished. EPA Contract 68-02-2489. Draft Final Report.

Hovan, R.A. and White, J.R. (1996). Laser dust monitors. In: Continuous Compliance Monitoring Under the Clean Air Act Amendments, VIP-58, 179–193. Pittsburgh: Air and Waste Management Association.

Hovan, R., Metcalfe, S., and Stuart, D. (2004). Light source for open path gas-monitoring. US Patent 6781695B2.

International Standards Organization (ISO) (1995). Stationary source emissions – automated monitoring of mass concentrations of particles – performance characteristics, test methods and specifications. ISO 10155. Geneva: Central Secretariat.

International Standards Organization (ISO) (2002). Stationary source emissions – manual determination of mass concentration of particulate matter (Dust) at low concentrations. ISO 12141. Geneva: Central Secretariat.

International Standards Organization (ISO) (2017). Stationary source emissions – manual determination of mass concentration of particulate matter. ISO 9096. Geneva: Central Secretariat.

Jahnke, J.A. (1984). Transmissometer Systems – Operation and Maintenance, an Advanced Course. APTI Course 476A. EPA 450-84-004.

Jahnke, J.A. (1993). Continuous Emission Monitoring. New York: Van Nostrand-Reinhold.

Jahnke, J.A. (2000). Continuous Emission Monitoring, 2ee. New York: Wiley.

Jaye, F., Steiner, J., and Larkin, R. (1978). Resource Manual for Implementing the NSPS Continuous Monitoring Regulations – Manual 1 – Source Selection ad Location of Continuous Monitoring Systems. EPA 340/1-78-005a.

Johnson, W.B. (1969). Lidar applications in air pollution research and control. Journal of the Air Pollution Control Association 19 (3): 176–180.

Lindau, L. (1991). NO₂ effect on flue gas opacity. Journal of the Air and Waste Management Association 41 (8): 1098.

Pennsylvania Department of Environmental Protection (PADEP) (2006). Continuous Source Monitoring Manual – Revision 8. 274-030-001. Pennsylvania Department of Environmental Protection. https://www.dep.pa.gov

Plaisance, S.J. and Peeler, J.W. (1988). Technical Assistance Document: Performance Audit Procedures for Opacity Monitors. EPA 600/8-87-025.

Rasnic, J. (1990). Compliance Issues Related to the Opacity of Combined Gas Streams Under the NSPS Regulations. Memorandum of 10/26/90. Stationary Source Compliance Division U.S. EPA Office of Air Quality Planning and Standards.

Stern, A.C. (ed.) (1968). Air Pollution, vol. II. New York: Academic Press.

Stuart, D.D. (2008). Opacity monitoring at very low levels. Paper presented at the Air and Waste Management Association Meeting, Portland, OR, paper 08-520.

Traina, J. and Myers, R. (1990). Compliance opacity monitor uses new solid state light source technique. In: Proceedings – Specialty Conference on Continuous Emission Monitoring – Present and Future Applications, Chicago (12–15 November 1989), 250–259.

U.S. Environmental Protection Agency (EPA) (1975). Standard of Performance for New Stationary Sources: Performance Specification 1. 40 FR 46259 (6 October 1975).

U.S. Environmental Protection Agency (EPA) (1983). Standards of Performance for New Stationary Sources: Revisions to Performance Specification 1 for Opacity Emission Monitoring Systems. 48 FR 13322 (30 March 1983).

U.S. Environmental Protection Agency (EPA) (2012). Recent Posts of Broadly Applicable Alternative Test Methods. 77 FR (2 February 2012).

U.S. Environmental Protection Agency (EPA) (2014). Quality Assurance Requirements for Continuous Opacity Monitoring Systems at Stationary Sources –Final Rule. 79 FR 28439 (16 May 2014).

U.S. Environmental Protection Agency (EPA) (2020a). Appendix A – test methods-method 9a – visual determination of opacity of emissions from stationary sources. Code of Federal Regulations – Protection of the Environment. 40 CFR 60. Washington, DC: Superintendent of Documents.

U.S. Environmental Protection Agency (EPA) (2020b). Appendix B – performance specification 1 – specifications and test procedures for opacity continuous emission monitoring systems in stationary sources. Code of Federal Regulations – Protection of the Environment. 40 CFR 60. Washington, DC: Superintendent of Documents.

U.S. Environmental Protection Agency (EPA) (2020c). Subpart AAa – standards of performance for steel plants: electric arc furnaces and argon-oxygen decarburization vessels constructed after 7 August 1983. Code of Federal Regulations – Protection of the Environment. 40 CFR 60. Washington, DC: Superintendent of Documents.

U.S. Environmental Protection Agency (EPA) (2020d). Appendix A – test methods- method 1 – sample and velocity traverses for stationary sources. Code of Federal Regulations – Protection of the Environment. 40 CFR 60. Washington, DC: Superintendent of Documents.

U.S. Environmental Protection Agency (EPA) (2020e). Appendix F – quality assurance procedures. Code of Federal Regulations – Protection of the Environment. 40 CFR 60. Washington, DC: Superintendent of Documents.

Uthe, E.E. (1983). Applications of surface based and Airborne Lidar systems for environmental monitoring. Journal of the Air and Waste Management Association 33 (12): 1149–1155.

Yuen, W., Koloutso-Vakakis, S., Rood, M.J., and Mattison, K. (2013). Measurement of plume opacity using smartphones and the Digital Optical Method (DOM). Paper presented at the Air and Waste Management Association Meeting, Chicago (25–28 June 2013), paper 13-12336.

BIBLIOGRAPHY

Avetta, E.D. (1975). In-Stack Transmissometer Evaluation and Application to Particulate Opacity Measurement. EPA 650/2-75-008.

Beutner, H.P. (1974). Measurement of opacity and particulate emissions with an on-stack transmissometer. Journal of the Air Pollution Control Association 24: 865–871.

Bühne, K.W. and Duwel, L. (1972). Recording dust emission measurements in the cement industry with the RM4 smoke density meter made by Messrs. Sick. Staub – Reinhaltung der Luft 31: 19–26. (in English).

Conner, W.D. and Hodkinson, J.R. (1972). Optical Properties and Visual Effects of Smoke-Stack Plumes. EPA AP-30.

Conner, W.D. (1974). Measurement of the Opacity and Mass Concentration of Particulate Emissions by Transmissometry. EPA 650/2-74-128.

Ensor, D.S. and Pilat, M.J. (1971). The effect of particle size distribution on light transmittance measurements. American Industrial Hygiene Association Journal 32: 287–292.

Eskra, B.J. (1981). Determination of stack exit opacity utilizing four duct-mounted transmissometers. In: Proceedings – Specialty Conference on Continuous Emission Monitoring – Design, Operation, and Experience, 268–276. Pittsburgh: Air Pollution Control Association.

Federal Ministry of the Environment, Nature Conservation and Nuclear Safety (2008). Air Pollution Prevention Manual on Emission Monitoring. Research Report 360 16 004 UBA – FB 001090. Dessau Rosslau, Germany. Federal Environment Agency.

Hartt, E.I. (1978). An Evaluation of Continuous Particulate Monitors. Environment Canada. M.S. Report No. O. R.-16.

Kraus, F.J. (1973). The influence of forward scattering on measurements of the degree of transmission of Aerosols. Staub – Reinhaltung der Luft 33: 341–345. (in English).

McElhoe, H.B., Dellinger, B., and Conner, W.D. (1982). The determination of particle size using multi wavelength attenuation measurements. Air Pollution Control Association Meeting, New Orleans, paper 82-39.6.

Molloy, R.C. (1975). Smoke opacity monitoring systems: pollution control and energy conservation. ASHRAE Journal 9: 27–32.

Nader, J.S., Jaye, F., and Conner, W. (1974). Performance Specifications for Stationary Source Monitoring Systems for Gases and Visible Emissions. EPA 650/2-74-013.

Oldaker, G.B., Rosenquest, J.M., and Purcell, R.Y. (1981). Quality assurance evaluation of transmissometers. In: Proceedings – Specialty Conference on: Continuous emission Monitoring – Design, Operation, and Experience, 285–292. Pittsburgh: Air Pollution Control Association.

Jahnke, J.A. (1984). Transmissometer systems – operation and maintenance, an advanced course. APTI Course 476A, EPA 450/2-84-004.

Peeler, J.W. (1986). CEMS Pilot Project: Evaluation of Opacity CEMS Reliability and QA Procedures, Volume I. EPA-340/-86-009a.

Peeler, J.W. (1986a). CEMS Pilot Project: Evaluation of Opacity CEMS Reliability and QA Procedures, Volume II (Appendices). EPA-340/1-86-009b.

Peeler, J.W. (1986b). Recommended Quality Assurance Procedures for Opacity Continuous Emission Monitoring Systems. EPA-340/1-86-010.

Peeler, J.W., Fox, V.L., and Plaisance, S.J. (1988). Inspection Guide for Opacity Continuous Emission Monitoring Systems. EPA-340/1-88-002.

Peterson, M. and Tomaides, M. (1972). In-stack Transmissometer Techniques for Measuring Opacities of Particulate Emissions from Stationary Sources. EPA-R2-72-099.

Plaisance, S.J., (1988). Advances in opacity CEMS performance auditing. Air Pollution Control Association Meeting, Dallas, paper 88-137.7.

Pilat, M.J. and Ensor, D.S. (1970). Plume opacity and particulate mass concentration. Atmospheric Environment 4: 163–173.

Purcell, R.Y. and Rosenquest, J.M. (1982). Field Performance Audit Procedures for Opacity Monitors, Environmental Protection Agency CEM Report Series 5-271-7/82.

Ruuskanen, J. (1980). Effects of size distribution variations on optical extinction in spherical particle populations. Staub – Reinhaltung der Luft 40: 157–159.

Thielke, J.F. and Pilat, M.J. (1978). Plume opacity related to particle mass concentration and size distribution. Atmospheric Environment 12: 2439–2447.

Van de Hulst, H.C. (1957). Light Scattering by Small Particles. New York: Wiley.

Note

1 The Commonwealth of Pennsylvania does however, have a requirement to compare the opacity determined by an opacity monitor with that of a VE observer. To meet this requirement, the difference between the two methods is determined over nine 15-minute periods, calculated from one-minute test data. The rule requires that none of the one-minute differences can exceed 15% opacity, and none of the differences for the nine 15-minute period averages can exceed 7.5% opacity (PADEP 2006).

CHAPTER 9
CONTINUOUS PARTICULATE MONITORING

Opacity monitors have long served in the United States as a means of tracking particulate emissions from stationary sources. A common assumption is that if an opacity limit of 20% is met, then particulate emissions standards (in mg/m³ or other) would also be met. However, mass emission requirements in state regulatory permits and federal programs have become increasingly stringent. At low particulate levels, opacity monitors are not sufficiently sensitive to either monitor the performance of particulate control equipment or to assure compliance with mass emission standards. Continuous particulate mass measurements are inherently more quantitative, enabling more precise control to be affected in plant operations. Monitoring systems that measure particulate mass concentration on a continuous basis are installed throughout Europe, where they are required for industrial boilers >50 MW and for municipal and hazardous waste incinerators, as well as other facilities.

In the United States, the 1990 Clean Air Act Amendments established requirements for enhanced monitoring, which were later translated into the Compliance Assurance Monitoring rule (CAM). CAM requires that compliance with emissions standards is always assured by either parameter monitoring or the application of particulate matter monitoring systems. Prior to 1990 particulate mass emissions were measured only periodically by conducting a manual reference test, such as the EPA isokinetic sampling test methods 5 or 17. The lead time necessary to conduct these manual methods allows the source to optimize both operations and control equipment performance in order to pass the tests. Consequently, the tests may not be truly representative of actual source performance – an issue addressed by the U.S. Congress in the Clean Air Act Amendments.

Since the late 1990s, a number of regulatory mechanisms have been used to require or allow the use of particulate monitoring systems in the United States. Consent decrees and prevention of Significant Deterioration (PSD) permits were among the first regulatory mechanism to require the application of particulate monitors. Part 60 source‐specific regulations, for fossil‐fuel‐fired steam generators (U.S. EPA 2007), municipal waste combustors, and cement kilns, among others require their installation, and in some cases encourage their use as an alternative compliance method (U.S. EPA 1997a). In accordance with their use for continuous compliance determinations, Performance Specification 11 was promulgated for their certification. The monitoring requirements incorporated in these programs have led to more extensive use of continuous particulate monitors in the United States; however, opacity monitors are still widely applied.

One problem with continuous particulate monitoring is that few methods exist that can measure mass both directly and continuously. An opacity monitor measures the ability of a flue gas to transmit light. A light scattering instrument measures the light intensity scattered back from flue gas particles. A beta gauge measures the transmission of electrons through a spot of collected particulate matter. A triboelectric monitor measures charge transfer from particles to a probe. All these commercially available continuous mass monitoring instruments produce an instrument output that is something other than “grams per cubic meter” (or lbs/ft³). Much has been made of this issue (Roberson 2007), which becomes irrelevant when a monitor is calibrated against a known standard or the results of a particulate reference method. The PS‐11 certification procedures specify how the monitor output is to be correlated against the particulate mass concentration determined by manual gravimetric test methods.

In developing a correlation, the source and/or control equipment operating conditions are varied in order to obtain a range of particulate concentrations. If this cannot be done, particulate matter can be injected into a flue or stack to vary the flue gas particulate concentrations (Baxter 2015). The instrument readings are then correlated with the simultaneous manual source test method data. A “calibration line,” or correlation, is then made between the instrument response and the manually determined particulate concentrations. A less rigorous (and less expensive) “correlation” can be established by merely determining the instrument response at the operating limit at the time of the initial compliance test. Continuous particulate monitoring systems are classified in the United States as either “particulate matter CEM systems” (PM CEMS) when following PS‐11, or as “particulate matter continuous parameter monitoring systems” (PM CPMS), when correlated at the operating limit.

Experience has shown that correlations must be made on a unit‐by‐unit basis. That is, a correlation developed at one coal‐fired boiler may not necessarily be the same as that developed at another coal‐fired boiler. In this chapter, correlation methods and the design and limitations of the analytical systems are discussed. Table 9‐1 summarizes the regulatory applications of continuous particulate monitoring in the United States.

Depending upon the rule, either PM CEMS or PM CPMS are required or can be used as an option for opacity monitors. In the 40 CFR 63 air toxics standards, there are few requirements for PM CEMS or PM CPMS. Instead, bag leak detectors are typically required at sources where baghouses are used to control particulate emissions. Here, the instrument output is displayed as a percent of scale, where the scale factor is set up relative to source operating and alarm conditions and not particulate concentration.

REGULATORY SPECIFICATIONS

Particulate monitors are characterized in several different ways for U.S. regulatory applications:

Their use for compliance purposes as PM CEMS requires certification through the procedures of Performance Specification 11

Their use as a parameter monitor or PM CPMS requires less rigorous calibration procedures for their role in monitoring control equipment performance

Their use as a bag leak detector (BLD) to alarm for leaks in the bags of baghouses

Data from PM CEMS is intended to be sufficiently accurate to monitor continuous compliance of a facility with PM emissions limitations, whereas data from a BLD need to be sufficiently qualitative to alert the owner of a baghouse that there is a problem that needs to be addressed. Data from a PM CPMS come somewhere in between; being sufficiently accurate to justify conducting a PM performance test to determine compliance or noncompliance (Baxter 2010).

Almost any type of particulate monitor can be used for these applications although some methods are not designed for regulatory applications. The difference relates to the ability to meet performance specifications for system calibration and certification as discussed next.

TABLE 9‐1 U.S. Continuous Particulate Monitoring Requirements

Part
Subpart
Source Category
Stacks
CFR Reference
Type of System

Consent
Decrees
FFFSG
Facility
Various
PM CEMS required

60
CCC
CISWI
Waste burning kilns
Energy recovery units
>250 mmBtu/hr
60.2145(x)
60.2165(4)(r)
PM CPMS Required

60
D,Da, Db, Dc
FFFSG
Facility
60.42(c)
60.48a (p)
60.46b (j)
60.45c (c)
PM CEMS (option)

60
Eb
Ec
MWC
Facility
60.58b (d)(10)
60.56c (c)(5)(v)
PM CEMS
BLD

60
Ja
Petroleum refinery
FCCU or FCU
60.105a (d)
PM CEMS required

60
F
Cement
Kiln, clinker cooler
60.6(c)(1)
PM CPMS required

63
LLL
Cement
Kiln, clinker cooler
63.1349 (b) (1)
63.1350(b)
PM CPMS required

63
UUUUU
EGU
Facility
63.10000 (c)(iv)
PM CPMS required

CALIBRATING PARTICULATE MATTER CEMS (PM CEMS)

In Europe, both gas and particulate CEM systems are calibrated against reference test methods to establish a “calibration line” from which subsequent CEM emissions data are obtained (CEN 2014). The calibration line must meet statistical criteria for the regression coefficient, confidence intervals, and tolerance intervals before the system can be used to report emissions data. In the United States and Canada, gas monitoring CEM systems are not calibrated in this manner. NIST calibration gases are used instead, supplemented by initial and periodic relative accuracy certification tests. However, this approach cannot be used for particulate monitors, since no viable, independent particulate mass concentration standards exist. Particulate monitors must therefore be calibrated by some other means, such as the correlation method.

The technique of correlating an instrument's response with manual source test measurements originated in German standards in the 1950s, as a means of determining particulate concentration from transmissometers (Beutner 1974). The method has become the accepted calibration method for particulate monitors and has since been extended to monitoring standards in the International Standards Organization (ISO) (ISO 1995), the U.S. EPA, and the European Union (EU) (CEN 2014, 2017).

U.S. Performance Specification 11 (U.S. EPA 2020d) is based on ISO 10155 (ISO 1995) and provides a method almost identical to that given in the international standard, albeit with modified criteria. Both standards are performance based and do not prescribe a particular analytical method; any method can be used as long as it meets the performance specifications.

The correlation method requires establishing a relation between manual gravimetric reference test data and the PM system's response. This is done at three particulate concentration levels. However, in many cases, such as sources with baghouses or scrubbing systems, changing emission levels may be difficult or prohibitively expensive.

Replicates of these measurements are obtained to provide a minimum of 9 (ISO 10155) to 15 (PS‐11) sets of monitor and reference method data for the correlation. Linear, polynomial, power, exponential, or logarithmic expressions may be applied to develop the correlation, depending upon the regulatory standard. From these data pairs, the correlation coefficient, 95% confidence interval, and tolerance interval are calculated. To be approved, the monitoring system must meet the criteria for the parameters specified either in PS‐11 in the U.S. or ISO 10155 elsewhere.

A PM correlation is essentially much like one developed for a predictive emission monitoring system (PEMS), in which present values are predicted from past performance. As with a predictive monitoring system, PM correlations are unit specific and if the conditions change for which the correlation was originally developed, the correlation may no longer be valid.

In addition to the correlation specifications, instrument operational specifications are given in PS‐11 and ISO 10155 (Table 9‐2). Whether for gas monitors or particulate monitors, response time, zero drift, and span drift specifications provide the expectation for a minimum level of operational performance between different systems.

Reference Method Tests

Developing the calibration line should not be regarded as a routine source testing application, but as a scientific study where the test variables and conditions are evaluated. A test protocol should be established to develop a correlation that makes practical sense. For example, the manual reference test method should measure the same material as the particulate monitor. If the gravimetric test method uses an external filter that is maintained at a temperature lower than the flue gas temperature, gases may condense and increase the filter weight. Although it may be argued that the condensables would appear as particulate matter when subjected to ambient temperatures after exiting the stack, the point is that they are not particles under stack conditions. In this case, the test method would be measuring something different than would an in‐situ particulate monitor sampling at stack temperature.

TABLE 9‐2 Instrument Specifications

PS‐11 Specifications
ISO 10155 Specifications

Span (range)
Complete range of source's actual PM emission concentrations
2–3 times the allowable emission concentration

Response time
≤15 minutes
<20% of the reference method sampling time

Zero drift
≤ ±2% of the range/day for certification
≤ ±4% of the range/day before requiring adjustment
System is out of control if drift >4% for each of five days or >8% for any one day
≤ ±2% of the range/month

Span drift
≤ ±2% of the range/day for certification
≤ ±4% of the range/day before requiring adjustment
System is out of control if drift >4% for each of five days or >8% for any one day
≤ ±2% of the range/month

The study conducted to establish the calibration line should consider the following experimental protocols:

The source and control equipment should be operated under a set of conditions that reflects the variation of particulate concentrations in the flue gas. These conditions should range over low, intermediate, and high emissions value and can be achieved in a number of ways, such as the following:

Varying process operating conditions

Partially bypassing the control device

Changing control device operating conditions (e.g. detuning an ESP, removing selected bags in a baghouse)

PM spiking

The particulate monitor should measure a sample at a location that is representative of the flue gas particulate emissions.

The particulate monitor and test methods should be concurrent, taken over a period sufficient to obtain an accurate measure of the particulate concentration.

Statistical Analysis Procedures

The monitoring method chosen is acceptable for compliance monitoring if the correlation with manual source testing measurements meets specified statistical criteria. The most generally accepted correlation methods, the International Standards Organization (ISO) continuous mass measurement standard, ISO 10155 or, variations such as PS‐11 are used for this purpose. These criteria are summarized in Table 9‐3. If any of these specifications cannot be met, the sampling strategy should be reexamined. If no problems have occurred in the manual sampling, another method of instrumental measurement may have to be selected.

In the correlation method, either a linear or nonlinear calibration curve is established between the instrument measurements and reference method measurements. When developing the correlation, the following procedures should be followed:

Set up the instrument – perform the instrument internal zero and calibration adjustments.

Operate the instrument for an initial 168‐hour period in its normal mode, prior to conducting the manual reference method testing.

Check the instrument zero and span drift according to the manufacturer's instructions. Determine the drift over a period of seven days to see if it meets the specifications given in Table 9‐2.

Develop the correlation curve:

Perform measurements within normal process operation at three levels of particulate mass concentration. The levels should range from low, intermediate, and high emissions values.

Repeat the measurements at the three concentration levels to provide a total of at least 15 measurements.

If low, intermediate, and high emissions values cannot be attained within normal process operation, vary emissions by adjusting the particulate emission control system or spiking the flue gas with particulate matter.

Integrate the instrumental monitoring system data over the periods of manual testing.

Perform the specified statistical calculations to determine if the monitoring system meets the specifications given in Table 9‐3. A least squares linear regression is normally performed to obtain a linear correlation function of the form:

TABLE 9‐3 Correlation Specifications for Continuous Particulate Mass Monitoring Systems for Linear Correlations

| PS‐11 Specifications | ISO 10155 Specifications
Correlation coefficient | ≥ 0.85 (≥ 0.75 low emitters) | ≥ 0.95
Confidence interval (95%) | ± 10% at emissions standard at half range | ± 10% of emissions standard
Tolerance interval | 95% confidence that 75% of values are within ± 25% of emissions standard at half range | 95% confidence that 75% of values are within ± 25% of emissions standard
Types of correlations allowed | Linear, logarithmic, polynomial, power* exponential* | Linear, quadratic

* Note: Other performance specifications are given in PS‐11 for exponential and power function correlations.

(9‐1)y equals a plus b x

where

y = reference test method particulate concentration (mg/m³)

x = instrument response value

a, b = regression constants

The regression constants “a” and “b” define the line of minimum deviation (the regression line) that can be calculated from n data sets (xi, yi).

(9‐2)sigma-summation left-bracket y Subscript i Baseline minus left-parenthesis a plus b x Subscript i Baseline right-parenthesis right-bracket squared equals normal a m i n i m u m v a l u e

whereyi  = reference test method particulate concentration (mg/m³) for the ith test run

xi = instrument response value for the ith run

Figure 9‐1 illustrates a typical correlation developed for a particulate monitor. The instrument reading is plotted on the abscissa and the mass concentration is plotted on the ordinate of the graph. A line of regression is drawn through the plotted points by the method of least squares. In these calculations, the gravimetric measurement is a predicted value of the mass concentration based on the calibration curve. After a regression line such as that shown in Figure 9‐1 is produced, it can be used to obtain a particulate mass concentration value from a measured instrument parameter. Nonlinear equations such as polynomial, logarithmic, or exponential expressions can also be used to fit the data. Such expressions are allowed in Performance Specification 11 as well as ISO 10155.

Because predictions for the concentration are essentially being made from the fitted line, it is desired to obtain some estimate of how good the predictions will be. This is obtained from the confidence and tolerance intervals that are required to be plotted in the method. The confidence interval is a measurement of uncertainty in the determination of the concentration value from the measured instrument parameter. The 95% confidence interval specification of ±10% of the emissions standard means that if it is met, one is 95% confident that a concentration determination at the value of the emissions standard is no greater than or no less than 10% of that value. The tolerance interval specification, if met, means that one is 95% certain that at least 75% of the values determined at the value of the emissions standard are within 25% of the emissions standard. It should be noted that calculations for confidence and tolerance intervals are more complicated if nonlinear expressions are used for curve fitting.

Issues Associated with the Correlation Method

The Elusive Generic Correlation

Particulate mass correlations are unit specific and must be determined for each instrument as installed on the source. Attempts were made in the 1970s to obtain generic, linear, and correlation functions for specific sources, such as coal‐fired boilers, cement kilns, or Kraft mill recovery boilers. These attempts, primarily using transmissometers, failed when no common correlations could be found. The studies, and those that have been conducted since (Conner 1974; Brennan et al. 1980), point out that to monitor particulate concentrations accurately by indirect measurement methods, site‐specific correlation testing must be conducted.

Figure 9‐1 Gravimetric – particulate monitor correlation for a particulate monitor.

Manual Testing Procedures

One of the assumptions made frequently in source measurements is that since a source tester is conducting a reference test measurement, the reference test data are correct. However, issues related to the manual test method itself can provide questionable correlations. The inability of a manual test method to measure emissions accurately at low particulate concentrations may lead to data spread that might make it difficult to meet the confidence and tolerance interval specifications.

Special quality control techniques may not normally be applied when conducting a Method 5 gravimetric test, but may be necessary if a valid correlation is to be obtained. Some of the problems in this regard have been

using an out‐of‐stack filtration method with filter temperatures lower than the flue gas temperature;

the inability to measure accurately low particulate concentrations;

comparing area averages in the test methods versus point averages obtained by a particulate monitor installed in a nonrepresentative location; and

inadequate experimental techniques:

inadequate probe and nozzle cleaning techniques to account for probe particulate deposition;

failure to calibrate the test apparatus, or performing calibration procedures improperly;

poor filter and probe catch weighing techniques, failure to perform buoyancy corrections;

failure to apply quality control procedures, such as filter and container blanks, dual probes.

Emission sources are controlled today to lower concentration levels than when the manual gravimetric methods were first established in the 1970s. Intended for the measurement of particulate concentrations greater than 20 mg/m³, the manual methods are inadequate for measurements at concentrations less than 20 mg/m³, which are commonly experienced today. A test method addressing low particulate sampling has been standardized by ISO (ISO 12414). In the United States, test Method 5i is used to serve this purpose (U.S. EPA 2020g). The following manual test methods for measuring particulate matter at low levels might also be considered.

ISO 12414 Determination of Particulate Emissions at Low Concentrations (Out‐of‐Stack Filter)

ASTM D6331 Determination of Particulate Matter at Low Concentrations (ASTM 2021b)

ASTM D6831 Determination of Particulate Matter using an In‐Stack Inertial Microbalance (ASTM 2021c)

EN‐13284‐1:2017 Stationary Source Emissions – Determination of Low Range Mass Concentration of Dust – Part 1: Manual Gravimetric Method (CEN 2017)

PS‐11 specifies that the EPA manual particulate test methods, Method 5, Method 5i, or Method 17 (U.S. EPA 2020a, g, b) be used in establishing the correlation. ISO 10155 specifies that ISO 9096 be used. Method 5i modifies Method 5 by using a lightweight filter assembly and requiring the use of paired sampling trains for each test run. For concentrations greater than 10 mg/dscm, the relative standard deviation between the trains must be less than 10%. At 1 mg/dscm, a 25% relative standard deviation is acceptable.

Although care should be taken in the selection of a monitoring method, equal attention should be paid to selecting a qualified test team as well as an appropriate test method when developing the correlation. It is recommended that source tester companies performing the testing for PS‐11 meet the requirements of ASTM D 7036, Standard Practice for Competence of Air Emission Testing Bodies (ASTM 2021e).

Representativeness

In Method 5, an extracted sample is collected on a filter outside of the stack, whereas many PM monitors measure in‐stack. Conducting an out‐of‐stack filtration method that collects particulate matter at temperatures lower than the flue gas temperature may lead to the collection of condensable materials not observed by an in‐stack particulate monitor. Some reference test methods extract particulate samples in the stack (EPA test Method 17), while other test methods collect particulate matter at a specified temperature (Method 5) (US. EPA 2020a, b). The correlation of two disparate measurements may lead to a correlation, but one that may not be valid under all operational conditions.

Also, PM monitors sample at a point, a small volume, or on a line (transmissometers), whereas in the source test methods, an area average is determined by usually sampling a minimum of twelve equal areas. This area average is then correlated to the single point average. If the flue gas particles are stratified over the area, a suitable correlation may be obtained, but only if the stratification pattern and particle size distributions associated with that pattern do not change appreciably with the unit operating conditions. If that pattern changes, the original correlation may have no relationship to the new pattern and the emissions values may no longer be accurate¹

The idea that the performance of an instrument is judged on factors that have little relevance to its operation is somewhat unique to source monitoring. In order to meet the criteria of PS‐11 or ISO 10155, a point monitoring instrument must correlate to an area average. A line monitoring instrument (such as a transmissometer) must similarly correlate to an area average. For particulate monitoring systems, conducting an area average reference test method against a point or line averaging instrument can lead to confusion regarding the instrument performance itself. Correlation testing lumps together stratification, particle size, and particle composition issues, making it difficult to separate testing issues from instrument performance. It would in fact be better to conduct instrument performance evaluations with collocated probes and address stratification issues separately.

Process Operating Conditions

One of the greatest problems in developing the correlation is the difficulty in changing particulate emission levels over the measuring range. PS‐11 requires the correlation test to be done at three levels: 0–50%, 25–75%, and 50–100% of the maximum PM concentration. These levels may be relatively easy to achieve with some sources, such as those controlled with electrostatic precipitators, but it may be more difficult with those using baghouses.

Changes in process operations that lead to significant changes in particle characteristics or the particle size distribution may greatly affect the slope of the correlation line. Changes in fuel, control equipment, or process rate changes may contribute to this problem. Also, changes in these operations could modify the stratification pattern. If the calibration is very sensitive to this pattern (as may be the case with point monitors), the point measurement may no longer correlate with the area average obtain by a traversing manual test method.

When developing a correlation under different operating conditions, three separate correlations could in effect be obtained (Figure 9‐2). Note from Figure 9‐2 that at each operating condition, a different slope can be drawn. However, if a combination of all the test data still meets the correlation specifications given in Table 9‐1, the resultant composite correlation will be valid within the limits of the specification. This composite calibration line may not pass through the zero point and the spread in the data will, in general, be greater than if only one distribution was correlated. Nevertheless, agencies may accept such correlations if the data fall within 90 or 95% confidence intervals.

Figure 9‐2 Correlation issues.

Low‐Level Concentrations – The Problem of Zero

Figure 9‐2 ilustrates that different slopes may occur under different operating conditions. It is often found the plant may not wish to change the manner in which it is operating, or to spike the flue gas with particulate matter, in order to vary the particulate concentration of the flue gas. Instead, the manual testing will be conducted at the normal plant operating conditions, or over a small range of operating conditions. This typically leads to a cluster or clusters of points such as those shown in Figure 9‐2. Note that a different correlation can be made at each level. Note also that none of the provisional correlations of the clusters of Figure 9‐2 go through zero. Whether the correlation curve should go through zero or not has been a matter of debate ever since the technique was being standardized by ISO in 1980. PS‐11 gives four options for the zero point:

For in‐situ instruments, remove the instrument from the stack and monitor ambient air on a test bench.

For extractive instruments, remove the extractive probe from the stack and draw in clean ambient air.

Perform manual reference methods measurements when the flue gas is free of PM concentrations or contains very low PM concentrations.

Estimate the monitor response when no PM is in the flue gas (e.g. use a zero‐output value provided by the manufacturer [e.g. 4 mA = 0 mg/m³]).

In other words, EPA views zero as a valid point that can be included in the correlation. On the other hand, if zero is ignored, the correlation may indicate that the flue gas contains particulate matter even if the monitor reads zero. If it is recognized that the monitor should register a value of zero when no particulate matter is in the stack, then zero should be included when developing the correlation. But then, another question arises, whether the correlation line should be forced through the zero point (0,0) or should the zero point be just another data point used in developing the correlation. Over the history of using such correlations, correlation data more often show a cluster of data points at some mid or high‐level value with a line drawn to zero, rather than allowing the zero value to float. The regulatory agency should be consulted for guidance if the method for using a zero is not clearly specified by the relevant method.

Developing particulate monitor correlations at three levels can be expensive, impractical, or, in some views, unnecessary. Whether or not correlations are developed at three distinct levels and meet the specifications given in Table 9‐3 is often a matter of regulatory enforcement, which may or may not be exercised.

Spiking

Spiking the flue gas with particulate matter is offered as an option in PS‐11, but issues associated with the particle size distribution of the spiked material arise. Materials used for spiking are often taken from the collection hoppers of air pollution control equipment. However, the size distribution of particulate matter collected in a hopper may be quite different from that found in the flue gas after the collection device. It is usually more difficult to collect smaller particles in air pollution control equipment, but it is the smaller particles (generally <10 μm diameter) that are measured in the flue gas. Spiking the flue gas with material from a collection hopper may increase the particle concentration, but the particle size distribution may be skewed to larger particle sizes, which may not be representative of the distribution in the stack, depending upon the operation of the unit and associated control equipment. In the case of units controlled with baghouses, this may not be an issue, because a bag break should cause the release of particles distributed similarly to those collected in the hopper. Procedures for particulate spiking in PS‐11 tests have been commercialized and have been successfully applied (Baxter 2010; Everett 2018).

Continuing Operation

The correlation method is a somewhat imperfect technique in defining a calibration line because the many variables involved are difficult to control. The Table 9‐3 specifications could be either more stringent or less stringent, but they do represent standards that are achievable in most applications today. The specifications account for instrument performance, testing performance, and plant variation. If they cannot be met by an analyzer, it does not mean that the technology represented by that monitor does not work. It rather means that either the wrong monitor is chosen for the application or that the correlation testing is not done properly. The statistical bounds specified for the method therefore provide a guideline for determining the applicability of the monitoring technique.

Developing a correlation provides no assurance that it will remain valid if plant operating conditions, fuels, or other parameters change. As will be seen in the next section, many of the monitoring techniques are sensitive to particle characteristics, which may affect the instrument response, and thereby, the correlation. If the particle size distribution or composition changes, the monitor response may no longer be correlated to the particle concentration in the same way as when the calibration line was developed. Because of this issue, it is necessary that the correlation be checked periodically by repeating the manual gravimetric tests. The quality assurance requirements of Part 60 Appendix F Procedure 3 for PM monitors require such periodic validations of the correlation.

CONTINUOUS PARAMETER MONITORING SYSTEMS (PM CPMS)

In 2012, a simplified procedure was introduced for correlating particulate monitors with stack particulate emissions. Although a particulate monitor may be the same as one certified under Performance Specification 11, when the simplified procedure is used, they are called “PM continuous parameter monitoring systems (PM CPMS)” instead of “particulate matter continuous emission monitoring systems (PM CEMS).” This might first appear as an issue of semantics, but the distinction is an important one because it takes considerably less effort to certify a continuous particulate monitoring system as a PM CPMS than as a PM CEMS.

The simplified procedure requires establishing an “operating limit” for the monitor. This is done at the time a performance test is used to demonstrate compliance with the particulate emissions limit for the operating unit. Depending upon the emission levels at the time of the test, the operating limit is determined in one of two ways.

Determining the Operating Limit (Case A)

If the PM emissions are less than 75% of the PM emissions limit over the period of the compliance test, the operating limit is determined by taking the average result of three Method 5 or 5i test runs, the average result of the particulate monitor during the test, and the instrument zero value (Figure 9‐3). The PM CPMS instrument zero is determined by one of the same four methods as given in PS‐11 (see above) for PM CEMS. Both the monitor average test and zero values are to be given in the units of the monitor response (ma, mv, or other). A simplified correlation equation is then developed, relating the milliamp or millivolt response of the analyzer to particulate emissions as follows:

Figure 9‐3 Determining the operating limit.

(9‐3)upper R equals StartFraction upper Y 1 Over upper X 1 minus z EndFraction

where

R = the relative value of PM emissions per PM CPMS milliamp (millivolt or other)

Y₁ = the PM compliance emissions average determined by the reference test method

X₁ = the analyzer average output in milliamp (millivolt or other) determined during the compliance test

z = the zero value of the instrument

The units of R and Y₁ are the same as the units in which the emissions limit is given. For example, R may be given in lb/MWh per milliamp for electric generating units, lb/ton clinker per milliamp for cement plants, lb/mmBtu for boilers, or mg/dscm for solid waste incinerators.

If, at the time of the testing, the emissions are less than 75% of the emissions limit, then the operating limit (OL) is established as 75% of the emissions limit. The operating limit is calculated as follows in Equation 9‐4.

(9‐4)o Subscript upper L Baseline equals StartFraction 0.75 upper L Over upper R EndFraction

where

OL = the operating limit on a 30‐day rolling average in instrument output units (ma, mv)

L = source emissions limit in units of the standard

R = PM CPMS response as determined from Equation 9‐3 in units of the standard

This can be looked at in another way as establishing a calibration function for the analyzer, using the zero value and the results of the Method 5 tests to extrapolate the line up to 75% of the compliance limit (Figure 9‐3), in compliance units.

Determining the Operating Limit (Case B)

If the PM emissions are equal to or greater than 75% of the PM emissions limit at the time of the testing (but still within the compliance limit), the operating limit is determined using Equation 9‐5:

(9‐5)o Subscript upper L Baseline equals StartFraction 1 Over n EndFraction sigma-summation Underscript i equals 1 Overscript n Endscripts upper X Subscript i

where

X₁ = the analyzer average instrument output in milliamp (millivolt or other) determined during the compliance test

n = the number of runs during the compliance test

Compliance is then determined on a 30‐day rolling average basis, where the average is updated each day. The operating limit is required to be determined annually and readjusted using the results. If the 30‐day rolling average exceeds the operating limit, a performance test must be conducted within 45 days of the exceedance.

BAG LEAK DETECTORS (BLD)

A third regulatory use of particulate monitors is as bag leak detectors. Cement plants using baghouses for particulate control are required to install bag leak detectors under the requirements of Part 63 Subpart LLL, as well as do other Part 63 sources. The only requirements for bag leak detectors are that they must be installed, calibrated, and maintained according to the manufacturer's specifications and that they follow the guidance given in the EPA document: Fabric Filter Bag Leak Detection Guidance. EPA‐454/R‐98‐015 (U.S.EPA 1997b). Bag leak detectors are discussed in greater detail in Chapter 13.

A more detailed and thorough set of specifications is given in the ASTM standard practice D7392 – PM Detector and Bag Leak Detector Manufacturers to Certify Conformance with Design and Performance Specifications for Cement Plants (ASTM 2021d). Although conformance with the requirements is not mandated by EPA, ASTM D 7392 can be incorporated into the purchase contract specifications by requesting a certificate of conformance to the standard from the instrument manufacturer. This is similar to the certificate of conformance to ASTM D6216 required by EPA for opacity monitors (ASTM 2021a).

ALTERNATIVE CALIBRATION METHODS

Methods other than the conducting a reference method correlation have been used to either calibrate or check the calibration (correlation) of particulate monitors. These include the generation of “reference samples,” the use of mass references, and the use of particle size standards. In generating reference samples, a known amount of particulate matter is dispersed in a known volume of air to provide a “reference sample” for the particulate monitor to measure. To reference to a sample mass, in extractive monitoring systems, the particulate matter can be collected and periodically weighed to calibrate the instrument response or a known mass reference can be used to check the instrument calibration.

These procedures may be of interest to audit instrument performance; however, they are not currently accepted as alternatives to conducting PS‐11 correlation testing. Although performance testing schemes could be developed using some type of mass standard, correlation testing would still be necessary to establish the relationship between the cross‐sectional area average particulate concentration and the point value or line concentration average of the particulate monitoring system.

Generating Reference Samples

An auditing method using a Quantitative Aerosol Generator (QAG) developed by Cooper (Cooper 2009; Peterson 2010) can provide a “system” check of PM monitors. In this check, an aerosol generator produces aerosol concentrations by evaporating solutions of metal salts (such as potassium iodide) to produce droplets that when dry will form particles of 4 μm and less. The aerosols generated will have a concentration

(9‐6)c Subscript a Baseline equals StartFraction c Subscript s Baseline upper R Over upper F EndFraction

where

ca = generated aerosol concentration

cs = concentration of metal salts in the solution

R = nebulization rate

F = the flow rate of air used to carry and dry the nebulized aerosol

The method has been used to validate the performance of multi‐metals analyzers and has been extended to particulate mass monitors. It can generate test standards with an accuracy of ±5% at a concentration of 10 mg/m³. It can serve as an alternative to PS‐11, allowing a particulate monitoring system to be calibrated without having to adjust plant operating or control conditions, and/or to serve as an audit device to serve in place of the relative correlation audits (RCAs) specified in Procedure 2 of 40 CFR Appendix F (U.S. EPA 2020c).

Mass References

Depending upon the design, extractive particulate monitoring systems can use either a reference material of known mass or collect a particulate sample and weigh it to check the system calibration. As will be seen in the next section, in β‐gauge systems, standards of known mass can be introduced into the system for calibration or audits. A calibration coefficient can be determined by using a series of reference standards having masses that bracket the range of the instrument. Once the calibration coefficient is determined, reference standards can be used relatively easily to periodically audit the performance of the instrument.

Hybrid systems enable internally calibrating one analytical technique with another. If one part of the system provides a predictable and consistent relationship to mass, the other part of the system can be periodically calibrated to the mass value. For example, a particulate filter, incorporated into the system can be periodically weighed to either validate or calibrate the primary sensor, such as a light scattering device. An advantage here is that if the hybrid system operates continuously, calibration checks will eventually be performed under different plant operating conditions, where particle distributions and characteristics may change. Although the system could be simply recalibrated after each check, the body of data collected over time could be used to develop a correlation that could more accurately relate mass emissions to the sensor responses.

Particle Size Standards

Glass and polystyrene spheres and gold nanoparticle particle size standards are available from NIST as Standard Reference Materials (SRMs) and a number of suppliers (e.g. Duke Scientific, Thermo Fisher) from sizes ranging from 10 nm to millimeters. Such spheres can be used in calibrating light scattering monitors. However, in most cases a separate apparatus is necessary to perform the calibration check.

Even though an instrument may be calibrated with primary standards, it may never be possible in source monitoring applications to obtain accurate total stack mass emission rates without relating the point or line average sampled by the monitor, to the overall area average emissions. As discussed, establishing such correlations is done by conducting PS‐11 or ISO 10155. Although at some point a correlation needs to be established, the use of primary standards to assess the “instrument” performance can be used to distinguish between instrument performance and fluctuations in flue gas parameters. For well‐characterized and stable sources, calibration checks using primary standards may allow a reduction in the frequency of correlation retesting.

PARTICULATE MEASUREMENT TECHNIQUES

A variety of analytical techniques have been applied to sensing flue gas particulate matter. The techniques utilized in commercial instrumentation function by different basic physical principles such as light scattering, charge transfer, and mass accumulation. Both extractive and in‐situ sampling methods have been used for sample delivery. In some cases, especially where water droplets are present, an analytical technique normally used for in‐situ monitoring is engineered into an extractive apparatus. As with gas monitoring systems, there is no one best system for all applications. In some cases, there may be no system that is completely satisfactory, i.e. that will meet all of the correlation criteria of Table 9‐3. However, experience in Europe and the United States over the past 50 years has shown that the range of options available is sufficient for establishing particulate mass monitoring regulatory programs (Martin 1996; Peeler et al. 1996; U.S. EPA 2000). Techniques used in particulate monitoring are listed in Table 9‐4.

TABLE 9‐4 Continuous Particulate Monitoring Techniques

Physical Principle
Sample Delivery Options

Accumulated mass sensors

Beta radiation attenuation

Extractive

Loaded oscillator

Dilution extractive

Optical sensors

Light extinction

Path in‐situ, extractive

Received light modulation

Path in‐situ

Light scattering

Point in‐situ, extractive

Forward

Point in‐situ, extractive

Back

Point in‐situ

Side

Point in‐situ

Probe electrification methods

Contact charge transfer

Point in‐situ

Electrodynamic induction

Point in‐situ

Most commercial analyzers used today measure particulate concentration indirectly, and the performance standards of PS‐11 or ISO 10155 are applied to the correlations developed. The transmissometer and beta gauge were the first analyzers used in Europe, followed by light scattering instruments. Probe electrification instruments have also been used, but for limited quantitative applications. Transmissometers can still be suitable for high concentration measurements, whereas light scattering techniques may be more applicable at low concentrations where the particle size distribution does not change appreciably. Where particle size distributions do change under changing process conditions or with unit upsets, accumulated mass methods may be more appropriate.

The optical methods typically measure in‐situ, in the stack without sample extraction, but they can also be incorporated into heated extractive configurations to vaporize flue gas water droplets for applications after wet scrubbers. The beta‐radiation attenuation method requires sample extraction; however, loaded oscillator methods can be designed in either extractive or in‐situ modes. Probe electrification sensors have been typically installed in in‐stack configurations.

Accumulated Mass Sensors

Accumulated mass sensing techniques are the closest in principle to the direct gravimetric test methods against which the mass correlations are made. In these methods, the particulate matter is collected on a filter and the collective mass is determined by some non‐gravimetric technique (Jaklevic et al. 1981).

β‐Radiation Attenuation

In beta radiation attenuation devices, flue gas is drawn isokinetically through a probe to be deposited on a glass fiber filter tape. The filter tape, wound on a roll, moves sequentially so that a spot of particulate matter is collected on the tape over the period that the tape is stationary (Figure 9‐4). Because the sample must be extracted, issues of particle deposition and water condensation become important. By diluting the sample and maintaining the sample system temperature above the dew point, many of these problems can be minimized.

The filter tape moves to a sensor, which is a ¹⁴C or other radiation source emitting beta rays (0.01–0.1 MeV electrons). The β‐radiation is both absorbed and scattered from the material collected. The intensity of the β‐radiation sensed by a detector (Geiger‐Muller tube) on the other side of the spot depends upon the electron densities of the atoms constituting the particulate matter and the amount of material collected. A reference measurement can be made by passing the β‐radiation through a blank portion of the filter tape.

Figure 9‐4 A β‐gauge paper tape monitor.

The amount of radiation absorbed and scattered by the collected particulate matter is dependent upon its composition. The intensity of transmitted radiation follows the approximate exponential relation attributed to P. Lenard, where

(9‐7)upper I equals upper I Subscript o Baseline e Superscript minus mu x

The absorption of β‐radiation depends upon the exchange of energy between the β‐radiation and the electric field of the electrons in the target material. The absorption and scattering are characterized by the mass absorption coefficient, μ (cm²/g), which is dependent upon the absorber thickness and the atomic number of the atoms comprising the particles. The parameter x is the mass thickness of the sample (g/cm²).

The absorption of the beta radiation is an energy loss process dependent primarily upon the number of electrons in the absorber and not on the nuclei. The mass absorption coefficient μ is dependent upon the electron density, Z/A (where Z is the atomic number and A is the atomic weight), and Emax, the energy of the beta ray (MeV). The exchange of energy between the β‐radiation and the electrons is only slightly dependent upon the atomic number for most of the elements that would be encountered in a flue gas because the electron density is essentially the same, as shown in Table 9‐5. Although the β‐radiation technique does not measure particle mass directly, it does measure the electron density of the collected material.

TABLE 9‐5 Mass Absorption Coefficients for Various Compounds

Source: Williams et al. (1993).

Compound | Z/A | μ (cm²/mg)
CaSO₄–H₂0 | 0.511 | 0.159
SiO₂ | 0.499 | 0.154
CaCO₃ | 0.500 | 0.154
Carbon | 0.500 | 0.154
Fe₂O₃ | 0.476 | 0.144
PbSO₄ | 0.417 | 0.126

The absorption coefficients will average out with a mixture of compounds collected on the β‐gauge tape. High levels of calcium sulfate or metal salts may cause some error in the measurements, which should not be significant except in problem cases. Accordingly, changes in particle composition from changes in unit operations are not as significant as in optical particulate monitors. If the atomic number of the material is relatively constant (as it will be, even for most process changes), the attenuation of the radiation can provide a measure of the spot thickness and hence the mass of the material collected. By calibrating the beta gauge using a known mass (determined gravimetrically) having a mass absorption coefficient equivalent to that of the measured material, the instrument can subsequently provide a measurement for the mass, m, collected on the filter. In the sense that the beta gauge method is closely and predictably related to mass, the method can be considered a direct method for the determination of mass (LBL 1975).

A principal advantage of the method is that it can be used to measure wet gas streams or gas streams containing water droplets, if the sampling system is maintained at elevated temperatures (typically > 180 °C). Also, a dilution system can be used to reduce the dew point so that moisture will not condense in the system. The gas stream can also be dried using a chiller, after particulate matter deposits on the tape. A volumetric measurement of the dry gas stream can then be used to report emissions on a dry basis (Zepeck 1997).

Since particles are being extracted from the flue gas, the sample velocity through the nozzle should be isokinetic, i.e. same as the flue gas velocity, in order to obtain a representative particulate sample. Temperatures must remain high or the flue gas must be diluted sufficiently to avoid condensation of water or other aerosols on the filter tape, since these materials will also absorb beta radiation. Spot collection efficiencies and gas volume and dilution ratio determinations are other factors that may produce error.

Problems can occur with particle deposition in the probe, which could lead to eventual probe plugging as well as lower than true sample measurements. The increased volume of air in a dilution system can minimize this problem, whereas in non‐dilution systems, a valve has been designed to produce a puff of flue gas through the probe to re‐entrain any deposited particulate matter (Griguoli 1997). If particle deposition in the probe is resolved, the β‐gauge technique will be essentially particle size independent, minimizing effects of changing process conditions on the system calibration.

Today, in well‐controlled sources with low particulate concentrations, particles tend to be small in diameter and stratification and settling issues tend not to be as important. Consequently, possible errors due to variation in particle size may be less than expected. Beta gauge instrument installations have been common in Europe and have been installed in coal‐fired power plants in the United States under consent decrees.

The Inertial Microbalance (Loaded Oscillator)

Electromechanical devices have been developed based on the principle that the frequency of a vibrating oscillator will change if the mass of the vibrating element changes. This technique is one of the most direct means of measuring particle mass outside of gravimetric analysis and has been studied extensively for monitoring of both particles and gases. Quartz crystals, oscillating filters, cantilevered beams, oscillating metal bands, and, today, micromachined vibrating elements have been applied in a variety of devices and permutations, as inertial microbalances, over the past 50 years.

When particulate matter adheres to a vibrating element of an inertial microbalance, the total mass of the element changes, and, consequently, its vibration frequency. This mass‐dependent vibration frequency can be used as a correlation parameter. Essentially,

(9‐8)

where

Δm = change of mass on the oscillating filter

K = constant

fa = the initial oscillation frequency

fb = oscillation frequency after the mass of the oscillator has changed

As with the beta gauge, by calibrating the instrument using a known mass, an inertial microbalance can read the mass collected on the filter directly without having to make any assumptions or reference method correlations. Here, the value of Ko is determined by placing a known mass (measured gravimetrically) on the filter and using the following equation:

(9‐9)

where

Ko = calibration constant

mknown = known mass

mo = the original mass of the filter

fknown = the vibration frequency with the known mass on the filter

fo = the original vibration frequency

Once the Ko value has been established, the uncertainty of the mass measurements will be dependent upon uncertainty associated with the measurement of the oscillator frequency. ASTM standard D 6831‐11 for the inertial microbalance specifies that subsequent K values should not differ from K₀ by more than ±5%. The total mass is determined from the measured frequency as follows in Equation 9‐10.

(9‐10)f squared equals StartFraction upper K Subscript o Baseline Over upper M EndFraction

where M = mass of the filter cartridge and any accumulated particulate matter

The method is used in equivalent EPA ambient mass monitoring instruments and has been used for ambient air monitoring for over 30 years. The technique has also been applied to monitoring particulate matter in flue gases (Burgher et al. 1999; Hiss 1997; Patashnick and Rupprecht 1991), and has been standardized under ASTM D6831 as a manual in‐stack source test method (ASTM 2021c). In this design, flue gas enters a probe nozzle and passes through a filter mounted on an oscillating, hollow tube. Particulate matter is caught on the filter as the flue gas is drawn through the tube (Figure 9‐5). As the flue gas sample is drawn through the filter, the mass of the assembly increases and using Equation 9‐10 the oscillation frequency can be directly related to the mass of the particulate matter collected.

This type of apparatus has undergone an EPA Method 301 validation against Source Test Methods 5i and 17. The advantage of the technique is that it can measure particle concentration ranges <5 mg/m³ and is capable of measuring down to 0.2 mg/m³ (Burgher et al. 2001). It has been successful in providing real‐time plant process information, particulate stratification isopleths and in calibrating continuous particulate monitoring analyzers. The instrument is useful in developing correlations for continuous mass monitors, especially at lower particulate concentrations, where it has been found to provide more accurate data than manual gravimetric filter methods.

Figure 9‐5 Design of an inertial microbalance for source testing.

When particles adhere to the filter, it will eventually become overloaded and must be cleaned. This is not a problem when conducting particulate source tests, but does limit the application of the technique for continuous particulate monitoring. The technique has been incorporated into a hybrid continuously operating system, by Thermo Fisher Scientific, where continuous measurements are provided by light scattering and periodic validation performed by an inertial microbalance (Kita 2010).

Optical Sensors

Many of the continuous particulate monitoring systems used today incorporate optical sensors to measure the effects of light transmission or light scattering in the flue gas. Transmissometers were applied widely in Europe in the 1970s and early 1980s for developing correlations between mass and optical density (light extinction). However, with the advent of more stringent emissions standards, light scattering techniques began to replace transmissometers due to their greater sensitivity at lower particulate concentrations.

As seen in Chapter 6, a transmissometer measures light transmission through flue gas. If a measurement is made across a relatively “clean” stack, the light transmission will decrease only slightly. Because the transmission across a clean stack is 100%, the instrument must subtract a relatively small number from the large number of 100%. Scattering instruments, however, start from zero. If there is no particulate matter in a stack, no light will be scattered. If particulate matter is present, light will be scattered. To design a viable instrument, a detector is chosen that will respond to a small amount of scattered light energy, resulting in greater sensitivity at low concentrations (Baujon, et al. 1992).

Light Extinction

Opacity monitors were discussed in Chapter 8 with regard to the measurement of opacity and are called “opacity monitors” with respect to that measurement. As a particulate monitor, in this chapter, the concern is more with the measurement of transmittance as it relates to mass concentration rather than with the simple observable, opacity. In that sense, the same instrument (the opacity monitor) will be termed a “transmissometer” in this chapter as a particulate monitor.

Mass correlations have been made using transmissometers since the 1970s. An advantage of the technique is that particulate stratification can be averaged over the measurement path of the instrument. Transmissometers are also relatively simple devices that are easy to maintain. Two major disadvantages in mass measurements are their limited sensitivity at low particulate concentrations and their dependence on particle size and particle refractive index changes.

From the discussion of the Bouguer relationship in Chapter 4, the transmittance measured by a transmissometer can be expressed as

(9‐11)upper T r equals e Superscript minus n a upper Q l

where

n = number concentration of the particles

a = projected area of the particles

Q = particle extinction coefficient

l = length of the light path through the flue gas

or,

(9‐12)upper T r equals e Superscript minus upper A Super Subscript upper E Superscript c l Baseline equals e Superscript minus b l

where

b = AE c and is defined as the “extinction”

AE = r²Q/m, the specific mass extinction coefficient

r = particle radius

m = mass of the particle

Again, note that the extinction, b = AE c, is directly proportional to the particulate concentration.

Taking the logarithm of the transmittance

(9‐13)ln upper T r equals ln e Superscript minus upper A Super Subscript upper E Superscript c l Baseline equals ln e Superscript minus b l Baseline equals minus b l

(9‐14)ln StartFraction 1 Over upper T r EndFraction equals b l

Again, as given in Chapter 4 in Equation 4‐8, the optical density is defined as the logarithm to the base 10 of the reciprocal of the transmittance:

(9‐15)

and

(9‐16)c equals 2.303 StartFraction upper D Over upper A Subscript upper E Baseline l EndFraction

The term “extinction” is more commonly used in European manufactured instruments and European regulation, than is “optical density,” which is more common to U.S. regulation. Both terms and their relationship to particulate concentration are given here for completeness. From Equation 9‐15, it can be seen that the extinction is merely the optical density per unit path.

Note that the extinction and optical density are both directly proportional to the particulate concentration. A plot of the extinction or optical density versus concentration should then be a straight line having a slope equal to the specific mass extinction coefficient, AE. This might appear to be convenient for applying transmissometers to measure mass concentrations; however, AE is dependent upon the size of each particle, its density, and its light absorption and scattering properties as a function of the light wavelength (refractive index) (see Jahnke 1984 and references therein). This has been known since the early 1900s when Gustav Mie solved the light scattering equations for homogeneous spheres (Mie 1908). This fact does not, however, invalidate the use of a transmissometer for continuous particulate mass measurements. If the particle characteristics and particle size distribution are sufficiently constant over the range of facility operating conditions, correlations can be obtained that meet the specifications of Table 9‐3. Numerous successful applications have been documented.

In cases where the particle size distribution changes to a degree where the correlation specifications cannot be met, modifications may be made to make the technique less particle size dependent. One such modification is to change the light wavelength from the visible (centered in the green, ~550 nm) to light in the infrared or near infrared. The shorter green wavelengths scatter to a greater degree from smaller, submicron particles than do longer, red wavelengths. A red‐light transmissometer would therefore be less sensitive to small particles and more sensitive to larger particles, which largely contribute to the mass. This has been shown experimentally by McElhoe (1982) and Uthe (1980), where Uthe found that infrared light at 3.9 μm was relatively independent of particle size for particle sizes <10 μm.

Also, as discussed above, the sensitivity of the transmissometer is limited since the detection systems are designed to measure transmittance over a range of 100–0% (0–100% opacity). The lower measurement limit of a transmissometer is about 10 mg/m³ per meter of measuring path (Martin 1993). Sensitivity can be increased by increasing the path length; however, this is not always practical or possible.

Received Light Modulation

The technique of “received light modulation” is alternatively termed “optical scintillation” or “dynamic opacity.” This variation of the extinction technique monitors rapid fluctuations in transmittance as particles move through the light beam. The fluctuations in the received light (the “scintillation”) are ratioed with respect to the average light intensity at the detector to produce a signal proportional to changes in the particulate concentration (Craney 1997), as expressed in Equation 9‐17:

(9‐17)upper Delta c equals StartFraction upper Delta upper I Over upper I Subscript a v e Baseline upper A Subscript upper E Baseline l EndFraction

Since the fluctuating light intensity and averaged light intensity are ratioed, dirty windows, lamp degradation, and detector drift biases cancel.

The technique offers an alternative to the transmissometer. In contrast to a transmissometer, where just the transmittance is measured, fluctuations in light intensity due to fluctuations in the particle concentration, Δc, are measured instead (Craney 1997).

The following equation is obtained from the Bougert equation, where the particulate concentration is expressed as the average concentration plus its change from the average (cave + Δc):

(9‐18)

The average transmitted light intensity Iave, is just upper I Subscript o Baseline e Superscript minus upper A Super Subscript upper E Superscript l c Super Subscript a v e. By expanding the exponential, we then have

(9‐19)

and

(9‐20)

Note from Equation 9‐20 that the fluctuation of the transmitted light intensity, ΔI, is proportional to the change in particulate concentration if the average light intensity, extinction coefficient, and path length remain relatively constant. By ratioing basically two transmitted intensities, issues such as dirty windows, lamp degradation, and beam misalignment are not as critical as in transmissometers. Physically, this allows the instrument to be simpler in design than the transmissometer.

Because the relationship of the mass concentration to the measured light intensity fluctuation is dependent upon the particle extinction coefficient, changes in particle size, refractive index, and so on will affect the measurement. As in the transmissometer, to make a direct measurement of the particulate concentration, AE must also be known. Again, because this is not practical for continuous particulate monitoring, the instrument is calibrated against manual stack test data using the correlation method.

Light Scattering Methods

When light is directed toward a particle, the particle may both absorb and scatter light, redirecting it from its incident path. A transmissometer measures the intensity of light that is not scattered, but the light that passes through the cloud of particles in the stack. For low opacities, the transmittance becomes a ratio between two signals that are very nearly the same – as the opacity decreases, it becomes more and more difficult to differentiate between the small reduction of light intensity and the initial light intensity. It becomes challenging to obtain measurements with a high degree of certainty below 3% opacity.

Instruments that measure scattered light instead of transmitted light are capable of sensing lower particle concentrations than transmissometers. Detectors today are capable of sensing light flashes from single particles, and as a consequence, instruments measuring scattered light are able to measure particulate concentrations as low as 0.01 mg/m3.

As discussed in Chapter 4, light scattering phenomena are classified into different regions of analysis, depending upon the particle size relative to the wavelength of the incident light. For particles much smaller than the wavelength of incident light, the light will scatter with almost equal intensity in all directions. This is called Rayleigh scattering. If the particle is much larger than the wavelength of incident light, light will be diffracted about the particle and scattering will be primarily in the forward direction.

Mie scattering will occur in the mid‐range when a particle is comparable in size relative to the wavelength of the incident light. For transparent particles (fly ash, quartz), very complicated scattering patterns can result. Light transmitted through a transparent particle will constructively and destructively interfere with light diffracted around the particle to produce an oscillatory pattern such as that shown in Figure 9‐6. The intensity of scattered light depends upon the angle of observation, the size of the particle, its refractive index and shape, and the wavelength of incident light. Figure 9‐6 shows this dependence for a particle having a diameter of about the same order of magnitude as the light wavelength. The lobes shown in the figure illustrate that light is scattered both in the forward and the backward directions, as well as to the side.

The theoretical analysis of the pattern was published by Gustav Mie in 1908 and shows mathematically the angular scattering intensity dependence upon particle size, wavelength, and refractive index (Mie 1908). The Mie–Lorenz theory assumes that the particles are spherical and that the scattering is from single particles. The theoretical analysis of the scattering pattern gives the angular scattering intensity dependence, i(θ, Φ, dp, λ, m), as a function of the scattering angle, θ, the polarization angle, Φ, the particle size, dp, the wavelength, λ, and, m, the complex refractive index of the particle. Scattering patterns such as these contain much information and by selecting appropriate light wavelengths and detection angles, both particle size measuring instruments and continuous particulate monitors can be designed (Giel et al. 1994; Knollenberg 1979). Most scattering instruments use light with wavelengths in the range from 400 to 700 nm. Therefore, for submicron particles (i.e. <1000 nm), which predominate in well‐controlled flue gas streams, light scattering phenomena can be described by Mie theory.

Figure 9‐6 Detail of Mie scattering phenomena.

Different viewing angles are chosen by instrument manufacturers in the design of light scattering measurement devices. These devices operate based on back, side, or forward scattering principles and are characterized by the placement of the detector relative to the light source as shown in Figure 9‐7. Each configuration has some advantages, either for minimizing dependence on the particle size distribution and particle refractive index, or for engineering design purposes. The forward scattering technique is less sensitive to particle size and refractive index changes over certain particle size ranges compared to other techniques. Side scattering (Figure 9‐7b) is most sensitive to refractive index and particle size changes, but allows a relatively easy method for in‐stack measurement. For light‐absorbing particles, backscattering is less sensitive to particle size changes (Nusplinger 2003).

Backscattering

Transmissometer manufacturers such as Teledyne Monitor Labs, Sick, and Durag have designed laser backscattering instruments that are all quite similar and, in terms of economy, use some components of the hardware associated with their transmissometers. The instruments are relatively simple, consisting of a transceiver case, a red laser, detector, and a blower. In these instruments, light from a laser is projected into the stack, where particles scatter light, and backscattered light is focused on a detector (receiver). Companies that manufacture backscattering particulate monitors include the following:

Teledyne Monitor Labs LaserHawk. In the LaserHawk system, a 655 nm laser light beam is projected into the stack at an angle and the detector field of view is focused in order to minimize the detection of reflections from the stack walls (Figure 9‐8). If the stack is less than 2 m in diameter, light may be reflected from the back wall, causing the instrument to read artificially high. This may also occur for larger stacks having low particulate concentrations. The installation of a light trap can prevent light from being projected back into the field of view of the detector. An internal reference detector is incorporated into the system to correct for any variation of laser light intensity. The instrument is scaled after it is installed so that the detector response will be within 60–80% of full scale. Teledyne provides an external calibration kit, similar to the opacity monitor “zero jig,” where diffusive reflectance filters can be inserted to check the instrument zero and upscale responses to attenuator filters.

Figure 9‐7 Light scattering instrument configurations. (a) Backscattering. (b) Side scattering. (c) Forward scattering.

Figure 9‐8 Teledyne Monitor Labs backscattering particulate monitor.

Sick Dusthunter SB. In a similar design, the Sick “Dusthunter” uses a laser diode emitting at 650 nm and two detectors (receivers), which monitor and correct for background and ambient light. Zero mirrors can be added to the system to slide into the light beam to check and correct for window contamination up to 30% of the light intensity. A light trap is used in small‐diameter stacks when necessary.

Durag DR‐320. This backscattering instrument similarly uses a red laser diode. In the instrument, one half of the detector monitors background light and the other half, backscattered light plus background light. Subtracting the two signals gives the backscattered signal.

SPTC/ESC P5‐C. In a probe‐type instrument, originally designed by Environmental Systems Corporation and now marketed by SPTC, Ltd, infrared light is focused on a detector as shown in Figure 9‐9.

The instrument is optimized to measure particles <10 μm in size through the selection of light at a wavelength of 900 nm and a back scattering measurement. The instrument response is found to be proportional to the cube of the particle radius which provides a direct relationship to particle volume, and hence, mass. The use of infrared light results in more backscattering from particles of the size normally encountered in flue gases, and hence more measurable light energy.

Figure 9‐9 SPTC/ESC P5‐C Backscattering continuous particulate monitor.

In this instrument, light from an infrared light emitting diode is focused on a sampling volume where the particulate matter in that volume scatters light. Backscattered light is in turn focused on the signal detector. The reference detector is used to compensate for any changes in the lamp intensity. A zero is performed by blocking the backscattered radiation, and the system performs an internal calibration by moving a surface of known reflectivity into the light beam.

The instrument is stated as having a measurement range of 1–20 000 mg/m³ for particle sizes of 0.1–10 μm and is relatively insensitive to particle size distribution changes in this size range. The detection limit is 0.5 mg/m³. The instrument is somewhat dependent upon the refractive index of the particles and the manual test method correlation may have to be redone if the particle characteristics change significantly to the extent of invalidating the original calibration.

Side‐Scattering

Side‐scattering instruments were developed by Sick Optic and Durag Corporation in Germany and were marketed for continuous particulate monitoring applications in the 1990s, continuing in the 2000s. This type of instrument is relatively simple and easy to install, but as with backscattering instruments, they are to some extent dependent on the refractive index of the particles and the particle size distribution. Both Durag and Sick instruments are no longer manufactured. However, descriptions of their operation can be found in the second edition of this book.

Forward Scattering

Both in‐situ and extractive forward scattering instruments have been developed. In the in‐situ instruments, a laser beam is projected through a relatively small probe cavity. Light scattered by the particles is detected at an angle near 10° to measure light in the forward‐scattered lobe shown in Figure 9‐7a. Forward scattered light is less sensitive to refractive index changes and may be more suitable for instruments applied in conditions where the particle composition is variable (Giel and Douglas 1995; Myers and McCall 1998) although this has not been well documented in source monitoring applications.

Figure 9‐10 Durag forward scattering in‐situ particulate monitor.

In‐situ forward‐scattering systems have been developed by Durag, Sick, and PCME/ENVEA with designs similar to that shown in Figure 9‐10. In this design, a transceiver mounted on the side of a duct or stack houses an infrared laser light source and detector, beam splitters, optical shutter, and associated electronics. The laser beam is projected through a relatively small probe cavity to essentially make a point measurement. Light scattered by particles is detected at an angle near 10° to measure light in the forward‐scattering lobe shown in Figure 9‐7a.

An objective lens at the probe end receives light scattered in the forward direction, which travels in an optical fiber waveguide to a photodetector (receiving diode) back in the transceiver of the instrument. A light trap is located at the end of the probe to capture unscattered light. Current output from the photodetector is related to the amount of scattered light, which is correlated to the concentration of particulate matter in units of mg/m³, following the procedures of PS‐11.

A periodic automatic stability check can be conducted by switching the light beam from the measurement path to a comparative path where light is transmitted directly to the objective lens. An air purging system located to the side of the transceiver can provide an air window to keep the exposed transceiver optical window clean. It can also protect the window from condensation from flue gas moisture and reduces thermal conduction from the stack to the transceiver assembly.

In an extractive forward‐scattering system manufactured by Sigrist (Christen and Rogner 1998), flue gas is sampled at a constant sample rate 1.5 times the isokinetic rate. The stream is split and a portion of the flue gas flows into a heated cell, shrouded by a sheath of purge air that serves to minimize contamination of the cell and the cell windows (Figure 9‐11). Light from a tungsten lamp is split into a measurement beam and a reference beam using a rotating chopper. The measurement beam passes through the flow‐through cell and light at an angle of 15° is measured at the detector. The reference beam provides a reference value to correct for variations in lamp intensity. When the chopper is in a position that blocks both beams, a dark background signal is registered by the instrument. Both reference values are used to obtain a compensated scattering intensity. The instrument measures down to a level of 0.02 mg/m³.

This design is useful in applications where water droplets are present in the flue gas. Water droplets can be vaporized by the system so that they will not be detected as particles in the measurement chamber. The volume of water vapor generated by the droplets may dilute the sample slightly; however, this is usually ignored or can be corrected through correlation with the manual method. Also, over‐isokinetic sampling will bias the results low if large particles (>5 μm) are present. Similarly, this bias can be corrected through correlation. Again, correlation will remain only valid when plant operations continue under the bounds and conditions under which the correlation was developed.

Particle Sizing Analyzers

Optical scattering methods for particle size measurements have become quite sophisticated in clean room, ambient air, and industrial applications. The Mie–Lorenz scattering functions can be more easily solved with today's micro‐processing systems so that particle size distributions can be readily calculated. The concentration can, of course, then be calculated directly if the particle density is known.

In the discussion of Figure 9‐8, it has been noted that when the particle size is near that of the impinging light, Mie scattering will occur and the scattering intensity will be angularly dependent. Basically, large particles will scatter light at smaller angles with greater intensity. Small particles will scatter light at larger angles with lower intensity. If the particles are too small to obtain enough resolution in the scattering, the wavelength can be changed to lower wavelengths (e.g. from red to blue) to increase the signal strength. These effects are due to Mie–Lorenz scattering, and from them, one can obtain information about the size of particles passing through the light beam.

Figure 9‐11 Extractive forward extractive particulate monitoring system.

Lasers are used typically in particle sizing devices, which may have several light sources and detectors placed at various angles to the axis of the light beam in order to measure over a wide range of particle sizes. Light scattering instruments for measuring particle size in coal‐fired power plants were developed as early as 1977 (Knollenberg 1979). The Public Service Company of Colorado's Valmont coal‐fired power plant was tested in 1978, using what was then known as the Fine Particle Stack Spectrometer System (FPSS). This early work was encouraging; however, the lack of commercial demand limited the development of the technique for this application. Insitec Measurement Systems, Inc., followed with a forward‐scattering instrument using a diode laser and water‐cooled probe (Giel 1994, 1995). In this device, both transmitted light and light scattered at an angle of 11° were measured. Monitoring both particle size and concentration (for known particle densities), the device was capable of monitoring particle sizes from 0.25 to 100 μm at concentrations from 10 μg/m³ to 10 mg/m³. Malvern, Inc., where the Insitec technology now resides, currently markets particle counting devices for industrial manufacturing applications but has discontinued their monitors used for source emissions monitoring.

More recently, Sick has developed an extractive monitoring system that monitors scattered light at several angles. By assuming or determining a value for the refractive index and analyzing the Mie scattering patterns, the instrument can determine the particle size distribution curve. By assuming a value for the particle density, it can output concentration values for total suspended particulate (TSP), and for particles having diameters in the range of 2.5 μm (PM2.5) and 10 μm (PM₁₀₎ (Altermann 2018; Altermann et al. 2020; Barreiro and Schladitz 2019).

Strickland (2001) indicates that accurate refractive index determinations can be obtained by the iterative deconvolution of the Mie scattering equations. If this is in fact true, the major impediment remaining to the wider application of this technology to source monitoring would be the determination and variability of the particle density. This variation has been estimated by some to be on the order of ±30%, however the degree of variation in a coal‐fired plant may be dependent upon its mode of operation, fuel variability, and method of particulate control.

Again, the one problem with determining particle mass concentration from particle sizing instruments is that the particle density must be known or assumed. For combustion processes, this may be problematic if the relative concentrations of unburned carbon, silica, and other materials vary with plant operations. However, for some applications, a determination of the particle size distribution may be more important than a mass concentration calculation and density considerations may be irrelevant.

Many of the problems in particle size measurement have been resolved in instruments designed for clean‐room and industrial, pharmaceutical, and many other applications. Unfortunately, the technology has been virtually ignored in the field of continuous emission monitoring, primarily since the regulatory interest is largely in terms of gravimetric mass determinations rather than particle size. This interest is, however, changing due to increased international concern in the dependence of health effects on particle size and the distinction between PM2.5 and PM₁₀ particulate matter. This concern has been primarily focused on ambient air particulate concentrations, but has been shifting to the mitigation of fine particle emissions from stationary sources.

Imaging Systems

Particles can be photographed as they are moving in a flue gas stream. By using a flashing light source, the particles can be “stopped on the photograph,” counted, and sized. In some instruments, shape analysis can also be performed. With the advent of digital image capture technology, and the concurrent advances in computing capability and pattern recognition software, the technique has become practical in applications where it was never considered.

Today, commercial imaging instruments are available for determining particulate matter in gas turbine air supplies and particulate matter in flue gases. The resolution of these instruments is dependent upon the optical system and capability of the charge‐coupled device (CCD) used as the sensor. A light scattering instrument using this technique is marketed by Greenbank Energy Solutions in partnership with GAIM Ltd (Figure 9‐12).

In this instrument, a pulsed laser beam is optically spread to focus a sheet of laser light, 5 mm by 100 mm, which faces the flue gas flow. A fast, high‐resolution CCD camera is installed at 90° to the transmitted light path to measure the light scattered by the moving particles. Each frame provides a record of the particles scattering light in each pulse, from which the particle size and particle size distribution can be determined. If the particle densities are known, the mass concentration in mg/m³ can be calculated from the distribution data. The technique can also be used to determine particle velocity and flue gas velocity by monitoring particle time of flight between subsequent “flashes.”

Figure 9‐12 In‐stack imaging particle size monitor.

Hybrid (Combination) Systems

As a relatively straightforward development, instrument manufacturers are finding advantages in combining monitoring techniques to develop hybrid systems. A transmissometer combined with a light scattering instrument can provide instrument responses at both high and low particulate emission levels. Or, a light scattering instrument combined with an accumulated mass sensor can provide for an internal check on the correlation curve as well as a direct mass measurement.

Extinction/Light Scattering Instrument

Sick has combined both extinction and light scattering techniques in their “Dusthunter C200” cross‐stack monitor (Kietzer 2010) (Figure 9‐13).

Here, a transmissometer measuring the extinction monitors particulate mass at medium to high levels after correlation with a gravimetric reference method. The forward‐scattering sensing elements are intended for the measurement of particulate matter at low concentrations in the range of 5 mg/m³, but the instrument can also be scaled to measure from 0 to 200 mg/m³.

Light Scattering/Gravimetric Filter

The hybrid TSI “DustTrak” light scattering/gravimetric filter instrument is designed for ambient air monitoring, not emissions monitoring. However, it does show a simple concept that can resolve issues of particle size effects in light scattering instrument correlations. In the monitoring system, continuous light scattering measurements are coupled with the periodic removal of a gravimetric filter for periodic analysis and calibration of the unit (Figure 9‐14). The instrument measures both the total scattered photometric signal and uses a laser photometer, to measure scattered light for PM₁, PM2.5, PM₁₀, and total particulate concentration determinations in ambient air. A 35 mm filter cassette sampler is used to perform gravimetric analysis for periodic calibration checks and, possibly, data adjustments.

This ambient air monitor is available in a variety of desktop and handheld configurations and has given results comparable to the tapered element oscillating microbalance (TEOM) (Moosmüller et al. 2001). The problem in source monitoring applications is, of course, that the filter removal and analysis is a manual operation. Also, if the particle characteristics change more frequently than the filter analysis, mass corrections to any response correlation curve using the filter weights might not be valid.

Figure 9‐13 Combination extinction, forward light scattering monitor.

Figure 9‐14 The DustTrak ambient air hybrid aerosol analyzer.

Light Scattering/Inertial Microbalance

The attraction of the hybrid system is that arguments such as “the refractive index or particle density can change” can be countered by periodic calibration of the optical sensing system with a direct mass monitoring sensor. An inertial microbalance system, developed by Thermo Fisher Scientific, utilizes this concept as illustrated in Figure 9‐15. The combination of light scattering with the TEOM™ was originally proposed for monitoring diesel particulate emissions (Moosmüller et al. 2001), where it was suggested that the TEOM could be used to calibrate an optical signal. Thermo Scientific has developed such a system using a light scattering sensor for continuous measurement and their tapered element inertial microbalance (TEOM™) (Rupprecht and Patashnick, Inc.), for periodic, self‐referencing calibration (Goohs 2010; Kita 2010). The instrument is dilution‐extractive in design, with heated and filtered air diluting the sample gas after the flue gas sample is withdrawn from the stack.

The analyzer combines an inertial balance and a scattering photometer for the measurements. The photometer, using a 660 nm wavelength light, measures forward and backward scattering at angles of 60° and 105°. From the discussion of the inertial microbalance given previously (Figure 9‐5), the change in mass on the oscillator filter is measured over a given time period. The particulate concentration is calculated from the particulate mass and the volume of gas, ΔV, passing through the filter over the period of mass accumulation (Equation 9‐21).

(9‐21)c Subscript upper P upper M Baseline equals StartFraction upper Delta m Over upper Delta upper V EndFraction

In a continuous mode of operation, an inertial balance will eventually become completely loaded and will have to be replaced. However, in this system, the inertial balance is not intended to be operated continuously but used only periodically to obtain a reference measurement for the application of a correction factor (PMfactor) to the response of the light scattering system by taking a ratio of the mass and light scattering signals (Equation 9‐22).

(9‐22)

where

mTEOM (avg) = averaged mass collected on the filter over the reference measurement period

iscattering(avg) = average scattering intensity over the reference measurement period

Figure 9‐15 Thermo Fisher Scientific combination light scattering/inertial microbalance particulate monitoring system.

The instrument particulate concentration readings are then obtained:

(9‐23)c Subscript upper P upper M left-parenthesis c o r r e c t e d right-parenthesis Baseline equals upper P upper M Subscript f a c t o r Baseline times c Subscript upper P upper M

Note that this will be a “wet” basis concentration because a dilution system is used in the extractive system. Flue gas moisture remains in the sampled gas, but at a dew point below the temperature of the instrument. These calculations, however, do still not complete the measurement. A PS‐11 correlation correction factor or function (PS‐11factor) must still be applied to correlate the instrument response to the manual stack test measurements of PS‐11.

(9‐24)

Because the instrument is sensing at two scattering angles. it can sense when particle characteristics are changing. At set threshold levels, this can provide as an immediate trigger to recalibrate the system. The instrument specifications give a wide dynamic measurement range from 0.001 to 400 mg/m³ for particles in the size range of 0.1–10 μm.

The instrument is unique in the sense that the flue gas is diluted with air and dwells in a residence chamber for the formation of condensable particulate matter to measure both “filterable” and “condensable” particulate matter. The dilution system design follows those of the ISO 25597 method for dilution particulate sampling (ISO 2013) and the U.S. EPA Conditional Test Method 039 (EMC 2004), being useful for measuring both filterable and condensable particulate matter.

Monitoring in Wet Stacks

All the techniques discussed above are not applicable for monitoring flue gases containing water droplets unless the droplets are vaporized. In extinction and scattering instruments, water droplets will scatter light in the same manner as particulate matter; any droplets present would be counted as particulate matter. Similarly, for impaction sensors, a hit is a hit, whether it occurs from a droplet or a dust particle. Water droplets on a beta gauge tape would affect the particle spot and instrument performance.

In most cases, wet stack problems can be resolved by extracting the flue gas and heating the droplets until they vaporize. For transmissometers and light scattering instruments, this requires that the optical system measure the flue gas in some type of chamber or cell outside of the stack, essentially by incorporating an in‐situ instrument into an extractive system. In beta gauge systems, the sample is easily diluted and heated. An extractive system configuration that has been used for transmissometers is shown in Figure 9‐16. An extractive system configuration for a forward‐light‐scattering in‐situ instrument is shown in Figure 9‐17. Such configurations raise problems associated with isokinetic sampling, particle deposition in the probe and sampling lines, heater power requirements, and reflections from the chamber surfaces. The problem of obtaining and monitoring representative samples on a continuous basis is more difficult here than in more straightforward in‐situ applications. However, such extractive/in‐situ hybrids have met PS‐11 correlation specifications.

Figure 9‐16 Extractive system configuration for vaporizing water droplets – in‐situ path monitor with heated sampling tube.

Figure 9‐17 Extractive system configuration for vaporizing water droplets – in‐stack point monitor with heated sample chamber.

Extra precautions must be taken when developing the mass correlation using manual gravimetric test methods. In‐stack filter methods may have to be modified to avoid wetting particulate filters. Out‐of‐stack filtration must similarly be maintained at elevated temperatures sufficient to vaporize any droplets. In addition, flue gas streams having a varying water vapor content may affect emissions values reported from the mass correlation. Regulations expressing emissions in units of mg/m³ on a dry basis (or dry standard cubic meter [dscm]) will require that a moisture correction be performed for systems that do not determine the concentration on a dry basis. If the flue gas water vapor content is relatively constant, a default value is often used in the correction. In sources with varying moisture content, the percentage of water vapor must be determined using another instrument or by some other means. However, depending upon the analytical technique, a simple mathematical correction may not account for the effect of changing water vapor content on the correlation itself. That is, if the particle detection mechanism is affected by varying water vapor content, a simple mathematical correction may not be adequate.

Probe Electrification Methods – Triboelectric Devices Applied for Bag Leak Detection

A variety of commercial instruments have been developed that sense particles either by charge transfer or charge induction effects. Commonly known as “triboelectric” devices, the technique is simple, consisting of a metal surfaced probe inserted into the stack. When particles in the flue gas contact the probe, a charge is transferred to the probe, producing a current. This current is measured using an electrometer at picoamp levels. In charge “induction” devices, the particles induce a charge in a metal rod as they move in streamlines around the rod.

Contact Charge Transfer

When two materials having different work functions make contact, there will be a net transfer of electrons from one material to the other after they are separated. The charge transfer can occur when a particle impacts on to the surface of the other material, or if it merely contacts by sliding and rubbing (triboelectricity). This is not an effect based on the accumulation or transfer of static charges, but an effect based upon the intrinsic electronic properties of the materials themselves. The amount of charge transferred depends on other factors besides the differences in work function. These include the particle resistivity, dielectric constant, and the physical conditions of contact (particle deformation, duration of contact, area of contact, etc.) (Wang and John 1988). A weak current, i, results, which can be correlated with the particulate mass concentration, c, according to Equation 9‐25:

(9‐25)c equals k 1 plus k 2 left-parenthesis i v Superscript n Baseline right-parenthesis

where

k₁, k₂ = calibration constants

v = flue gas velocity

n = power dependence on the flue gas velocity

The contact charge transfer method has been qualitatively successful as a baghouse particulate monitor. However, a large number of factors involved in the charge transfer limit its application for quantitative measurements (Gruber 1975; John 1975). In addition to the flue gas velocity, the current is dependent upon the particle resistivity, the dielectric constant relative to that of the rod, and the physical conditions of contact (duration of contact, area of contact, etc.). Electrostatic charges on the particles, chemical composition, condition of the sensor surface (particle buildup, corrosion), probe grounding, and particle size will all affect any correlation made with manual test methods. Particles with a high surface‐to‐mass ratio will generate a greater current than those where the surface area per unit mass is lower. A basic physical limitation exists with this technique since submicron particles that follow gas streamlines around the probe will not contact the probe. Water droplets and wet, sticky particles will also degrade instrument performance. In addition, if the particulate matter accumulates on the probe, the probe can become insulated or short circuit to ground. These factors essentially limit the contact charge transfer technique to alarm monitors where a large signal, resulting from the failure of control equipment, is generated. They are commonly used as bag leak detectors for baghouses.

Although quantitative correlations can be developed for contact transfer electrification methods, the particle characteristics have to remain relatively more constant than for other methods used for particulate monitoring by the correlation technique. The method works well when applied to flue gas streams where the particles are dry, uncharged, and constant in composition.

Electrodynamic Induction

In the contact charge transfer method, small, submicron particles following streamlines around the probe do not make contact with the probe and are not detected. However, they do induce a charge into the rod. There will be a certain rate at which the particles pass the probe, leading to periods when the probe is charged by the particles and when it is not, which is sensed as an alternating current due to variation in the particulate matter in the flue gas stream (an effect also sensed by the optical scintillation method discussed earlier). Particles will still contact the probe, but the direct current that they produce is filtered out, leaving the alternating current, which is also directly proportional to the mass concentration.

This method is said to avoid problems associated with the sensor surface conditions, grounding, probe condition, and particle velocity (Averdieck 1997a, b). The method does remain dependent on the particle size distribution, particle composition, and precharging of the particles; however, particles can be detected as small as 0.1 μm in diameter. Due to its low cost, relative to optical systems, it is attractive for a number of applications, particularly for monitoring after baghouses.

Bag Leak Detectors and the Part 63 Air Toxics Rule

Bag leak detectors are either required or are allowed as an optional method, acceptable for meeting continuous particulate monitoring requirements in 40 CFR 60 Part 63 air toxics rules (Wesselman and Askins 2005). Although many of Part 63 subparts mention specifically that bag leak detectors operate by the “triboelectric principle,” opacity monitors or light scattering instruments can also be used to provide an alarm for baghouse bag leaks.

Major stationary source categories in which Part 63 Air Toxics rules specify the use of “bag leak detectors,” BLDs, either as a requirement or as an option, are given in Table 9‐6 (U.S. EPA 2020e, f).

Major sources are those that emit or have the potential to emit 10 tons per year or more of any hazardous air pollutants or 25 tons per year or more of any combination of hazardous air pollutants.

Area sources are those that do not emit at high enough levels to be classified as a major source but nevertheless are subject to certain monitoring requirements (U.S. EPA 2020f). Area sources are associated with foundries, smelters, and institutional and industrial boilers that use baghouses to control particulate emissions. Part 63 rules and requirements for triboelectric and other bag leak detectors will be discussed in greater detail in the next chapter.

Choosing a PM System

For continuous particulate monitors, application dependence is paramount and good technical judgment must be made in the instrument selection if the correlation is to hold. Table 9‐7 lists some of the factors that will limit the performance of an instrument, either in monitoring particulate matter in the application initially or in maintaining a valid mass correlation later.

The importance of particle physical and chemical characteristics cannot be overemphasized when selecting a continuous particulate monitor (Farthing and Williamson 1996; Gnyp et al. 1979; Greening 1997). Problems in monitor application arise when the limitations of an instrument are not understood or when too much is expected from the correlation. The problem is often not in developing the correlation, but expecting it to remain valid when process operations change. Some monitors are less sensitive to particle size distribution changes than are other. Some are less sensitive to composition changes. Others are more sensitive to humidity effects. Even more so than for gas monitoring systems, there is no “best” system for continuous particulate monitoring.

TABLE 9‐6 Summary of 40 CFR 63 BLD Monitoring Requirements

Part 63 Subpart
Source Category
Affected Units
CFR Reference
Monitoring Requirements

L
Coke oven batteries
Coke oven shed
63.213
63.305(f)(4)
COMS option

X
Secondary lead smelting
Exhausts
63.548(c)(8)
BLD

AA
Phosphoric acid
Baghouse
63.605(f)
BLD

BB
Phosphate fertilizer production
Baghouse
6.625(e)
BLD

MM
Pulp mills
Baghouse or ESP
63.864(d)
63.864(d)(12)(i)
BLD
COM

DDD
Mineral wool production
Baghouse
63.1181(a)
BLD

EEE
Hazardous waste combustors
Stack emissions
63.1209(a)(1)(iii)
Opacity, BLD or PMCEMS

LLL
Portland cement
Stacks
63.1350(b)
63.1350(f)(4)
63.1350 m(xi)
PM CPMS
COMS option
BLD

MMM
Pesticide production

63.1366(b)(1)(xi)
BLD

NNN
Wool fiberglass
Glass furnace
63.1383(b)(1)
BLD

QQQ
Primary copper smelting
Baghouse
63.1452(b)
BLD

RRR
Secondary aluminum
Fabric filter
63.1510(f)(1)
63.1510(f)(2)
BLD
COM

TTT
Primary lead smelting
Baghouses
63.1547(c)(8)
63.1547(j)
BLD

UUU
Petroleum refineries: units
Catalytic cracking
63.1572(b)(1)
63.1572(a)(2)
Opacity
BLD

XXX
Ferroalloys production:
Baghouses
63.1652
BLD

FFFF
Miscellaneous organic
Chemical manufacturing
Process vents
63.2450(j)
63.2525(k)
BLD

CCCCC
Coke ovens
Baghouses
63.7330(a)
BLD

DDDDD
Industrial, commercial, and institutional boilers and process heaters

63.7525(a)
63.7525(b)
PMCEMS
or PM CPMS
COMS, BLD

EEEEE
Iron and steel foundries
Baghouse
63.7736(c)
BLD

FFFFF
Integrated iron and steel
Baghouse
ESP
63.7830(b)(1)
63.7830(b)(2)
63.7830(d)
BLD
or COMS
COMS

JJJJJ
Bricks & structural clay products manufacturing
Baghouse
63.8425
63.8450(e)(1)
BLD

KKKKK
Clay ceramics manufacturing
Baghouse
63.8600(e)
BLD

LLLLL
Asphalt
Vent gas
63.8868(f)
COMS

RRRRR
Taconite iron ore processing
Baghouse
Dry ESP
63.9631(a)
63.9631(d)(1)
BLD
COMS

SSSSS
Refractory products
Baghouse
63.9804(f)
BLD

TABLE 9‐7 Limitations of the Analytical Methods

Physical Principle
Performance Limitations

Accumulated mass sensors
Changing velocity
Particle stratification

Optical sensors

Light extinction
Low particulate concentrations

Small‐diameter stacks/ducts

Varying particle sizes

Varying particle composition

Light scattering
Varying particle composition

Particle stratification

Limited particle size range

Impaction
Sticky particulate matter

Particle charge

Particulate stratification

Varying particle sizes

Particle composition

Changing flue gas velocity

Note: The presence of water droplets and varying water vapor content can be a significant issue for all of the techniques. This problem may be resolved as has been discussed above.

PM CEMS QUALITY ASSURANCE – REQUIREMENTS FOR CONTINIUING OPERATION

Quality assurance procedures for particulate monitors used for continuous compliance are found in Appendix F of Part 60, as Procedure 2 (U.S. EPA 2020c). Procedure 2 addresses daily checks, quarterly audits, and audits of the PM correlation curve, conducted at longer intervals specified by applicable regulations or facility operating permit. Unfortunately, Procedure 2 is replete with acronyms, which are often more confusing than helpful when attempting to interpret the requirements. The following discussion outlines these requirements.

The Quality Assurance/Quality Control Manual

The first requirement of Procedure 2 is, of course, to develop and implement a quality control program for the particulate monitoring system. As we will discuss in Chapter 15, this requires not only writing a quality assurance/quality control manual but also to follow through and perform the procedures committed in the manual. At a minimum, written procedures are required for the following:

Zero and upscale drift checks

Methods for adjustment

Preventive maintenance, extractive system checks

Spare parts

Data recording, calculations, and reporting

Audit procedures

Corrective action procedures

This does not require writing a separate quality assurance manual just for the particulate monitoring system, and it is recommended not to do so. Many of the procedures listed above can be addressed within the sections that may have already been written for the facility CEM system. The major effort will be to write or reference preventive and corrective maintenance procedures and the audit procedures specific to particulate monitoring systems.

Routine Checks

As with any continuous monitoring system subject to U.S. federal requirements, a routine daily check of zero and span calibration check is required to assure that the monitor is operating properly. Although European monitoring systems approved through the type‐testing procedures of EN 15267 and calibration procedures of EN 14181 (CEN 2014), may be advertised as being “maintenance free,” requiring no calibration adjustment for periods of ninety days or more, such approvals are not relevant in the United States or Canada.

Daily Drift Check

A daily drift check at the zero and span levels is required. The procedure requires that daily checks using reference standards with values be documented by the instrument manufacturer. No traceability to standard reference materials is required, because the check is merely a check of the day‐to‐day variation of the instrumentation response to the reference materials. The materials may be a filter, a particulate standard, or other. The zero‐check value may be between 0 and 20% of the instrument range. The upscale drift check value may be between 50 and 100% of the instrument range.

The daily zero and span drifts are required to be ≤4% of the instrument range. If any daily drift check indicates a drift of greater than 4% of the instrument range, the instrument must be adjusted. The instrument is considered to be out‐of‐control if the zero drift or upscale drift check is greater than 4% for 5 consecutive days or exceeds 8% for any one day.

Extractive Systems Daily Volume Check

Extractive systems, such as beta gauge systems, that measure sample volume must perform a daily volume check. The check must be done at a normal operating sampling rate. The system must be adjusted if the volume check error exceeds 10%. The system is considered to be out‐of‐control if the check is greater than 10% for 5 consecutive days or exceeds 20% for any one day.

Light Scattering Systems Dirty Window Check

For light scattering systems (including transmissometers), the system optics must be checked on a daily basis to determine if window fouling or particulate agglomeration is affecting the performance. Such checks are usually conducted automatically, typically by monitoring the strength of the detector response.

Quarterly Audits

Two types of quarterly audits are required; one, the absolute correlation audit (ACA), which correlates the instrument response to audit standards, and the other, the sample volume audit (SVA), that applies to extractive particulate monitoring systems only.

Linearity Check – The Absolute Correlation Audit (ACA)

A linearity check using audit reference materials is required quarterly. The check is conducted using three audit standards recommended by the manufacturer, one 0–20% of the measurement range, one, 40–60%, and one 70–100% of the measurement range. The check is analogous to Part 60 cylinder gas audit or Part75 linearity check, except that reference materials traceable to NIST standards are not required in the absolute correlation audit.

In conducting the audit, the instrument is challenged with the three audit materials nonconsecutively. The instrument passes the audit if the average of the three challenges for each reference is less than or equal to 10% of the reference value or ±7.5% of the applicable standard. The “ACA” accuracy is calculated as a percent of the reference value as follows:

(9‐26)

where

ACA Accuracy = the ACA accuracy at each audit point in percent

RCEM = system response to the reference standard

RV = value of the reference standard

Quarterly Sample Volume Audit (SVA)

A quarterly sample volume audit is required for extractive systems where the sample volume is measured to calculate the monitoring system response. This is typically required of beta gauge monitoring systems where the particulate concentration is obtained by dividing the particulate mass of each filter spot by the sample volume necessary to collect it over the measurement cycle.

The sample volume audit is performed by conducting an independent volume measurement for at least three measurement cycles. If the instrument monitors continuously, data from three 20‐minute measurement periods are evaluated when performing the audit. The audit samples are acquired without including any dilution air and must be corrected, if necessary, to the same temperature, pressure, and moisture basis consistent with that of the monitoring system. The monitoring system passes the SVA audit if the average monitoring system volume is ≤ ± 5% of the average audit volume.

PM Correlation Audits

The correlation technique for “calibrating” a continuous particulate monitor might be considered similar to that used in predictive emission monitoring methods (PEMs). A predictive emission monitoring method gives real‐time emissions data from a model correlated with past source test data. A particulate monitor gives similar real‐time emissions data based upon past data. The robustness of a particulate correlation or a PEMS model depends upon how well the assumptions made in developing the correlation hold in the future operation of the emissions source. Periodic retesting is therefore essential to verify the viability of the correlation over time. Two audits specified for this purpose are given in Procedure 2:

Relative Response Audit (RRA)

Response Correlation Audit (RCA)

These audits are conducted at frequencies specified in the applicable implementing rule or facility operating permit, but not in Appendix F Procedure 2.

The Relative Response Audit

The Relative Response Audit (RRA) is performed under as‐found unit operating conditions and serves as a one‐point check of the correlation curve at that condition. A three‐run reference method (e.g. Method 5 or 5i) is conducted and the test method data compared with the output value of the particulate monitoring system. To pass the audit, the following criteria must be met:

For all three data points, the particulate monitor response value cannot be greater than the greatest response value used to develop the original curve.

At least two of the three data sets must fall within two lines parallel to the correlation regression line, offset at a distance of 25% of the numerical emissions limit value from the regression line (see Figure 9‐18).

Figure 9‐18 Passing criteria for the Relative Response Audit (RRA).

If these criteria are not met, the monitoring system is out‐of‐control. If the system is out‐of‐control, corrective action must be taken and the audit must be repeated to verify that the system is back in control. If the RRA cannot be met after corrective action is taken, a response correlation audit (see the next section) must then be conducted.

At the risk of confusing this jungle of acronyms even further, it might be noted that the RRA is similar to the three‐run Relative Accuracy Audit (RAA) allowed in Part 60 Appendix F Procedure 1 as an alternative to the cylinder gas audit (CGA) for gas monitors.

The Response Correlation Audit

The Response Correlation Audit (RCA) is basically a repeat of the original correlation testing performed to develop the correlation curve. This is, of course, the most onerous of Procedure 3 audits and is used to validate the correlation over its range, not just part of the range. It is again performed by conducting tests independent from the operation of the particulate monitoring system.

The Response Correlation Audit is conducted according to the same procedures as given in PS‐11 to develop the correlation. However, a minimum of 12 runs at three‐unit operating levels is allowed instead of the 15 runs as specified in PS‐11 to develop the correlation. To pass the audit, the following criteria must be met:

For all twelve data points, the particulate monitor response value cannot be greater than the greatest response value used to develop the original curve.

At least 75% of the data sets must fall within two lines parallel to the correlation regression line, offset at a distance of 25% of the numerical emissions limit value from the regression line (see Figure 9‐19).

If a response value is lower than the lowest response value on the correlation curve, the correlation curve (line) may be extended to that value. The data then can be examined from the extended correlation to determine if the second criteria above is met.

If these criteria are not met, the monitoring system is out‐of‐control. If the system is out‐of‐control, corrective action must be taken and the audit repeated to verify that the system is back in control.

In addition, the data set from the Response Correlation Audit is combined with the data set from the original PS‐11 correlation to develop a new correlation. If the expanded data set meets the PS‐11 statistical criteria, the new correlation can then be used.

Figure 9‐19 Passing criteria for the Response Correlation Audit (RCA).

If the new correlation is used and the RCA is still failed, the correlation is again revised, this time by using only the data set from the RCA. In this case, 12 data points are allowed instead of the 15 required in the original correlation. If the RCA data correlation meets the PS‐11 statistical criteria, the system is viewed as being back in control.

DEVELOPMENTS IN PM CEMS

Innovations in particulate monitoring are dynamic at present. Regulatory concerns related to the health effects of particles in outdoor air, indoor air, and workplace atmospheres have brought more attention to monitoring atmospheric particulate concentrations. The commercial availability of low‐cost particulate monitors capable of monitoring PM2.5 and PM₁₀ concentrations is a response to these concerns (Jahnke 2010). Consumer‐driven instrumentation, such as handheld particle counters are now available from several vendors as industrial hygiene monitors for measuring particle levels in the workplace or the indoor air of homes or offices. Here, the size of the market drives the development of versatile instruments that can be sold at competitive prices. This extends to the market for ambient air monitors, where there is sufficient demand to support a variety of instruments. There is, however, little advantage to miniaturizing either sensors or analyzers intended for continuous emission monitoring (unless it leads to improvements in sensitivity, response, or discrimination) (Jahnke and Evans 2006). There is usually sufficient room at industrial facilities to accommodate a walk‐in shelter on the ground, and sometimes even on the stack to accommodate close‐coupled, temperature‐controlled, extractive systems or in‐situ systems, that require a shelter.

Advances in Mie scattering–based instruments for ambient and indoor air/workplace monitoring can certainly be extended to source emissions monitoring. In‐situ imaging techniques and advanced scattering methodologies are of particular interest. A number of new products for particulate monitoring have recently emerged in the emissions monitoring arena and others are underway. The hybrid systems discussed in this chapter are encouraging in that respect.

REFERENCES

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Note

1 Note: Correlating a point value with an area average is an approach that is also used in establishing K factors for flow monitoring systems mandated in the U.S. EPA Acid Rain and NOx Budget programs under 40 CFR 75. In fact, determining a K factor for a continuous flow monitor is virtually the same as establishing a linear correlation for a PM monitor. The difference is that EPA has established no requirements similar to PS‐11 for flow monitors, and K factors are determined without specifications for a correlation coefficient, confidence interval, or tolerance interval.

CHAPTER 10
CEM SYSTEM CONTROL, DATA ACQUISITION, AND REPORTING

A data acquisition and handling system (DAHS)* is considered by regulatory agencies to be an integral part of a CEM system. When certifying a CEM system, monitor responses must be recorded from the DAHS (U.S. EPA 2020a,b), not from the analyzers. On a routine basis, CEM system technicians and environmental engineers work more with the DAHS than with any other CEM subsystem. Activities such as verifying daily calibration values, reviewing data, responding to excess emissions problems, and generating reports are all performed within the DAHS.

To complete a CEM system, there are three functions essential to its operation: (i) control of the automatic functions of system, (ii) acquiring analyzer and ancillary data generated by the CEM system, and (iii) handling the acquired data. A control subsystem is needed to perform such functions as initiating daily calibration cycles, performing periodic probe blowbacks, or providing for system fault alarms, whereas data acquisition and handling involves recording instrument outputs, processing data into required formats, generating reports, and archiving the data. This chapter reviews methods used to perform these functions.

CEM systems typically use a hardware interface to perform the control functions. This may be a programmable logic controller (PLC), a data logger, an embedded system, or another computer. Outputs from the controller are sent to the DAHS computer to record, display, and report the data. The DAHS computer may be a dedicated CEM system computer, the plant distributive control system (DCS), or other plant computer. Separating the functions of control and data handling between a controller and DAHS computer may characterize a typical data acquisition system; however, in some systems, analyzer data may be manipulated in the controller before being transmitted to the CEM system computer or, in others, the system computer may perform both control and data acquisition and handling functions. Of course, other peripherals, such as printers and a system for backup data storage, complete the system. Figure 10‐1 illustrates the general processes of data input, control, data handling, and communication encountered in CEM systems.

Increasing demand for CEM system data both inside and outside the plant has resulted in application of a variety of communications methods. Data can be transferred to the DCS for process control and optimization or transmitted through a local area network (LAN), wide area network (WAN), intranets, or internet for use by other departments and corporate offices. In some cases, data need to be sent to regulatory agency computers on a real‐time, batch, or call‐up basis.

The data handling process begins with data input, proceeds with initial data processing, data handling, continues with further data manipulation necessary for recording and reporting, and, finally, communicates the information. This chapter discusses each of these functions. Recommendations for the specification and selection of CEM data acquisition and handling systems can be found in the Institute of Clean Air Companies’ (ICAC) DAHS Guidelines (ICAC 2013).

Figure 10‐1 CEM systems control and data acquisition and handling: functions.

CONTROL SYSTEMS

The DAHS computer serves many functions, but even with multitasking systems, programming can become difficult with numerous data inputs and their processing demands. For this reason, operational control of the CEM system is commonly performed by a control subsystem that interfaces between the sampling and analytical hardware and the DAHS computer. Typical options used for system control employ control computers, programmable logic controllers, data loggers, and embedded microprocessors.

A control system provides for the automatic operation of the CEM system hardware. Functions such as daily zero and span checks, extractive system probe purging, monitor sequence control, and alarming for excess emissions and system malfunctions are usually performed automatically. The control system provides the signals and timing necessary to activate relays or valves for these operations. Control functions commonly performed by the interface are

daily calibration checks;

probe blowback;

fault annunciation;

analyzer sequencing (for time‐share systems); and

alarming (system faults).

The definition, timing, and sequencing of these events should be configurable by the user since they may need to be changed as experience is gained in operating and managing the system.

Controllers can also perform various data processing functions prior to the DAHS computer. Analog data can be converted to digital form. Calibration drift corrections, diluent corrections, and other calculations necessary to convert the data into units of the emissions standard can be performed. Data can also be averaged over specified periods. In addition, limited data storage (over several weeks or more) can be used to back up data if lost due to a DAHS computer or software failure.

It may appear that if all these functions are exercised by the controller, there remains little for the DAHS computer to do. This may be true for CEM systems with undemanding report formats, but with the extensive electronic reporting procedures often required by regulatory programs today, these initial data manipulations can free up the DAHS computer to focus on data editing, recording, and reporting functions.

Separating the control functions from the recording and reporting functions allows a relatively clean break to be made between the sampling/analytical system and the DAHS. Frequently, a vendor's analytical hardware may be preferred, but the data acquisition system that comes with it may not be suitable. Using a control system that provides for all automatic functions and output signals for the DAHS gives a choice among DAHS vendors. The DAHS system of choice can then be combined with the analytical system of choice. While such flexibility might appear ideal, problems can develop if the analytical system and DAHS vendors are not familiar with each other's communication protocols or if they do not collaborate well with each other when integrating the total CEM system – not an uncommon situation.

Computer Control

CEM system control can be accomplished simply in the DAHS computer. This might be cost‐effective in a CEM system design; however, as noted above, it complicates the system software. Multitasking becomes more difficult, and, in fact, in some early DOS‐based systems, data recording was stopped when the control functions were exercised or reports were generated. Also, when a computer or communications failure stops the system from recording data, data availability decreases accordingly.

A direct approach to avoiding the aforementioned problems is to use two computers: one for control and initial data processing and the other for data recording and reporting. This approach was more common in the late 1970s and early 1980s before PLCs and data loggers became more prevalent. Using two computers is not particularly elegant since the processing power of the control computer is largely wasted on simple control functions.

Programmable Logic Controllers

Programmable logic controllers (PLCs) have been applied widely in industry to handle logic, timing, counting, and data transfer in manufacturing operations. PLCs are microprocessor based and programmed by ladder‐logic methods usually specific to the manufacturer. To bring uniformity to control and instrumentation systems within a plant, PLCs began to be specified for CEM systems in the late 1980s. When PLCs manufactured by major providers such as Allen Bradley, Siemens, GE, ABB, Schneider Electric, or others are used exclusively in the plant, the same PLCs are usually specified for CEM systems to minimize retraining in their programming.

PLCs are modular and can be chosen to perform the necessary CEM system automatic functions, as well as signal processing and data storage. They can accept analog or digital signals and provide serial or parallel outputs. Their modularity is convenient, enabling the demands of a particular system – analog‐to‐digital (A/D) conversion, system diagnostics, sequence control, alarming, data backup, and so on – to be met by assembling the appropriate collection of PLCs.

Data Loggers

Data loggers perform much like a collection of PLCs. More than a PLC but less than a computer, the data logger serves as an interface between the CEM sampling and analytical systems and the DAHS. One advantage of data loggers is that they can simplify the communications between the CEM systems on multiple plant operating units and a single DAHS and/or the plant DCS. The application of data loggers to a two‐unit CEM system is illustrated in Figure 10‐2.

Before the advent of today's powerful PCs, data loggers were used to store and report digital data from ambient air monitoring and CEM systems alike. They served to obtain data in a form more usable than that from a strip chart recorder without incurring the cost of the then‐costly computer. By incorporating control function capabilities, as well as functions of A/D conversion, alarming, data backup, data manipulation and display, data loggers were seen as a convenient means to relieve the DAHS computer of relatively trivial functions. With the non‐multitasking DOS‐based systems, this relief was important and allowed the DAHS computer to better perform its primary job of recording and reporting emissions data.

Figure 10‐2 An example CEM system data acquisition and handling system for two operating units.

Accumulated experience in applying data loggers to interface between analyzers and computers has served well in CEM applications having extensive data recording and data manipulation requirements, such as the allowance trading programs. In fact, in the acid rain program, data logger–based DAHS systems were used to retrofit a significant number of Phase I Part 75 DAHS systems based originally on PLCs.

Embedded Microprocessors

Automatic functions can be performed simply with timers and relays. Although incorporated into some early systems, the relatively low cost and miniaturization of microprocessors allow actuation subsystems to become part of the sampling and analytical system itself. Several CEM system component vendors assemble “flow control panels” that route calibration, sample, and blowback gases automatically to perform calibration check and blowback functions typical of an extractive system. Some have gone further and provide a microprocessor embedded in the system, which performs the functions of a bank of PLCs or data logger.

This concept can be taken further by integrating a sampling and analytical system with a dedicated microcontroller. Such systems can be designed to incorporate individual gas sensors or optical benches on a modular basis, which take advantage of a common system amplifier and power supply. In addition, the embedded microprocessor can control gas distribution, pressure regulation, and system diagnostics as well as manipulate, display, and transmit emissions data. The redundancy that occurs with the traditional rack‐mounted analyzers is consequently eliminated in these integrated systems. System costs can correspondingly be reduced; however, vendors adopting this approach have found that the demand for CEM systems is not sufficient to provide the volume necessary for supporting a low‐cost product.

THE DAHS COMPUTER

Whichever choice is made for the controller/interface, data eventually is received by the DAHS computer. Connection is made typically through an RS232/422 interface or, in some cases, by modem via conventional I/Os or Modbus TCP/IP. In the computer, operating systems such as Linux or Windows are commonly used.

Over 20 years ago, a trend was noted in the use of the plant DCS or even the corporate data processing center (Acklin et al. 1995; Nueveo and Esmoris 1998). The use of DCS systems is encountered frequently when the original CEM system software fails to provide satisfactory emission reports or when it becomes difficult to access the recorded data for further communication. In some cases, the original CEM system PC is completely bypassed, data being transmitted from the interface to the DCS. In other cases, the data are transmitted from the PC. Using a DCS or a centralized control system offers greater processing power and communications capability than a typical DAHS PC. With appropriate commitment to maintaining the CEM functions in the DCS, greater flexibility in data handling and communications can be realized.

CEM System Software Development

In the late 1980s, CEM system operators were using menu‐driven, monochrome, text‐based screens on DOS‐based systems, whereas plant operators were using object‐oriented programs with color graphics in multitasking operating systems. Software issues became more serious in the early 1990s when many of the software packages developed for the U.S. acid rain program were constructed initially with faulty logic and failed to meet the requirements of Part 75, as well as the operational needs of users (Elliot 1994; Haberland 1995). Software problems were often chronic, the DAHS being a major contributor to CEM system downtime. Changes in part of the code could cause problems in other parts. Thus, relatively simple modifications had to be made by the original developer and could not be made by the user. As software has changed, the choice of software vendors has also changed among CEM system owners. In a survey of electric utility Part 75 DAHS users, for the systems installed in the 1990s, 70% of responders had replaced their software by 2005 (Fain 2010). Poor vendor support, system errors, obsolescence, and maintenance issues were primary causes for changing software vendors. Eventually, the software packages offered by commercial vendors became more standardized, yet providing more user configurable options. Increased competition and necessary upgrades have led to significant improvements in CEM software since that time. Also, the capability of vendors to rapidly service software remotely has improved confidence. A choice of vendor today is more often made on the basis of system support capabilities, service package costs, flexibility and compatibility with other plant information systems, and enhanced capabilities that other suppliers may not provide.

Commercial CEM system software vendors use a variety of programming languages and operating systems to meet the demands of the CEM DAHS. With more advanced programming languages available today, CEM system software has become more flexible. The methods of CEM system software development are discussed in further detail by Nelson (1993), Hovan (1993), Baranowski (1995), Caiazza and Rengert (1995), Kulpa and Cline (1995), Williams (1997), and Ruger (2012). The use of object‐oriented programs allows for ease in program modifications. Windows and other graphical user interfaces (GUIs) have come to be expected. In addition, the programs are more configurable, thereby reducing the necessity of custom programming. Rather than being constrained to vendor‐defined report formats and screen configurations, the user now has greater control over reconfiguring program outputs for specific plant and regulatory requirements. Flexibility can, however, become counterproductive; too many options can lead to confusion to both the CEM system operator and the plant operator. The problem is, as with most software, that the user may not understand the limits of the package until it is installed and tested. The true limits are often still not understood until the first quarterly emissions report is to be generated.

There are different approaches to develop CEM system software. Depending on the options chosen, the result may be a package that meets all regulatory requirements but is not flexible for plant operations, or has excellent displays and graphics, but may not be sufficiently configurable or open. How a program is written or the type of computer hardware that is used are not the important issues. As with CEM system analyzers, the question is whether the DAHS installed is the proper tool for the application. Besides monitoring emissions to meet regulatory requirements, today, additional demands for plant operation and control, corporate planning, and oversight are made by plant and corporate personnel.

Programming may be done either by plant programmers or information technology (IT) staff, or by a DAHS vendor. Each approach has its advantages and disadvantages. Plant programmers are often the best in designing software that meets the requirements of the plant and the company (Payne and Christianson 1994; Pickett 1995). Third‐party software vendors may sometimes focus only on the regulatory requirements, having too little experience in plant operations. On the other hand, using a plant programmer no longer allows for a “turn‐key” CEM system and loses the advantage of ongoing support of a dedicated DAHS vendor. In the face of system failures, the plant programmer's time and resources may not be adequate to resolve problems quickly. Also, as agency requirements change or system upgrades become necessary, the original plant programmer may no longer be available or may have lost interest. Here, the software vendor may have better capability in keeping up with rule changes and software developments out of necessity for serving a wide range of clients.

Whoever develops the software, the software should incorporate the following:

Minimum Software Recommendations

Program Logic. The program logic should be straightforward and easily understood without reference to manuals or requiring extensive training for plant personnel.

Configuration. The user should be able to reconfigure the system on‐site to change parameters such as emission limits, data correction constants, alarm set points, calibration tolerances, and range scales. Also, textual information and fault codes should be able to be redefined. Reports formats should be configurable.

Data Input. The system should acquire data from the emission monitors as it is generated, while allowing for operator input and report generation.

Database. The database should, at a minimum, incorporate the entire past quarter's data and the data generated in the current quarter. The database should be open: that is, the file structure should be in standard query language (SQL), ODBC, Oracle, or other, so that data can be imported easily into other software packages and integrated easily in local area and wide area networks.

Displays. Data should be able to be displayed and printed in selectable formats – numerically, in trend plots, bar charts, and so on.

Error Messages. Error messages should be recognized easily and preferably be displayed on any open screen.

Data Editing. The DAHS should be capable of editing suspect data. With such editors, original data should never be eliminated, but should be flagged as should also, any corrected or substituted data. Status and editing codes should be incorporated into the reporting system for conditions such as out‐of‐service instruments, abnormal calibrations, insufficient samples, data substitutions, and data invalidations. The user should be able also to enter additional codes after system installation.

Data Averages. New averages should be readily computed from edited data.

Text Entry. Text entry provisions should be made for conditions such as reason code entry/modification, plant malfunction, emergency conditions, and nonoperating conditions.

Provision should be made for the entry of manual test or alternate monitor data in case of CEM system malfunction.

Help Screens. Help screens should be available and actually useful. Software should be accessible by remote access for troubleshooting and information retrieval.

Reports. The user should be able to prepare reports for any selectable period. Printed reports should be able to be generated from the database, on demand. Provisions for inserting comments from the keyboard into the report should also be available.

Password Protection. Access should be password protected at successive need‐to‐know levels.

Advanced Software Functions – Missing Data Substitution

CEM systems used to report emissions on a mass rate basis (g/hr, tons/year) are required typically to substitute data into the CEM database when the CEM data is either unavailable due to a malfunction or invalid due to such issues as a failure in passing a quality assurance performance test or meeting a test deadline. The type of data substituted, or backfilled, can be either reference test data, quality assured data from a certified backup system, data from rudimentary predictive models, or from agency‐defined missing data algorithms.

In Canada, data missing for a period of up to 168 hours may be substituted with data derived from emissions versus load correlations, or from mass balance correlations (e.g. sulfur in fuel) that have been established previously (ENVC 2005). In the case where emissions control equipment is installed, data obtained from a predictive model may be backfilled. However, if a CEM system malfunction continues for more than 168 hours, data used for backfilling must be obtained by using another CEM system or by conducting reference method tests.

In the U.S. EPA Part 75 allowance trading programs, a complex incentive scheme has been instituted to backfill missing data using agency‐defined algorithms (40 CFR 75.30) where the substitute values are to be calculated and applied automatically by a Part 75 data acquisition and handling system (DAHS). The algorithms are based upon CEM system availability, which is computed by the DAHS on an hourly basis. For example, for SO₂, CO₂, and O₂ monitors, Part 75 CEM availability is calculated using the following expression:

(10‐1)

This is calculated as an 8760 hourly rolling average, computed each hour by the DAHS. Continuing the example, data to be substituted for SO₂, CO₂, and O₂ monitors are based upon the conditions summarized in Table 10‐1.

The conditional nature of these data substitution procedures summarized in Table 10‐1 is also illustrated in Figure 10‐3a. In the first case (Figure 10‐3a) where the calculated hourly monitor availability is greater than or equal to 95%, if the missing data period is less than or equal to 24 hours, the hourly average values recorded before and after the missing data period are averaged and substituted for the missing data. If, however, the period extends beyond 24 hours, the 90th percentile hourly SO₂ concentration recorded in the preceding 720 hours is substituted instead, or the average of the SO₂ emissions before and after, whichever is greater. In other words, if the monitoring system is not operating within 24 hours, an SO₂ value higher than true will be substituted, in effect penalizing the utility through a loss of allowances. These scenarios are illustrated in Figure 10‐3a.

TABLE 10‐1 U.S. EPA Part 75 Missing Data Scheme for SO₂ and CO₂ Monitors

Availability | Number of Hours Unavailable | Hourly Data to Be Substituted for Each Missing Data Hour
| ≤24 | Average of SO₂ concentrations recorded hour before and hour after the missing data period
≥95% | >24 | Greater of 90th percentile hourly SO₂ concentration recorded in preceding 720 hours or, average of hour before and hour after
| ≤8 | Average of SO₂ concentrations recorded hour before and hour after the missing data period
≥90% <95% | >8 | Greater of 95th percentile hourly SO₂ concentration recorded in preceding 720 hours or, average of hour before and hour after
≥80% <90% | >0 | Maximum value in preceding 720 hours
<80% | >0 | Maximum potential concentration

The punitive nature of the scheme becomes greater as the availability decreases, the intent of which is to institute an incentive to maintain high system availability. In the second case (Figure 10‐3b), if the data availability is between 90 and 95%, only 8 hours are given to repair the monitor, before artificially high data are backfilled. Here, if the system is not back on line after 8 hours, the 95th percentile hourly data are substituted instead of the 90th percentile data. In the third case (Figure 10‐3c), if the availability is a greater than or equal to 80% and less than 90%, the maximum hourly SO₂ value recorded in the past 720 hours is substituted for each hour of missing data. And lastly, in case d (Figure 10‐3d), if the availability is less than 80%, the maximum potential SO₂ concentration, calculated from the maximum sulfur concentration and minimum gross calorific value, is substituted (40 CFR 75 Appendix A §2.1.1.1).

Figure 10‐3a Part 75 missing data routines. Availability ≥95%.

Figure 10‐3b Part 75 missing data routines. Availability ≥90% <95%.

Figure 10‐3c Part 75 missing data routines. Availability ≥80% <90%.

Figure 10‐3d Part 75 missing data routines. Availability < 80%.

These procedures are similar for NOx and flow monitors. Instead of substituting hourly averages before and after the missing data period, NOx or flow values at the corresponding unit load range (or “load bin”) are substituted (unless the before and after values are greater than the percentile values, in which case they are backfilled). Using NOx concentration and flow rate averages at similar load levels in 10 load bins by dividing the load range into ten equal parts (U.S. EPA 2020e). The values in the bins are obtained from historical NOx and flow vs load data running over the past 90 days, from look‐up tables in the DAHS. Also, for NOx and flow monitors, the availability is based on a 2160 hourly rolling average instead of the 8760 hourly rolling average for SO₂ analyzers.

These procedures are complex and become more detailed when multiple fuels are used or when non‐load‐based units affected by the rule. For units with add‐on SO₂ or NOx emission controls, other conditions apply depending upon whether or not the controls are operating over the time of the missing data period. To be implemented properly in the DAHS, they require both an understanding of the rules and the ability to accurately incorporate them in the recording software. It should be noted, however, that sources subject to the Part 75 missing data requirements routinely achieve availabilities greater than 98% (Schreifels 2016) and highly punitive emission values rarely need to be substituted.

Advanced Functions – Preventive Maintenance

Analyzer diagnostic information as well as system status indicators can be used to track maintenance needs. By linking diagnostic information from smart analyzers into the DAHS, additional alarms, rates of change, and so on can alert the CEM operator when maintenance may be required. A less sophisticated approach is to program into the DAHS, preventive maintenance schedules, cylinder gas usage rates, and routine functions, which alert the CEM operator on a maintenance screen. A system diagram can also be used to alert the operator when maintenance is required (White 1993).

Advanced Functions – The Electronic Logbook

As CEM system software has matured, additional features are sometimes offered in commercial products. The electronic maintenance logbook is one tool, which in addition to maintenance scheduling, that can be useful for the CEM system operator. Because logbooks are intended for permanent records of work performed on the CEM system, care should be taken to assure that entries and comments cannot be erased or overwritten.

Advanced Functions – Predictive Emissions Monitoring

Various calculation methods can be used to validate CEM system data. By correlating CEM data with mass balance or engineering calculations, or correlating CEM data with process parameter data to build a predictive model, reality checks can be incorporated in the DAHS program to flag data that are not consistent with the operating conditions of either the CEM system or the unit. Once programmed, such checks can be relatively automatic – if one inputs the fuel feed rate and the fuel sulfur content, the SO₂ emission rate can be readily determined; an initial correlation between NOx emissions and load can serve to estimate future NOx emissions as a function of load.

By inputting value of process and operational parameters into the DAHS, the CEM system DAHS can be used to model emissions by developing a “predictive emissions monitoring system” (PEMS). This application may appear redundant if one is already measuring the emissions with an analytical, independent CEM system. However, modeled data can be used to provide for missing data occurring during CEM system calibration checks, blowback cycles or when CEM systems are malfunctioning. Alternatively, CEM system data can be used to update and strengthen the model. This interplay of quality control in a CEMS–PEMS combination is illustrated in Figure 10‐4.

The CEMS–PEMS combination can thus provide a valuable quality assurance check for either system (DeFriez et al. 1996). Three types of modeling techniques have been used in the development of PEMS:

Figure 10‐4 The CEMS – PEMS combination.

Phenomenological Models

When developing a PEMS model, plant process or operational parameters such as pressure, temperature, fuel flow, steam flow, water pressure are typically correlated against the CEM data. Theoretical, first principal equations, that underlie the operation of the unit, might form the basis for a model, particularly for gas turbines whose operation is fairly well understood, but are not common for most industrial processes due to the complexity of the processes. Even so, empirical correction factors are commonly used to “tweak” phenomenological models for the effects of factors that are not well understood.

Least Squares Regression Models

A more common modeling technique is least squares regression, a statistical technique used to calculate a line or curve that best correlates the parameter data with CEM data. Here, a series of tests are performed, where unit operating parameters are varied to change emissions, while the emissions are monitored by the CEM system. An equation is then developed that weighs the influence of each parameter on the resultant emissions value.

Neural Network Models

Neural network models have also been applied to model source emissions. In the neural net method, the model constants are not calculated (as in the least squares regression technique) but are determined by iteration. The constants in the model are varied incrementally until a set of constants are obtained that will reproduce the actual emission (as measured by the CEM system). The model constants again weight the importance or unimportance of the different input parameters in contributing to a given result. This weighting process is performed similarly to the neural processes in the brain, hence the term “neural net.”

No matter what type of model is developed, once either a simple correlation or a detailed PEMS is available, it can be combined with the installed CEM system to provide a powerful quality assurance tool as shown in Figure 10‐4. If the process operating conditions change from those at the time the model was developed, the original correlation to the CEM system data may no longer be valid. However, with a CEMS–PEMS combination, the CEM system continues to obtain data during and after this change – data that can then be used to retrain the model. Because the CEM system can provide data independent of the operating conditions, the model can be continually retrained until it too can provide valid data over a range of conditions.

Conversely, if the CEM system fails, or if its operation becomes inconsistent and the data questionable, the PEM system can provide a quality assurance check and possibly provide substitute data during periods of CEM system downtime. If the PEMS passed the certification criteria of 40 CFR 60 Appendix B Performance Specification 16 (U.S. EPA 2020c) or met the statistical evaluation criteria of Part 75 Appendix E (U.S. EPA 2020d), the PEMS data could be used to provide “certified” backup data.

Data Handling Functions of the DAHS Computer

The DAHS computer may sometimes interface with the CEM system analyzers to provide control of the CEM system. This aspect of the DAHS was discussed in detail above. As noted earlier, there are a number of choices; the most popular one is incorporating an interface such as a PLC or data logger between the analyzer inputs and DAHS computer. An advantage of using PLCs and similar control systems is that with their use, the options become more flexible for the DAHS computer. If a plant DCS or a PC system with a commercial software package is used, it can then simply accept inputs without having to be programmed for the control functions of the system.

The essential functions of the DAHS are to display, record, and report data. When data are acquired continuously from a bank of analyzers and process sensors, it is not practical to record or report all of the data received by the system. As a result:

All data acquired are not recorded

All data recorded are not reported

When computer memory is limited, recording real‐time real‐time second‐by‐second data can eventually swamp a computer's memory. To limit this problem, data are first averaged over convenient periods (typically 1–15 minutes) in the analyzer, interface, or DAHS computer. Data may then be combined to be presented in required units (for example, a pollutant gas value in ppm may be corrected to account for dilution air, using a diluent gas measurement (O₂ or CO₂) – see Appendix A). The data may be averaged again, for example, over the 15‐minute response time required by U.S. EPA for gas analyzer, or the 6‐minute recording period for opacity monitors. The data are then displayed on the screen, but although a screen may display 15‐minute averages, only hourly averages may be recorded and reported. Depending upon the rule, emissions data that exceed the regulatory limit (excess emissions) may be the only data reported. Along the way, information can be lost; information that may be useful for process optimization may not be available from software written purely to satisfy regulatory requirements. However, with today's numerous options for data storage, all the data and records generated by the CEM system could be stored for years. Whether that is necessary or even desirable is another question.

Data collected by a PLC or data logger will be polled by the DAHS computer at specified intervals. The data transmitted to the computer may have been already manipulated or sent in its raw form. Typically, the interface will convert the data into units of the standard in real time and average it prior to transmission.

Data Correction

Some systems automatically “correct” analyzer data after each zero and calibration cycle. This is used in systems that have inherent drift that is not possible to remove. In this technique, if an analyzer drifts, for example, by −5 ppm between calibration checks, the DAHS will automatically add 5 ppm to all subsequent readings until the next calibration check. However, there are different ways for the DAHS to express such a correction. The drift (in ppm or percentage of span) can be displayed and recorded either (i) from the previous day's calibration response or (ii) from the calibration response of the system at the time the system was actually calibrated (adjusted).

There is nothing technically incorrect with either method if it is understood how the correction is done. However, such computer corrections can mask the true state of the analytical system. For example, the first method can lead to unacceptable drift in the system (Figure 10‐5).

In the example of Figure 10‐5, daily corrections are applied to the previous day’s correction. If only the daily computer adjustment is displayed, it can give a false impression of the system status. However, if the percent drift is displayed from the original baseline calibration adjustment on day zero, a cumulative correction will be shown. Here, with a daily drift of −5% of span every day, after four days, the system drift is actually −20% from the original calibration baseline. However, the control chart of Figure 10‐5 illustrates deterioration in system performance. The problem can be solved simply by displaying the cumulative drift or a cumulative correction factor.

Figure 10‐5 Automatic computer drift corrections.

Data Conversion – Units of the Standard

Emission regulations require that analyzer data be converted into specified units, such as part per million (ppm), milligrams per cubic meter (mg/m³), kilograms per hour (kg/hr), nanograms per Joule (ng/J), pounds per million BTU (lbs/mmBtu), and so forth. These units or “units of the standard” or “emission limit values” (ELVs as termed in Europe) depend upon the type of source regulated and the regulatory policies of the environmental control agencies. Mass rate standards (kg/hr) are common for national emissions trading and greenhouse gas programs. Process rate standards (kg emissions/unit of product) and thermal rate standards (ng/J or lbs/mmBtu) are often specified in the New Source Performance Standards, operating permits, and other regulatory programs. Table 10‐2 provides examples of input parameters necessary to calculate emissions in units of typical emission standards.

Appendix A lists the most common types of units specified and the parameters used in their calculation. It should be clear from the table that more data is required than just that from the pollutant gas analyzer to report emissions in units specified by the regulatory agency. Data conversions into the appropriate units require different measured parameters and different analyzers, depending upon the form of the corresponding equation. Agency reporting requirements, therefore, considerably affect the design of the both the CEM analytical system and the DAHS software. Data from a flow monitor, diluent monitors, or the process unit itself must be input into the DAHS to perform proper calculations. Formulas programmed to perform these calculations may not always be correct due to lack of familiarity with the underlying environmental regulation. They must be checked and cross‐checked.

Data Averaging

A monitoring system may output emissions data every few seconds or minutes. Some agencies now require the recording of one‐minute data. This was previously not feasible, due to limited computer data storage capacities, but has become possible today due to greatly enhanced computer memory and data storage techniques. However, recording one‐minute data is generally not necessary when hourly emission averages need to be reported. Hourly averages may be further averaged into a “regulatory average,” which may be the average of three or more hourly averages. There are different ways in which a regulatory average can be calculated, but first a distinction must be made between the polling average and the regulatory average.

Polling Averages

A PLC or data logger may acquire data from analyzers that have been already averaged. An analyzer may produce a noisy signal due to limitations of the analytical method (particularly at low concentrations) or limitations of the detector. A common remedy is to average the instrument output for several minutes. If the noise is random, it should average out, providing a more stable signal. Similarly, an extractive system may have a relatively slow response time, due to long sampling lines or sample sorption effects. When the analyzer is polled by the DAHS, the averaged value is obtained. In other designs, an instantaneous value may be polled, which then may be averaged in the DAHS and used in subsequent data processing.

A minimum number of data points are specified in some regulations. For gas monitors in the United States and Canada, one cycle of operation (sampling, analyzing, and data recording) must be performed and recorded for each successive 15‐minute period [40 CFR 60.13(e)(2)]. At least one data point in each of the 15‐minute quadrants is required to calculate an hourly average. However, all valid data points should be used to calculate the hourly average [40 CFR60.13(h)(v)]. For gas monitors, the hourly averaged emission value is the working parameter used in environmental regulation for defining emission limits, performance criteria, and reporting limit exceedances. For opacity monitors, a six‐minute average (made up of 36 equally spaced measurements) is the working parameter on which emission limits and exceedances are based.

Most monitoring systems average all valid continuous data obtained over the cycle of operation (as is required) rather than selecting just an interval within the period. However, the 15‐minute recording period for gas analyzers does allow for the installation of “time‐sharing” systems, where, for example, three stacks could be monitored for 5 minutes each over a 15‐minute period. The four 5‐minute averages are then polled to determine the hourly averages. But again, as discussed in Chapter 3, this practice is not recommended.

TABLE 10‐2 Converting Emissions Data into Units of the Standard

Type of Standard | Units of the Standard | Calculation
Concentration | ppm, mg/Nm³ | c corr = gas concentration × diluent correction (using O₂ or CO₂ data)
Pollutant mass rate | lbs/hr, kg/hr, tons(tonnes)/year | pmr = gas concentration × volumetric flow rate
Process weight rate | kg/ton, lb/ton of product | pwr = pmr/ton product produced per hour
Emission rate (thermal) | lbs/mmBtu (ng/J) | E = pmr/heat input rate or F factor calculation using O₂ or CO₂ data

Figure 10‐6 A three‐hour rolling average and how it differs from a three‐hour block average. (a) Three‐hour block averages. (b) Three‐hour rolling averages.

An exception to the four data point averaging requirement is allowed when required maintenance or quality‐assurance activities are performed. In this case, a minimum of two valid data points separated by at least 15 minutes is required to calculate the hourly average [40CFR60.13((h)(iii)(A)]. This exception might be invoked for a system that needs more than 15 minutes to complete a required daily calibration verification, or when conducting a required quarterly cylinder gas test. This exception is not intended for periods of corrective maintenance, but is sometimes improperly used in order to report higher system availabilities.

Although the four data points are all that are required for NSPS recording and reporting, it is more convenient when the CEM system can output data at shorter intervals. When conducting the relative accuracy test for CEM system certification, a reference test may be run for only 21 or 30 minutes. In this case, DAHS providing an output in 15‐minute intervals might have difficulty in correlating with the test method period.

Regulatory Averages

The one‐hour averages for emissions data are often further averaged over periods defined in applicable regulations. Two types of regulatory averages are common: the block average and the rolling average.

A block average is an average of sequential data points or an integrated average obtained over a specified time period. For example, opacity monitoring data are generally recorded and reported as six‐minute block averages, which, in every hour, offers 10 opportunities to be out of compliance with an opacity standard. For gas monitors, sequential hourly averages can be averaged in turn to produce the recorded (and reported) emissions value. Figure 10‐6a illustrates a three‐hour block average, where three hours of sequential emissions data are averaged to give the reportable value. The next reportable value is the average of the next three hourly averages and so on. In this case, in any 24‐hour period, there are eight opportunities to be out of compliance with an emissions standard.

Hourly emissions data can also be averaged by using a “rolling average.” The rolling average is an arithmetic average over a specified number of contiguous periods. For example, in a three‐hour rolling average, three contiguous one‐hour averages are averaged as shown in Figure 10‐6b. Note from the figure that at the completion of four hours, the one‐hour value of the previous three‐hour average is dropped, and the value for the fourth hour is averaged with the two remaining hourly averages. Similarly, the average “rolls” along from hour to hour. This differs from a block average, given that in a 24‐hour period, there will actually be 24 contiguous 3‐hour periods, or 24 opportunities to be out of compliance with an emissions standard, as opposed to only eight using a 3‐hour block average. The 3‐hour rolling average is used in the U.S. Federal reporting requirements for NSPS Subpart D fossil‐fuel‐fired steam‐generating facilities.

As another example, a 30‐day rolling average is specified in the reporting requirements for U.S. NSPS Subpart Da (electric utility steam‐generating units). This is an average of 30 contiguous 24‐hour block averages, as shown in Figure 10‐7.

This average is similar to the 3‐hour rolling average, except that 30 days of daily data are averaged. In a 30‐day period, 30 averages (not 1 average) would be obtained, after the initial 30 days lapse. To allow for CEM system maintenance or repair, the rolling average may not actually be the average of 30 days of data, and the daily data may not be composed of an average of 24 hours of data. The specification allows a minimum of 18 hours of hourly data (block averaged) to be included in each 24‐hour block average. This works out to a CEM system availability of 75% in the 24 hr period. The rule also allows a minimum of 22 daily averages to be used in calculating a 30‐day rolling average, again an availability of about 75%. Under these conditions, if only 18 hours of data were available for only 22 days out of a month, the CEM system availability would be 55%. That is, the CEM system was available to give data only 55% of the time. Since CEM system availability for criteria pollutant gas monitoring systems is today typically better than 95%, the specification is particularly generous, but has little significance except for those who fail to maintain their systems.

Figure 10‐7 A 30‐day rolling average.

Rolling averages are useful for the regulated source because the averaging period allows for the correction of control system problems. For example, if the removal efficiency of an SO₂ scrubber is found to be degrading, and the 24‐hour average tend to exceed the compliance value, steps could be taken to improve the scrubber performance and balance the previous high‐data averages with subsequent lower averages to remain in compliance with emission regulations. The net effect of the rolling average is to smooth out highs and lows in emissions data.

Generally, the longer the rolling average period, the easier it is for a facility to meet the emissions standard. For a short averaging period, the facility may have to “overcontrol” to ensure that emissions standards are met. For a longer averaging period, flexibility is provided to make up for excess emissions by overcontrolling at a later time, instead of all of the time. This has been illustrated by McRanie (1990), as shown in Table 10‐3. Although the emissions standard here is 1.2 lb/10⁶ Btu, the actual long‐term means are well below this value, and the mean is lower for shorter averaging periods.

Rolling average periods of 7, 30, and even 365 days are found in EPA regulations. Long‐term averages such as the 30‐day or 365‐day rolling average raise another concern of a “valid” hour or a “valid” day. In Subpart Da, a valid daily average is composed of a minimum of 22 valid hours. But what if a day has only 21 valid hours? Are those hours of data to be thrown away, even though they may accurately represent the emissions over the period in which they were obtained? One way to resolve this is to calculate a weighted average over the averaging period. For example, if only 20 hours of valid data are available, a prorated 24‐hour average value could be calculated using Equation 10‐1.

TABLE 10‐3 Effect of Averaging Period and Source Variability on Reported Emissions: Averaging Time Versus Long‐Term Means to Comply with a 1.2‐lb SO₂/10⁶ Btu Emission Limit

Source: McRanie (1990).

Rolling‐Average Period | Long‐Term Mean (lb SO₂/10⁶ Btu)
90 days | 1.04
30 days | 0.95
24 hours | 0.76
3 hours | 0.63

(10‐2)p p m Subscript p r o r a t e d Baseline equals 24 sigma-summation Underscript i Overscript n Endscripts left-bracket StartFraction p p m Subscript h r i Baseline Over n EndFraction right-bracket

where

ppmprorated = daily average with invalid hours, prorated over valid hours

n = the number of valid hours

ppmhri = ppm for valid hour i

If such a procedure is not specified in the rule or applicable guidance, the method should be documented in the CEM quality assurance manual. The method can also be submitted to the regulatory agency for approval, the QA manual documentation serving to indicate good faith until a decision is forthcoming.

With CEM system availabilities better than 95%, and often better than 98%, the question of what constitutes a valid hour or valid day becomes an academic one for quality assurance manuals. With today’s mature CEM systems, availabilities of less than 95% would alternatively raise questions over the choice of the CEM system or the adequacy of the facility’s CEM system quality assurance program.

DAHS Computer Screen Displays

Many types of screen displays are available in commercial CEM computer programs, which are dependent on the complexity of regulations, reporting requirements, and user custom specifications. CEM screen displays are the distinguishing feature of most CEM software. Because the operators tend to spend more time at the computer terminal reading and evaluating data rather than with the CEM system hardware, it is essential that the DAHS screen displays be readable, intuitive, and practical. However, programmers often pay too little attention to screen design and presentation formats that can aid in the review and evaluation of data.

Screen formats are often not designed in the perspective of an instrument or unit operator, resulting in the software being more difficult to use. Although some formats are more intuitive and easier to view, a programmer may tend to put too much information on a screen in tabular, digital form. Data presented in trend plots can provide a more readable alternative, often enabling interpretation at a glance that can aid in the review and evaluation of data.

The following features should be considered:

Graphics should be used as much as possible. A graphic of the stack, gas cylinders, or a plumbing diagram of the CEM system in conjunction with operational data can provide visual interest and improve readability.

Color should be used to block sets of data, highlight suspect data or tagged data, or highlight alarms to, again, provide visual interest in the screen. Colors should be coordinated and visually pleasing, taking full advantage of the color palettes of graphic programs. However, this can be done to excess when the instrument technician starts making judgments based on “color” and not the actual data.

Type fonts should be of readable size and consistent throughout the software. Twenty different fonts in multiple colors are not necessary and can be confusing and visually unpleasing.

There are usually no regulatory requirements for screen displays; however, several different types of displays have come to be expected, such as those listed in Table 10‐4. Other screens may be necessary, depending on the requirements of state and/or federal regulatory programs. Displays may be available on either a dedicated CEM terminal, from the DCS, or a plant information system; it doesn’t matter where, as long as they can be readily accessed. The software should allow any screen image to be printed.

TABLE 10‐4 Recommended Basic DAHS Screens

Screen

Operator default

Menu

Instantaneous emissions data

Hourly averaged emissions data

Emission averages in units of the standard (s)

Alarm summary (exceedance and malfunction)

Daily summary report

Daily calibration drift report

Calibration drift quality control chart

Hourly flow‐to‐load ratio (for combustion units with flow monitors)

Trend plots (for any measured parameter over any time period, with zoom and cursor for digital values)

Daily summary

Report(s) for Part 60 EERs or Part 75 EDRs or other

Configuration/setup

Database

Utilities (digital, analog contact summary, database editor)

Data Recording

In most cases, a file must be maintained of the continuous monitoring data, including records of adjustments, repairs, calibration checks, and audits. Depending upon the regulation, the file must be retained typically for two to three years and is required to be maintained in such a condition that it can be easily audited by an agency inspector.

DATA REPORTING

Reporting requirements directly impact on the design of the CEM data acquisition system. In most cases, where emissions data are used for control operations and regulatory reporting, a computerized system is necessary. Agency reporting requirements and formats vary, depending upon the source category and agency policies. Facilities will often increase the sophistication of the DAHS and reporting system when it becomes apparent that too much time is spent by senior personnel in manually reducing emission report data.

Formats and other requirements for reporting CEM data are dependent upon the regulatory body. Data demands vary from relatively simple requirements of the U.S. excess emission report (EER) of the Part 60 NSPS to detailed requirements of the Part 75 electronic data report (EDR). Standard formats and programming requirements for CEM reports are becoming increasingly common where CEM systems are required. It is beyond the scope of this discussion to describe them in detail, except to address features of the two most common U.S. reporting rules and to highlight features of others.

The U.S. EPA Excess Emission Report

The most common reporting format in the United States is the Excess Emissions and Monitoring Systems Performance Report (EER) and the ancillary excess emissions summary report (U.S. EPA 2020a). Depending on the NSPS source category, an EER report or summary report must be submitted to the agency semiannually or quarterly. If the total duration of excess emissions over the report period is less than 1% of the total unit operating time during the period, and the CEM system availability is greater than or equal to 95% (e.g. downtime is less than 5%) over the unit operating time, only a summary report is required to be submitted. Table 10‐5 lists the information required in the summary report.

As stated above, if the emissions exceed the standard more than 1% of the time or the availability decreases below 95%, then both the summary report and the EER must be submitted. The EER differs from the summary report by including the dates and times of excess emission occurrences or monitoring system downtime. Also, reasons and actions taken must be included in the report as follows:

Magnitude, date, and beginning time and ending time of excess emission period

Process (unit) operating time during the report period

Identification of excess emission periods occurring during start‐up, shutdown, and unit malfunction. Nature and cause of the malfunction and corrective action or preventive measures taken

Date and time for each period of CEM system downtime (except for zero and span checks)

Description of the nature of system repairs or adjustments

Submitting an EER can take an appreciable amount of time of the plant engineer, particularly if the CEM system software is not programmed to recognize periods of downtime or excess emissions for the generation of the report. If not adequately recorded, obtaining reasons for CEM system downtime from CEM technicians can sometimes be frustrating.

The exceedance and downtime criteria for submitting only the excess emission summary is often misunderstood. The criteria do not say that excess emissions of 0–1% of unit operating time are allowable, nor do they say that 95% CEM system availability is required. The criteria are only intended as a cut‐point for reporting. Agency enforcement policies on exceedances and availability are often held at the discretion of the agency unless otherwise specified by legislation or in the operating permit.

The U.S. EPA Part 75 Electronic Data Report

The first program in the United States to require electronic data reporting was instituted in 1993 in the U.S. EPA Part 75 acid rain program. In this program, the Fortran‐based Electronic Data Report (EDR) format was established. Emission units affected by this regulation were required to submit data in the EPA‐specified EDR format, where all CEM and related data were incorporated in data files divided into six categories or “record” types, with over 60 record types being defined. It has been estimated that over 150 000 fields of data (including all hourly emissions data, plant operational parameter data, quality assurance data, availabilities, and other information) were required to be reported by a typical unit affected by the program (Mitnik 1993). Data transfer was initially performed by sending a floppy disk or tape to EPA, but this soon changed to direct electronic transmission.

TABLE 10‐5 Required Contents of the EER Summary Report

Source: U.S. EPA (2020a).

Emission Data Summary
CEM System Performance Summary

Duration of excess emissions in reporting period, due to:

Start‐up/shutdown___hrs

Control equipment problems_____

Process problems_____

Other known causes_____

Unknown causes_____

Duration of CEM system in reporting period, due to:

Monitor equipment malfunction___hrs

Non‐monitor equipment malfunction_____

Quality assurance calibration_____

Other known causes_____

Unknown causes_____

Total duration of excess emissions:

Total CEM system downtime:

Total duration of excess emissions/source operating time × 100

Total CEM system downtime/total source operating time × 100

By 2009, rapid changes in computer applications and internet capabilities led to the replacement of the EDR procedure with a format based on extensible markup language (XML) (U.S. EPA 2021a, b). The XML format was found to interact better with both the CEM data acquisition systems and the internet formats. Procedures for reporting are given in Part 75 Emissions Collection and Monitoring Plan System (ECMPS) and the electronic data reports are transmitted to EPA by direct computer‐to‐computer transfer using an EPA‐provided software tool, the “ECMPS client tool.” This software can be downloaded from the EPA Clean Air Markets Website (U.S. EPA 2021a, b). Data required to be reported include the following:

Facility information

Hourly and cumulative emissions data

Hourly unit operating information (e.g. load, heat input rate, operating time)

Monitoring plan information

Result of performance tests

Daily calibration error tests

Quarterly linearity checks

Semiannual/annual RATAs

Certification statements from the designated representative (or alternate) attesting to the completeness and accuracy of the data

The ECMPS client tool also checks the resultant quarterly report for reporting inconsistencies and calculation errors and provides immediate feedback to avoid errors in the submittal. Errors can be identified as “critical” or “noncritical,” where a noncritical error is procedurally minor, whereas a critical error makes the data unacceptable for transfer to EPA’s database. If the report is not corrected before submission, it will not be accepted until it is corrected.

Other U.S. Reporting Programs

For most sources, reporting emissions monitoring data is not just a matter of dealing with Part 60 or Part 75 reporting requirements. Industry‐specific requirements in Part 63 (Air toxics/MACT rules), Part 98 greenhouse gas mandatory reporting rule, and location‐specific programs, such as the cross‐state air pollution rule (CSAPR), Title V permit requirements, and so on, have their own reporting demands. The problem is one of developing an integrated emissions management program that can simplify the multiple reporting tasks of the environmental manager (Ruger 2012).

Reporting Guidelines in Canada

Environment Canada monitoring guidelines (ENVC 2005) specify that CEM data be expressed as 720‐hour rolling averages, submitted both in digital and analog form. The analog form is to be plotted as a trend in units of the standard versus time over the reporting period. The trend plot shows directly the compliance status and performance of the facility to both corporate management and agency inspectors. The guidelines also specify that daily zero and calibration drifts be recorded, computed, and reported quarterly in the form of a quality control chart.

The Province of Alberta requires that CEM data be submitted electronically in codes and file formats specified by Alberta Environment and Parks (AEP) (AEP 2016, 2019). Procedures for creating, uploading, verifying, and submitting monthly CEM data are found in the AEP electronic reporting user’s guide (AEP 2019).

Reporting Requirements in the European Union

A standard for handling and reporting data has been published by the Comité Europeén de Normilisation (CEN) as EN 17255‐1 (CEN 2019). The EN standard is planned in three parts (Baum 2016,; Robinson 2017) to include DAHS performance testing requirements as well as data calculation, handling and reporting procedures.

Communication

Communicating CEM system data from the plant to corporate offices is becoming increasingly important. The importance of SO₂ allowance usage has resulted in several utilities incorporating accessing this data as a factor in electric utility dispatching. Similarly, the increased use of CEM system data for process optimization requires a connectivity that often was not considered in the past.

The function of the DAHS computer is not limited to generating reports demanded by regulations. As commented in the introduction to this book, originally, one of the primary purposes for requiring the installation of CEM systems is to provide a way of determining whether pollution control equipment is working. In this sense, if CEM data provide feedback for the unit operators to control the operation of the unit so as to keep within emission limits, the CEM system meets its primary purpose. Figure 10‐8 expands on this consideration, where the DAHS computer provides feedback for process control optimization and CEM system control, but also keeps everyone informed: the plant engineer, the regulator, and, today, corporate offices.

Figure 10‐8 Functions of the DAHS computer.

With the multiplicity of processes and computer systems operating in a plant, “islands of information” frequently result. The system does its job, but does not make the information available for other uses. This was sometimes purposeful in CEM installations, when concerns predominated that CEM system data could be used as compliance data for enforcement purposes. However, the need for connectivity was seen in the 1990s (Nelson 1993) and systems are incorporating capabilities to transmit text and graphics to nodes on local area and wide area networks. Using TCP/IP protocol, the Web is also being used in company “intranets” to make data more accessible without necessarily upgrading system hardware. Corporate departments, such as engineering, plant dispatch, fuel purchasing, and environmental compliance, can utilize CEM system data for a range of plant and corporate management programs.

A system may be required to transmit emissions data directly to the regulatory agency, to view the CEM data when desired, require real‐time transmittal, or the periodic submission of a batch report. However, this is not common due to concerns over access and plant security. Care should be exercised by agencies in requiring real‐time CEM system data since real‐time data may not be quality assured. Also, knowledge of immediate data can make an agency party to plant emission problems. For example, if an agency had access to real‐time CEM data, and a plant upset or catastrophic release occurred without the agency taking subsequent action, the public could respond negatively to the agency’s inaction. In those cases where access is required, some sources have insulated the main CEM system DAHS from agency queries by installing a separate computer for such access. This enables plant and process data to be kept separate from the emissions data and prevent possible interference of the queries with the operation of the DAHS.

DAHS QUALITY ASSURANCE

The software used in the DAHS should be evaluated prior to the use of the CEM system. Even in the most straightforward CEM applications, the DAHS must still be custom programmed for plant‐specific inputs and outputs. This leaves room for programming errors, whether the software is produced in‐house or by a DAHS vendor. Checking the form of equations used in program algorithms may be a first step, but they must also be checked to determine whether they work in practice. For this purpose, test data should be entered into the software programs to determine whether known results can be reproduced. This is, in fact, a requirement for systems subject to Part 75, where it is stated in 40CFR75.20(c) that “the owner or operator shall compare reference method values with the output from the automated data acquisition and handling system.”

Missing data routines required in Part 75 CEM systems must be verified at each location where the software is installed (U.S. EPA 2006, 2013). This may be done by the vendor over the internet, or by installing a test software package at the site. If tested by a software package, a provision must be added to the CEM QA plan to examine the data during missing data periods for “reasonableness.” Reasonableness means that the substituted data are consistent with the Part 75 criteria for the length of the missing data period.

Because CEM data are critical to the allowance trading procedures instituted in the U.S. Part 75 programs, the EPA Clean Air Markets Division developed report assessment programs to check and cross‐check data submitted in quarterly electronic data reports (Frushour 2019). Because hourly emissions data, unit operating data, and performance test data, including daily calibration drift and relative accuracy test data, are all submitted, cross‐checks between the data can alert the agency when the reported data may be in error. System leaks, monitor failures, flow correlation problems, repetitive values, and even willful misrepresentation have all been traced by this software. Although specific to the requirements of Part 75 systems, the concept can be easily applied in any monitoring program where electronic data reports are submitted.

Ongoing quality assurance procedures software should be included in the QA plan. The plan itself should address review and audit procedures on four different levels (after Suess et al. 2013):

Update Review: A check that the software is up to date; verifying that the latest DAHS vendor update (if applicable) has been incorporated, proper span/range values are set, configurable factors, such as flow monitor K factors, bias adjustment factors (BAFs), F factors, and so on are up to date. Also, the concentration of calibration gases currently being used should be verified when entered into the DAHS.

Regulatory Revision Review: A review of the proper implementation of software revisions or configuration changes due to either monitoring system changes or a change in permit or other regulatory requirements. This may involve a similar use of test data, as in the initial software verification.

Comprehensive DAHS Audit: A configuration audit to review and verify that

compliance exceedance limits and warning limits are appropriate to the latest permit requirements;

calculations for converting analyzer data and process data into units of the standard(s) are correct. Verify that correct constants and factors are used in the equations;

averaging procedures (six‐minute, hourly, block averages, rolling averages) are applied correctly as per permit requirements;

missing data routines (as applicable) are correctly applied;

daily calibration drift/error calculations are performed properly, using current certified gas values, out‐of‐control and tolerance alarm limits are appropriate to the applicable performance specifications, quality control charts are generated at specified or required intervals;

cylinder gas audit and relative accuracy test audit data have been properly entered, that bias adjustment factors have been changed (as applicable);

reporting formats meet the requirements of the applicable state, provincial, or federal regulations or guidelines;

links and external network communications are operating as intended;

password protections, security provisions, and firewalls are active and sufficient;

an analysis of the past four quarterly audits with recalculation of all reported data, based on raw and hourly data is satisfactory.

A comprehensive audit might be necessary after a major change in either the software or the monitoring system, or after a change in personnel who may be uncomfortable with the present programming or past vendor support. A comprehensive audit can be useful in assembling a list of ongoing configurational problems and other issues for the software vendor to resolve, or to serve as a basis for alternative technical specifications when seeking a new software provider. However, such an audit requires considerable time and expertise and might best be conducted by an independent contractor specializing in DAHS audits.

SUMMARY

CEM data acquisition and handling systems evolve continually as developments in computers, computer software, process controls, and network communication create opportunities to improve and expand data acquisition and handling capabilities. However, the basic functions of the DAHS – to display, record, and report data– remain fundamentally the same.

The CEM database can be a valuable resource for the environmental program of any industry needing to control its pollutant emissions. Although often used primarily for meeting reporting requirements, applications for process improvement and optimization have increased as confidence in the accuracy of CEM system data has increased. This confidence in CEM system data has also allowed CEM systems to play a role in a broader spectrum of regulatory programs. CEM system data can satisfy requirements of compliance assurance monitoring programs and periodic monitoring, as well as providing “credible evidence” that a source is in compliance with its emission limitations.

For the regulatory agencies, CEM data provide more than just a means to determine if emission sources are in “continuous” compliance. CEM system data also provide accurate metrics to track allowances in the U.S. emissions trading programs, as well as to track the progress of the programs themselves. The emissions data can be extended to ambient air modeling programs, where questionable “emission factors” can be replaced with real‐time, quality assured emissions data, and provide a basis for source apportionment studies (Hidy 1984; Hopke 2016). And today, CEM system data serve to address greenhouse gas and global warming issues by contributing to the information base from which mitigation programs can be developed and environmental projections can be derived (Rausch et al. 2015).

POSTSCRIPT ‐ SUGGESTED PROGRAMMING PRINCIPLES FOR CEM DATA ACQUISITON SYSTEMS

The following list provides a summary of a number of the issues discussed above, as well as suggestions that might appear obvious, but are often overlooked by programmers who are unfamiliar with instrumentation systems and their operation, or CEM system regulatory requirements.

The DAHS should provide a continually updated display of parameters measured, corrected, and averaged by the monitoring system. The displays should provide easily readable formats in one screen or several screens.

Trending should be possible for any input parameter, including process inputs. It should be possible to display historical data in trend plots. Trend plots should be scalable from minutes to months. A cursor should be available to display selectable data from the plot in numeric form. However, trend plots in 2 cm by 4 cm boxes do not convey much information. The full screen should be used to display trend plots.

The CEM control system should initiate the daily zero and span calibration checks automatically. The DAHS should report the drift in both ppm (or % CO₂ or %O₂) and as a percent of span. The DAHS, therefore, must have an input parameter for the span gas certified value (for each gas) and the span of each instrument to calculate the % of span drift values. A daily calibration report screen and report printout of these results should be available.

Data obtained during calibration adjustment or instrument/system maintenance are not averaged into a reported hourly emissions data set. Also, the DAHS/control system should incorporate a key or code to indicate to the DAHS when the system is “in maintenance.” This key is usually triggered either manually or at the request of the instrument technician.

The software should enable both the zero and calibration drift to be presented in control charts updated automatically after each calibration check. Quality control charts are merely a plot of the daily drift over a given time period. The time period of the control chart should be configurable for any time period specified by the CEM operator. At a minimum, the software should be able to generate weekly, monthly, quarterly, and annual quality control charts for any parameter subject to drift. Meeting this recommendation by requiring the data be first be downloaded to an Excel spreadsheet, indicates relatively unsophisticated programming skills on the part of the software developer.

In 40 CFR 60 rules, a minimum of four equally spaced data points are required to calculate an hourly average. Most CEM systems will obtain a data point within one to three minutes, and it is typical in CEM DAHS programming to just average all the minute data to make an hourly average. A problem arises when conducting the required daily zero and calibration check. If the check takes 14 minutes, one can usually still obtain one data point in the calibration check quarter to obtain at least one data point in each quadrant of the hour. Even if the calibration check takes 28 minutes, one could use the last and first quadrants of two hours and still meet the minimum data requirements as long as one had at least one data point in each quadrant (e.g. minute 46 of the last quadrant of the first hour and minute 14 of the second hour). The fact that these two points are not “equally spaced” has generally not bothered regulatory agencies. The view is generally held that reporting any 46 minutes as constituting a valid hour is better than declaring the whole hour invalid and having no data at all. In any event, the DAHS should be capable of obtaining 15‐minute averages and then average these four averages into the hourly averages.

When using time‐sharing systems (e.g. multiplexed systems sharing one set of analyzers when monitoring multiple units), only real data are used when computing averages. For example, if a 5‐minute reading is obtained in each quarter, the hourly data will consist of the average of the four 5‐minute quarterly readings. If the system samples and “holds” for plant purposes, the “held” data are not regarded as regulatory data and are not to be incorporated in the averages.

If there is a time lag before a time‐shared analyzer or system comes up to its asymptotic value, data obtained before this asymptote is reached are not valid and are not to be incorporated into the reported average (otherwise the data reported would be lower than true).

All data must be retained by the DAHS, even invalid data. If invalid data are subsequently corrected, the substituted or corrected data must be identified as such with an appropriate code (number, color, etc.). Invalid original data should be flagged as such and substituted data also appropriately flagged. The original “bad” data must not be removed from the database. In other words, the system should have the capability of editing the database without overwriting the original data.

The question often arises as to how long the data must be retained. Typically, CEM DAHS systems will retain minute data for a few days or weeks and the 15‐minute averages for a few weeks or months, depending on whether there is a need to retain this “fine” data for process optimization purposes. The hourly data is always retained from two to five years or longer, depending upon the regulatory requirements and company policy. However, some regulatory agencies such as the Pennsylvania DEP and Alberta Environment and Parks do require the retention of one‐minute data.

System availability (or unavailability) may be required to be calculated and reported monthly, quarterly, or annually. For 40 CFR 60 affected units, availability is the percentage of valid CEM hours obtained during unit operation divided by the number of unit operating hours during the quarter. Unavailability is the reverse, the number of invalid CEM hours during unit operation divided by the number of unit operating hours. Availability reporting frequencies and calculation methods differ, depending upon the regulatory programs – specific program requirements must be addressed in this case.

In the case of invalid data, two scenarios may result:

a.if the unit is regulated under 40 CFR 60 requirements, the invalid data are not submitted, but the number of hours for which data were not obtained are reported in the quarterly excess emissions report submitted to the state, along with the quarterly system availability. Reasons for missing data may also be required to be submitted.

b.if the unit is regulated under an emissions trading program, data must be substituted for any missing periods. Missing data substitution procedures are either defined in the trading program rules (U.S. EPA 2020b) or left to the discretion of the regulated source (ENVC 2005), such as employing predictive or correlation techniques, substituting continuous stack test data, portable monitor data. However, any such procedures used must be documented and may require approval by the program administrator.

When a parameter value does not change over an extended period of time, it is said to be “flat‐lined.” If the flat‐lined data are due to instrument or system failure, the data must be identified as being invalid and removed from any hourly averages reported. However, flat‐lined data must still be retained (see 7 above) in the database. In PI systems, if the software notes no change of a parameter within a specified range over a specified period, the last parameter value may be held until a change occurs. This may save on data storage, but when the actual data are no longer recorded, the monitoring system is no longer considered to be continuous unless four data points (actual) are recorded each hour.

If flat‐lining occurs because the span (range) of the instrument is too low and the instrument value exceeds the range set, a dual‐range analyzer may be necessary, with one range set for reading normal values that are within 20–80% of scale (as is standard in instrument practice, but is not always a regulatory requirement) and a second range to catch excursions or upsets in the process, which may be much higher.

On the other hand, if the span was set too high, the analyzer may be giving the appearance of flat‐lining when reading at the bottom of the scale at the “noise” level. In such cases, a dual‐range system should again be used.

Rolling averages and block averages: Reporting rules may vary between different units, depending upon the regulatory program. As discussed, a “block hourly average” is simply an hourly average reported by itself. A three‐hour “rolling average” is the average of three hours reported every hour. The average rolls, so the next average subtracts off the first hour constituting the average and adds on the next hour. Note that 24 averages are still obtained each day for a 3‐hour rolling average.

Units of the standard: Emissions data are to be reported in units of the standard, the units in which the emissions limit is expressed. For example, if the emissions limit is in lbs/hr, averaged emissions must be reported in lbs/hr. This will require input from two monitors, a pollutant concentration monitor (e.g. NOx or SO₂) and a flow monitor (velocity monitor). Alternatively, flue gas flow can be determined from the heat input for a combustion source, by knowing the fuel feed rate (from a fuel flow monitor) and its heating value (from an in‐line GC or lab analysis). If emissions are in lbs/mmBtu, one calculates the emissions using an F factor relationship, which requires input from the pollutant monitor and a CO₂ or O₂ monitor.

When 40 CFR 60 Appendix F Quality Assurance requirements apply, three primary performance audits must be conducted over the year: (a) daily zero and span calibration verifications, (b) three quarterly cylinder gas audits, and (c) an annual relative accuracy test audit (RATA).

A CEM system analyzer is out‐of‐control if the calibration drift is greater than two times the drift performance specification for five consecutive days or four times the drift performance specification for any one day. (Most performance specifications for drift of pollutant monitors are 2.5% of span, so if the analyzer drifts by 5% for five days it is out‐of‐control as of the last day. If it drifts by 10% in one day, it is out‐of‐control since the last good calibration). Out‐of‐control data are viewed as invalid data and do not count in the availability calculation.

A cylinder gas audit is conducted in three out of the four quarters of the year (vs. four out of four quarter for the Part 75 quarterly linearity check). This involves injecting the analyzer with two calibration gases at the probe. Most systems will be programmed to do this automatically through the CEM system controller, but it may be done manually also. The DAHS should be designed to accept the data obtained during these tests and calculate the calibration drift values as specified.

A RATA must be conducted annually or semiannually. In programming the DAHS, some facility should be made to read and print minute‐by‐minute data. This is necessary to compare the CEM data with source tester data when calculating the relative accuracy.

The DAHS or controller should receive status lines that indicate CEM system and analyzer failures such as

power loss

sample vacuum loss

instrument/purge air loss

analyzer lamp failure

sample pressure loss.

The DAHS should incorporate an alarm screen or some other means of making known that the system is in an alarm condition. The system should also have the capability to generate printed alarm summaries.

Most CEM DAHS systems also have the capability of alarming when emission levels begin approaching or exceeding the emissions standards. These alarm limits are usually a configurable parameter in the DAHS.

When a CEM system malfunctions or a unit exceeds the emissions standard, most CEM system DAHS enable the operator to enter a “reasons code” for the malfunction or exceedance. The reasons are usually configurable and are manually keyed into the DAHS when the incident occurs in order to maintain a record for the preparation of the quarterly report.

Reports: The DAHS should have the capability of generating reports specific for the CEM system, both for diagnostic record‐keeping purposes, internal plant reporting and for regulatory reporting. These reports and other CEM data should also be able to be distributed through the appropriate plant communications network. Some suggested reports are as follows:

Daily Calibration Report: A summary of calibration drift in ppm or % and the calibration drift as a percent of span of the instrument

Alarm Summary: A summary of all CEM system alarms for any configurable period

Daily Summary: A summary of hourly emissions data for the day

Downtime Report: A summary of CEM system availability and reasons for CEM system downtime

For Part 60 Systems: Quarterly Excess Emission Report (EER): A summary of periods of excess emissions and reasons for excess emissions. Also, a summary of periods of CEM system downtime with reasons and corrective action taken

For Part 75 Systems: Emissions Collection and Monitoring Plan System (ECMPS)

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Note

* Note: With respect to terminology, the acronym, “DAS,” for “data acquisition system,” has been commonly used to refer to a CEM data recording system. An alternate acronym “DAHS,” for “data acquisition and handling system” was introduced in the rules for the U.S. EPA 40 CFR 75 acid rain program, where “DAHS” is used in that context. In practice, either term refers to the data recording system and DAS and DAHS are viewed as equivalent.

CHAPTER 11
CERTIFYING CEM SYSTEMS

Emissions monitoring systems used in regulatory programs must first be certified for meeting a set of minimum design and performance specifications. Such requirements separate continuous emission monitoring systems from process monitors, whose operation is determined and overseen according to the needs of plant or corporate personnel. In contrast, the performance of CEM systems is determined and overseen by the regulatory agency according to rules that have been established by either regulatory agencies or by independent standardization bodies. When the certification procedures are followed and the performance standards are met by an emissions monitoring system, system data are then viewed as having accuracy and precision sufficient for use in the programs of the regulatory body.

The U.S. EPA established performance specifications for CEM system design, certification and quality assurance procedures for a wide variety of monitors used for regulatory applications. In Canada, CEM Guidelines, with procedures similar to those in the United States, have been established by Environment Canada, which the Canadian provinces incorporate into their own rulemaking. In Europe, the European Union (EU) Comité Europeén de Normalisation (CEN) has established many standards and procedures that specify requirements for emissions monitoring systems termed “Automated Monitoring Systems” (AMS) for system design, certification, and quality assurance. In addition, the International Standards Organization (ISO) has standardized continuous monitoring procedures for many pollutants. These principal guidelines, specifications, and procedures are listed in Table 11-1.

In the United States, CEM certification requirements were established in 1975 under Part 60 as “performance specifications” (U.S. EPA 1975), where the specifications are centered on the performance of the monitoring systems and not their design (with the one exception of opacity monitors). In other words, it does not matter how an instrument works, or what analytical technique it uses, but it does matter how it performs. Specifications for zero and calibration drifts, response time, and “relative accuracy” were enacted in 1975 for monitoring systems installed in new stationary sources, and, in 1990, for sources subject to allowance trading programs. To assure that emissions data are comparable nationwide, all gas monitor data were required to be traceable to NIST standard reference materials (NIST SRMs) in both programs (U.S. EPA 2012).

Canada established guidelines for continuous monitoring systems in 1993 (Environment Canada 2005), which essentially crystalized the complex monitoring rules of the United States acid rain program without reducing their stringency. In addition, the guidelines were expressly written for the plant engineer, and remain today as one of the most understandable set of CEM performance specifications available.

In Europe, standards for automated monitoring systems were first established as guidelines by the Federal Republic of Germany. Many of these guidelines were then adopted and expanded either by the International Standards Organization (ISO) or by the Comité Europeén de Normalisation (CEN), the European standards body. The ISO standards are written for specific types of monitors (e.g. SO₂, NOx, particulate matter) and are used internationally, and in Europe when CEN standards are not available. After the formation of the European Union (EU) in 1993, CEN began a program of standardization for automated monitoring systems. The European approach is fundamentally different than that taken in North America, requiring that monitoring systems first be accredited by independent laboratories conducting “type” or “suitability” tests. Also, once installed, the monitors are calibrated against reference test methods, not calibration gases, as is the practice in North America.

TABLE 11-1 National Documents for CEM Performance Specifications and Quality Assurance Requirements

Organization | Document Reference | Specifications and Procedures
U.S. EPA | 40 CFR 60 Appendix B | Design, installation, and certification
| 40 CFR 60 Appendix F | Quality assurance
| 40 CFR 75 Appendix A | Design, installation, and certification
| 40 CFR 75 Appendix B | Quality assurance
Environment Canada | EPS 1/PG/7 | Design, installation, certification, and quality assurance
ISO | ISO 10396 | Gas sampling
| Various – by pollutant | Installation, certification, and quality assurance
EU – CEN | EN 15627 | Type testing – fitness for use
| EN 14181 | Installation, certification, and quality assurance

Emission monitoring systems performance specifications and standards established in the United States, Canada, and Europe have allowed other countries to choose those requirements that might be the most suitable for their own programs. Some jurisdictions have chosen to use the Part 75 allowance trading requirements, as it is the most stringent. Others, not having established monitoring programs, may use the rules recommended by the monitoring system supplier on a case-by-case basis. Others may require that “accredited” continuous emission monitors be installed, but not require performance tests. This, of course, raises the question of comparability – will a ton of emissions reported by one country be reported at the same level of accuracy by another? This question may not be important for internal programs, but with concerns over pollutant transport and impacts of greenhouse gas emissions, international accountability is becoming increasingly important. Fortunately, although the methods used to achieve certification differ, they ultimately provide for traceability to standard reference materials.

This chapter will address certification procedures used in the United States, Canada, and Europe. It will highlight the differences among the procedures as well as their similarities, illustrating the various paths taken to standardize monitoring systems to meet objectives for comparability, accuracy, and precision.

PART 60 PERFORMANCE SPECIFICATIONS AND TEST PROCEDURES

The U.S. performance specifications and test procedures for CEM systems were instituted as part of the performance standards for new stationary sources. The first three performance specifications for opacity, SO₂ and NOx, and O₂ and CO₂ were published in 1975 (U.S. EPA 1975), establishing the characteristic United States CEM test procedures and specifications. The list of performance specifications has since expanded as EPA regulations developed, extending to Hg, HCl, and other types of monitoring systems (U.S. EPA 2020c) (see Table 11-2).

Performance Specification 2 defined criteria for zero and calibration drifts, response time, and relative accuracy, which continued in the other performance specifications except for PS1, PS11, PS12A, and PS16 where they do not apply (PS1 is discussed in Chapter 8, PS11 in Chapter 9, and PS12A in Chapter 12). Similar criteria were adopted into the Part 75 allowance trading program requirements and the Environment Canada Guidelines.

It was found early in the application of source monitors that a monitoring system may work well at one facility but the same type of system might give erratic data at another. It was realized that the analyzer is not necessarily the controlling element for system performance, but that the total system (probe or stack interface, conditioning system, analyzer, and the controller/data acquisition system) must be considered. As a result, it was realized that system certification should be based on its performance rather than on its design and that certification must be done on a case-by-case basis to account for stack conditions and the unique characteristics of each CEM system application.

TABLE 11-2 Performance Specifications and Test Methods for Certifying CEM Systems

Number | Type of System | Date Promulgated
PS1 | Opacity | 10/6/75
PS2 | SO₂, NOx | 10/6/75
PS3 | O₂, CO₂ | 10/6/75
PS4 | CO | 8/5/85
PS5 | TRS | 7/20/83
PS6 | Velocity mass emission rate | 3/9/88
PS7 | H₂S | 10/02/90
PS8 | Volatile organic compounds | 12/15/94
PS9 | Gas chromatographic systems | 12/15/95
PS11 | PM CEMS | 1/12/04
PS12A | Hg CEMS | 5/18/05
PS12B | Hg sorbent trap | 9/9/10
PS15 | FTIR | 10/17/00
PS16 | PEMS | 3/25/09
PS18 | HCl | 7/7/18

The Part 60 performance specifications for gas monitors include the specifications, basic criteria for installation, a few rudimentary design requirements, and test procedures for determining if the monitoring system meets the specifications.

Installation Specifications

Two overriding principles for CEM system installation are that (i) measurements must be representative of stack emissions and (ii) the sampling location should be accessible for system maintenance and repairs. It is often difficult to satisfy both criteria, particularly in existing sources where sampling considerations are not addressed in duct or stack design. Also, in newly constructed sources, sampling criteria are often secondary in importance to the practical concerns of design engineers.

Accessibility

Because the frequency and quality of maintenance is directly related to the accessibility of a CEM system, the location of a probe or monitor is an important consideration in any CEM system design. Sheltered locations that can be reached by elevators or stairways are preferred to those that are not sheltered and can only be reached by ladder. An installation in the boiler house or in the annulus between the stack and stack liner provides shelter at the measuring point. An exposed location on a roof or off of a catwalk is less preferable, but is often chosen so that measurements can be made at a representative location. CEM subsystems may be housed in a shelter at the base of the stack or duct, or even on the stack. CEM shelters are used typically for extractive systems to house conditioning systems, analyzers, controllers, and frequently, data acquisition systems. Such shelters allow these subsystems to operate under relatively clean conditions and stable temperatures. For unprotected stack installations of in-situ analyzers, factors such as vibration, lightning, ambient atmospheres, and temperature extremes, in addition to accessibility and representativeness, must be considered for long-term operation.

Representativeness

Although accessibility is an important consideration in finding a site for monitoring systems, if a location does not offer the possibility of obtaining a representative sample of the flue gases, little will be gained. In a regulatory sense, representative means that “the pollutant concentration or emission rate measurements are directly representative or can be corrected so as to be representative of the total emissions from the affected facility …” (U.S. EPA 2020c). Representativeness for opacity monitors means that the monitor should be placed at a location where the measured opacity corresponds to the opacity of the emitted flue gas. When considering the overall accuracy of the CEM system in terms of stack emissions, representativeness of the sample being measured is as dependent on the measuring location as it is on the accuracy of the analyzers performing the measurements.

Gas Stratification

Flowing gases are generally well mixed, but stratification can occur when there are differing temperatures or dissimilar gas streams (see, e.g. Figure 6-13, Jahnke 1994). Air leaking into a duct, combining two process gas streams into a stack, or the reintroduction of scrubber by-pass gas into a flue; all can result in such stratification. In combustion sources, air in-leakage occurs usually near the preheaters. Columns of gas with high unmixed NO concentrations have even been observed from burners. The problem is further complicated since this stratification is not only spatial – stratification can also change temporally, as a function of time. As process load or other conditions change, the gas distributions can vary dynamically.

Particle Stratification

Particles may not be uniformly distributed in a flue gas. Because of their momentum, particles may not be able to change direction as rapidly as the flue gas flowing through the plant exhaust system. This will cause the development of gradients in particle number concentrations at certain locations in the ductwork (Figure 11-1).

The particles may even become stratified in layers over relatively long sections of a flue. Particle stratification depends largely on four factors:

The size of the particles

The flue gas velocity

The distance between the point of interest and a disturbance

The nature of the disturbance

Figure 11-1 Particle stratification in ducts and stacks.

The disturbance can be a bend in the ductwork, air in-leakage, a control device, internal support structures, or a disturbance caused by the stack exit.

In long, horizontal ducts, gravitational settling can lead to the stratification of larger particles toward the bottom. The problem of stratification can be compounded by low flue gas velocities because the carrying capacity of the gas for large particles will be reduced. Bends, fans, and obstructions will also affect the distribution of particles in these layers. Also, a helical flow pattern (cyclonic flow) can be produced from the tangential entry of gas from one flue into another (see Figure 8-16) or the entry of gas from multiple ducts into a single stack. The swirling pattern of gas flow may make it difficult to find an opacity monitor path that will produce an average opacity representative of the actual emissions.

Another problem occurs when the location being sought is to be representative for the determination of mass concentration instead of opacity. Manual source testing methods for particulate matter (U.S. EPA 2020a) have their own criteria for sampling locations, and they may differ from those for opacity monitors. An opacity monitor measures opacity, not mass concentration. Some of the best locations for measuring opacity would be very difficult locations from which to extract a manual reference method sample (an area of high turbulence is an example of such a location). In practice, the important factor is that particles of all sizes should be well-mixed in the stack gas. Areas of turbulence (where there is sufficient time to provide mixing) are good monitor locations, but may be poor for manual sampling because of reverse and fluctuating gas flows.

Quantifying the Degree of Stratification

The degree of stratification in a duct or stack can be quantified. One method of quantification (Environment Canada 2005; U.S. EPA 2020e) involves traversing the stack or duct and obtaining gas concentration values. An example scenario for a rectangular duct would be to sample at nine or more sampling points of a balanced matrix. The degree of stratification at each sampling can be calculated as follows:

(11-1)percent-sign upper S t r a t i f i c a t i o n equals StartFraction c Subscript i Baseline minus c Subscript a v e Baseline Over c Subscript a v e Baseline EndFraction times 100

where

ci = concentration of the pollutant at point i

cave = average of the nine concentrations

The sampling plane is said to be stratified if any value is greater than 10%.

Another approach to quantifying stratification is to calculate the mean value and standard deviation from the data obtained in the stratification test (Brooks and Williams 1976). Using the standard deviation as a measure of spread, one can use a value of 2σ (where σ = the standard deviation) to define the stratification from the mean concentration value in the sampling plane. For example, if 2σ = 11%, then the probability is 95% that a point measurement taken anywhere in the sample plane will deviate from the mean concentration by less than ±11%. This treatment, however, assumes that the individual measurements are normally distributed.

When performing a stratification test, it is good practice to sample at a single point over the entire sampling period (e.g. Elam and Ferguson 1985). This is easily done using another test apparatus. The data obtained can be used to determine if gas concentrations are changing as a function of time as well as spatially. If the concentration varies at a single point over the sampling period, the traverse data will be difficult to interpret.

Because stratification patterns may change under varying plant operating conditions, stratification tests can be difficult to perform well. Studies can be costly if a complete characterization is needed for pollutant gas and flow distributions under different plant operating conditions. Also, many CEM systems are installed in new plants and must be on-line at the time of plant start-up. Because sampling locations are decided upon during plant design and construction, it is not always possible to conduct stratification tests to guide CEM installation decisions in new plants. In this case, for flow stratification, computer models using the techniques of computational fluid dynamics (CFD) or the construction and testing of scale models can be useful for characterizing flow distributions.

EPA-Recommended Locations for Gas Monitoring CEM Systems

As a means to facilitate the installation of CEM systems at representative locations, guidance has been provided (U.S. EPA 2020d, e). Some suggestions for measurement location are listed below.

Probe Locations

The location should be at a point at least two equivalent duct diameters downstream from (i) the nearest control device, (ii) the point of pollutant generation, or (iii) a point at which a change in the pollutant concentration or emission rate may occur. The location should also be at least one-half equivalent diameter upstream from the exhaust or one-half an equivalent diameter upstream from a control device when measuring uncontrolled emissions. However, these criteria do not guarantee that flue gas concentrations are not stratified at such locations.

Sampling Locations – Point Monitoring Systems

After choosing the measuring location for sampling probes or monitors, it is further suggested that (i) the probe tip be greater than 1.0 m from the stack or duct wall and (ii) the probe tip monitor be either within or over the centroidal area of the stack or duct cross section.

Diluent monitors should sample at the same point as the pollutant monitor. If the O₂ or CO₂ concentrations vary between the two points because of air in-leakage effects, the CEM system may not be certified.

Sampling Locations – Integrated Path (Cross-Stack) Monitoring Systems

Monitoring locations and sampling points for in-situ monitors are recommended in Part 60 Performance Specifications 2 and 18, where it should be noted that in both specifications they are given as recommendations and are not requirements (Figure 11-2). For in-situ point monitoring CEM systems, it is again recommended that the measurement point be no less than 1.0 m from the stack or duct wall, or within a centrally located area that is no greater than the cross-sectional area at the measuring location. For integrated path monitors, it is recommended that the measurement path be within the inner area 1.0 m of the stack or duct wall and have at least 70% of the path within the inner 50% of the stack or duct cross-sectional area at the monitoring location or be located over any part of the centroidal area.

If the CEM system fails to certify, and if it is determined that this failure is due to the monitor location, then the system may have to be relocated. It may be possible to apply a correction technique to avoid relocation, but this is often difficult. For situations of highly stratified flow, it is difficult to show a relationship between the composition at a single point and the average concentration when the spatial distribution of pollutant concentrations changes with time.

PART 60 DESIGN SPECIFICATIONS FOR GAS MONITORING SYSTEMS

In contrast to the detailed design specifications given for opacity monitors (see Chapter 8), design specifications for gas monitoring systems merely address requirements for the span (range) of the analyzer and the ability of the system to determine zero and calibration drifts.

Figure 11-2 Monitoring location for integrated path monitor.

Span

One would think that the range of an analyzer would be a straightforward concept in the world of instrumentation. In fact, an instrument technician or engineer may use the terms span, full-scale, or range interchangeably. Terms that have been used in this regard are:

Range

Span

Full scale (FS)

Full-scale value

High-level value

The U.S. EPA has not been consistent in this regard in its rulemaking, although in the context of a standard or a method, the meaning is usually clear. Unfortunately, with the promulgation of Part 75, the EPA Clean Air Markets Division coined its own meaning for “span,” where “span” and “range” have different meanings than in Part 60. Span is calculated from the maximum potential concentration (MPC) or maximum potential velocity (MPV) using procedures given in 40 CFR 75 Appendix A (U.S. EPA 2020h). The majority of readings must be between 20 and 80% of the full-scale range and the span and range must be reevaluated annually. If a majority of the values fall out of the 20–80% window, the span must be revised. This can be confusing when the calculated span and range values are different, especially when the calibration and linearity gases are specified as a percent of the “span” value and not the “range.”

Performance Specification 2 requires that for an uncontrolled unit, the CEM system be able to measure between zero and a high-level value between 1.25 and 2 times the maximum potential emission level. Where emissions are controlled, the high-level value (the span value) should be between 1.5 times the pollutant concentration corresponding to the emission limit and the span value defined in the applicable subpart of Part 60 (U.S. EPA 2020b). The principal consideration is that the monitoring system should never go off-scale.

The problem with this requirement is that a plant will often have emissions that are much lower than the maximum potential emission level or a concentration corresponding to an emission limit. When following EPA requirements for instrument span, the day-to-day readings may, as a result, be at the bottom end of the instrument range, rather than the center of the range, which is the practice with most instrumentation. Unless the analyzer is linear over its span and has the same sensitivity from zero to the upper span value, an instrument calibration conducted near the high span level might introduce errors at the lower values. In such cases, multirange analyzers or two analyzers, a low-range and a high-range analyzer, may be necessary to obtain accurate readings over the scale of measurement.

When reading specifications, either those required by a regulatory agency or those advertised by an instrument manufacturer, careful attention should be paid to the measurement range of the analyzer. An instrument designed to measure over a range of 0–1000 ppm may not be suitable for monitoring emissions levels < 10 ppm, and almost certainly, an instrument with a specified measurement range of 0–10 ppm will not be able to measure at levels near 1000 ppm.

Calibration Drift Capability

Performance Specification 2 requires that the monitoring system be able to determine calibration drift at a zero level (from zero to 20% of the high-level value) and a high-level (between 50 and 100% of the high-level value). Under Part 60, calibration gases, gas cells, or optical filters may be used for this purpose. Under the Part 75 allowance trading programs, only calibration gases may be used. Performance Specification 18 for HCl also requires the use of calibration gases only.

When conducting a calibration drift test, an alternative relative accuracy procedure (PS2 §16.2), or an Appendix F cylinder gas audit (U.S. EPA 2020f§5.1.2), the tests are conducted on the CEM system and not just the analyzer. This means that calibration gases are to be injected through the system components used during normal sampling, such as filters, scrubbers, chillers, or dilution orifices. This generally means injecting the calibration gas “as close to the probe as possible,” or at least at the connection between the probe and the umbilical line.

PART 60 PERFORMANCE SPECIFICATIONS FOR GAS MONITORS

The primary U.S. EPA performance specifications for gas monitors are found in 40 CFR 60 Appendix B (U.S. EPA 2020c) and 40 CFR 75 Appendix A ( U.S. EPA 2020h). Similar specifications are found in the U.S. Federal MACT program, which address hazardous substances (40 CFR 63). In the U.S. performance specifications, there are two major criteria that CEM systems must meet: (i) calibration drift (error) and (ii) relative accuracy.

The calibration drift specification is not difficult for most commercial CEM systems to satisfy. In some cases where an analyzer may drift beyond the specification, automatic correction made by the instrument or system controller may bring the system within specification. In certifying a CEM system, the calibration drift is defined as “the difference in the CEM system output readings from the established reference value after a stated period of operation during which no unscheduled maintenance, repair or adjustment took place.”

The relative accuracy formalism is used in both the U.S. and Canada CEM regulatory programs, where meeting relative accuracy criteria is the central requirement of the certification process. The relative accuracy test is conducted to determine if a CEM system is capable of providing data that can be compared with data obtained using the compliance test methods of 40 CFR 60, Appendix A, within the limits specified in the applicable performance specification.

The U.S. EPA procedure for calculating CEM accuracy uses a method for the comparison of data pairs and results in the expression of “relative accuracy” (Natrella 1963). The relative accuracy is composed of two terms: (i) the mean difference which expresses the average deviation of the CEM value from the reference value, which is the bias or systematic error associated with the test and (ii) the confidence coefficient, which gives an estimate of the “spread” or “precision” of the test data.

The EPA definition for relative accuracy is “The absolute mean difference between the gas concentration or emission rate determined by the CEM system and the value determined by the reference method's (RM) plus the 2.5% error confidence coefficient of a series of tests divided by the mean of the reference method tests or the applicable emission limit,” expressed as

(11-2)RA equals StartFraction StartAbsoluteValue d overbar EndAbsoluteValue plus StartAbsoluteValue cc EndAbsoluteValue Over ModifyingAbove RM With bar EndFraction times 100

where

∣d∣ = the mean difference between the reference method result and CEM result

∣cc∣ = the confidence coefficient

ModifyingAbove upper R upper M With bar = the average of the reference method values obtained in the test series

(11-3)ModifyingAbove upper R upper M With bar equals StartFraction 1 Over n EndFraction sigma-summation Underscript i equals 1 Overscript n Endscripts upper R upper M Subscript i

The accuracy of a measured value is an expression of its relationship to a standard or true value. In the case of source emission measurements, the true value is not determinable, so accuracy is expressed here with respect to a reference method value. Reference method values are obtained by using instrumental or manual test methods, as applicable. The use of manual wet chemical methods is allowed; however, source testers rarely employ them today unless requested, or if there is no instrumental test method published for the pollutant.

The relative accuracy expression essentially gives an estimate of accuracy for only one point, the average value of the emissions (RM) at the time the relative accuracy test was performed. It may not be statistically relevant at other emission levels that the CEM system might measure, particularly at lower values. A modified relative accuracy expression that substitutes the value of the emissions standard in place of RM is used to accommodate problems associated with the expression at low emission values. Such modifications are regulatory constructs and have little statistical meaning. It also should be noted that the relative accuracy is dependent upon the accuracy and precision of the reference method itself.

Despite these shortcomings, the relative accuracy expression has served as a useful criterion for accepting or rejecting newly installed CEM systems. The tendency has also been to use relative accuracy as a measure of the total performance of a CEM system on an ongoing basis, required in Appendix F Procedure 1 to be repeated annually (U.S. EPA 2020f). Part 60 relative accuracy criteria are given in Table 11-3.

TABLE 11-3 Part 60 Relative Accuracy Specifications

PS Number
Type of System
Relative Accuracy (RA)
Other Performance Criteria

PS1
Opacity
N/A
N/A

PS2
SO₂, NOx
20% of RM value in units of the standard
RA 15% of the emission standard if RMavg <50% of std

PS3
O₂, CO₂
20% of RM value in units of the standard
1.0% O₂ or CO₂

PS4, 4a, 4b
CO
20% of RM value in units of the standard
RA 5% of the emission standard if RMavg < 50% of std

PS5
TRS
10% of RM value in units of the standard
RA 10% of the emission standard if RMavg < 50% of std

PS6
Velocity mass emission rate
20% of RM value in units of the standard
RA 10% of the emission standard if RMavg < 50% of std

PS7
H₂S
20% of RM value in units of the standard
RA 10% of the emission standard if RMavg < 50% of std

PS8
Volatile organic compounds
20% of RM value in units of the standard
RA 10% of the emission standard if RMavg < 50% of std

PS8A
Volatile organic compounds
N/A
Zero and calibration drifts ≤ 3%

PS9
Gas chromatographic systems
N/A
Seven-day calibration error test ≤ 1% of calibrated protocol gas value

PS11
PM CEMS
N/A
Calibrated against RM by regression analysis, with r < 0.85
or < 0.75 for low emitters and TI
≤25% of emission limit

PS12A
Hg CEMS
20% of RM value in units of μg/scm
≤1.0 μg.scm if emission ≤50 μg/scm
Hg° Measurement Error (ME):
5% of span for low, middle, and high gases
HgCl₂ Measurement Error (ME):
% of span for low, middle, and high gases

PS12B
Hg sorbent trap
20% of RM value in units of μg/scm
≤ 1.0 μg/scm if emission ≤ 50 μg/scm

PS15
HAPs monitored by FTIR
20% of RM value in units of the standard
Use an applicable RM and PS2 or
Method 301 validated method

PS16
PEMS
10% of RM value in units of the standard
< ±2 ppm for emissions < 10 ppm
≤ 20% if emissions < 100 ppm and > 10 ppm

PS18
HCl
20% of RM value in units of HCl concentration or in units of the standard
RA 15% of emission standard if RMavg < 75% of std
HCl Measurement Error (ME):
5% of span for low, middle, and high gases

*  The maximum EPA Part 75 criteria for relative accuracy is ≤10.0% for SO₂ and NOx, CO₂, and O₂. For the pollutant and flow monitors, meeting alternative criteria of ≤7.5% allows for annual, instead of semiannual, relative accuracy testing.

Unlike calibration drift, a Part 60 relative accuracy determination may not be based solely on data from individual analyzers, but may include the data from pollutant, diluent, or flow monitors to perform the calculation in terms of “units of the standard.” For example, SO₂ emissions standards expressed in terms of ng/Joule or lb/million Btu for fossil fuel–fired steam generators require an F-factor calculation using SO₂ and O₂ (or CO₂) data. As another example, SO₂ emissions standards for municipal waste combustors are corrected to 7% of O₂ on a dry basis that can incorporate data from SO₂, O₂, and H₂O (or equivalent) monitors. However, in Part 75, relative accuracies for SO₂ and flow monitors are expressed separately, and not in terms of the pollutant mass rate in pounds per hour (Schakenbach et al. 1995).

Performance Specification Test (PST) Procedures in the United States and Canada

The Performance Specification Test is required by the U.S. EPA to accept or certify CEM systems. Performance Specification Test procedures similar to those of the United States are also employed in Canada. The test evaluates how well the system performs under the physical and environmental conditions at the plant. The ability to sample the flue gas, response to line voltage fluctuations, sensitivity to duct vibration, ambient temperature, and ambient atmospheres are implicitly checked in the calibration drift test or the relative accuracy test. The PST is not a laboratory evaluation of an instrument under controlled conditions, but a realistic evaluation under plant operating conditions.

It is important to note that PST procedures have been established to certify the CEM system as installed, and that a certified system should generate data that are representative of the stack emissions. The installation specifications, performance specifications, and test procedures common to most certification programs have been developed with this intent. However, it should be noted that the performance specifications do not evaluate the continuing operation of the system. The long-term operation of the system depends on the QA program developed for the system. The elements of CEM QA programs will be discussed in Chapter 15.

For competitive purposes, a CEM system vendor must often guarantee that the installed system will meet the specifications and consequently, the PST determines success or failure for the CEM system vendor. Companies that purchase the systems often demand such guarantees in their contract with the vendor and may hold partial payment or apply other penalties until the system is certified. However, even with such guarantees and other inducements, a system may not pass the test. Most often, problems can be resolved by tracking down mistakes in the system design or modifying the system to meet the special demands of the plant. In some cases, particularly with the application of new technology, the entire monitoring concept may prove unworkable and the system will have to be replaced by one that is more suitable. Therefore, these tests are considered extremely important and must be carried out correctly. The calculations must be performed properly and a well-documented report of the test must be prepared. As mentioned above, the two primary tests that are conducted are (i) the calibration drift (or error) test and (ii) a relative accuracy test. Depending upon the rule, a response time test may also be required. The following section describes how each of these are performed.

The Calibration Drift (Error) Test

The calibration drift (error) test can be carried out easily by plant personnel prior to conducting the comparative tests used to determine the relative accuracy. In the 40 CFR 60 Appendix B and 40 CFR 75 Performance Specifications, the zero- and high-level drift (error) tests examine the CEM system's ability to hold its calibration over a period of time. The Part 60 calibration drift test and the Part 75 calibration error test are essentially the same procedures except that the Part 75 test requires the use of protocol gases traceable to the National Institute of Standards and Technology (NIST) and Part 60 does not. The term “calibration error” refers to the difference between the certified value of a NIST traceable reference material and the analyzer response. Calibration drift refers to the deviation of the response value over time, but where the reference material does not necessarily have to be certified or traceable to NIST.

The calibration drift test is typically conducted over a period of 168 h when the unit is operating at more than 50% of normal load (Part 60 units). The CEM system is then evaluated at 24-h intervals for seven consecutive days. The calibration drift test is conducted by introducing calibration gases into a gas injection port that allows a check of the entire measurement system (including sample lines, conditioning systems, and as much of the probe as practicable). In Part 60, an in-situ monitor may determine the zero- and high-level calibration drift by producing a mechanical instrument zero and checking the calibration with a gas cell or optical filter. This is not allowed in Part 75, where protocol calibration gases are required in determining calibration error, even for integrated path or point in-situ systems.

For a CEM system that accepts calibration gases, the test is performed in the manner shown:

Day 1 – Zero gas (or one with a low-level value, 0–20% of the span value) is introduced into the system. The system is zeroed.

Day 1 – High-level value calibration gas (50–100% of span, 80–100% of span [Part 75]) is introduced into the system. The system is calibrated to this value.

Day 2 – Zero gas is injected into the system after 24 h. The CEM system value is recorded.

Day 2 – After injecting zero gas, the high-level value calibration gas is injected. The CEM system reading is recorded. (If desired, the system may be adjusted at this point to the values set on day 1.) (Note: If periodic automatic or manual adjustments take place to bring the system into calibration, the calibration drift must be determined immediately before these adjustments take place. In some CEM systems, an analyzer or system microprocessor may automatically zero and calibrate the system daily. Obviously, if the calibration drift test is conducted after such a procedure, there will not be any observable drift.)

Days 3–8 – Steps 3–4 are repeated.

Part 60 Calibration Drift Calculations

Part 60 calibration drift is calculated as a percentage, using the units of reference gas, cell, or optical filter and dividing by the span value:

(11-4)

where

dCD = the difference between the data pair

The calibration drift is calculated and must be passed each of the six or seven days of the test, as applicable. The daily drift test values are not averaged over the test period to give an averaged value. The CEM system may not exceed the drift specification for any one of the seven days of the test. The Part 60 seven-day calibration drift specifications that are to be met are given in Table 11-4.

The Linearity (Measurement Error) Test

System linearity is required to be checked in Part 75 CEM systems, and in PS12A and PS18 of Part 60. In this test, each analyzer is challenged with three gases at the probe calibration port. Low-, mid-, and high-range protocol gases at concentrations of 20–30% of span, 50–60% of span, and 80–100% of span, respectively, are used in the test. Each analyzer is challenged three times with each gas (not in succession) and the average response is calculated.

For Part 75 CEM systems, the linearity error is calculated with respect to the protocol calibration gas concentration (not the span value) as follows:

(11-5)

The reference value is the protocol gas cylinder concentration for the low-, mid-, or high- calibration gas introduced into the monitoring system. For SO₂ and NOx analyzers, the linearity error is required to be ≤5.0% or ≤5 ppm of the reference value, for each gas. For O₂ and CO₂ analyzers, the linearity is required to be ≤5.0% or ≤0.5% O₂ or CO₂ for each calibration gas.

TABLE 11-4 Calibration Drift Specifications for Part 60

Number | Part 60 Systems | Calibration Drift Performance Specification | Period
PS1 | Opacity | 2% opacity | Seven day test
PS2 | SO₂, NOx | 2.5% of span | Seven day test
PS3 | O₂, CO₂ | 0.5% O₂ or CO₂ | Seven day test
PS4 | CO | 5% of span | For six of seven test days
PS5 | TRS | 5% of span | For 6 of 7 For six of seven test days
PS6 | Velocity/mass emission rate | 3% of span | Seven day test
PS7 | H₂S | 5% of span | For six of seven test days
PS8 | Volatile organic compounds | 2.5% of span | Seven day test
PS8A | Total hydrocarbon using FID | 3.0% of span (3 ppm) | Seven day test
PS9 | Gas chromatographic systems | N/A |
PS11 | PM CEMS | 2.0% of range | Seven day test
PS12A | Hg CEMS | 5.0% of span | Seven day test
PS12B | Hg sorbent trap | N/A | N/A
PS15 | HAPs monitored by FTIR | N/A | N/A
PS16 | PEMS | N/A | N/A
PS18 | HCl | 5% of span | 5% of span

For Part 60 Method 12A and PS18, the measurement error is expressed as a percent of span, not as a percent of the protocol gas value as in Part 75.

(11-6)

In PS12A, the calibration error specification is ≤±5.0% for the system Hg⁰ response and ≤±10.0%.

In Part 60 and Part 75, the measurement error test is conducted only once during the certification period and is not a drift test. This is in contrast to the Canadian procedures, where the test is conducted for each of seven days, essentially checking drift in linearity over the period.

The Environment Canada Calibration Drift Test

A combination drift-linearity test is given in Environment Canada CEM Guidelines (2005). In this test, NIST traceable gases at 0–20%, 40–60%, and 80–100% of the full scale of the analyzer are injected three times (not consecutively) at the probe. This is repeated for each of the seven days of the calibration drift test. Calibration drift is calculated as follows:

(11-7)

The system is acceptable if every daily calibration drift calculated for each analyzer is ≤2.0% of full scale for the low- and mid-range gases and ≤2.5% for the high-range gas, or <8 ppm or <0.5% O₂ or CO₂ (whichever is greater) for the mid- and high-range gases.

Cycle Time/Response Time Test

A response time test is required in Part 75 and in Environment Canada CEM Guidelines. It was required in the original 1975 PS2 and 3 Part 60 performance specifications, but was eliminated in a 1983 revision. The response time test is conducted primarily to determine if a system time-sharing between several sample points can make a stable measurement for each point within a 15-minute period. It also checks the capability of systems performing a series of operations, such as back-purging, sampling, and sample averaging, to obtain a stable reading during the requisite period.

The response time is conducted by injecting low- and high-level gases into the system at the probe and determining the time that it takes for the monitoring system to complete 95% (90% in Canada) of the step-change. Data are obtained from the output of the data acquisition system. The response time, as stated, must be less than 15 minutes.

The response time test was used to assure that a monitoring system could provide a minimum of four “equally spaced” data points over a one-hour period, to calculate hourly averages, the basic CEM reporting unit for most regulatory programs. It also allows for time-sharing a bank of analyzers between different stacks or ducts, although this system concept has fallen into disfavor. Most monitoring systems today can provide emissions data with a response time of a few minutes or less, so the need for a response time test is unnecessary, except for certain gas chromatographic applications or in cases where long sampling times are necessary to measure gases at low concentrations.

Dynamic Spiking Test (Method of Standard Additions)

Dynamic spiking is a method that is used to validate the performance of both reference test methods and installed CEM systems. Dynamic spiking tests are included in relatively few of the Part 60 Appendix B performance specifications or Appendix A test methods, except for those relating to the use of FTIR systems. The test becomes particularly important when measuring emissions at low concentrations where the “relative accuracy” formalism breaks down and becomes less useful, particularly at concentration levels < 5 ppm.

Dynamic spiking tests, also called “methods of standard additions,” have been used in Method 301 (U.S. EPA 2020g) FTIR and GCMS validations since 1993 (Kinner 2013); however, the method is often viewed as a relatively new procedure. It is now incorporated in all of the EPA FTIR test methods, and test method 7E for NOx and 30A for Hg. In the Appendix B performance specifications, it is included in PS15, which addresses installed FTIR continuous monitoring systems, and PS18 for HCl CEMS (EMC 2006; Zemek 2014). Unfortunately, the method is treated inconsistently between its various applications as a source test method and as installed systems. The procedures, equations, symbols, and subscripts differ between the standards, which can contribute to some confusion when applying or evaluating the method. These applications are summarized in Table 11-5.

The dynamic spiking test can be used to determine the level of detection, calibration drift, and calibration error by injecting a known quantity of a pollutant into the flue gas sample stream. This provides the advantage of measuring a known quantity of the pollutant (analyte) in the actual flue gas “matrix” of gases, which may include water vapor and CO₂ at percent level concentrations and an array of other pollutants present at part per million levels. The method can be superior to the use of dry calibration gases for calibration verifications or audits because it can account for the synergistic effects of the matrix on measurement accuracy. For example, using a dry calibration gas for a calibration check would miss the effect of dipole interactions between H₂O and HCl in FTIR measurements.

TABLE 11-5 Application of Dynamic Spiking in U.S. EPA Test Methods and Performance Specifications

Method ID
Method Purpose
Gas/Application
Spike/Flue Gas Flow
Spike Gas Concentration
Acceptable Bias or Recovery

7E
Instrumental NOx test method
NOx
≤10%
Two levels
50 & 150% of stack conc.
100 ±10%
Or ≤ 0.2 ppm

30A
Instrumental Hg test method
Hg
≤1 : 5
150–200% of cHg native
±10% or 0.5 μg diff

301
Test method validation
Any
<1 : 10
Level equivalent to emission limit
≤10% Bias
>10% ≤ 30%
Facility specific

320
321
FTIR test method
FTIR test method
Organic/inorganic gases
HCl (cement plants)
<1 : 10
~1 : 10
About same as native conc.
50 ppm HCl
M301 criteria
±30%

D6348
FTIR test method
Gaseous compounds
<1 : 10
About same as native conc.
±30%

PS15
FTIR CEM
HAPs
1 part in 9

Apply M301 criteria and correction factor

PS18
Any HCl CEM
HCl
≤10%
HClTotal < 100% of span
50–60 DSA
80–100 DSA
DSA
5% of span or 20% of emission limit

In the “spiking” method, a pollutant gas of known concentration, traceable to NIST standards, is injected into the sampling system. This is normally done near the probe at the calibration port, ahead of the conditioning system. In contrast to conducting a calibration verification, the spike gas flow does not flood the probe or probe system, but dilutes the native flue gas stream. When performing the method, the total flow (spike gas flow + flue gas sample flow) is set to be the same as the normal flue gas sample flow.

To calculate the expected pollutant concentration resulting from the injection of the spike, the dilution factor is first calculated. The dilution factor, DF, is the ratio of the spike flow to the total flow:

(11-8)upper D upper F equals StartFraction upper Q Subscript s p i k e Baseline Over upper Q Subscript t o t a l Baseline EndFraction

Mass flow meters, controllers, or rotameters can be used to monitor the flow; however, this should be done as accurately as possible. Calibrated, NIST-traceable flow meters accurate to at least 2.0% should be used (PS18 in U.S. EPA 2020c).

Alternatively, a tracer gas, such as SF₆ or N₂O can be used to determine DF. In this case,

(11-9)upper D upper F equals StartFraction c Subscript upper S upper F 6 Baseline i n s p i k e Over c Subscript upper S upper F 6 Baseline i n s p i k e d f l u e g a s s a m p l e EndFraction

In most procedures, the calibration gas is introduced into the sampling system at a rate no greater than 10% of the sample flow (1 : 10).

When conducting the test, the “native” or unspiked flue gas pollutant concentration is measured before the spike gas is introduced into the sampling systems. This provides a value for the “native” concentration value(s), cnative, of the flue gas. This measurement is performed prior to the spike test or (depending upon the applicable method or specification) after each of the multiple runs of a test.

Next, the spike gas, having a NIST-traceable concentration of cspike, is introduced into the monitoring system at the controlled flow rate (e.g. ≤10% of the total flow) set at the dilution factor, DF. The “native” gas concentration will, of course, be diluted by the flow of the spike gas. Through this addition, the “spiked” flue gas, which now contains native gas and spiked gas, is measured to provide the concentration value, cmeasured.¹

The theoretical, or “expected,” value of cmeasured can be calculated from the knowledge of cspike, cnative, and DF. First, the diluted concentration of the native analyte can be calculated from cnative and the dilution factor DF as

(11-10)c Subscript n a t i v e Baseline left-parenthesis 1 minus upper D upper F right-parenthesis

Second, the contribution to the native analyte concentration from the analyte in the spike gas in the combined flue gas sample is

(11-11)c Subscript s p i k e Baseline upper D upper F

The expected, calculated concentration is then

(11-12)c Subscript e x p e c t e d Baseline equals c Subscript s p i k e Baseline upper D upper F plus c Subscript n a t i v e Baseline left-parenthesis 1 minus upper D upper F right-parenthesis

The difference between the measured spiked flue gas sample pollutant concentration, cmeasured, and the expected concentration, cexpected, should equal zero in a perfect world. If it is not zero, bias is exhibited in the measurements. The bias, B, is the difference between the measured analyte concentration of the spiked flue gas sample, cmeasured, and the expected, calculated, concentration cexpected (Equation 11-13):

(11-13)

(11-14)equals c Subscript m e a s u r e d Baseline minus c Subscript s p i k e Baseline upper D upper F minus c Subscript n a t i v e Baseline left-parenthesis 1 minus upper D upper F right-parenthesis

In some standards, a limit is set for the level of bias allowed. In others, another performance expression, the percent recovery R, is used. The percent recovery can be calculated in several ways; the calculation method used should be specific to the applicable standard. Two of these methods are

as a percentage of the measured value of the spiked sample versus the theoretical value for the spiked sample [ASTM 6348 (ASTM 2020a)]:

(11-15)

and,

as a percentage recovery of the spike (M7E, Method 321)

(11-16)

CEM systems can use dynamic spiking as a method for performance testing for the level of detection, calibration drift, bias, and the dynamic spike audit (DSA) accuracy of PS18. The dynamic spike audit is the average of the bias values from three spike tests, limited to ≤5% of the span value or ≤20% of the emission limit value. Also, if the bias calculated from a dynamic spiking test is found to be statistically significant, a bias correction factor is applied in Method 301 and Performance Specification 15.

A dynamic spiking test does not provide measurements that are independent of the installed system and therefore does not constitute a test of a CEM system's accuracy. It can, however, verify that the CEM system can transport and measure the analyte in the flue gas matrix to within a specified level of recovery (Dunder 2015, 2017).

The Relative Accuracy Test

The relative accuracy test is the most important test required for CEM system certification. The test has traditionally been called the “relative accuracy test audit,” and the acronym “RATA” is used in its application to both initial CEM system certification and its use as an annual quality assurance performance test.

The RATA is typically conducted by a source testing contractor who sends out a mobile van with instrumentation performing automated reference methods (e.g. EPA Methods 3a, 6C, 7E), although some facilities do their own testing. The instrumentation is operated according to the procedures given in the automated source test methods of Part 60, Appendix A, such as the instrumental analyzer methods 6C (SO₂) and 7E (NOx). Wet chemical methods may be used if methods with suitable instruments are not available or are disallowed by regulation. Two or more source testing personnel usually perform the relative accuracy tests – the number of personnel depends on the complexity of the test.

Source testing contractors performing the RATAs must be experienced in conducting Part 60 RATAs and EPA reference test methods. Contractors accredited to ASTM D7036, “Standard Practice for Competence of Air Emission Testing Bodies,” should be used for any testing (ASTM 2020b). Also, a “Qualified Individual” (QI) as defined by ASTM D7036 should be present during the test. The ASTM D7036 standard practice is required for any tests conducted under the Part 75 programs, but not in the Part 60 programs. This does not prevent incorporating the requirement as part of the contract specifications with the air emission testing body (AETB), the source test contractor.

At the certification of a new CEM system, representatives from the CEM system vendor and the agency may be present to observe and watch for any problems. Through the development of a test plan prior to the tests, all parties involved should determine and understand their roles during the testing. The agency representative is particularly important because problems often occur during plant start-ups that may require the modification of the test plan. In such cases, the ability of the agency to approve or disapprove such changes is central to completing the test.

Test Protocol

Because there are many areas in the testing and data interpretation that may be ambiguous, it is recommended that facility personnel and the source testing team leader agree prior to the test under what unit operating conditions the tests will be conducted, how the test data will be compared to the CEM data, and how the calculations will be performed. Any such agreements should be stated in the test plan or protocol. The test protocol is written by the source test contractor in consultation with plant personnel and should address, at a minimum, the following:

Project description

Project organization, personnel, and responsibilities

Test plan and schedule

Plant operational status on the test date

Identification and description of test equipment

Description of test procedures to be conducted

QA objectives and procedures

Description of equations applied and data reduction procedures

Documentation and reporting procedures

ASTM D7036 and QI accreditations

Pretest Meeting

A pretest meeting or conference call may be held before the day the relative accuracy test is performed to help test coordination. The meeting may include the plant environmental engineer or CEM coordinator, a control agency representative, a source test contractor representative, and a CEM system vendor representative. The test protocol should be discussed and any last-minute changes should be confirmed and agreed upon. If a test plan has not been prepared, the items given in the listing for “Test Protocol” should constitute the discussion outline for the meeting.

Any issues regarding access, staging points, test locations, and sampling points should have already been resolved. It is important that miscommunication be minimized during the test to avoid issues that lead to the rejection of the test data and a repeat of the test.

Safety Policy and Procedures Safety

When accessing monitoring systems on the stack, all personnel should be aware of safety procedures to be followed when working at the stack. The plant shift and maintenance supervisor as well as unit operators should be aware of the activity prior to climbing to elevated stack platforms.

External stack platforms should not be accessed under severe meteorological conditions such as lightning, high wind, or icing. Activities on the stack should be coordinated between at least two people of the test team, each being responsible for the other's safety at all times. The test should never be conducted by just one person. A safety awareness program should be in place, with checks of the installation surroundings, access, plant operating conditions, and potential hazards.

Source testers and any source test observers representing the regulatory agency, systems integrators, and consultants should as well, be familiar with the facility safety procedures and adhere to plant personal safety equipment requirements.

Relative Accuracy Test Procedures

Relative accuracy is relative only to the reference method determinations and does not necessarily indicate the accuracy of the CEM data with respect to the true value of the stack emissions. To obtain a “truer” value of the stack emissions, the reference method testing is performed on a three-point traverse rather than at a single point in the stack or duct.

The reference method sampling locations are the same as those specified for the CEM system, which are at least two equivalent diameters downstream from a control device and one-half equivalent diameter upstream from the effluent exhaust or control device.

The reference method sampling points are different than those specified for the CEM system. The sample points are chosen to provide representative samples over the duct or stack cross section. As a minimum, samples are taken on a three-point traverse on a measurement line that passes through the centroid of the stack or duct and in the direction of any expected stratification. Reference measurements are made or samples are taken at traverse points that are 16.7, 50, and 83.3% of the line (Figure 11-3a). For ducts or stacks with a measuring line greater than 2.4 m and where stratification is not expected, sampling may be conducted at 0.4, 1.2, and 2.0 m (Figure 11-3b). (This second option is not allowed after wet scrubbers or where two gas streams with different pollutant compositions combine.) Samples are to be taken within 3 cm of these traverse points.

The reference method sampling point should not interfere with the CEM system probe. A distance of 30 cm or 5% of the equivalent diameter of the cross section (whichever is less) is specified as an appropriate separation.

The principal sampling strategy for the relative accuracy test is to take CEM readings and reference method samples at the same time. This may seem obvious, but it is sometimes forgotten or not corrected for in the test program. Care must be taken to account for the response time of the CEM system relative to that of the reference method (Figure 11-4).

Figure 11-3 Reference method traverse points on a measurement line (a) <2.4 m and (b) >2.4 m.

Figure 11-4 illustrates that the length of the umbilical cord to the CEM system may be important by giving a lag time before the analyzer sees the sample. If the reference method instantaneously samples, or if its response is faster, the time difference must be considered when comparing the data. Note from the figure that the CEM system data are obtained at a time Δt from when the reference method data are taken.

A problem also arises when a time-shared CEM system samples over only a few minutes to perform one “cycle of operation for each 15-minute period.” This often results in an attempt to compare data obtained over a few minutes with a sample or sample data averaged over a 20–30 minute period. This may be satisfactory for a steady process, such as a utility boiler, but for a highly variable process such as municipal waste combustion, this comparison may not be suitable to evaluate CEM system performance.

Data obtained from the reference methods and the CEM system must all be corrected to the same basis, typically to standard conditions of temperature and pressure (20 °C and 1 atmosphere [atm] dry), and corrected for dilution using the %O₂ or %CO₂ data. Because there are many areas in data interpretation that may be ambiguous, it is imperative that the control agency, the source representative, and the source tester agree prior to the test how the data will be obtained, compared, and calculated (e.g. Jorgenson and Highberger 1985).

Reference method data are obtained at each of the three points on the traverse line when conducting the test. Sampling is conducted simultaneously by the CEM system and the reference test method.

The automated Reference Methods 3A, 6C, 7E, and 10 (as opposed to Manual Reference Method 3, 6, and 7) are usually used when conducting the relative accuracy test for criteria pollutants. Manual Reference Methods 2 and 4 are used for flow and H₂O measurements, respectively.

Figure 11-4 Correlation of reference method data and CEM data in response time.

A typical relative accuracy test is conducted as follows:

Unit to be tested is operated at its normal operating level while the RATA is being conducted.

As discussed above, gas sampling reference method measurements are conducted at three traverse points at the measurement location. Traverse points are located at 16.7, 50.0, and 83.3% of the measurement line. If stratification has been shown not to be present, sampling may be conducted at alternative sampling points 0.4, 1.2, and 2.0 m from the stack wall. Flow measurements must be conducted on a 12-point traverse at sampling points specified in Reference Method 1.

A minimum of nine (9) sampling runs are performed over the duration of the test. Each run lasts for at least 21 minutes, divided equally over the three (3) sampling points for stratified flow testing, or at the single point for nonstratified flow.

The tester may carry out more than nine (9) sets of comparisons. All data, including any outliers, along with all calculations should be recorded and included in the test report.

Data from the CEM system and reference method runs are correlated, noting clearly, the beginning and end of each run on the CEM data acquisition record. After each run is completed, the results from the CEM system are compared with the data derived from the reference method results over the time period that the run was performed.

The CEM system and reference method results are correlated on the same basis, applying corrections for moisture, temperature, pressure, etc. as appropriate. Auxiliary measurements taken during the testing are used to make any such corrections. O₂, CO₂, and/or flow data are used to convert both the source test and CEM data into units of the applicable emissions standard, if the monitoring system is being certified under the performance specifications of Part 60. If being certified under Part 75, relative accuracies are calculated in terms of the analyzer-reported units (ppm, μ/m³, %, m/s, etc.).

A minimum of nine data sets are obtained. Each set of data is recorded over a period of 30–60 minutes, so an efficient test team should be able to conduct the relative accuracy test in one day. The tester may conduct 12 runs and collect 12 sets of data. The tester may reject, at his or her discretion, three sets of data. No statistical basis is necessary for rejecting any set of data in U.S. procedures, but all of the data, including those that have been rejected, must be reported (a statistical outlier test is required in Environment Canada Guidelines).

Diluent and moisture measurements should be obtained simultaneously with the pollutant measurements, although Performance Specification 2 gives the option that they may be obtained during the 30- to 60-minute sampling period. The sampling error associated with these measurements will be as significant in the relative accuracy calculations as those associated with the pollutant measurements; therefore, it is best to be as consistent in diluent and moisture measurements as possible.

Relative Accuracy Test Calculations

The relative accuracy of the CEM system is determined by comparing the instrument-determined emission values either in ppm, as a percentage, or in units of the standard to the reference test method analysis. As previously noted, the reference method may be either an instrumental or a manual test method. When comparing CEM system data with manual reference method data, a few more calculations are necessary than if instrumental methods are used. In a manual reference method, data are reported from the analytical laboratory in terms of milligrams of pollutant per dry standard cubic meter (dscm) or dry standard cubic feet (dscf). These results are corrected to a standard pressure of 760 mmHg (29.92 in. Hg) and a standard pressure of 293 K (528 R). All data for the reference methods and the CEM system are usually given on a consistent, dry basis unless reporting a mass rate (kg/hr) is the only requirement. Because in-situ analyzers, dilution probes, and hot-wet extractive systems measure on a wet basis, a moisture correction may be necessary if a dry basis concentration is required.

The relative accuracy is determined by first summing two terms: StartAbsoluteValue d overbar EndAbsoluteValue, the absolute value of the mean difference between the reference method data and the CEM system data, and |cc|,a confidence coefficient, and dividing by average reference method value during the test, or the applicable emissions standard, as follows:

or,

(11-17)upper R upper A equals StartFraction StartAbsoluteValue d overbar EndAbsoluteValue plus StartAbsoluteValue c c EndAbsoluteValue Over ModifyingAbove upper R upper M With bar EndFraction times 100

The mean value of the differences, StartAbsoluteValue d overbar EndAbsoluteValue, shows, on the average, the systematic error or bias between the CEM system and the reference method. The confidence coefficient, |cc|, is an expression that reflects the spread of the data; that is, the precision of the test.

To obtain the relative accuracy, first, for each run of the test, a difference (di) is calculated:

(11-18)d Subscript i Baseline equals upper R upper M Subscript i Baseline minus upper C upper E upper M Subscript i

where

RMi = reference method value for the ith run

CEMi = CEM system value for the ith run

The absolute value of the mean difference between the data pair is calculated by

(11-19)

where

n = number of data pairs (9–12, or more)

Note: In calculating the sum of the differences between the data pairs, the signs of the differences are retained (e.g. the absolute value is taken of the total summation, not the individual di values).

The confidence coefficient (cc) is expressed in terms of a statistical value found in a table and the standard deviation of the data set. The expression is

(11-20)c c equals t 0.975 StartFraction upper S Subscript d Baseline Over StartRoot n EndRoot EndFraction

t0.975 = t value derived in the one-tailed t test corresponding to the probability that a measured value will be biased by 2.5% at the 95% level of confidence (see Table 11-6)

Sd = standard deviation of the differences of the data pairs obtained during the relative accuracy test:

(11-21)

TABLE 11-6 t-Values

n * | t 0.975 | n | t 0.975 | n | t 0.975
2 | 12.706 | 7 | 2.447 | 12 | 2.201
3 | 4.303 | 8 | 2.365 | 13 | 2.179
4 | 3.182 | 9 | 2.306 | 14 | 2.160
5 | 2.776 | 10 | 2.262 | 15 | 2.145
6 | 2.571 | 11 | 2.228 | 16 | 2.131

* The values in this table are already corrected to n − 1 degrees of freedom. Use n = the number of individual values.

The confidence coefficient is a measurement of the uncertainty in the calculation of StartAbsoluteValue d overbar EndAbsoluteValue minus StartAbsoluteValue c c EndAbsoluteValue representing the largest variation in StartAbsoluteValue d overbar EndAbsoluteValue that would be expected 97.5% of the time (i.e. it would only be exceeded 2.5% of the time).

Example calculation can be found in Jahnke and Aldina (1979). The calculation of the relative accuracy, RA, is valid at the average emissions value (RMavg) at the time the test was conducted. Because the test is required to be performed under normal load, the “relative accuracy” of the CEM system is generally a good measure of the accuracy of the continuous monitoring data, as long as the unit is operating at normal load. It is commonly assumed that the relative accuracy reported to the agency holds over the range of operation of a unit; however, this is not true statistically.

Bias Tests

Possible causes of bias in CEM systems can be due to temperature and pressure effects, interferences, stratification problems, sample losses, inaccurate cylinder gas values, and so on (Jahnke 1994). Bias tests are used to determine the degree of bias of the CEM system relative to the reference test method. A bias test may not detect all the biases in a system, particularly if the reference test method analyzer or system is the same as the CEM system. Using similar systems to do the relative accuracy test may result in excellent relative accuracy and bias test results, but may not necessarily reflect the “true” emissions values if both systems are identically biased.

The Part 75 Bias Test

Systematic errors giving CEM readings either lower or higher than the reference method are allowed in the CEM regulations of 40 CFR 60 as long as the relative accuracy calculated by Equation 11-17 is within the relative accuracy specification mandated for the CEM system. These requirements were written before those of Part 75 and have not been revised to incorporate criteria relating to bias.

In the Part 75 CEM specifications, low bias in CEM system data is not permitted. If a CEM system were to read systematically low, the value of the allowances from the utility monitored by such a system would be questioned. Low bias in allowances would of course make it more difficult for a trading program to meet its reduction goals.

Therefore, in the Part 75 program, low bias in systems is not permitted. A bias test is applied to check for low bias. Low bias is considered to be present if:

(11-22)d overbar greater-than StartAbsoluteValue c c EndAbsoluteValue

This expression merely states that systematic error is considered to be present if, on the average, the CEM measurements are so far below the reference method measurements as to lie outside the confidence limits. In other words, the CEM system is reading so low relative to the reference method that we are 97.5% confident that the system has low bias. Or conversely, there is at most a 2.5% probability of mistakenly detecting bias when there really is none (Jahnke 1994).

The bias test is quite useful in detecting CEM system problems. Although the U.S. EPA does not allow low bias in Part 75 systems, high bias in systems is permitted (as long as the relative accuracy specification of 10% is still met). Obviously, high bias in a system would result in the loss of allowances and would provide a benefit to a trading program. However, a CEM system owner should apply the test to check for both low and high biases between the CEM system and reference method. Ideally, the cause of the bias should be detected and remedied to give the most accurate data possible.

A Part 75 CEM system owner is allowed the option of applying a bias adjustment factor if the cause of the bias is not determined or corrected. The bias adjustment factor is given as

(11-23)upper B upper A upper F equals 1 plus StartFraction StartAbsoluteValue d overbar EndAbsoluteValue Over ModifyingAbove upper C upper E upper M With bar EndFraction

where

BAF = bias adjustment factor

StartAbsoluteValue d overbar EndAbsoluteValue = absolute value of the arithmetic mean of the difference obtained during the failed bias test using Equation 11-11

ModifyingAbove upper C upper E upper M With bar = mean of the data values provided by the monitor during the failed bias test

This factor is then used to adjust all subsequent CEM system data for the measured parameter using Equation 11-24 until after the next relative accuracy test is performed.

(11-24)upper C upper E upper M Subscript i Superscript a d j u s t e d Baseline equals upper C upper E upper M Subscript i Superscript m o n i t o r Baseline times upper B upper A upper F

where

upper C upper E upper M Subscript i Superscript a d j u s t e d = data value, adjusted for bias at time i

upper C upper E upper M Subscript i Superscript m o n i t o r = data (measurements) provided by the monitor at time i

If the CEM system passes the bias test at the time of the next relative accuracy test, no corrections would then be required. If the system fails, a new bias adjustment factor must them be calculated and applied unless the cause of the bias is determined and corrected. Note that it would be better to “fail” the bias test and adjust the data upward rather than “pass” the bias test, because data cannot be adjusted downward according to the rule.

CEM system bias adjustment factors are typically on the order of 3–4% of the CEM system measurement values. This level of correction may be acceptable, or the CEM system user may specify to the CEM system vendor that zero bias or low-biased Part 75 systems are to be provided.

The Environment Canada Bias Test

A different form of bias test is used in Environment Canada CEM Guidelines (Env. Can. 2005) and in some ISO CEM specifications (ISO 1992). In these bias tests, both positive and negative biases are considered.

Here, a systematic error or bias is considered to be present if

(11-25)StartAbsoluteValue d overbar EndAbsoluteValue greater-than-or-equal-to c c

Note that in this expression, in contrast to Equation 11-11 used in Part 75, the absolute value is taken of the mean difference.

For each pollutant and diluent analyzer, or flow monitor, the bias is calculated according to Equation 11-26 and must be less than ±5.0% of full scale.

(11-26)StartFraction StartAbsoluteValue d overbar EndAbsoluteValue minus StartAbsoluteValue c c EndAbsoluteValue Over upper F upper S EndFraction times 100 less-than-or-equal-to 5.0 percent-sign

or, alternatively for low level measurements:

│d overbar│ ≤ 5.0 ppm for pollutant concentration, or

│d overbar│ ≤ 0.5% O₂ (or CO₂) for diluent concentration, or

│d overbar│ ≤ 0.6 m/s for stack gas flow monitors.

If the bias test fails (e.g. >5.0% of span), the relative accuracy and bias tests must be repeated until both pass. The guideline recommends that the sources of bias be investigated and remedied, but even if the bias test is passed, a bias adjustment factor must be applied to correct for either positively or negatively biased CEM data between 0 and 5%. Passing the bias test does not exclude application of a bias adjustment factor. The bias adjustment factor specified in EPS 1/PG/7 is defined as

(11-27)

where

BAFCAN = Environment Canada bias adjustment factor (Note that Equation 11-27 can be shown to be equivalent to Equation 11-23 when |d overbar| in Equation 11-23 is replaced by ModifyingAbove d period With bar right-parenthesis

ModifyingAbove upper R upper M With bar = average of reference method results during relative accuracy test

ModifyingAbove upper C upper E upper M With bar Subscript upper R upper A upper T upper A a v g = average CEM analyzer results during relative accuracy test

As in Part 75, this factor is then used to adjust all subsequent CEM system data for the measured parameter using Equation 11-28 until after the next relative accuracy test is performed.

(11-28)upper C upper E upper M Subscript a d j u s t e d Baseline equals upper C upper E upper M Subscript m o n i t o r Baseline times upper B upper A upper F Subscript upper C upper A upper N

Additionally, in Canada, the use of a BAF in any measurement must be stated in the QA/QC manual. The Alberta Canada CEMS Code (AEP 1998) has similar requirements for the bias adjustment factor, where analyzer bias must be <4% of full scale. However, the application of bias adjustment factors is not required in Alberta.

International Standards Organization (ISO) Bias Tests

In the original ISO source monitoring standards for SO₂ and NOx (ISO 7935 and ISO 10849), the bias test is similar to Environment Canada and Part 75. However, the ISO bias check calculations are expressed in a slightly different statistical form than those of the United States and Canada. In ISO standards, a bias, or systematic error, is considered to be present if

(11-29)StartAbsoluteValue d overbar EndAbsoluteValue minus 2 StartFraction upper S Subscript upper D Baseline Over StartRoot n EndRoot EndFraction greater-than-or-equal-to 0

A monitoring system is considered to fail the bias test if

(11-30)

As in the Environment Canada Guidelines and the Alberta CEMS Code, bias greater than a stipulated amount (here, 2% of the full scale) is not allowed, and the cause of this error must be found and eliminated. The expression 2 StartFraction upper S Subscript upper D Baseline Over StartRoot n EndRoot EndFraction is essentially equivalent to the confidence coefficient cc. The value of 2 in Equations 11-29 and 11-30 is an approximation for t-values for which n > 9.

Relative Accuracy Procedure as a Percentage of the Emission Limit

If plant emissions are well below the emissions standard (e.g. less than 50% of the standard), Part 60 Appendix B allows the relative accuracy to be calculated as a percentage of the emission limit (standard) instead of the reference method value, ModifyingAbove upper R upper M With bar, as in Equation 11-31.

(11-31)upper R upper A equals StartFraction StartAbsoluteValue d overbar EndAbsoluteValue plus StartAbsoluteValue c c EndAbsoluteValue Over upper E m i s s i o n s t a n d a r d EndFraction times 100

The problem with the expression for relative accuracy is that as emission concentrations decrease, it becomes more difficult to pass the relative accuracy test. It is much easier to pass a relative accuracy test when the NOx concentration is 500 ppm than when it is 5 ppm. Between the installed CEM system and the source tester apparatus, imprecision in conducting the test may lead to high values of the confidence coefficient, in addition to higher inaccuracies in the low-level measurement. Although a CEM system might be purchased to measure accurately at 5 ppm, if the emission limit is 500 ppm, there is no reason to monitor at that level if the purpose of the system is to report excess emissions. However, if the purpose of the monitoring system is for process control at the 5 ppm level, then a low-level monitoring system may be necessary. A case where passing a RATA may be particularly difficult is in monitoring for HCl, where the emission limit is ~1.2 ppm in the Part 63 electric utility MATS rule and 3 ppm in the Portland cement MACT rule.

With this consideration, if the purpose of the CEM system is to demonstrate compliance with the emission limit, this alternate calculation is allowed. This is a reasonable option to Equation 11-17, if one considers that if a compliance test indicates that emissions are, for example, less than 50% of the standard, the CEM system data could still be within the emission limit even if the CEM system relative accuracy is off by 100%. In a way, the calculation is an estimate of the “relative accuracy” of the CEM system at the emission limit, not at the actual emissions value RMave. As mentioned earlier, this is not statistically rigorous, but serves as a regulatory remedy to balance monitoring costs and the purpose for monitoring.

Relative Accuracy as a Percentage of Certified Gas Concentration (Alternative Procedures)

As another option, if plant emissions are less than 50% of the emissions standard, the EPA may be petitioned under the General Provision of Part 60, §60.13(j)(1) to waive the RATA and instead conduct the alternative procedures given in Part 60 Appendix B §16.0. However, the procedures do not apply if the CEM system is used to determine continuous compliance with the applicable standard.

The procedures consist of (i) conducting a complete CEM systems status check and (ii) challenging each pollutant monitor (and its associated diluent) monitor with NIST traceable protocol gases or certified calibration cells. Here, the relative accuracy is defined as

(11-32)upper R upper A Subscript upper A l t Baseline equals StartAbsoluteValue StartFraction d overbar Over upper A upper C EndFraction times 100 EndAbsoluteValue less-than-or-equal-to 15 percent-sign

where

RAAlt = Alternative Relative Accuracy

d overbar = mean difference between protocol gas (or gas cell) value and analyzer response

AC = known concentration of cylinder gas or calibration cell

For O₂ or CO₂ diluent gases, the specification is RAAlt ≤ 0.7% O₂ or CO₂.

The alternate procedure is quite forgiving and is, for comparison, much less stringent than the Part 75 calibration error test specification of ≤5%. It should be understood that this alternative procedure is not an independent testing procedure since the same monitoring system is making the measurement, albeit with different standard gases. This lack of independence may fail to uncover system or analyzer problems that affect the actual accuracy of the monitoring system.

The Relative Accuracy Test Report

After the tests have been successfully completed, the test report is prepared. The test report documents the tests performed on the CEM system and presents the test results. The results of the calibration drift test may also be included in this report. The report should be well-organized, readable, and complete. All data, including raw data necessary to recalculate any of the reportable parameters, should be included in the report.

Performance specification 2 includes a minimum list of items that are to be reported. These are the following:

Results of calibration drift and relative accuracy tests

Data sheets

Calculations

Computer printouts of CEM system response

Cylinder gas/calibration cell concentrations and certifications

Some agencies have additional report requirements or require special formats and tables.

To prepare a thorough report, it is recommended here that the report include the following in addition:

Type of CEM system (cool-dry extractive, hot-wet extractive, dilution, in-situ, etc.)

Type of source test system (6C, 7E, cool-dry extractive, hot-wet, manual, etc.)

CEM system analyzer manufacturer(s), analytical method(s), model(s), and serial number(s)

CEM system analyzer range(s)

Source tester system analyzer manufacturer(s), analytical method(s), model(s), and serial number(s)

Source tester system analyzer range(s)

Formulas and constants used in all calculations

An auditor should be able to assess how the test was conducted and replicate the test results given in the report summary from the raw test data.

Some source testing companies provide detailed reports written specifically for the test conducted. Others rely on “boiler-plate” wording, forms, and discussions. A schematic of a generic sampling system and list of equipment owned by the testing company do not constitute a description of the equipment used for the test. Unfortunately, sometimes calculation and computer errors occur, and the flexibility in rounding data is of particular concern.

For the costs associated with source testing, inadequate test reports should be returned as unacceptable. This, of course, requires the plant engineering or supervisory personnel to read past the executive summary report and conduct a thorough review.

Causes for Failure of a Relative Accuracy Test

For a new CEM system, the relative accuracy test, more often than not, represents the culmination of a year of planning: from understanding the impact of a new CEM requirement, selecting a system, purchasing the system, coordinating with the system integrator, installing the system, and resolving the IT issues to finally, determining whether it is operational. It is expected that with all this work, the monitoring system should meet the CEM performance specifications and easily pass the relative accuracy test. If, however, the test fails, the failure can represent a major problem.

Often, when conducting a relative accuracy test, particularly for a new and unfamiliar system, the relative accuracy test may be a big event. Representatives from the state or federal agency, the system integrator or analyzer vendor, or various consultants may be observing the test along with plant personnel. When failure occurs, the problem has to be found and must be resolved quickly. Unfortunately, a failed test often does not raise the question what the problem is, but who is to blame – is the problem due to the monitoring system or the source testers? If the system vendor is already on-site, a frantic search will begin for any system or analyzer problems, while the source test data will be examined in detail.

Possible problems associated with the monitoring system may be:

improper/inadequate system design

malfunctioning equipment

flue gas location/stratification problems

interferences by other flue gases

incorrect calibration gas values

improper calibration methods, failure to calibrate

uncorrected ambient or source effects (T, P, % H₂O)

DAS problems (incorrectly programmed equations, incorrect input parameter, incorrect timing/averaging)

The seven-day calibration drift test should have been conducted prior to RATA and many of the above issues should have been already addressed. If a monitoring system fails a seven-day drift test, it is not ready for the relative accuracy test and the source test should be rescheduled after the cause for the drift failure has been identified. The system purchase and installation should have been scheduled to allow sufficient time for test and troubleshooting before an agency system operation deadline. Rushing to complete a system and conduct a relative accuracy test is not recommended.

On the other hand, a relative accuracy test failure may be due to the source tester's measurements. Possible problems associated with the source testers may be:

all of the previous issues associated with the installed system, but which may also be questioned with respect to the source tester's monitoring system

different measurement technology used than the installed CEM system

point measurements compared against an integrated path CEM system

differing response times (integrated versus instantaneous measurements)

improper or modified source testing procedures

leaks in sampling lines and/or equipment, inadequate or failed equipment

untrained, inexperienced source testers

coordination problems – failure to correlate CEM system and RM data (P, T, % H₂O) properly

incorrect calculation/round-off procedures

incorrect accounting for source tester system/analyzer bias

incorrect data due to fabrication, fatigue, or lack of attention

Source testers are sensitive to failure as much as their clients and prefer that the test passes. As a precaution, a few test runs may be performed before conducting the actual test. If it does not appear that the CEM system will pass the test after performing two or three runs, it may be recommended that the test be canceled and rescheduled. However, the legitimacy of this practice is questionable. If this practice is suggested, it should be included in the test protocol and subject to review by the regulatory agency.

Data from aborted tests should be reported, but often is not, unless the agency makes it clear that reporting aborted tests is required. In the EPA Part 75 program, the results of aborted test runs are required to be reported, and the CEM system is considered out-of-control as of the hour in which the test was discontinued due to a problem with the CEM system (U.S. EPA 2013a, b, 2014).

PART 75 PERFORMANCE REQUIREMENTS

With the passage of the Clean Air Act Amendments of 1990, an emissions trading program for resolving the problem of acid deposition was initiated in the United States. As discussed in Chapter 2, Part 75 was added to the U.S. Code of Federal Regulations to detail the procedures to be used in the program implementation. Because the fundamental basis of the program is to allow the trading of SO₂ and NOx allowances between affected facilities, all parties involved realized that the success of the program would depend upon the validity of the allowances. The situation is similar to using gold coins for currency – to resolve questions involving the true weight of a coin, balances were used to measure their weight in the past. In the acid rain program, CEM systems are, in the same sense, used as the “gold standard,” whose “weight” (the emission rate) backs the currency of the allowance.

Because costs of allowance trades were expected to be substantial, corporate executives expressed to the EPA that the monitoring data used to determine allowances should be as accurate as possible. As a result of such concerns, and other stakeholder input, new CEM performance and quality assurance procedures were developed, which transcended the earlier Part 60 requirements. These requirements are incorporated in Appendices A and B of the EPA 40 CFR 75 acid rain regulatory program (U.S. EPA 2020h,i).

The Part 75 Appendix A requirements were designed specifically for the Acid Rain and NOx Budget programs, where the net result was a complex rule that is more stringent than the requirements of Part 60, but was achievable by building on the experience and state-of-the-art equipment developed over 20 years since Part 60 was first written. Table 11-7 summarizes the Part 75 CEM system performance specifications.

PART 63.8 MONITORING REQUIREMENTS

The Part 63.8 monitoring requirements address continuous monitoring systems (CMS) generically, whether they are continuous parameter monitoring systems (CPMS), continuous emission monitoring systems (CEMS), or continuous opacity monitoring systems (COMS). The requirements are written from the point of view of CEM hardware installation and are sometimes difficult to interpret for a continuous parameter monitoring system, which can evolve to be basically a sensor management program. Nevertheless, a Part 63 CEM system (or CPMS) must meet the operation and maintenance requirements given in 40 CFR 63.8(c), paraphrased as follows:

The CMS must be installed such that emission (or parameter) measurements are representative. CEMS must be installed in locations according to the applicable performance specification.

TABLE 11-7 Part 75 CEM System Performance Specifications

U.S. Part 75 Specifications

Seven-Day Drift
One-Day Linearity*
Relative Accuracy**

SO₂ (ppm)
≤2.5% of span for each of seven days or ±5 ppm
≤5.0% of ref. gas or ±5 ppm
≤10.0% of RM or ±15 ppm if RM
<250 ppm

SO₂ (lb/mmBtu) (ng/J)
—
—
≤10.0% of RM or ±0.03 lb/mmBtu if RM < 250 ppm

SO₂ (lbs/hr, kg/hr)
—
—
—

NOx (ppm)
≤2.5% of span for each of seven days or ±5 ppm
≤5.0% of ref. gas or ±5 ppm
≤10.0% of RM or ±15 ppm if RM <250 ppm

NOx (lb/mmBtu)
(n/J)
—
—
≤10.0% of RM or ≤0.02 lb/mmBtu if RM <0.20 lb/mmBtu

O₂ or CO₂ (%)
≤2.5% of span for each of seven days or ±0.5% O₂ or CO₂
≤5.0% of ref. gas or ±0.5 % O₂ or CO₂
≤10.0% of RM or ±1.0% O₂ or CO₂

Flow
≤3.0% of span for each of seven days or ±0.01 in H₂O
—
≤10.0% of RM or ≤2.0 fps at three load levels

H₂O (%)
≤0.5% O₂ if O₂ monitors used for H₂O
—
≤10.0% of RM or ±1.5% O₂ or CO₂

* Part 75 certification specifications include the determination of the system linearity. This specification is not included in the Part 60 Appendix B certification procedures.

**  Part 75 has no specifications or limits for either analyzer bias or system bias; however, data must be corrected for negative bias.

The CMS shall be verified to be operational prior to or during the facility compliance (performance) test.

CEM systems shall check low- and high-level calibration drifts daily.

All of these requirements are basically the same as those for a CEM system required to be installed under a Part 60 or Part 75 program. A site-specific performance evaluation test is to be submitted to the Administrator at least 60 days prior to the required CMS performance evaluation (63.8[e] [3]).

ENVIRONMENT CANADA EPS/1/PG/7 CEM GUIDELINES

Canada extracted the salient features of the U.S. EPA Part 60 and Part 75 rules in addition to those of ISO to publish more straightforward CEM certification guidelines (Environment Canada 2005). This was done without losing any of the stringency of the rules from which it was developed (Williams and Jahnke 1994).

However, CEM system specifications differ in both major and minor ways between the Canadian and U.S. regulatory programs. The PG/7 Guidelines are generally consistent with the requirements of 40 CFR 75 and, in some ways, can lead to a more accurate representation of emissions for SO₂ and NOx emissions (see Jahnke 2007). Part 75 requirements were designed specifically for the Acid Rain and NOx Budget programs, but the net result is a complex rule that offers little flexibility in its application.

The specifications of the U.S. Part 75 and Canadian EPS1/PG/7 are given for comparison in Table 11-8. Note that Part 75 incorporates a linearity test that is performed only once, whereas in PG/7 it is calculated for seven days to determine “linearity drift.” Also, the concept of bias is applied differently in Part 75 than in PG/7 (and incidentally, in ISO), where Part 75 allows for bias corrections but PG/7 places a limit on the percent bias allowed. Further, the calculation of the relative accuracy in terms of the emissions standard in PG/7 is like that in Part 60 and differs from Part 75, where it is computed separately for concentration and flow monitors for emission standards expressed in kg/hr.

INTERNATIONAL APPROACHES TO CEM SYSTEM CERTIFICATION AND APPROVAL

International Standards Organization (ISO) Standards for Gas Monitoring Systems

The International Standards Organization (ISO) has prepared standards for SO₂, NOx, CO, CO₂, NH₃, and O₂ CEM systems. Standards for flow, particulate, and greenhouse gas monitoring systems have also been published. A list of ISO standards applicable to automated monitoring systems (AMS, as CEM systems are termed in ISO and Europe) is given in Table 11-9. As in the U.S. CEM performance specifications, the ISO standards reflect the philosophy that each CEM system, as installed, must meet a set of minimum performance criteria, regardless of the measurement technique used by the system analyzer.

TABLE 11-8 CEM System Certification Specifications – Comparison Between Part 75 and PG/7 Criteria

| U.S. Part 75 Specifications | PG/7 Specifications
Parameter | Seven-Day Drift | One-Day Linearity | Relative Accuracy | Seven-Day Linearity | Relative Accuracy | Bias*
SO₂ (ppm) | ≤2.5% of span for each of seven days or ±5 ppm | ≤5.0% of ref. gas or ±5 ppm | ≤10.0% of RM or ±15 ppm if RM <250 ppm | ≤2.0 and 2.5% of FS for each of seven days | ≤10.0% of RM or of FS if RM < 250 ppm | ≤2% of FS
SO₂ (ng/J) | — | — | ≤10.0% of RM or ±0.03 lb/mmBtu if RM <250 ppm | — | ≤10.0% of RM | ≤4% of RM
SO₂ (lbs/hr) | — | — | — | — | ≤10.0% | ≤4% of RM
NOx (ppm) | ≤2.5% of span for each of seven days or ±5 ppm | ≤5.0% of ref. gas or ±5 ppm | ≤10.0% of RM or ±15 ppm if RM <250 ppm | ≤2.0 and 2.5% of FS for each of seven days | ≤10.0% of RM or of FS if RM <250 ppm | ≤2% of FS
NOx (lb/mmBtu) (n/J) | — | — | ≤10.0% of RM or ≤0.02 lb/mmBtu if RM <0.20 lb/mmBtu | — | ≤10.0% of RM | ≤4% of RM
O₂ or CO₂ (%) | ≤2.5% of span for each of seven days or ±0.5% O₂ or CO₂ | ≤5.0% of ref. gas or ±0.5% O₂ or CO₂ | ≤10.0% of RM or ±1.0% O₂ or CO₂ | ≤2.0 and 2.5% of FS for each of seven days | ≤10.0% of RM | ≤2% of FS
Flow | ≤3.0% of span for each of seven days or ±0.01 in H₂O | — | ≤10.0% of RM or ≤ 2.0 fps at three load levels | ≤3.0% of reference value | ≤10.0% of RM or ±0.3 m/s for flow < 3 m/s | ≤2% of FS
H₂O (%) | ≤0.5% O₂ if O₂ monitors used for H₂O | — | ≤10.0% of RM or ±1.5% O₂ or CO₂ | — | — | —

* Part 75 has no specifications or limits for either analyzer bias or system bias; however, data must be corrected for negative bias.

The format of the original ISO SO₂ and NOx AMS standards (ISO 7935 and ISO 10849) differs from U.S. Performance Specification 2 (40 CFR 60 Appendix B) by incorporating (i) required standards and (ii) recommended standards and test procedures. The ISO standards also provide a discussion of CEM monitoring techniques and the physical-chemical principles of measurement of monitoring instrumentation. Since the standards are intended for use by all countries, some of which may not have an existing technical base in environmental monitoring, it is felt that descriptive information of this nature is useful.

ISO Performance Characteristics

The main performance characteristics (analogous to U.S. “performance specifications”) of the ISO AMS standards are given in Table 11-10. Automated monitoring systems that can demonstrate performance at, or better than, the levels specified in the table meet the ISO performance requirements.

ISO-recommended performance characteristics are given in Table 11-11. These specifications are not required to be met, but it is viewed that by meeting them, the system will have a better chance of meeting the requirements given in Table 11-10. Note that the zero drift and span drift specifications are only recommended in the ISO standards, in contrast to U.S. Part 60 and Part 75 specifications that require that CEM calibration drift or error meet the specification requirements.

ISO Test Procedures

The ISO Performance Characteristic (specification) test procedures exhibit two basic differences from the U.S. methods:

Several of the tests may be conducted in the laboratory.

Reference method testing is conducted over a period of “unattended operation,” typically seven days.

Reference method testing may be conducted by using either manual reference methods or an automated method that employs an analyzer that uses a measurement principle different than that of the installed analyzer.

TABLE 11-9 International Standard Organization (ISO) Standards

Standard No.
Standard
Date Published
Reference

ISO 7935
SO₂
1995
(ISO 1992)

ISO 10155
Mass concentration of particles
1995
(ISO 1995)

ISO 10396
Sampling for the automated determination
of gas concentrations
2007
(ISO 2007)

ISO 10849
NOx
1996
(ISO 1996)

ISO 12039
CO, CO₂, and O₂
2001
(ISO 2019)

ISO 14164
Volume flowrate of gas streams in ducts
1999
(ISO 1999)

ISO-14385-1
Greenhouse gases – Calibration of automated measuring systems
2014
(ISO 2014a)

ISO 14385-2
Greenhouse gases – Ongoing quality control
2014
(ISO 2014b)

EN-ISO 16911-1
EN-ISO 16911-2
Velocity and Volume flow in ducts –
Automated measuring systems
2013
(ISO 20113a)
(ISO 2013b)

ISO 17179
NH₃
2016
(ISO 2016)

TABLE 11-10 ISO Required Performance Characteristics

ISO required performance characteristics for SO₂ and NOx CEM systems (AMS)

Performance Characteristic
Numerical Value

Lower detection limit
≤2% of span

Interference rejection
≤ ±2% of span for SO₂
≤ ±4% of span for NOx

Response time
200 s

Integral performance, SA (Standard deviation of reference method test data)
≤ ±2.5% of span for SO₂
≤ ±5% of span for NOx

Implicit performance characteristics in test procedures

Synergistic interference effects
≤ ±20% between measured and calculated interference

Analyzer linearity
≤ ±2% from calibration curve

Bias check
∣d∣ − ∣cc∣ ≤ 2% of span

TABLE 11-11 ISO Recommended Performance Characteristics

ISO recommended performance characteristics for SO₂ and NOx CEM systems

Performance Characteristic
Numerical Value

Zero drift
≤ ±2% of span for SO₂ and NOx

Span drift
≤ ±2% of span for SO₂ and NOx

Temperature responsive zero drift
≤ ±4% of span for SO₂ and NOx

Temperature responsive span drift
≤ ±3% of span for SO₂
≤ ±4% of span for NOx

ISO Laboratory (or Installed System Test Procedures)

Tests that may be performed either in the laboratory or on the AMS installed at the site are conducted as follows.

Lower Detection Limit (Required Specification)

The test is to be conducted on the complete AMS as set up in the laboratory or at the site. The procedure involves injecting zero gas at the probe or as close as possible to the probe, a minimum of 30 times to obtain the readings. For in-situ path monitors, flow-through gas cells may be used. If the system is installed, the test is to be done as rapidly as possible to avoid effects of zero drift or temperature effects.

The lower detection limit is given by the following expression:

(11-33)x equals x Subscript o Baseline plus 2 s Subscript x o

where

xo = mean of the readings

sxo = standard deviation of the readings

This is basically a test of the noise level of the system at the zero value and any offsets at zero that are particular to the system.

Interference Rejection (Required Specification)

The interference rejection test is designed to determine the effects of other flue-gas constituents on the SO₂ or NOx measurements. The test is performed by injecting into the CEM system possible interfering gases at concentration values corresponding to their typical levels in the flue gas. The gas is to be injected, again, at the probe of the complete CEM system set up either in the laboratory or on-site. The interference is determined for each individual interfering gas. In addition, a mixture of the interfering gases must be made up and injected into the system to determine if there are possible synergistic effects between the gases that may affect the pollutant measurement.

Response Time (Required Specification)

The AMS response time is determined by injecting calibration gas at the probe of the complete system either installed at the site or assembled in the laboratory. The calibration gas is to have a value between 50 and 90% of full scale (in contrast to U.S. Part 75 requirements, where an 80–100% high-level gas is used).

Response time is the average time interval between injecting the gas and reaching 90% of the concentration value (as contrasted to 95% of full scale in Part 75). The required response time is less than 200 seconds for the system (in contrast to the Part 75 specification of 15 minutes). The Environment Canada EPS 1/PG/7 response time requirement is the same as that specified by ISO.

Analyzer Linearity (Required Specification – Given Implicitly in Test Procedures)

The AMS analyzers are to be checked for linearity. This may be done either in the laboratory or on the system as installed. Because nonlinearity is viewed by ISO as an effect due only to the analyzer and its principle of detection, the checks may be made by injecting calibration gases directly at the analyzer and not through the total CEM system.

In the test, five uniformly distributed gas concentrations (e.g. 20, 40, 60, 80, and 90% of full scale) are injected into the analyzer. A gas divider (dilution) device may be used in this test, rather than using individual cylinders for each concentration.

The analyzer is viewed as linear, if the deviation of a measured value from the linear relation is not greater than ±2%. If the relationship is found to be nonlinear, it is recommended that 10 points be used to establish a curve and that the curve then be used in determining the emission values. This procedure does not constitute a pass/fail test for the analyzer, but establishes a check on the analyzer linearity or nonlinearity. For either situation, the relationship determined may be programmed into the system.

Temperature-Responsive Zero and Span Instability (Recommended Specification)

This test can only be conducted in the laboratory by using a temperature-controlled chamber. The complete CEM system is placed in a climate chamber in which the temperature can be varied from 5° to 35 °C at 10 K intervals, or the permissible ambient temperature range given by the manufacturer of the equipment. The analyzer is initially zeroed and calibrated at the monitor calibration port. At temperatures of 5, 15, 25, and 35 °C, zero and span gases are injected and the system readings are noted. The differences of the readings from one temperature to the next higher or lower temperature point are calculated relative to full scale for zero drift and as a percent of the calibration gas value for span drift.

This test is the most relevant for in-situ analyzers, which are not normally contained within a temperature-controlled shelter. For extractive systems, the test may be impractical to perform if the extractive system, in addition to the analyzer is to be placed into a temperature chamber. In the United States, there are no temperature drift requirements, although they are included in Environment Canada specifications.

Zero and Span Drifts (Recommended Specification)

Zero and span drifts may be determined either in the laboratory on the total CEM system or the CEM system as installed at the site. This specification differs significantly from the U.S. specifications in that Performance Specification 2 and the Part 75 Rules, and Environment Canada CEM Guidelines, require the test to be conducted only on the system as installed at the site.

It is of interest that the ISO test is conducted over the period of “unattended operation,” typically seven days. During that period, zero and span gases are to be injected at the probe into the CEM system. No adjustments or corrections to the CEM system are to be made during this period (note that it is a period of “unattended operation”). The differences between zero and span readings between the first and last days of the period of unattended operation is used to determine the zero and span drifts.

ISO Field Test Procedures

The only ISO performance characteristic that is required to be determined on the CEM system installed at the site is the “integral performance characteristic,” sA, the standard deviation of the differences between data pairs (CEM – Reference Method). The ISO integral performance test (the ISO equivalent of the U.S. relative accuracy test) is performed over the period of unattended operation. During this period, a minimum of 10 reference method data sets are to be taken, although 30 are recommended. The test is not conducted in one day, but over the seven-day period.

Either manual reference methods or instrumental methods may be used in conducting the test. The instrumental methods, however, must use a measurement technique different than that of the installed AMS. Before each run, the zero and calibration is checked at the analyzer and also at the probe. AMS measurements are compared to the reference method values over the time period in which the reference measurements were taken.

The integral performance characteristic sA is calculated from the following expression:

(11-34)s Subscript upper A Baseline equals StartRoot s Subscript upper D Superscript 2 Baseline minus s Subscript upper M Superscript 2 Baseline EndRoot

where

sM = the precision of the reference method expressed as a standard deviation

sD = the standard deviation of the difference between data pairs, di, as given in Equation 11-21

The CEM system meets the specification if sA is less than 2.5% of span (range) for SO₂ CEM systems or less than 5.0% of span for NOx CEM systems (Table 11-8). Calculations are performed in units of milligrams per cubic meter as determined by the analyzer of the AMS. The calculation does not address accuracy criteria in terms of units of the standard (e.g. nanograms per joule or kilograms per hour) or any corrections for dilution performed with the use of O₂ or CO₂ analyzers.

Note that the integral performance characteristic, sA, is referenced with respect to the span value of the analyzer and not the reference method value, as is done in the United States and Canada. This method corresponds with the practice of instrumentation engineers, who refer to matters of precision with respect to the measuring range. This is practical in the sense that the type of analyzer one builds for measuring at high levels (concentrations) may be quite different from one required to measure at low levels. For example, a precision of ±5% for an analyzer with a range of 0–1000 ppm gives some uncertainty over ±50 ppm. If one wished to make precise measurements in the range of 0–10 ppm with this analyzer, there would clearly be a problem. On the other hand, a precision of ±5% on an analyzer designed to measure over a range of 0–10 ppm gives an uncertainty of ±0.5 ppm. The trick, of course, is being able to develop an analyzer that can measure at such a level of precision over a range of 0–10 ppm.

In contrast, the U.S. EPA relative accuracy performance specifications are expressed as a percentage of the reference method value, as we have seen earlier. Because the average pollutant concentration should lie within 40–70% of span, the U.S. specifications are implicitly related to the span value. Although the U.S. “relative accuracy” only has meaning at the “average” reference method value, this may not be a problem in a regulatory sense, because by definition, this is where the source should be operating. However, instrument engineers are not accustomed to thinking in this manner because the precision becomes a moving target, depending on the reference method value. An instrument engineer, instead, prefers to establish instrument characteristics with respect to fixed decades or preestablished ranges.

The European Union EN 14181 Standard for Automated Monitoring Systems

In Europe, automated monitoring systems are calibrated against standard reference methods (SRMs) and certified after meeting statistical correlation criteria for the linear regression functions. This is in contrast to the U.S. procedures, where, as we have seen, CEM systems are calibrated against certified gases traceable to NIST and are certified at one point over their range, using the relative accuracy expression. For pollutant and diluents gases, this test is generally conducted at the normal operating level of the emissions source. The U.S performance specification procedures have not been considered as an approach for certifying automated monitoring systems in Europe. Instead, the EU Comité Europeén de Normalisation (CEN) has published standardized procedures for AMS type approval, calibration, and quality assurance standards derived from the German DIN (Deutsches Institut fur Normung) specifications given in a series of emission standards documents published by the VDI (Verein Deutscher Engenieure) in the 1970s. The procedures are given in the CEN standard EN 14181 (CEN 2014), which serves as the fundamental EU standard for automated monitoring systems.

The EN 14181 standard consist of three different levels, QAL1, QAL2, and QAL3:

QAL1 – CEM System Fitness for Use: An evaluation program that demonstrates whether a CEM is suitable for use in the intended application, following procedures given in EN 15267 (CEN 2009). The program consists of both laboratory and field demonstrations of CEM systems types (analyzer plus gas delivery system).

QAL2 – Calibration and Uncertainty Verification: A set of procedures used to calibrate the CEM system against the source tester's reference test method (i.e. the EU Standard Reference Method). QAL2 includes statistical procedures used to verify whether the CEM system will measure emissions at the emission limit value (ELV) to within the uncertainty specified by European Directives issued for affected facilities through directives such as the industrial emissions directive (EU 2010).

QAL3 – Continuing Operation: Procedures focused on the use of calibration error (drift) quality control charts to assess ongoing performance of the CEM system. As part of QAL3, an annual surveillance test (AST) is required. The AST is an abbreviated form of the procedures used to calibrate the CEM system conducted to assure that the system continues to operate within the specified uncertainty limits.

There are minimal design specifications for U.S. CEM systems, with adherence to most performance specifications being determined after the system is installed and operating on the stack for which it will be monitoring. In contrast, in Europe, automated monitoring systems must meet the three sets of “quality assurance levels” (QAL) given in the standard EN 14181 known as: (i) QAL1 – suitability, (ii) QAL2 – calibration and verification, and (iii) QAL3 – continuing operation. An annual surveillance test is also included in the standard.

QAL1: CEM System Fitness for Use

The QAL1 procedures are to determine “fitness for use” and are similar to those of the “type approval” procedures conducted by the Technischer Überwachungsverein (TÜV) (VDI 2007) in Germany or MCERTS (Environment Agency 2021; Tipping et al. 1998) in the UK. Analyzers are tested in conjunction with a sampling system. Instrument models and sampling systems are submitted to the test laboratory for evaluation by the manufacturer, who must pay for the service.

To demonstrate compliance with QAL1, the uncertainty of the measurement must be compared with the uncertainty value established by EU or national legislation. The uncertainty is calculated simply in the traditional manner by taking the square root of the sum of the variances associated with the operational characteristics of the system. Also, two systems are tested side by side in the field. An AMS that is successful in meeting the requirements receive a type certification, which is published. CEM systems are evaluated for the factors given in Table 11-12.

The actual monitoring systems that will be installed and used on the stack do not undergo this testing. It is assumed that the monitoring systems installed will be constructed in a manner similar to those that have been approved through QAL1. Also, if problems occur in the installation, it may not be a simple matter to modify an extractive system and assume that it conforms to the type originally tested and certified, or to show that it does not degrade performance below the QAL1 requirements.

Type testing in the manner of EN 15267 is not required in the United States, except for opacity monitors, where opacity monitors must meet the design requirements of ASTM D6216 (see Chapter 8). D6216 requires that at least one analyzer out of each month's production be tested to verify that it meets the design specifications (ASTM 2020c). Testing, however, is done by the opacity monitor manufacturer and not an independent laboratory. A voluntary program for the evaluation of environmental technology was managed by Battelle laboratories in collaboration with the U.S. EPA Office of Research and Development to perform type testing (Hill and Harten 2002), but did not serve to provide accreditation for those systems evaluated. The Environmental Technology Verification (ETV) program did result in the publication of many studies on ammonia, dioxin/furan, mercury monitors, as well as portable monitors, but was discontinued in 2014.

TABLE 11-12 Type-Testing Criteria

Laboratory Tests
Field Tests (With Two Systems)

Voltage variation

Vibration

Ambient temperature

Ambient water vapor

Sample gas temperature and pressure

Response time

Linearity

Interference rejection (individual and combined)

Detection limit

Sample flow rate

Accuracy (against an SRM)

Integral performance characteristic

Field repeatability

Zero drift

Span drift

Availability

Maintenance Interval

For gas monitoring systems, in lieu of procedures to evaluate instrument design parameters, the U.S. approach depends upon market forces and the rigor of the Performance Specification Tests. Basically, if an analyzer has stability problems because of vibration, voltage fluctuations, temperature variations, etc., it will not last long in the commercial market. The networks of instrument engineers and technicians working in the electric utilities, cement companies, paper companies, and petroleum refineries tend to reach consensus on specific types of monitoring systems, analyzers, data acquisition systems, and on the most competent system integrators for their own industry. To choose instruments or systems outside of this consensus network creates a risk that career-minded individuals might not wish to take. Although an MCERTS or TÜV certification may help to sway a consensus in the direction of a manufacturer's technology in Europe, such certifications have been regarded as irrelevant in the United States. The question that is asked in the United States is whether or not a CEM system can consistently achieve a relative accuracy of 10% or less, with minimal drift, low maintenance, and high availability.

The expense of such programs is borne by the instrument manufacturer. If an instrument company does not wish to incur the expense of accreditation, it is effectively barred from selling in the country where the accreditation is required. Unless an analyzer or system manufacturer intends to compete in the European market, applying for an EN 15267 type certification may not be worthwhile.

Although accreditation requirements such as EN 15267 may lead to improvements in instrument quality, they can also inhibit innovation and lead to de facto trade barriers. If each new design must undergo accreditation, a manufacturer may wish to gain the maximum life out of an approved system before making improvements. Established instrument companies are not eager to update approved instruments if the improvements will require recertification.

QAL2: Calibration and Uncertainty Verification

In the EN 14181 standard, an AMS is calibrated using a standard reference method to obtain a “calibration function.”QAL2 of EN 14181 describes the test methods and statistics for obtaining the calibration function and verifying the system. The procedures are similar to those used in the United States for calibrating continuous particulate monitors under Performance Specification 11 (see Chapter 9). It is also applied implicitly in the United States in Part 75 procedures for flow monitors. In Part 75, “K” factor(s) are established at low, middle, and high loads by correlating flow monitor data to EPA flow reference test data (see Chapter 7).

Assuming the calibration function is correct, its variability is assessed to validate whether the CEM system measures emissions within the uncertainty limits specified by the EC Directives. The EN 14181 standard and specifications are particularly heavy on statistical procedures, some of which are particularly opaque, such as the variability test. The following are addressed in QAL2.

The Calibration Function

In the European Union, the calibration function is determined by a source testing company (test laboratory) that has achieved and maintains accreditation for operating standard reference methods. A minimum of 15 simultaneous runs are conducted between the CEM system and the standard reference methods. The standard reference method equipment used should have specifications at levels equivalent to or better than the installed monitoring system.

The calibration function is derived from the test data and is assumed to be linear, as expressed in Equation 11-21.

(11-35)y Subscript i Baseline equals alpha plus beta x Subscript i

where

xi = the AMS data from the ith run

yi = the standard reference method data from the ith run

α = the intercept of the calibration line

β = the slope of the calibration line obtained by the linear least squares method

The determination of the EN 14181 calibration function is similar to the determination of the emissions model of a predictive emissions monitoring system (PEMS). Here, the model is a linear equation, which, in the future, is used to calculate (“predict”) emissions. It should be remembered that the equation is developed from past data, in the same manner as a PEMS model is developed. As long as the operating conditions are the same as those under which a model or calibration function was constructed, the model or function should be valid. However, if the operating conditions change, the equation or model may no longer provide accurate data.

The slope, β, of Equation 11-21 is obtained by regression analysis, using the linear least squares method. Uncertainties resulting from the variability of the source, the sampling method, stratification issues, interference effects, solubility losses, adsorptive losses, and pressure and temperature effects are reflected in both the AMS and standard reference method data. The calibration function is generated with the assumption that the standard reference method data represent “true values.”

The Variability Test

For the QAL2-determined calibration function to be acceptable, the standard deviation of the paired differences, obtained during each of the 15 simultaneous stack test runs, must be less than the uncertainty of the AMS system at the emission limit value (ELV). The ELV is the maximum emission level of a pollutant allowed to be emitted from a regulated source. It is determined by the regulatory authorities and may be different for different types of sources and may vary between regulatory jurisdictions. The variability is acceptable, if

(11-36)sigma Subscript upper D Baseline less-than-or-equal-to sigma Subscript normal o Baseline k Subscript v

where

σD = the standard deviation of difference between the measured SRM and AMS values obtained from the calibration function

p is a percentage, typically 10–30% of the ELV at the 95% confidence level. The percentage p may be equal to 0.20, 0.30, or other, depending upon the affected source category.

kv = StartRoot StartFraction chi squared left-parenthesis upper N minus 1 comma gamma right-parenthesis Over n minus 1 EndFraction EndRoot, the χ² test value at the 95% confidence level with a β-value of 50% (i.e. where the χ² distribution is evaluated at a probability of γ = 0.5 and n − 1 degrees of freedom)

In the method, difference values, Di, for each data set are determined:

(11-37)equation

where

Di = the difference between the standard reference method (SRM) values for data set i and the AMS values determined from the QAL2 calibration curve for data set i

yi = standard reference method (SRM) values for data set i

ŷi = AMS values determined from the QAL2 calibration curve for data set i

The variability of the differences, the standard deviation σD, is then calculated:

(11-38)

The test calculates the value of the standard deviation, σD, at which the true value of AMS uncertainty has a 50% probability of exceeding the required standard uncertainty, σo. Values for kv are tabulated in Section 6.2 of EN 14181, ranging from 0.9761 at 15 parallel measurements to 0.9885 when 30 parallel measurements are conducted.

Here, the criteria for the acceptance of the calibration function are referenced to the uncertainty about the ELV. The acceptance criteria are therefore dependent upon the ELV, which may be different for different plants or may differ between different states or countries. The expression for σo appears more as a regulatory construct (e.g. as “10–30% of the limit value”) similar to U.S. EPA relative accuracy specifications of 10 or 20%.

In QAL2, the variability criteria are referenced to the uncertainty about the emission limit value (ELV). Special considerations must be made for monitored parameters that do not typically have emission limit values, such as CO₂, O2, and flow. Default values, such as 21% (for O₂ monitors) could be used in these cases.

If systematic errors are present between an AMS and the standard reference method, they can be factored into the EN 14181 calibration function, allowing the system to still be certified. Biases could affect accuracy, but not necessarily the variability. That is, if the standard reference method is not truly representative, the variability test could be passed, but the data could still be biased.

In contrast to QAL2, in the U.S. EPA and ISO procedures, a calibration function is preprogrammed into the analyzer and the system calibration is checked daily using zero and span gases. If a system is within the specifications of the standards and bias is not indicated, the CEM system can run under its own calibration function. If a bias were found from the relative accuracy and bias test procedures, either the cause of the bias would have to be determined and removed or a calibration function similar to that of EN 14181, or a bias adjustment factor (BAF), may have to be applied, as discussed earlier.

It should be noted that, in EN 14181, if the emissions are <30% of the ELV and the scatter of data points indicates that it is not possible to derive a valid calibration function, the CEM may be calibrated using reference materials (gases).

The robustness of the correlation depends upon the spread of the data, and although EN 14181 caveats against establishing linear regression functions over a limited range of operation, it is often difficult for a source to vary its emissions over the range required. One way to minimize the effect of such offsets is to tie the data to zero. Because most analyzers will measure zero when no pollutant gas is present (unless a fixed offset, typically 20 ma, is used to allow the measurement of negative drift), it is possible to regard the zero point as a fixed point and force the regression line through zero. When this is done, it has been found that emissions data from a monitoring system calibrated using a QAL2 regression equation will correspond well with data obtained from a monitoring system calibrated merely with calibration gases, if the data are corrected for bias (either positive or negative) (Jahnke 2011).

QAL3: Ongoing Quality Assurance

Procedures given in QAL3 of EN 14181 are focused on the use of calibration error (drift) quality control charts to assess the ongoing performance of an AMS. An abbreviated form of the procedures used to calibrate the AMS, the AST (Annual Surveillance Test), is performed annually to assure that the system continues to operate within the specified uncertainty limits. QAL3 requires the following:

Periodic verification of zero and span

Control charting of zero and span verifications

Annual Surveillance Test (AST)

The principal procedure used to check the operation of an AMS is the control charting of the zero and span drift (calibration error), using either Shewart or Cusum charts. The AST is conducted annually to assess whether the calibration function remains valid. The AST is an abbreviated version of the QAL2 procedures, where the testing is conducted in a day and at least five sets of data are extracted over any 8–10 hour period within the day. A variability test is conducted, where the variability is calculated in a similar manner as in QAL2, where the variability requirement is that:

(11-39)sigma Subscript upper D Baseline less-than-or-equal-to 1.5 sigma Subscript o Baseline k Subscript v

This is in contrast to the QAL2 verification criteria that σD ≤ σokv.

An additional test for bias is conducted, which must also be passed, indicating that systematic error is present if:

(11-40)StartAbsoluteValue upper D overbar EndAbsoluteValue greater-than-or-equal-to StartFraction t 0.95 upper S Subscript d Baseline Over StartRoot n EndRoot EndFraction plus sigma 0

where t0.95 is the student t test value at the 95% confidence level for n − 1 degrees of freedom.

This expression accounts for both positive and negative bias and incorporates the uncertainty of performing the verification test (first term) and the uncertainty of the measurement at the emission limit value. This is similar to the Environment Canada and Part 75 bias tests.

The EN 14181 QAL3 AST procedures allow a 50% variation in the calibration curve from the original QAL2. The AST is an abbreviated version of the original QAL2 and greater flexibility is accorded in the verification procedure. In contrast, the U.S. Part 75 relative accuracy criteria are the same for the original system certification and ongoing RATAs. For the ongoing performance of an AMS, this relaxation of the EN standards in QAL3 could potentially result in emissions data having greater uncertainty after passing an AST than when it was originally certified.

DEVELOPING CEM CERTIFICATION PROCEDURES AND STANDARDS

CEM certification procedures have been extended to a wider range of emission monitoring equipment than SO₂, NOx, and diluent monitors. Although SO₂ and NOx tend to be the first to be addressed in the development of national standards, as experience is gained in their application, the original SO₂ and NOx certification procedures are usually modified, as appropriate, when applied to other pollutant monitoring systems. The U.S. EPA has published 15 performance specifications; the specifications for mercury monitoring systems and HCl monitoring systems being among the most recent. ISO and CEN are similarly extending standards to a wider range of pollutants and monitoring instrumentation.

International approaches to CEM system approval or certification vary between countries. Countries without their own procedures tend to use methods established either by the U. S. EPA or by CEN. Several countries in Latin America and Asia have applied the U.S. Part 75 Performance Specification Test procedures, whereas others have applied those of CEN. If there is a lack of national CEM certification requirements, the system vendor will usually use the procedures from their country of origin. As a result, in some countries, continuous monitoring systems are certified using the EN 14181 standard and in others, Part 60 or Part 75 specifications.

One of the reasons for giving perhaps too detailed discussions of the mathematical approaches to calculating “relative accuracy” (EPA), the “integral performance parameter” (ISO), and the “calibration function” (CEN) in this chapter is to provide the reader with an understanding of what will be involved when choosing one procedure over another. The work of Cipriano et al. (2002) has shown that CEM systems can meet the requirements of EN 14181, but yet fail the relative accuracy criteria of EPA Performance Specification 2. However, it has also been shown that a monitoring system can meet the requirements of EPA Part 75, but fail those of EN 14181 (Jahnke 2011). Any country wishing to adopt one or the other methods should consider carefully the expense associated with conducting the certification procedures relative to the degree of precision and accuracy necessary to implement a successful national source emission monitoring program.

Standards development is generally a lengthy process in both national and international forums. Competing interests between national regulatory agencies, the CEM system users, instrument manufacturers, and the standards setting bodies (who may be different from the regulatory agency) often result in protracted negotiations before a consensus is reached. Both regulatory policy and technical issues become intertwined in standards development, which can result in standards and certification methods that are either overly complicated or internally inconsistent. Requirements for a periodic review of the procedures can help to apply lessons learned in initial applications.

Stakeholders on all sides of this process have become more experienced with monitoring systems and more sophisticated in their use. A greater understanding of the implications of performance specifications has led to increased flexibility in some cases, but in others, increased stringency. Although in some cases performance specifications have been forcing technology, commercial instrumentation must, in the end, be able to meet them. In the case of both mercury and HCl monitoring systems, the interplay of technological feasibility and regulation took many years of monitoring system development, field testing, and evaluation before consensus was reached in publishing achievable performance standards.

Although there may be many routes to CEM system certification, the end result is to provide confidence that a CEM system can provide results that are representative of the “true” emissions value. It may not be possible in all cases to achieve the accuracies that might be preferred for emission measurements, particularly at low emissions levels; but through the application of sound performance evaluation procedures, it is possible to obtain some estimate of the uncertainty of the measurements. As instrumentation and test methods have improved and matured, that uncertainty has correspondingly decreased.

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Gemmill, R. and Woodfield, M. (1998). Implications of International Standards (BSI, CEN, ISO) for regulatory monitoring of emissions. In: proceedings – CEM98 – International Conference on Emissions Monitoring, 7–16. London: IEA Coal Research.

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Note

1 Note: The symbols and terminology used in dynamic spiking have not been standardized between the various standards and performance specifications in which the technique is used. For example, in ASTM D6348, cmeasured is given the symbol “Sa”; in Performance Specification 18, it is termed “SAR,” Sm in PS 15, and CSS in EPA test method 7E.

CHAPTER 12
MONITORING FOR MERCURY

Monitoring mercury emissions from coal‐fired power plants, cement plants, and other industrial sources presents challenges that go far beyond those associated with measuring criteria gases such as SO₂ and NOx. In flue gas emissions, mercury can be found as atomic mercury in the form of a vapor (Hgo), as a compound in an oxidized form (Hg⁺²) such as HgO or HgCl₂, or in a particle, bound to fly ash or other particulate matter. Without applying proper techniques, both atomic and oxidized forms are difficult to transport through monitoring systems. Although the analysis of atomic mercury in the vapor form is relatively easy, calibration techniques can be problematical, requiring solutions that go beyond utilizing the traditional calibration gas cylinder. Despite of these challenges, accurate and reliable continuous mercury monitoring (CMM) systems capable of measuring at levels of a few tenths of a microgram per cubic meter (μg/m³ or parts per trillion) were developed within a relatively short period of 2000–2010.

MERCURY ISSUES

The United Nations Environment Program (UNEP) provides periodic assessments of global emissions (UNEP 2008, 2013). Mercury is emitted into the atmosphere from human (anthropogenic) activities and geological sources such as volcanoes and mineral surface exposures; anthropogenic activities accounting for approximately 2000 tonnes/year, and natural sources and remission both contributing emissions of several thousand tons per year (Pirrone et al. 2010; UNEP 2013). Approximately 30% of the annual mercury emissions are anthropogenic. A large percentage of the mercury present in the atmosphere is due to the reemission of mercury previously deposited in soils and oceans (approximately 60%) (UNEP 2013).

After elemental mercury is released into the atmosphere, it can circulate as a global pollutant from 7 to 15 months. However, through various absorptive and chemical processes depending upon atmospheric conditions, mercury can deposit locally and regionally in shorter time periods (Street et al. 2019). Although approximately 30% of the mercury in the United States has circulated from outside the United States, deposition rates tend to be higher near local emission sources.

Once deposited in the soil, mercury can be converted to methyl mercury and other compounds, which make their way into vegetation and the food chain. Mercury is bioaccumulative and there are few permanent sinks for its natural disposal. It is only when that soil is subsumed deeper into the earth or seabeds that the mercury is removed from circulation.

The toxic effects of mercury and its compounds are well known. Mercury and its compounds can have significant health impacts in developing children, causing mental retardation, cerebral palsy, and sensory and motor impairment. The accumulation of methyl mercury in fish has been shown to lead to higher mercury levels in populations dependent on fish, shellfish, or marine mammals for their subsistence. Chronic low‐dose exposure to methyl mercury can have significant health effects and is one of the prime reasons for the institution of regulatory controls for mercury emissions. As a result of these controls, mercury emissions from power plants and other sources, such as municipal waste combustors, have led to the reduction of mercury in soil, fish, and other animals (Zhang and Jaegle 2013). This was demonstrated in Florida, where state mercury regulations instituted in the 1990s led to lower levels of methyl mercury in fish populations within a period of five years.

The U.S. EPA has since expanded mercury regulations to coal‐fired power plants and cement plants. The 1990 Clean Air Act Amendments called for the regulation of toxic substances and became the driver for mercury control, although through a somewhat torturous route. As discussed, the effectiveness of pollutant emission controls can best be determined by measuring the emissions after the controls are in place. Accordingly, mercury reference test methods and CMM system performance specifications developed along with the mercury rules.

MERCURY REGULATIONS

This section is a narrative on a period of instrument development, where within 15 years the CEM industry was able to design Hg CEM systems that could measure concentration levels which were at first thought unachievable. With the knowledge and techniques gained in the previous acid rain program, and being spurred by regulation, the resources of instrument manufacturers and systems integrators were applied to this task. As a result, the challenge of monitoring mercury at part per trillion levels was met in a relatively short period of time.

Hg CEM systems were first installed in Germany in the 1980s to measure emissions from municipal waste combustors (Jockel 1996). At that time, the emission limit was set at 50 μg/m³ and analyzers were developed to monitor at that level. In the United States, hazardous air pollutants (HAPs) were originally addressed in the Clean Air Act of 1970. However, in the NESHAPS program established for HAPs, no requirements were established for mercury under the original act. Congress gave more specificity to the program in the 1990 Clean Air Act Amendments in §112, requiring that 188 hazardous air pollutants emitted from major sources be regulated by EPA. Mercury was listed as one of these pollutants. Consequently, the U.S. EPA did not begin drafting mercury regulations until after 1990. After a relatively long and convoluted process, “final rules” for mercury monitoring were promulgated over 20 years later. This was due in part to the involvement of multiple stakeholders in the rulemaking process, which included environmental groups, industry, and state agencies, as well as the federal government. Questions associated with performance standards and calibration procedures as well as litigation and policy changes contributed to the length of time necessary to finalize mercury rules for coal‐ and oil‐fired electric generating units and cement plants.

Coal‐Fired Electric Generating Units

A special subsection of the Clean Air Act Amendments [§112(n)(1)] required EPA to study the effects of mercury emissions from coal‐fired electric generating unit (EGUs) and provide a report to Congress. The reports generated (U.S. EPA 1997, 1998) provided the basis for an EPA ruling on 20 December 2000, that §112 of the Clean Air Act was “necessary and appropriate” for regulating mercury emissions from electric generating units.

In 2005 (U.S. EPA 2005), EPA claimed that it erred in its “finding” that mercury emissions should be regulated under §112, where EPA viewed that it was neither “appropriate” nor “necessary” to regulate the pollutant under §112 of the Act. The EPA considered that mercury regulation was “inappropriate” under §112 because, with the imposition of other parts of the Act, such as the NOx Budget program and the Clean Air Interstate Rule, mercury emissions would be reduced also, and that the remaining emissions “would not cause a hazard to public health.” Regulation under §112 was also viewed as “unnecessary” because other regulatory means could be employed for the control of mercury emissions from coal‐fired power plants. This reversal was significant because EPA chose to implement under §111 of the Clean Air Act, a trading program, similar to the acid rain trading program, to reduce mercury emissions. The resultant Clean Air Mercury Rule (CAMR) was familiar to the electric utilities who would rely on CMM systems to keep track of allowances and facilitate trades the same way as in the acid rain program.

Because mercury emissions from U.S. coal‐fired power plants were on the order of 5 μg/m³ for uncontrolled sources and < 1 μg/m³ for controlled sources, obtaining accurate emissions became a concern when it was realized that mercury monitoring systems developed in Europe for measuring mercury at a level of 50 μg/m³ would not be suitable to support a trading program. This was borne out in numerous field studies, where vendors competed to demonstrate the adequacy of their systems. Consequently, extensive mercury monitoring research and evaluation programs by the electric utilities, instrument vendors, contractors, and EPA were initiated to develop monitoring systems that would be accurate enough to assure confidence in allowance trades.

It was expected that CAMR would be a program as successful as the acid rain program, and with the deadline of 31 December 2009 for the installation of mercury monitoring systems approaching, several instrument manufacturers and system integrators by and large achieved their goals in developing systems that could read at levels of a 10th of a microgram. However, on 8 February 2008, the U.S. District of Columbia Court of Appeals ruled that EPA violated the Clean Air Act and overturned the Clean Air Mercury Rule. Over 650 systems and over 100 sorbent trap systems had already been purchased by 2008. At that time, less than 50% of the continuous monitoring systems were installed and less than 25% of the sorbent trap systems were installed. Less than 3% were certified (Offen 2008). The ruling left the systems in limbo, with some utilities choosing to operate them to gain experience and others putting them in storage until EPA decided on a new approach. Although there was short‐term uncertainty, the industry viewed that in the long term, CMM system performance requirements would be relatively unchanged.

The court ruled that essentially, no matter how the words “appropriate” and “necessary” are parsed, §112 of the Clean Air Act requires that coal‐fired power plants must be regulated for toxic materials, including mercury, under §112, the air toxics rule, and not under any other part of the Act. The electric utility industry Utility Air Regulatory Group requested the U.S. supreme court to reconsider the ruling; however, on 23 February 2009, the court announced that it would not review the earlier decision to overturn the Clean Air Mercury Rule. As a result of these rulings, the coal‐fired electric utilities were required to meet the more stringent requirements of §112, for applying “maximum achievable control technology,” the EGU “MACT” rule (see Chapter 13).

Although this regulatory maneuvering did delay the regulation of mercury emissions from coal‐fired power plants, it allowed time to resolve technical issues in both emissions monitoring and control. Because of the CAMR program, the anticipated correlation of emissions and allowance prices created incentives to assure the effectiveness of the monitoring systems in accounting for mercury reductions. As a result, numerous research and field demonstration programs were conducted to develop and optimize mercury monitoring methods for coal‐fired power plant applications. An instrumental test method for mercury (Method 30A) and a carbon trap reference method (Method 30B) were promulgated previously on 7 September 2007 to provide alternatives to the manual wet chemical Test Method 29 (U.S. EPA 2020a) and ASTM D6784 (Ontario Hydro Method)(ASTM 2020). In addition to this activity, performance specifications for the certification of continuous mercury monitoring and sorbent trap systems and quality assurance requirements were in active development during this period and were published on 9 September 2010. And in addition to all of the above, NIST traceable gas cylinders for mercury were not available, necessitating the use of elemental and oxidized mercury generators for system calibration. A protocol had to be developed for their use, which was published as the “Interim Protocol for Elemental and Oxidized Mercury Generators” in U.S. EPA (2009).

EPA was subsequently required to prepare standards for hazardous air pollutants consistent with §112 for coal‐ and oil‐fired EGUs by the end of 2011. The final standard, the “MATS rule,” was published on 16 February 2012. The rule established emission limits for hazardous air pollutants, as well as monitoring requirements for mercury. Mercury monitoring systems were now required to demonstrate compliance to the emission limits, rather than to serve as the basis for an allowance trading program. Either instrumental Hg CEM systems or the intermittent sorbent trap systems were allowed and were required to be installed and certified by the HAP compliance date of 15 April 2016.

TABLE 12‐1 Mercury Emission Limits for U.S. Coal‐Fired Electric Generating Units

| Existing Units | New Units
| lb/GWh | lb/TBtu | ≈μg/m³ | lb/GWh | ≈μg/m³
Non‐low‐rank coal | 0.013 | 1.2 | 1.4 | 0.003 | 0.3
Low‐rank coal | 0.04 | 4.0 | 4.7 | 0.04 | 4.2

The emission limits for mercury established in the MATS rule are summarized in Table 12‐1 of the MATS rule (U.S. EPA 2020j). Table 12‐1 lists several of these limits for coal‐fired electric generating units (U.S. EPA 2020j). The limits are an order of one to two magnitudes lower than those previously established in Europe, requiring measurements in terms of parts per trillion (1 μg/m³ ≈ 112 ppt).

With the application of the MATS rule, the retiring of coal‐fired power plants and the advent of natural gas and renewable energy sources, when compared to Hg emissions of 29 tons in 2010, Hg emissions, were reduced by 89% down to 3.2 tons in 2019 (U.S. EPA 2020k).

Cement Plants

For mercury, Portland cement plants in the United States are subject to the emission limitations of Subpart LLL of 40 CFR 63.1343 (U.S. EPA 2020i), summarized in Table 12‐2.

Mercury is found in the raw materials used in cement production (i.e. limestone, shale, and other feed materials), and also in coal or other fuels used in the precalciner and cement kiln. Cement plant process operations introduce several difficulties for emissions monitoring that does not occur in coal‐fired power plants. The mercury concentration in the raw materials can be highly variable depending upon the mercury content of the feed materials and/or coal or other fuels used in the process. In the contemporary process, materials are ground in the raw mill prior to their introduction into the kiln. Exhaust gas from the kiln is directed through the raw mill to preheat the raw mix, and dust captured in the air pollution control device is returned to the kiln feed. When sent back through the kiln, the dust adsorbs mercury vapors released in the mill and the mercury is recirculated through the process, accumulated and concentrated in the kiln feed, and is at some point exhausted from the stack. When the raw mill is off for a maintenance cycle, malfunctions, or the feed silo is full, the kiln gases bypass the raw mill and the accumulated mercury goes directly to the stack. As a result, emission concentrations can increase by two orders of magnitude during mill‐off operation. Mercury concentrations in a cement plant can range from 0.5 to 15 μg/m³ when the raw mill is on, and from 50 to 150 or as high as 300 μg/m³ when it is off (Peeler 2020). Plants that do not have in‐line raw mills are less variable. To monitor this variability in emissions, a continuous mercury monitoring system must be able to measure a sample over a range of two orders of magnitude. For some cases, special procedures for “above span calibrations” may be necessary. Quality assurance procedures for elevated Hg emissions are addressed in 40 CFR 63.1350(k)(2) Subpart LLL (U.S. EPA 2020i) and in EPA ALT 132 (U.S. EPA 2018).

TABLE 12‐2 Mercury Emission Limits for U.S. Cement Plants

Existing Cement Plant | New Cement Plant
55 lb./MMton clinker | 21 lb./MMton clinker

Municipal Waste Combustors and Incinerators

U.S. mercury rules for solid waste combustion are not regulated under the MACT rules directed under §112 of the Clean Air Act, but are addressed under §111 and 129 of the Act for both new and existing units. In addition, federal requirements, state initiatives for municipal waste combustors, medical waste incinerators, and hazardous waste incinerators in the 1990s led to mercury reductions by 90–97% by the year 2000 for these sources. Medical waste incinerators reduced emissions from 51 tons/year in 1990 to 1 ton in 2005/year, a 97% reduction. Municipal waste combustors reduced emissions from 57 tons/year in 1990 down to 2 tons/year in 2005; and hazardous waste combustors reduced emissions of 6.6 tons/year in 1990 essentially down to zero by the year 2000. These emission reductions were achieved primarily by limiting mercury in the feedstocks and using control techniques such as carbon injection.

Many states have required the installation of Hg CEM systems at municipal and hazardous waste incinerators through their operating permit programs. Mercury monitors are also allowed as an alternative to manual reference testing to show compliance as an option under the New Source Performance Standards, 40 CFR 60 Subpart Eb, for municipal waste combustors.

Canadian Mercury Regulations

In contrast to the U.S. requirements, in Canada, the Canadian Council of Ministers of the Environment (CCME) set Canada‐wide Standards (CWSs) for each province in the form of emission caps for coal‐fired electric power generation plants (CCME 2006). This required reductions of 60–70% from a 2002 to 2004 national baseline of 2695 kg/year to a national cap of 1130 kg/year in 2010. This goal was achieved in 2011, primarily through plant and unit closures (in Ontario and Alberta) and the application of emission controls (carbon injection in Saskatchewan). Emissions from coal‐fired plants were 630 kg/year in 2014 (CCME 2016). Emission limits were also established for new coal‐fired plants; however, it is not expected that new coal‐fired power plants will be constructed in Canada in the future.

Annual emissions were determined primarily through the use of mass balance calculations, manual source testing, and the application of Hg CEM systems. Mercury monitoring systems were installed in the plants in Alberta and Saskatchewan, which were required to follow the CCME Monitoring Protocol (CCME 2007).

Mercury emissions from all Canadian sources (smelter, power plants, and incinerators) have been reduced significantly since 2000 and are estimated to be now less than 6 tonnes/year. It is estimated that over 95% of the anthropogenic mercury deposited in Canada now comes from global circulation, with deposition in the arctic being particularly problematic (CCME 2016; ECCC 2016).

Mercury Emissions Outside of North America

Global emissions of mercury in 2015 were 2000 tonnes in 2015, with Europe contributing approximately 13% of the emissions, China 45%, and North America (Canada, the United States, and Mexico), approximately 8%. Coal combustion contributes to approximately 25% of these emissions, while artisanal and small‐scale gold (principally in Africa and South America) approximately 40%. Emissions limits for cement plants outside North America range from 20 to 100 μg/m³. The limit in the EU is 50 μg/m³ for coal‐fired power plants and cement plants, with the exception of Germany, were the standard of 30 μg/m³ daily average changes to 20 μg/m³ after 2018, with a yearly average of 10 μg/m³ set after 2019. A limit of 30 μg/m³ was set in China in 2014.

MERCURY MONITORING

The chemistry of mercury and its compounds is particularly complex in flue gases, where mercury is volatilized in the combustion process. The presence of gases such as Cl₂ and Br₂ and particulate matter, as unburned carbon, or fly ash, causes the oxidation of the elemental mercury. The reactions proceed with the formation of the chlorine and are kinetically controlled, rather than thermodynamically controlled. The most typical end products are mercuric chloride (HgCl₂) and mercuric oxide (HgO). In a simplified view, the reaction with chlorine results as follows:

The reactions of mercury with flue gas constituents have been studied extensively for both coal‐fired power plants and cement kilns. Understanding the reaction kinetics of mercury has been important in the design of mercury control technologies. Through this understanding, it has been possible to reduce mercury emissions through the co‐benefit effects of air pollution equipment applied for the control of criteria pollutants SO₂ and NOx. It has also enabled the optimization of active mercury controls, such as the use of activated carbon and other materials for mercury removal. Since the ionic form is soluble in water, much of this work has focused on how to maximize the removal of mercury in wet scrubbers.

For source monitoring, the complexity of mercury flue gas reactions is not as important as it is for the design and optimization of control technologies. What is important for source monitoring is designing either a test method or monitoring system that can account for all of the mercury present in a sample. Techniques are available to analyze for either one or a combination of the following:

Hgo | Gas‐Phase Elemental Mercury
Hg²⁺ | Oxidized Mercury (Gas‐Phase Ionic – HgCl₂, HgO)
Hg(p) | Particle Bound
TGM | Total Gaseous Mercury (Hgo + Hg²⁺)
Total Mercury | [Hgo + Hg²⁺ + Hg(p)]

Whether a manual source testing technique or a continuous monitoring method, no analytical methods measure oxidized mercury directly. The mercury in mercuric chloride, mercuric oxide, or other mercury compounds is first reduced to its elemental form and measured as elemental mercury using spectroscopic methods.

Regulations typically require the measurement of either total gaseous mercury or total mercury. The measurement of total mercury requires isokinetic sampling for particulate matter but is not normally required for Hg CEM systems due to the added difficulty in collecting and analyzing mercury adsorbed onto particles.

Analytical Methods for Mercury Monitoring

The analytical methods employed in commercial mercury monitoring systems measure elemental mercury only. Because regulatory agencies require that total mercury (HgT) emissions be reported, the ionic species present in the flue gas sample must first be converted to something that is measurable, namely elemental mercury. Reducing ionic mercury to elemental mercury can be accomplished by either using liquid reducing agents or dry methods using thermal convertors and catalysts.

Liquid reducing agents such as stannous chloride (SnCl₂), ascorbic acid (C₆H₈O₆), and sodium borohydride (NaBH₄) were used primarily in the earlier European monitoring systems. In one method illustrated in Figure 12‐1, an isokinetically extracted, continuous sample is first heated in an infrared oven to volatilize particulate‐bound mercury and a sodium borohydride solution is used to reduce mercury compounds to elemental mercury.

In practice, however, monitoring liquid levels and replacing spent solutions are preventive maintenance tasks that most instrument technicians dislike. In addition, the chemicals may generate a hazardous waste and cause corrosion problems. As a result, CEM systems requiring the use of chemical solutions are not preferred in most industrial applications if other options are available.

Other options to reduce ionic elemental mercury species are to use thermal pyrolysis (thermal convertors) or catalytic convertors. Stainless steel or carbon‐based pyrolysis units have been used but can suffer from the recombination of elemental mercury with HCl and other acid gases in the gas stream (Schaedlich and Schneeberge 2008). Thermal catalysis converters are the most common, using materials such as copper or copper alloys, noble metals, iodated carbon, or silicon carbide (Schaedlich and Schneeberger 2008). The materials used are typically specific to the system manufacturer, and are often identified in applicable patents. Thermal convertors are most commonly used in commercial mercury monitoring systems, where most vendors have resolved the design and operation conditions necessary to minimize recombination of mercury reduced from its previously oxidized forms.

Figure 12‐1 Reduction of ionic mercury to elemental mercury using reducing agents.

By splitting the flue gas sample stream to have one part bypass the convertor and one part pass through it, measurements of elemental (Hgo) total mercury (HgT = Hgo + Hg²⁺) and elemental mercury (Hgo) can be made. The concentration of ionic mercury in the sample can then be determined by taking the difference between the two measurements.

Several analytical methods are used to measure elemental mercury in commercial mercury CEM systems (Ingle and Crouch, 1988;,Laudal 2015 including atomic absorption spectroscopy, Zeeman‐corrected absorption spectroscopy, atomic fluorescence spectroscopy, and X‐ray fluorescence spectroscopy. An X‐ray fluorescence spectrometer system that can measure elemental mercury as well as other metals will be discussed in the next chapter with regard to its application for monitoring multi‐metals to satisfy Part 63 hazardous air pollutants (HAPs) monitoring requirements.

Atomic Absorption Spectroscopy

Atomic absorption spectrometry is specified in reference test methods for mercury in water, soils, and air, but the technique is also used as the detection method for Hgo in a number of commercially available Hg CEM systems.

In atomic absorption spectroscopy, atoms are irradiated with UV light, where light at a wavelength corresponding to an electronic transition in an atom will be absorbed. In mercury analyzers, a collimated beam of UV light is generated using a mercury‐containing hollow cathode, mercury discharge, or electrodeless discharge lamp (EDL) (Figure 12‐2). Using internal electrodes or an external electric field, the mercury within the lamp is excited to emit light at a wavelength of 253.7 nm. This light is directed through a sample cell and then to a solid‐state detector or photomultiplier tube where the light intensity is measured. Sample gas flows through the sample cell, and mercury in the sample will absorb light at the 253.7 nm wavelength and consequently reduce the intensity of the light at the detector. By knowing the both the initial light intensity and the intensity of the light after it passes through the sample cell, the Beer–Lambert law (Chapter 4) can be applied to determine the mercury concentration. Because the light emitted from the “mercury” lamps is specific to mercury, it is not necessary to incorporate a monochromator into the instrument to select light at 253.7 nm. This simplifies the overall design.

Since elemental mercury can exist in the gaseous state at ambient temperatures, the methods are often preceded with the term “cold vapor.” In the “cold vapor” atomic absorption spectroscopic (CVAAS) method, argon is used to sweep out elemental mercury to the analyzer gas cell.

One limitation of atomic absorption spectroscopy is that SO₂ absorbs UV light in the same region as mercury to interfere in the measurement. For this reason, it is necessary to avoid this interference either by first removing SO₂ from the sample, using dual measurement cells, using gold amalgamation techniques or applying the Zeeman‐effect differential absorption technique.

Removing SO₂

Interference from SO₂ in mercury photometric measurements can be avoided by removing the SO₂ prior to measurement. This can be done simply by passing the gas sample through a sodium hydroxide solution or a water scrubber. The ionic mercury species must first be converted to elemental mercury before passing through the scrubber or they will be removed along with the SO₂.

Figure 12‐2 Atomic absorption analyzer for mercury.

Interference Corrections Using Dual Sample Cells

Another method for minimizing the effect of interferences uses dual sample cells, a technique that has been frequently employed in infrared photometric systems. In this technique, UV light absorption at 253.7 nm, is simultaneously measured in each of two sample cells (Figure 12‐3). The sample gas enters the first cell and the UV radiation is absorbed at 253.7 nm by elemental mercury and any SO₂ in the sample. The flue gas sample enters a mercury trap, which removes any elemental mercury in the gas cell. The sample then enters the second cell, where the SO₂ again absorbs the UV radiation. Because the trap has removed the elemental mercury from the sample stream, this second measurement provides a background correction to the first measurement. Although two lamps and/or two detectors may be used, differences in light intensity or detection sensitivity can easily be compensated when the instrument is zeroed.

Interference Corrections Using the Zeeman Effect

In the presence of a magnetic field, the mercury spectral absorption at 253.7 nm will be split into multiple levels, each having a slightly different energy. This phenomenon is known as the Zeeman effect, named after Dutch physicist Pieter Zeeman who observed it in 1896 and received the Nobel Prize for the discovery in 1902 (Kox 1997). This feature of the mercury atom can be utilized in designing a mercury UV absorption analyzer that is insensitive to interferences from molecules such as SO₂ that absorb light near 253.7 nm. Because the line splitting caused by a magnetic field is unique to mercury, an analyzer utilizing the Zeeman effect can differentiate between mercury and other absorbers in the spectral region (Brown 1977).

In its ground state, the two outermost electrons of mercury occupy a spherical volume known as the “6s orbital.” i.e. when it is not excited. If they are excited from the ground state to the next electronic level of the atom, they will occupy one of three possible “p‐orbitals,” which are dumbbell shaped. These three orbitals occupy volumes situated on each of the three‐dimensional spatial axes as shown in Figure 12‐4. In this representation, the orbital orientations are on the x, y, or z axis.

In a mercury discharge lamp, energy from the lamp excites an electron from a 6s orbital up to the higher energy states of the three 6p orbitals. As the atom de‐excites, light at 253.7 nm is emitted to serve as the light source for the atomic absorption spectrometer discussed in the previous section. Normally, it does not matter if a px, py, or pz orbital is occupied; they each have the same energy and an electron will de‐excite back to the 6s level emitting at the same wavelength for the px, py, or pz orbital (Figure 12‐5). If, however, the lamp is surrounded by a strong magnetic field, the p orbitals become distorted and an excited electron in a p orbital will have an energy dependent on the orbital's orientation with respect to the direction of the magnetic field. In other words, the p energy level “splits,” and the light will be emitted at three different wavelengths. The three spectral lines resulting from the magnetic field are identified as the σ₋, π, and σ₊ emissions. This “Zeeman effect” is shown in Figure 12‐6 for mercury in the region of 253.65 nm. In the analyzer, a mercury lamp, in this case, contains a mercury isotope, ²⁰²Hg, where the spectral emission does not coincide exactly with the absorption profile of the mixture of Hg isotopes encountered in Hg samples, which is also shown in Figure 12‐6.

Figure 12‐3 The use of dual sample cells.

Figure 12‐4 Orientations of the p orbitals.

The central wavelength, the central π emission, is at the same wavelength as that emitted without the application of the magnetic field. Because of the way the orbital electrons interact with the magnetic field, the σ₋ and σ₊ components have wavelengths that are slightly lower and slightly higher than the original. The light corresponding to the π central line is linearly polarized (parallel to the magnetic field) and that corresponding to the σ₋ and σ₊ lines are circularly polarized in the direction of the magnetic field, but with opposite “handedness.” The σ₊ emission is left‐circularly polarized (clockwise) and the σ₋ emission is right‐circularly polarized (counterclockwise).

Note from Figure 12‐8 that the σ₊ emission is shifted to the edge of the mercury absorption envelope and that the σ₋ emission is at a wavelength of maximum absorption. As a result of light splitting into the σ₋ and σ₊ components, a differential absorption spectrometer can be designed by using light at the σ₊ wavelength as a reference wavelength and light at the σ₋ wavelength as a measurement wavelength. In Chapter 5, it was seen that in a differential absorption IR or UV instrument, a diffraction grating or a laser can be used to produce reference and measurement wavelengths. In a Zeeman mercury analyzer, a magnet is used for this purpose.

Figure 12‐5 Splitting of the p energy levels.

Figure 12‐6 ¹⁹⁸Hg Lamp σ−, π, and σ₊ emissions and Hg light absorption from 253.6 to 253.7 nm.

Source: Modified from Disch (2012).

In the longitudinal Zeeman Hg analyzer configuration shown in Figure 12‐7, a mercury lamp is placed between the poles of an electromagnet, where one of the poles has a hole drilled through it to allow light from the lamp to pass through it in the direction of the magnetic field, B. In terms of instrument design, an electrodeless discharge lamp containing a mercury isotope such as ²⁰²Hg or ¹⁹⁸Hg is used as a light source. When the magnetic field is on, the light splits into the σ−, π, and σ₊ components. The π component is emitted perpendicular to the magnetic field and is not seen by the detector, whereas the σ₋ and σ₊ components can be detected in the direction of the magnetic field as well as perpendicular to the field. A photoacoustic modulator alternately allows the σ₋ and σ₊ components to pass through the sample cell and to the detector where the light intensity is measured for each.

The flue gas sample flows through the sample cell, where mercury atoms in the gas will absorb light at the wavelength, λmeas of the σ₋ emission. Light at the σ₊ wavelength serves as a reference wavelength, λref to increase the sensitivity of the analyzer. The σ₋ and σ₊ are so close together (<0.05 nm) that most potential interfering compounds will absorb the same amount of light energy at each wavelength. This may act to reduce the light intensity at λmeas and λref but will not otherwise affect the measurement.

Figure 12‐7 Longitudinal Zeeman effect analyzer configuration.

The Ohio Lumex mercury analyzers used for carbon trap and process analysis are similar in design to the longitudinal Zeeman instrument illustrated in Figure 12‐9 (Sholupov 2013; Sholupov et al. 2004; Stroganov et al. 2017). Sick has developed a transverse‐mode Hg Zeeman analyzer for CEM system applications (Disch 2012; Greiter and Boness 2012).

Atomic Fluorescence Spectroscopy

When mercury atoms absorb light at 253.7 nm, the atoms elevated to higher energy levels will reradiate the absorbed energy at the same wavelength because of the type of electronic transition that occurs. However, the reemitted light will radiate in all directions, resulting in a net loss of energy at the detector which receives light in the forward direction. Atomic fluorescence analyzers take advantage of this fluorescent radiation by placing a photomultiplier tube detector at right angles to the direction of the exciting radiation. The configuration is similar to that of the SO₂ fluorescence analyzer discussed in Chapter 5. Figure 12‐8 illustrates the same configuration for an atomic fluorescence analyzer.

In mercury fluorescence, the fluorescent radiation measured is the same as the radiation incident to the atom. This is because atoms do not vibrate and rotate like molecules. The internal conversion process in which the absorbed photons lose energy does not occur and the absorption and emission wavelengths are the same. This condition where the same upper and lower energy levels are involved in the excitation–deexcitation process is called “resonance fluorescence.” For mercury, it can be expressed as

Mercury fluorescence can be “quenched” in the same manner as discussed in SO₂ fluorescence. By colliding with molecules or atoms in the background gas, an excited mercury atom can transfer the energy of excitation in the collision. As a result, the excited atom will not emit light, but will cause the kinetic energy associated with the collision to increase. Because different molecules have different efficiencies in quenching the radiation, it is important to keep the composition of the background gas relatively constant. In mercury continuous monitoring systems that use atomic fluorescence analyzers, sample dilution with nitrogen or gold amalgamation techniques have been used to minimize the problem.

Figure 12‐8 Atomic fluorescence analyzer for mercury.

The atomic fluorescence spectrometer is used in conjunction with dilution‐extractive systems by the two vendors who have sold the majority of CMMS in the United States and Canada, Thermo Fisher and Tekran. The atomic fluorescence spectrometer has a detection limit of 0.001 μg/m³, which allows the use of the dilution‐extractive technique in system designs.

Continuous Mercury Monitoring Systems

The design of a Hg CEM systems is unique to each system vendor. Given a variety of options available in system components, the commercial vendors of these systems have chosen what they believe to be the “best system” for monitoring mercury. There are no two commercial systems that are exactly alike, but some are becoming more similar in design after a manufacturer finds a solution to a specific problem and it is adapted by others. The possible options available to an integrator when integrating a continuous mercury monitoring system are given in Table 12‐3.

Although it was first thought that the mercury monitoring technology developed in Europe from 1980 to 1995 could be adapted to monitor at the levels less than 5 μg/m³, and eventually <1 μg/m³, required by U.S. regulations (Laudal and Thompson 2011), numerous field demonstrations indicated otherwise. It was soon realized that considerable effort would be needed to improve mercury measurement technology to measure at lower levels. In North America, from 1995 to 2010, the goal was to develop high‐resolution mercury monitoring systems capable of monitoring in the range of 0.1 μg/m. The primary challenges were to deliver a representative sample to the analyzer and provide reproducible results from a gas sample containing high levels of moisture and contaminants. Other major challenges were to quantitatively convert the ionic mercury species to elemental mercury and to standardize methods for calibrating the systems for both Hgo and Hg²⁺. Analytically, there was little problem, since mercury analyzers were already proven to be able to measure at ambient air at levels of 0.02 μg/m³. However, monitoring pollutants in ambient air has always been more straightforward than monitoring pollutants in flue gases. The complex interaction of mercury species at part per trillion levels with other pollutants, and to particulate matter, system surfaces, and system components was a problem that each integrator had to solve. The solutions were not always intuitive, but had to be resolved through experience, research, trial and error, and, sometimes, borrowing from others. Candidate monitoring systems were extensively evaluated through numerous field studies sponsored by EPRI, EPA, DOE, and others (Hosenfeld 2006; Laudal and Behrens 1999; MRI 2006; Sarunac 2007a). A number of companies dropped out due to either the difficulties associated with low‐level mercury measurement or the costs of system validation.

TABLE 12‐3 Options for Hg CEM systems Integration

Probe Options
Hg²⁺ Conversion Options
Analyzer
Options
Interference Reduction
Options
Hgo
Calibration
Check Options
Hg²⁺
Integrity check
Options

Eductor
External Dil.
Extractive (No Dil.)
Wet Chemicals Heated Tube Heated Catalyst
AAS
AFS
DOAS
Gold Trap Dual Cells Zeeman Corr.
N₂ Dilution
Cal. Gas Hgo Vapor Perm. Tube
HgCl₂ Solution
Hg + Cl₂ Reaction

By 2010, viable systems capable of meeting the U.S. EPA requirements of the CAMR program were commercially available. In general, they contained more system components and were more expensive than gas monitoring systems designed for measuring criteria pollutants such as SO₂ and NOx. Although some mercury monitoring systems initially required higher levels of maintenance, if routine preventive maintenance procedures and quality assurance tests are conducted, their operational performance is today not considerably different from other CEM systems.

The following examples illustrate different approaches taken in integrating mercury monitoring systems. Because there are relatively few manufacturers of Hg CEM systems, the techniques used by any one company tend to identify their system in contrast to others. For that reason, the examples given next are distinguished by vendor name.

Example 1: Dilution‐Extractive with Gold Amalgamation and Atomic Fluorescence Spectrometer

The Tekran Model 3300 Series continuous mercury monitoring system was developed to meet the initial demands of the U.S. EPA Clean Air Mercury Rule. Designed years in advance of the rule's promulgation, it built on experience gained in providing mercury analyzers for ambient monitoring. Because the challenge of measuring ambient mercury levels of less than 0.1 μg/m³ had already been met by Tekran, their primary focus in developing its continuous mercury monitoring system was on delivering a continuous representative sample to its fluorescence spectrometer. To achieve this, they focused on the incorporation of a dilution‐extractive system in the probe design and a gold trap amalgamation system to minimize fluorescence quenching errors in the spectrometer. Table 12‐4 summarizes the Table 12‐3 listed options incorporated in the Tekran system.

TABLE 12‐4 Options Incorporated in the Tekran Model 3300 Continuous Mercury Monitoring System

CMMS Component | Options
Probe | Eductor external dilution
Hg²⁺ conversion methods | Heated catalyst
Analyzer | AFS
Interference reduction methods | Gold Trap
Hgo Cal. Method | Hgo Vapor
Hg⁺² integrity check methods | HgCl₂ solution
| Hg + HCl reaction

Tekran initially used the EPM “race‐track” probe design in their systems, where the flue gas is drawn through an eductor by which it passes through a critical orifice and diluted by clean, dry air through a second eductor. A more compact dilution probe design, developed by M&C Products, has since been employed, where the modular eductors simplify maintenance and replacement. This out‐of‐stack dilution probe was discussed in Chapter 3 (see Figure 3-24).

In the Tekran system, the flue gas is extracted from the stack using a Hastelloy probe that has been treated to resist the adsorption of mercury on the metal surface by evaporating a thin film of quartz a few molecules thick on its inner surface. This “glass” film is also applied to other metal parts of the system that will be exposed to the sample gas, particularly those in the dilution probe. The sample is then sent to the conditioning system through a PFA Teflon umbilical heated to 180 °C. The conditioning system and principal analytical components of a Tekran CMM system are usually installed in a CEM shelter located at ground level near the stack.

A schematic of a system configuration is shown in Figure 12‐9. Components of the system include the following:

Probe

Mercury analyzer

Hgo calibrator

Figure 12‐9 The Tekran continuous mercury sampling system.

Oxidized mercury (Hg²⁺⁾ calibrator

Data logger

System computer

Air clean‐up systems

Water clean‐up system

In the system shown in Figure 12‐9, after the probe, the sample gas is separated into two gas streams to provide for the speciation of the flue gas mercury into its elemental (Hgo) and oxidized (Hg²⁺) forms. In one stream, the oxidized mercury in the flue gas sample (Hg²⁺) is converted into elemental mercury (Hg⁰) for the determination of the total mercury (HgT or TGM). Oxidized mercury (Hg²⁺) from the other gas stream is scrubbed and only the elemental mercury (Hgo) present in the flue gas is analyzed. The concentration of oxidized mercury in the flue gas is then obtained by difference

The process is similar to the method used in NOx analyzers, where total NOx and NO are measured separately. In that case, by subtracting the NO concentration measurement from the total NOx concentration, one obtains a value for the concentration of NO₂.

In the total mercury path, a thermal pyrolyzer containing silicon carbide (or other pyrolytic material) converts all mercury species to elemental mercury. A small amount of pure water is added to the sample, which is then immediately introduced into a chilled scrubber unit. This water serves to wet the interior of the chiller, which removes any residual mercury species and other pollutant gases such as SO₂. The chiller also reduces the sample dew point low enough to prevent downstream condensation. In the elemental mercury path, the diluted sample passes through a scrubber, where water removes the soluble ionic mercury species. The insoluble elemental mercury then passes to the gold trap analytical system.

A detection limit of <0.01 μg/m³ is possible with this system, achieved by using a preconcentration technique. In this technique, two traps containing gold granules alternately trap and desorb mercury in the sample gas stream. This is shown in Figure 12‐10. In this technique, elemental mercury is preconcentrated in gold traps to allow the collection of measurable levels of mercury. Sampling times can be increased in order to increase measurement sensitivity. Two operations occur in the method. While gold trap no. 1 is sampling, gold trap no. 2 is heated to desorb the mercury previously amalgamated on the gold in the trap. In the desorption operation, argon gas is used to carry the mercury to the sample measurement cell for analysis. The valves are then rotated and the sample is collected in gold trap no. 2 while gold trap no. 1 is desorbed.

A cold vapor atomic fluorescence mercury (CVAFS) analyzer is used to quantify mercury concentrations in the diluted sample stream. The sample stream is continuously drawn into a reaction cell where it is irradiated with light in the far ultraviolet (UV) region of the spectrum at 253.7 nm, as discussed earlier and illustrated in Figure 12‐10. The use of argon as a carrier gas through the gold traps provides a constant gas background for the fluorescence measurement to eliminate the problem of fluorescence quenching. This is in contrast to the need to address quenching problems in chemiluminescence NOx and fluorescence SO₂ analyzers when the composition of the background gas is variable (see Chapter 5).

Clean air and water are particularly important in mercury monitoring systems if mercury concentrations less than 0.1 μg/m³ are to be monitored. The air filtration system provides motive air for the ejector pumps used in the probe box and mercury free zero air for the dilution and calibration systems. Coarse and fine filters are used to remove particulate matter, and iodated carbon scrubbers are used to remove any mercury or mercury compounds from the air stream. A final carbon filter is used to ensure the removal of residual iodine and other interferants.

The water filtration system provides deionized, mercury‐free water necessary for the monitoring system calibration checks. Incoming water is first filtered to remove particulate matter and organic contaminants. Ion exchange resin filters follow to remove ionic compounds, including mercury.

The Tekran Model 3300 is used in a large number of installed units. The model has since been updated to Model 3300 Xi.

Figure 12‐10 Gold trap pre concentration technique.

Example 2: Dilution‐Extractive with Atomic Fluorescence Spectrometer

The Thermo Fisher “Mercury Freedom” system is similar to that of Tekran; it incorporates an atomic fluorescence analyzer and dilutes the flue gas at the stack, as does Tekran. However, the approach to minimize fluorescence quenching effects and to system calibration differs. The techniques employed by Thermo Fisher are summarized in Table 12‐5.

TABLE 12‐5 Techniques Incorporated in the Thermo Fisher “Mercury Freedom” System

CMMS Component | Method
Probe | Eductor EPM external dilution
Hg²⁺ conversion methods | Heated catalyst
Analyzer | AFS
Interference reduction methods | N₂ dilution
Hgo Cal. method | Hgo vapor or permeation tube
Hg⁺² integrity check methods | HgCl₂ solution or Hg + Cl₂ reaction

The Thermo Fisher mercury monitoring system used a number of probe designs in the past. One of the designs used by both Tekran and Thermo Fisher incorporates an inertial filter and eductor to minimize the collection of particulate matter on the internal filter (Thermo Fisher Scientific 2007). The concern here is that particulate matter adhering to a filter could absorb mercury vapor in the sample gas and lead to lower than true readings. This so‐called “race‐track” probe was incorporated in a number of the earlier Thermo Fisher “Mercury Freedom” systems and is illustrated in Figure 12‐13. The race‐track probe was eventually discontinued and the M&C probe shown in Figure 12‐11 has been used instead. After the sample is drawn from the stack, it is then divided after the critical orifice to pass untreated for the measurement of elemental mercury (Hg°) and through a heated catalytic convertor for the measurement of total mercury, HgT (Hg° + Hg° converted from ionic mercury in the sample). The sample gas is then transported to the analyzer in an umbilical line heated to 120 °C. Each gas stream is measured alternately by a switching system contained within the analyzer. Similar to the Tekran system, the ionic mercury concentration can be obtained by subtracting the measurement of the elemental mercury (Hg°) from the total mercury measurement (Hg° + Hg²⁺[converted]). As with the Tekran system, the system may be configured to monitor only total mercury, by not switching the gas stream from the converter.

The atomic fluorescence technique is used for the measurement of elemental mercury in this system, similar to the Tekran system. To increase sensitivity, fluorescence quenching effects are minimized by using nitrogen as the dilution gas, instead of air. Nitrogen is produced in a nitrogen generator, using air previously scrubbed off water, oxygen, carbon dioxide, and other possible interferents. The efficiency of the nitrogen generator in removing oxygen is dependent on the inlet air pressure and flow rate through the generator, which may be a problem if the instrument air supply fluctuates or if nitrogen demand varies.

There have been a number of design iterations in the Mercury Freedom system since its commercial introduction in 2005. System changes were made as experience was gained from operational challenges in both electric utility and cement industries; sometimes requiring scaling back unique design approaches incorporated in the earlier systems. Because Thermo Fisher sold approximately three quarters of the coal‐fired power plant mercury monitoring systems in the United States and Canada from 2005 to 2015, these challenges were met relatively rapidly (Whorton 2011).

Other Systems

Mercury monitor systems are currently provided by approximately a dozen different vendors. Similar techniques to those discussed in detail above are used in a variety of combinations. Depending on the mercury concentrations to be measured, dilution systems or gold traps may not be used. Although the atomic absorption technique may be more susceptible to interference from SO₂ at 253.7 nm, the use of the dual cell technique shown in Figure 12‐4 or Zeeman splitting can minimize this problem. Several vendors have utilized these methods (Tables 12‐6 and 12‐7).

Calibrators

The calibration of a mercury CEM system is not as straightforward as that for SO₂ or NOx monitoring systems. During the formative years of mercury monitoring, mercury calibration gases were expensive, inaccurate, unstable, and not NIST traceable. Mercury calibration gas cylinders formerly cost from 5 to 10 times that of regular protocol gases, and their accuracy was typically good to only ±5%. Concentration stability in the cylinder is also an issue, and problems extend to delivering the gas to the analyzer, since mercury can adsorb in regulators and supply tubing, requiring special procedures to minimize mercury losses. Due to this adsorption problem, the long equilibration times necessary to come to a stable concentration value depletes the gas in the cylinder, requiring more frequent replacement than might be expected.

These gas cylinder problems are better understood today, but to meet EPA installation deadlines, it has become necessary to apply calibration methods other than the use of traditional gas cylinder calibration gases. These methods involve generating a gas standard in elemental or oxidized mercury “generators.” Calibrators (generators) constitute another box or subsystem that must be purchased for the mercury monitoring system, which adds to the system expense. The following types of calibration systems are used:

Figure 12‐11 The Thermo Fisher continuous mercury monitoring system.

TABLE 12‐6 The Mercury Instruments and Durag Systems

CMMS Component | Options
Probe | Extractive (No Dil.)
Hg²⁺ conversion methods | Heated catalyst
Analyzer | AAS
Interference reduction methods | Chiller/dual cells
Hgo Cal. Method | Cal. Gas
Hg²⁺ integrity check methods | HgCl₂ solution

TABLE 12‐7 The Sick Continuous Mercury Monitoring System

CMMS Component | Methods
Probe | Extractive (No Dil.)
Hg²⁺ conversion methods | Heated catalyst
Analyzer | AAS
Interference reduction methods | Zeeman correction
Hgo Cal. Method | Hgo vapor
Hg²⁺ integrity check methods | HgCl₂ solution

Elemental Mercury Head Space Calibrators

Elemental Mercury Permeation Tubes

Evaporative HgCl₂ Calibrators

HgCl₂ Generators

Elemental Mercury Head Space Calibrators

Elemental mercury head space calibrators incorporate a container of mercury maintained at a constant temperature and pressure, from which elemental mercury is swept off from the surface of the container head space by a carefully controlled flow of air. Mass flow controllers are used to deliver a known, constant flow of air over the surface of the pool of mercury. By knowing the vapor pressure of mercury (Huber et al. 2006; Dumarey, et al. 1985) at the temperature of the mercury pool and the air flow rate, the concentration of mercury can be determined in the gas stream. This air stream, saturated in mercury, can then be diluted to obtain a calibration gas at a desired concentration. A schematic of typical calibrator is shown in Figure 12‐12.

Mercury Permeation TubesPermeation tubes

produce only a small amount of gas and are more suitable to perform an analyzer check than a system check or to perform quarterly checks on the stability of the head space calibrators.

In a mercury permeation tube, mercury is sealed inside a tube made of material permeable to mercury, typically PTFE Teflon. The permeation rate of mercury through the tube is small (on the order of nanograms/minute), which is dependent upon the temperature of the tube, length, and permeability of the tube to mercury. The tube is contained in an oven, where a stable temperature is maintained. Argon or nitrogen is passed over the tube at a fixed rate, using mass flow controllers, precision pressure regulators, and/or capillaries to obtain the gas standard for checking the system calibration. In addition, stable temperatures and flow rates are critical in the performance of permeation tubes. Tekran and Thermo Fisher both provide Hg permeation tube calibration systems.

The Integrity Check – Calibration with Oxidized Mercury

Because oxidized mercury may constitute a significant percentage of the mercury in a flue gas stream, the effectiveness of the system in reducing the oxidized mercury must also be checked. Obviously, an elemental mercury calibrator cannot do this, so the check must be made using a reference gas of a known concentration of oxidized mercury, in particular HgCl₂.

This check must be performed weekly for Hg CEM systems installed in U.S. coal‐fired power plants subject to the MATS rule and quarterly for cement plants. The check is called the “Integrity Check,” and requires that a NIST traceable oxidized mercury reference gas be injected as close to the probe as possible, before any convertor, and transported to the analyzer through the extractive system to the analyzer.

Two types of oxidized mercury calibrators have been used. In evaporative oxidized mercury generators, an NIST traceable standard solution of HgCl₂ in water is used to inject HgCl₂ at a known concentration through the system. In conversion HgCl₂ generators, elemental mercury from a mercury calibrator is reacted with chlorine to form HgCl₂, which is then injected through the system.

Figure 12‐12 Schematic of an elemental mercury (Hg⁰) calibrator.

Evaporative HgCl₂ Calibrators

Evaporative calibrators for oxidized mercury utilize commercially available NIST traceable standard solutions of HgCl₂ in water. In a typical calibrator using an NIST standard reference material, SRM 3313, the HgCl₂ solution is diluted with water using volumetric injection, and the resulting solution is nebulized (vaporized) in the vaporizer. The vaporized solution is combined with air injected into the nebulizer to provide a gas stream of known HgCl₂ concentration. The flow rates of the liquid and air streams are carefully metered for the concentration determination. Generators are manufactured by mercury monitoring system vendors and also by the company HovoCAL, which provides calibration systems for incorporation by system vendors or for independent testing. A typical oxidized mercury calibration system is shown in Figure 12‐13. Operationally, the HgCl₂ standard solution and deionized water supply will be depleted over time and must be periodically replenished. Temperature throughout the system is again important in determining output volumes and consequent mercuric chloride concentration.

Reactive Mercuric Chloride Generators

Another approach to generate an oxidized mercury calibration gas is to react the mercury produced in an elemental mercury calibrator with dilute chlorine gas (Kita et al. 2013). Here, the mercury standard generated from an elemental mercury calibrator system is sent to a heated reaction chamber contained within the probe at the stack. Chlorine obtained from a bottle located at the stack is quantitatively reacted with the mercury in the elemental mercury standard. One advantage of the method is in avoiding problems common to dealing with liquid solutions in industrial settings.

In this system, a heated, porous cylinder provides a large surface area, which allows mixing of the gases and for the heterogeneous surface reaction occurs between elemental mercury and chlorine (Figure 12‐14). This cylindrical reaction chamber may be composed of sintered stainless steel, sintered Hastelloy, porous ceramic, silica coated materials, or other materials, which are porous and do not react themselves with the gas stream components. Heating the reaction chamber enhances the reaction and reduces adsorption of mercury on the surfaces of the system. Humidification of the gas also reduces sticking of both elemental mercury and the end product, mercuric chloride. With sufficient chlorine, all of the mercury can be converted into mercuric chloride, or also, by limiting the injection of chlorine, the mercuric chloride concentration can be varied.

The oxidizer assembly can be incorporated in the probe box to inject the HgCl₂ calibration gas directly into the probe filter. This minimizes problems associated with HgCl₂ losses in system transport lines and surfaces. In this configuration, a lecture bottle of chlorine, with a nominal concentration of 900 ppm Cl₂, will typically last a year when conducting a weekly system integrity check (Thermo Fisher Scientific 2007).

Another conversion method utilizes hydrochloric acid to react with the mercury generated by an elemental mercury calibrator (Mandel and Shields 2005). Here, a metering pump injects a solution of hydrochloric acid into a heated nebulizer to react with the mercury from the calibrator (Figure 12‐15).

Figure 12‐13 Evaporative oxidized mercury calibrators.

Figure 12‐14 HgCl₂ generator using Cl₂.

Calibrator Traceability Protocol

In the U.S. EPA 40 CFR 63 rules for hazardous air pollutants, monitoring systems required under the rule must provide data traceable to NIST standards (e.g. 40 CFR 63 Subpart UUUUU Appendix A §3.2.1.2.1). The problem with elemental and oxidized mercury calibrators is that they constitute part of the system, and although their operation is based merely on evaporation or vaporization principles, in order to be certified and approved for use in EPA monitoring programs, the calibrators must produce an output that is traceable to the National Institute of Standards and Technology. In the case of calibration gases, a traceability protocol (U.S. EPA 2012) is used to reference a prepared cylinder gas to NIST standard reference materials (SRMs) to produce the so‐called “protocol gases.” For mercury monitoring system calibrators, traceability is instead established to an NIST “reference calibrator,” the “NIST Prime Calibrator.” The NIST Prime is calibrated using a method based on isotope dilution inductively coupled plasma mass spectrometry (ID‐ICP‐MS) (Christopher et al. 2001; Long et al. 2007). The isotope dilution mass spectrometric method has proven to be quite accurate and is used to provide certified values for a number of NIST standard reference materials. Applying this method provides an analysis of the gas calibrator output that is independent of any vapor pressure, flow rate, temperature, or other factors that are used in calculating its output.

Because the isotope dilution method equipment is costly and the method is expensive to perform, a protocol has been established (U.S. EPA 2009) where the NIST Prime generator is used to calibrate a NIST Certification Analyzer. This analyzer, once calibrated, is used to calibrate analyzers submitted by vendors, to produce “Vendor Primes.” The Vendor Prime generator is then used to calibrate a Vendor Certification Analyzer that can be used to calibrate generators submitted from installed monitoring systems by users. The protocol further allows the certification of “Field Primes” that may be taken out to the field or purchased by a user to calibrate or verify the calibration of installed generators. This avoids the prospect of sending calibrators back to the vendor for calibration checks, allowing Field Primes to be used to validate installed CEM system calibrators. This process is illustrated in Figure 12‐16.

In this procedure, each generator (Field Prime and the user's candidate generator) is adjusted to produce a reference gas at specified low, mid, and high concentrations. Each gas is tested three times by the candidate generator and four times by the Field Prime so that each candidate generator response is “bracketed” by a Field Prime generator response (Table 12‐8). The two Field Prime responses are averaged, and the ratio between the Field Prime and candidate generator at each concentration is used as a subsequent calibration factor for the User's generator.

Figure 12‐15 HgCl₂ generator using HCl.

Figure 12‐16 NIST Hg/HgCl₂calibrator traceability.

TABLE 12‐8 Bracketing Procedure for Bracketing Procedure for Hg/HgCl₂ Generator User Certification

Gas | Bracket | Generator
Zero Gas |  | Field Prime & Candidate
| 1 | Field Prime
| 2 | User Candidate Generator
Low Level | 31 | Field Prime
Concentration | 2 | User Candidate Generator
| 31 | Field Prime
| 2 | User Candidate Generator
| 3 | Field Prime
| 1 | Field Prime
| 2 | User Candidate Generator
Mid Level | 31 | Field Prime
Concentration 2 | 2 | User Candidate Generator
| 31 | Field Prime
| 2 | User Candidate Generator
| 3 | Field Prime
| 1 | Field Prime
| 2 | User Candidate Generator
High Level | 31 | Field Prime
Concentration 3 | 2 | User Candidate Generator
| 31 | Field Prime
| 2 | User Candidate Generator
| 3 | Field Prime
Zero Gas |  | Field Prime & Candidate

The traceability protocol requires that a quality control check be conducted periodically on installed monitoring system calibrators. This check is required quarterly for coal‐fired EGUs under the MATS rule and annually for cement plants subject to the cement MACT rule. The check need not be the bracket test using a Field Prime generator since the protocol allows four other options:

Option 1: Field Reference Generators

Option 2. Permeation Tubes

Option 3: Sorbent Tubes

Option 4: Cylinder Gases

SORBENT TRAP MERCURY MONITORING SYSTEMS

Sorbent trap mercury monitoring systems are basically automated versions of EPA Method 30B, allowed for meeting the mercury monitoring requirements of coal‐fired power plants and cement plants. Sorbent trap monitoring systems used for meeting the mercury monitoring requirements for coal‐fired electric utilities and cement plants are certified following the procedures of Performance Specification 12B of 40 CFR 60 Appendix B.

As with Method 30B sampling systems, sorbent trap monitoring systems consist of a probe, paired sorbent traps, an umbilical line, moisture removal systems, sample pumps, dry gas meters, and a control unit (Figure 12‐17). A major difference between the reference method sampling system (Method 30B) and a continuous sorbent trap mercury monitoring sampling system is that continuous systems are required to use a three‐section sorbent trap (Figure 12‐18), instead of a two‐section trap, as specified in Method 30B. The first two sections of the trap are used to collect total gaseous mercury, e.g. elemental mercury vapor and gaseous ionic mercury compounds. The first section traps the sample, the second is used to measure breakthrough from the first section, and the third one contains a spike of a known amount of mercury to be analyzed for a quality control check. Mercury caught on particulate matter may collect in the front of the first section. Pre‐spiked traps, spiked at concentrations 50–150% of the expected mercury mass retained, are typically obtained from trap suppliers.

Figure 12‐17 Sorbent trap monitoring system (meeting PS‐12 specifications).

Flue gas is sampled through traps filled with an iodated carbon sorbent that captures atomic and ionic mercury, as well as mercury caught on particulate matter. The system samples the stack gas at a constant rate, proportional to the stack gas velocity as is required in PS‐12B. The traps are removed and replaced and the samples are analyzed using UV absorption or fluorescence techniques as in Method 30B. The total mercury concentration is reported, where the mass concentration in μg/m³ is calculated by dividing the mass of mercury trapped by the volume of gas sampled over the sampling period. Although sampling is continuous, the sampling is a batch process, providing an integrated sample over a selectable period of time, up to 14 days. As with continuous mercury monitoring systems, sorbent trap monitoring systems have been extensively validated in both the laboratory and the field (Sarunac et al. 2007b; Schmid and DeRosier 2011; Senior 2015; Staudt 2014; Thompson et al. 2011).

Using sorbent traps for the periodic measurement of mercury may appear simpler than installing a continuous mercury CEM system; however, their application is highly prescribed in Performance Specification 12B of 40 CFR 60. Performance Specification 12B provides a set of “QA/QC” criteria, which must be met when the system is being certified, but which also must be met for each batch sampling period when the system is in operation. These criteria are reminiscent of the ASTM D6216 “design criteria” referenced for opacity monitors in Performance Specification 1 of 40 CFR 60 (see Table 8‐1). Similarly, Performance Specification 12B prescribes sets of design, operation, and calibration criteria for sorbent traps. These sorbent trap criteria are summarized in Table 12‐9.

Figure 12‐18 Paired carbon traps for mercury sampling for a continuous sorbent trap Hg monitoring system.

TABLE 12‐9 Hg Sorbent Trap Monitoring System Performance Criteria

Required Design Criteria
Calibration Criteria
Operational Criteria

Three‐section Trap
Section 1 – sample
Section 2 – breakthrough
Section 3 – spiked
Paired traps
Proportional Sampling capability
Flowmeter
Gas Flowmeter
Temperature Sensor
Barometer
Hg Analyzer multipoint calibration
Hg Analyzer independent standard check
Three‐level spike recovery study
Pre‐sampling leak check
Proportional sampling limit
Post‐sampling Leak check
Section 2 breakthrough limit
Paired sorbent trap agreement
Spike recovery

Sorbent Trap System Design Criteria

Many of the EPA reference test methods, including Method 30B, simply draw a sample from the flue gas, provide a means to collect the pollutant in the sample and then measure the volume of gas that was sampled in the process. A mercury sorbent trap sampling system is no different; however, PS‐12B does stipulate that a three‐section trap is to be used for collecting the Hg sample, the system is to be designed to use paired traps for quality control purposes, that sampling is to be conducted proportionally to the stack flow, and, of course, the sample flow is to be measured.

The system is also required to provide a means for proportional sampling where the sample flow rate is changed proportionally as the stack flow increases or decreases. This is similar to isokinetic sampling used in particulate sampling, where the sample probe velocity is adjusted to be equivalent to the flue gas velocity at the sampling point. In PS‐12B systems, the flue gas flow measurement signal, sent from a stack flow monitor, is used to automatically adjust the sample flow rate.

Required Calibrations

Because the sampling system is used to determine the concentration, temperature and pressure sensors are necessary (see Figure 12‐19) to correct the volume of gas sampled to standard conditions. These components, as well as the flowmeter, must be calibrated quarterly. The calibration procedures are common to source sampling equipment and should be described in the CEM Program quality assurance manual.

The mercury analyzer used for sample analysis must undergo a multipoint calibration on the day of analysis, prior to analyzing the samples. Also, to validate the calibration, an independent calibration standard must be analyzed, to within ±10% of its true value after the instrument has been calibrated.

PS‐12B QUALITY CONTROL CRITERIA

In contrast to Method 30B, the sorbent trap test method, where sampling is conducted over a one‐half hour to hour period, an PS‐12B installed sorbent trap sampling system may collect a sample over a longer period of up to 14 days. The sampling starts with a leak check and ends with a leak check. Besides that, the sampling must be conducted proportionally to the flue gas flow, and the total sample volume determined. Quality control procedures are also given for the trap analyses, where the paired traps have to show reasonable agreement, breakthrough to the second trap is minimal, and the spike in the third trap section is within a reasonable range. These specifications are summarized in Table 12‐10.

Leak Checks

Both before and after sampling, the sampling system must be leak checked. The pre‐sampling leak check is limited to less than 4% of the target sampling rate. The post‐sampling leak check is limited to less than 4% of the average sampling rate.

Proportional Sampling

Proportional sampling must be maintained over the period the samples are collected. To meet the requirement, both the flue gas flow and sample flow must be monitored. In the first hour of sampling, a reference ratio, Rref, is established:

TABLE 12‐10 Performance Specification 12B Specifications for Batch Sampling

Parameter
Specification

Pre‐sampling leak check
≤4% of target sampling rate

Post‐sampling leak check
≤4% of average sampling rate

Maintain stack flow‐to‐sample flow ratio (proportional sampling)
<±25% deviation for no more than 5% of the hourly ratios

Percent Breakthrough, %B
≤5% of Section 1 Hg mass
if Conc. >0.5 μg/dscm

Paired Trap Agreement
Relative Deviation (RD)
RD ≤ 10%
if Conc. >01.0 μg/dscm
RD ≤ 20%
if Conc. ≤01.0 μg/dscm

Spike recovery study (Lab study)
85–115% at 3 levels

Spike recovery, R (Note c) (Recovery spike must be within ±50% of the expected mass collected)
75–125%

(12‐1)normal upper R Subscript r e f Baseline equals StartFraction upper K upper Q Subscript r e f Baseline Over upper F Subscript r e f Baseline EndFraction

where

Rref = reference ratio of hourly stack gas flow rate to hourly sample flow rate

Qref = average stack gas volumetric flow rate for the first hour of collection period (scfh)

Fref = average sample flow rate for the first hour of collection period

K = power of 10 conversion factor

For each subsequent hour of sampling, the ratio, Rh, between the stack gas flow volumetric flow rate and sample flow rate is calculated using Equation 12‐2:

(12‐2)upper R Subscript normal h Baseline equals StartFraction upper K upper Q Subscript normal h Baseline Over upper F Subscript normal h Baseline EndFraction

where

Rh = hourly ratio of hourly stack gas flow rate to hourly sample flow rate

Qh = hourly average stack gas volumetric flow rate (scfh)

Fh = hourly average sample flow

K = power of 10 conversion factor

The value of Rh is required not to deviate from Rref by more than 25% over the sampling period for more than 5% of the hourly ratios.

Percent Breakthrough

The amount of mercury passing from the first trap to the second trap is known as “breakthrough” and is expressed as a percentage of the mass of mercury collected on the first trap. Percent breakthrough is defined as

(12‐3)percent-sign upper B equals StartFraction m 2 Over m 1 EndFraction

where

%B = percent breakthrough

m₂ = mass of Hg collected in the second section

m₁ = mass collected in the first section

PS‐12B requires that no more than 5% of the total Section 1 mass collected be present in the second section of the trap for average flue gas mercury concentrations that are greater than 0.5 μg/dscm, but does allow 10% if the flue gas mercury concentration is less than 0.5 μg/dscm. The EGU MATS rule makes an exception for this specification, allowing instead a breakthrough of up to 10% of the Section 1 Hg mass if the flue gas Hg concentration is >1 μg/dscm. Breakthroughs of 20 and 50% are allowed for lower flue gas Hg concentrations. At concentrations <0.1 μg/dscm, there is no breakthrough restriction.

Note that the PS‐12B criteria for breakthrough are more stringent than for Method 30B, which allows a breakthrough of 10% for Hg concentrations >1 μg/dscm (see Table 12‐10).

Paired Trap Agreement

Paired traps are required as design specification in PS‐12B sorbent trap monitoring systems for system quality. If only one trap were to be used, more certainty might be ascribed to the measurement than might be warranted. If two traps are used, a difference between them would provide an indication of uncertainty associated with the sample measurements.

The relative deviation between the traps is given as RD, calculated according to Equation 12‐4 as follows:

(12‐4)upper R upper D equals StartFraction upper C Subscript a Baseline minus upper C Subscript b Baseline Over upper C Subscript a Baseline plus upper C Subscript b Baseline EndFraction

where

RD = Relative deviation

Ca = mercury concentration of trap a

Cb = mercury concentration of trap b

Results from the paired traps are considered to be in agreement if they differ by less than or equal to (a) 10% if the concentration is greater than 1.0 μg/m³, or (b) 20% if the concentration is less than or equal to 1.0 μg/m³. The same criteria are given for paired traps in Method 30B. PS‐12B RD results are also acceptable if the absolute difference between concentration from paired taps is less than or equal to 0.03 μg/m³.

Spike Recovery Study

Before analyzing the field samples, the laboratory must conduct a spike recovery study. This involves spiking traps with elemental mercury at three different concentrations over the range of the mass concentration expected in the field samples. Three traps are spiked at each concentration level in the third trap section. A separate spike recovery study is required for each type of sorbent material used and for each range encountered in the field. The average of spike recovery at each concentration is required to be between 85 and 115%.

The spike recovery R, is calculated according to Equation 12‐5.

(12‐5)equation

where mrecovered is the mass of mercury recovered from the mass of the mercury on the spike, mspike

Field Sample Spike Recoveries

The third sorbent section of each trap used in the field is spiked with a known quantity of elemental mercury, ranging from 50 to 150% of the anticipated mercury mass captured in the first section during a sampling run. Laboratory recoveries of the mercury spiked in the third section of the trap must range between 75 and 125% for each trap.

If a leak check fails, if proportional sampling is not maintained, or the spike recovery criteria are not met.

If one of the two sample traps fails to meet the sampling criteria, or if the trap is lost or damaged, and the other trap meets the criteria, data from the valid trap may be used for reporting purposes if a punitive factor of 1.111 is applied

Advantages and Disadvantages of Sorbent Trap Systems

The primary advantage of installing sorbent trap mercury monitoring systems is that their initial cost is lower than the costs for Hg CEM systems. Also, maintenance of the systems is generally straightforward, involving pumps, meters, and controls technicians are most familiar with. Additionally, for sorbent trap systems, since daily calibration verifications and periodic integrity checks for HgCl₂ are not required, issues associated with elemental mercury and mercuric chloride calibrators and calibration gas transport are avoided. Differences between mercury CEM system and sorbent trap system mercury data due to high bromine levels have been discussed by Staudt (2014).

Sorbent trap systems do require that new traps be purchased for each sampling period. At the end of the sampling period, the traps have to be removed and new ones installed, following the chain of custody procedures between the sampling location and laboratory where they are analyzed. Technicians tasked with this activity must remove a hot, heavy probe from the stack and delicately remove and replace the glass sorbent traps (Figure 12‐19). Depending on the installation, weather conditions may make this task more difficult. In the long run, when counting the cost of traps and their analysis, along with the manpower associated with sustaining the change‐out procedures, cost differences between the instrumented systems and sorbent trap systems may not be as great as expected.

Because sorbent trap systems measure mercury emissions periodically and not continuously, they are not useful for real‐time process control. Without knowing instantaneous mercury emissions, a source may inject more activated carbon than necessary to assure compliance with mercury emission limits.

Figure 12‐19 Removing sorbent traps.

Alternatively, carbon costs can be managed by continuously monitoring the mercury emissions and adjusting carbon injection rates to meet emission limitations. Some facilities have chosen to purchase and use Hg CEM systems as “process monitors,” to control activated carbon injection and retain sorbent trap systems to monitor compliance. Because a process monitor is not required to meet the quality assurance criteria for calibration and calibrators, the operation and maintenance costs are expected to be lower than if it were to be used as a compliance monitor.

EPA reports that in 2019, 204 sorbent trap monitoring systems were installed by units reporting hourly data under the MATS rule. This is in contrast to 212 installed continuous mercury monitoring systems, with 47 units installing both sorbent trap and continuous mercury monitoring systems (U.S. EPA 2020k).

CONTINUOUS MERCURY MONITORING SYSTEMS – CERTIFICATION

PS‐12A and 12B Performance specifications for continuous mercury monitoring system, and sorbent trap systems were published in 75 FR 54970, 9 September 2010 as part of the Portland Cement Part 60/63 Final Rules (U.S. EPA 2020e, f). However, mercury monitoring systems required for electric generating units under the MATS rule follow an alternative set of specifications found in 40 CFR 63 Subpart UUUUU Appendix A.

Both sets of specifications are similar to those of other gases, except a relative accuracy of 20% is given instead of the 10% set for criteria pollutants. The performance specifications apply to the measurement of total gaseous mercury, where the concentration is expressed in micrograms per cubic meter (μ/m³) of vapor‐phase mercury.

Part 60 Continuous Mercury Monitoring System Certification Requirements – Instrumented systems

For mercury monitoring systems subject to the CEM certification requirements of Part 60, Performance Specification 12A, require three specifications to be met: Measurement Error (ME), Calibration Drift (CD), and Relative Accuracy (RA). The specifications are summarized in Table 12‐11.

TABLE 12‐11 Part 60 Performance Specifications for Continuous Mercury Monitoring Systems

Test | Certification Test Performance Specifications
Measurement error (Linearity) | │R – A│≤ 10.0% of Span (low, mid, high reference gases)
Calibration drift (7‐day) | │R – A│≤ 5.0% of Span (zero and upscale gas)
Relative accuracy test audit | RA ≤ 20.0% or │RMavg – CEMavg│ + │CC│ ≤ 0.5 μg/m³ if RMavg < 2.5 μg/scm with RD ≤ 10.0% for each of the 9 runs or RD ≤ 20.0% or │ ≤ 0.2 μg/scm│ if Hgo ≤ 1.0 μg/m³

The measurement error (linearity) test may be conducted using either elemental mercury or ionic mercury reference gases. Gases at three concentrations at 0–20, 50–60, and 80–100% of the span value are injected alternately, as close to the probe as is practical, into the monitoring system. The measurement error (ME) is calculated at each of the concentrations, using Equation 12‐6.

(12‐6)upper M upper E equals StartFraction StartAbsoluteValue upper R minus upper A EndAbsoluteValue Over upper S p a n EndFraction times 100

The 10% specification must be met at each of the test concentrations. Note that the ME calculation is expressed as a percentage of the analyzer full scale (span) value, not the reference gas concentration as in the Linearity Error (ER) calculation of Part 75.

The seven‐day calibration drift (CE) test is the same as the calibration drift tests of Part 60 and Part 75, and again, may be conducted using either elemental or ionic mercury reference gas.

The reference test methods allowed when conducting the relative accuracy test audit (RATA) are specified in the implementing rules for monitoring systems. These include methods 29, 30A, 30B, or the Ontario Hydro method – ASTM D6784 (U.S. EPA 2020d; ASTM 2020). However, Method 30B is applied most often due to its ease of use in measuring vapor‐phase mercury. Method 30A is rarely performed, due to the cost and effort necessary to set up the equipment.

If either Method 29, 30B, or ASTM D6784 is used in the test, the reference method sampling must be conducted using paired or duplicate sampling trains. The average of the two measurements for each run is used in calculating the relative accuracy if the relative deviation (RD) between the two is less than 10.0% (or <20% if the mercury concentration is less than 1.0 or ≤0.2 μ/m³ difference between the pairs).

For cement plants with in‐line raw mills, RATAs are conducted only when the mill is on. Mercury emissions when the raw mill is off are elevated and too variable to be used when calculating relative accuracy.

Part 63 MATS Rule Certification Requirements for Electric Generating Units

Electric generating units (EGUs) that monitor mercury using Hg CEM systems follow a different set of certification procedures than those given in PS‐12A, discussed above. The EGU MATS Rule certification requirements are found in 40 CFR 63 subpart UUUUU Appendix A (U.S. EPA 2020j). The MATS rule requirements for both certification and quality assurance were based on the requirements established by the Part 75 program and integrated into the Clean Air Mercury Rule. As discussed in the first section of this chapter, the Clean Air Mercury Rule was deleted from the Code of Federal Regulations after it was vacated and EGU mercury regulation transferred to the air toxics program.

For Hg CEM systems certification in the MATS rule, five specifications are required to be met: Linearity Error (LE), Calibration Error (CE), and Relative Accuracy (RA).

The specifications are summarized in Table 12‐12.

TABLE 12‐12 Part 63 EGU Performance Specifications for Hg CEM Systems

Test | Certification Test Performance Specifications
Calibration error (7‐day) | │R – A│ ≤ 5.0% of Span (zero and upscale gas) or │R – A│ ≤ 0.8 μ/scm (may be used any day of test)
Linearity check (Hgo) | │R – A│ ≤ 10.0% of Hgo Reference Gas Concentration (low, mid, high) or │R – A│ ≤ 0.8 μ/scm (may be used any gas level)
3‐level system integrity test (Hg²⁺) | │R – A│ ≤ 10.0% of Hg²⁺ Reference Gas Concentration (low, mid, high) or │R – A│ ≤ 0.8 μ/scm (may be used any gas level)
Relative accuracy test audit | RA ≤ 20.0% or │RMavg – CEMavg│ + │CC│ ≤ 0.5 μg/m³ if RMavg < 2.5 μg/scm with RD ≤ 10.0% for each of the 9 runs when Hgo > 1.0 μg/m³
Cycle time test | 15 Minutes

Note the differences from Tables 12‐11 and 12‐12

Alternate specifications, not offered in PS‐12A, are given for the calibration error test, the linearity check, and the integrity test. These alternate specifications are expressed not as a percentage, but as a mean difference between the reference value and the system reading.

The linearity test is conducted using low‐level (20–30% of span), mid‐level (50–60% of span), and high‐level (80–100% of span) gases.

The “3‐level system integrity test” is included as an additional “linearity test”, where an NIST traceable source of oxidized mercury is injected at three different concentrations to obtain the “system integrity error” (SIE) at each concentration level.

The alternate relative accuracy, │RMavg –  CEMavg│ + │CC│, for electric generating units is more stringent, where the calculation includes the addition of the confidence coefficient, CC, and the value of the difference allowed is reduced from 0.8 to 0.5 μg/scm.

A cycle time test is included, where a zero‐level and a high‐level gas are injected into the system. The time taken for the system to register 95% of the way between initial and final stable readings is taken as the response time.

Sorbent Trap Monitoring Systems – Certification

Sorbent trap monitoring systems are certified using Performance Specification 12B of 40 CFR 60 and, as applicable, Appendix A of the MATS rule. Because there are no daily calibration error checks for sorbent trap system, there is only one performance specification that has to be met: relative accuracy. As in any other RATA, relative accuracy is determined from at least nine concurrent measurements against a reference method, following the same methodology as that given in PS‐12A. The reference method may be Method 30A, 30B, or ASTM D6784. The relative accuracy criteria are given in Table 12‐13.

That the relative accuracy criteria for certifying a sorbent trap monitoring system are the same as for certifying a continuous mercury monitoring system.

TABLE 12‐13 Performance Specification for Sorbent Trap Systems

Test | Certification Test Performance Specifications
Relative accuracy test audit | RA ≤ 20.0% or │RMavg – CEMavg│ ≤ 1.0 μg/scm if RMavg < 5.0 μg/scm with RD ≤ 10.0% for each of the 9 runs or RD ≤ 20.0% or │ ≤ 0.2 μg/scm│if Hgo ≤ 1.0 μg/m³

CONTINUOUS MERCURY MONITORING SYSTEMS – QUALITY ASSURANCE

Quality assurance procedures for mercury CEM systems and sorbent trap systems are found in Appendix F Procedure 5 of 40 CFR 60, for source categories subject to that rule (U.S. EPA 2020g). The QA requirements were published in 75 FR 54970, 9 September 2010 as part of the Portland Cement Part 60/63 Final Rules, as were the certification criteria (U.S. EPA 2010). Mercury monitoring systems required for electric generating units under the MATS rule follow the alternative set of requirements found in 40 CFR 63 Subpart UUUUU Appendix A.

Part 60 Quality Assurance Requirements

The Appendix F procedures require periodically conducting tests that check the ongoing performance of the system certification. The tests and quality control criteria are listed in Table 12‐14.

TABLE 12‐14 Part 60 Appendix F Procedure 5 Quality Control Criteria for Hg CEM Systems

Frequency
Test
Quality Control Criteria

Daily
Calibration drift check (CD)
(Hgo)
Adjust analyzer if │R – A│ > 10.0% of Span (low and high level)
Out‐of‐Control if │R – A│ > 10.0% for 5 consecutive days
Out‐of‐Control if │R – A│ > 20.0% for any CD check

Weekly
Systems integrity test (SI) Hg²⁺
No criteria given.

Quarterly
Quarterly gas audit (QGA)

(Hgo) and (Hg²⁺)
Out‐of‐control if │R – A│ > 15% of Hgo Concentration (low, mid, high) or │R – A│ > 0.5 μ/m³ of Hg²⁺ Concentration (low, mid, high) or │R – A│ > 0.5 μ/m³

Annually
Relative accuracy test audit (RATA)
RA ≤ 20.0% or │RMavg – CEMavg│ + │CC│ ≤ 0.5 μg/m³ if RMavg < 2.5 μg/scm with RD ≤ 10.0% for each of the 9 runs when Hgo > 1.0 μg/m³

The calibration drift check is performed daily at the zero (or low level) and a high level using elemental mercury. The system is required to be adjusted if the drift exceeds twice the value of the measurement error specification (ME) given in Performance Specification 12A, which is 5.0% of span. A weekly system integrity (SI) check (e.g. a calibration drift test using Hg²⁺ instead of Hgo) is required in §3.1(c) of Procedure 5; however, no adjustment or out‐of‐control criteria are given for this test.

A repeat of the measurement error (ME) test conducted during system certification is required quarterly. The test is conducted by challenging the Hg CEM system with a zero‐level gas and two upscale gases, one at 20–30% of the span value and one at 50–60% of the span value. The measurement error test conducted during certification required testing the system with Hgo only. The Procedure 5 quarterly gas audit (QGA) requires challenging the system with both Hgo and Hg²⁺. The QA relative accuracy audit (i.e. a three‐run RATA) may be run in lieu of a quarterly gas audit. An RAA passes if the relative accuracy is less than 20% of the reference method value or less than 20% of the emissions standard.

A relative accuracy audit must be conducted annually. The allowable relative accuracy for the annual audit is the same as that for certification, given in 40 CFR 60 Appendix B Performance Specification 2.

The Procedure 5 quality control criteria are essentially mimicking those given in Appendix F Procedure 1 for SO₂ and NOx analyzers, promulgated in 1989. Unfortunately, Procedure 5 is not consistent with the more relevant Hg CEM systems quality control criteria given in the MATS rule.

Part 63 MATS Rule Quality Assurance Requirements for Electric Generating Units

As with the Hg CEM systems certification criteria, EGUs using Hg CEM systems follow quality control requirements given in the MATS rule. These requirements were again derived from the more advanced rules of the Part 75 program and better reflect the capabilities of today's monitoring systems. The ongoing quality control test requirements and acceptance criteria for EGU Hg CEM systems are given in Table 12‐15.

The MATS rule quality assurance requirements differ from those given in Appendix F as follows:

In the MATS rule, calibration error (CE) corresponds to the calibration drift (CD) given in Table 12‐14. In the MATS rule, the reference gas used in the daily calibration check may be either at a mid‐level or a high level and it is clarified that daily calibration verifications are not required when the unit is not operating.

A weekly, single‐level system integrity check using oxidized mercury is required in the MATS rule as it is in Part 60 Appendix F. However, in contrast to Appendix F, where no criteria are given for passing the test, the MATS rule specifies an acceptance criterion: the deviation of the instrument response from the reference gas value must be ≤10.0% of the Hg²⁺ reference gas value. Note that in contrast to the daily calibration error test, the acceptance criterion is expressed as a percentage of the reference gas value and not as a percentage of the span value.

TABLE 12‐15 Part 63 EGU Quality Assurance Requirements for Hg CEM Systems

Frequency | Test | Acceptance Criteria
Daily | Calibration error test (Hgo) | │R – A│ ≤ 5.0% of span value (zero and mid or high level) using Hgo or │R – A│≤ 1.0 μ/scm
Weekly | System integrity test (Hg²⁺) | │R – A│ ≤ 10.0% of Hg²⁺ reference gas value (mid or high level) or │R – A│≤ 0.8 μ/scm
Quarterly | Linearity check (Hgo) or 3‐level system integrity test (Hg²⁺) | │R – A│ ≤ 10.0% of Hgo reference gas value (low, mid, high) or │R – A│≤ 0.8 μ/scm (may be used any gas level)
Annually | Relative accuracy test audit | RA ≤ 20.0% or │RMavg – CEMavg│ + │CC│ ≤ 0.5 μg/scm if RMavg < 2.5 μg/scm with RD ≤ 10.0% for each of the 9 runs when Hgo > 1.0 μg/m³

The quarterly linearity check (Appendix F quarterly gas audit [QGA]) may be performed using either elemental or oxidized mercury. If oxidized mercury is used, the test could also be called a three‐level system integrity test. Again, note that the acceptance criterion is given as a percentage of the reference gas value, and not as a percentage of span. If it is found difficult to meet this criterion (particularly when using the low‐level gas), an alternative criterion may be used:│R – A│ ≤ 0.8 μ/scm.

The relative accuracy acceptance criteria in the MATS rule are identical to the criteria given for initial certification.

In this program, if a mercury CEM system does not meet acceptance criteria, it is considered to be out‐of‐control and the CEM system data cannot be reported as being “quality‐assured.” Also, if a quality control test such as a weekly integrity test or a quarterly linearity test is not performed on schedule, the CEM system is considered to be out‐of‐control. However, a 168 operating hour grace period is allowed for the quarterly tests and a 720 operating hour grace period is allowed for the annual RATA.

Sorbent Trap Mercury Monitoring Systems – Quality Assurance

Because sorbent trap monitoring systems are required to undergo extensive quality control procedures for both sampling and analysis, no quarterly quality control procedures are mandated under Appendix F 40 CFR 60 or the Appendix A of the 40 CFR 63 MATS Rule. The only procedure required under either Part 60 or Part 63 is for conducting an annual RATA (see Table 12‐13).

REFERENCE TEST METHODS FOR MERCURY

Mercury reference test methods are used for determining compliance with mercury emission limits, verifying its status as a low‐emitting electric generating unit (LEE status) for coal‐fired power plants, certifying Hg CEM systems, demonstrating compliance with control equipment performance guarantees, and conducting studies to determine control or monitoring strategies. Each method discussed below has its own range of application; however, the most commonly used method today is U.S. EPA Method 30B, the sorbent trap method. The Ontario Hydro Method, ASTM D6784, has been used primarily for source characterization, due to its capability of determining separately, particle‐bound, elemental, and ionic mercury.

Ontario Hydro Method – Standard Test Method for Elemental, Oxidized, Particle‐Bound and Total Mercury in Flue Gas Generated from Coal‐Fired Stationary Sources (ASTM D6784)

The Ontario Hydro method is used to measure total mercury and, for speciation, to measure the relative concentrations of elemental, ionic, and particulate‐bound mercury. The Ontario Hydro method was developed in 1994 by the Canadian utility, Ontario Hydro (now Ontario Power Generation) in their source testing laboratory. It was standardized by ASTM in 2002 as ASTM D6784 and was updated in 2016 to include additional quality assurance procedures.

The method utilizes an isokinetic sampling train to collect particle‐bound mercury on a heated filter, and a series of impingers in an ice bath to collect elemental mercury vapor and oxidized forms of mercury (Figure 12‐20).

Oxidized mercury is collected in a potassium chloride solution contained in the first three impingers and elemental mercury is collected in the two impingers containing 10% H₂SO₄/4% KMnO₄. To prevent flue gas SO₂ from reaching and reacting with the permanganate in the following impingers, the preceding impinger contains an acidified hydrogen peroxide solution to remove SO2. The last impinger contains silica gel to dry the remaining gas before it enters the pump and dry gas meter.

Figure 12‐20 The Ontario Hydro sampling train.

The Ontario Hydro method was extensively validated in the late 1990s and was used to evaluate the performance of Hg CEM systems in the numerous field demonstrations conducted in the period 1995–2005 (Laudal et al. 1997, 2007). It was also used to evaluate the efficacy of the sorbent trap method, which eventually became EPA test method 30B. The Ontario Hydro method is a complicated method to perform and requires a considerable amount of glassware and chemicals. The laboratory analysis procedures are likewise complicated and require experienced analysts. In the final steps, a solution of 10% stannous chloride in 10% HCl is added to the digested sample solutions to reduce the Hg²⁺ in solution to elemental mercury (Hgo), e.g.

Mercury is swept out of solution with a carrier gas, such as argon or nitrogen, to an absorption cell of a cold vapor atomic absorption spectrometer (CVAAS) or cold vapor atomic fluorescence spectrometer (CVAFS) to determine the mercury (Hgo) concentration.

It is necessary to follow carefully the quality assurance procedures outlined in ASTM D6784 if reproducible results are to be obtained. These include calibration procedures, evaluation of blanks, and pre‐ and posttest leak checking (Ryan and Keeney 2004).

Although less commonly used today, the Ontario Hydro method remains the standard to which other test methods are evaluated and may be employed in new applications where the influence of interfering gases or other flue gas conditions may not be well understood when using the sorbent trap method.

EPA Test Method 30A – Determination of Total Vapor‐Phase Mercury Emissions

Method 30A is an instrumental test method designed to measure total vapor‐phase mercury (Hg⁰ and Hg²⁺) in flue gases in units of μ/m³. It can be used to determine compliance with emission limits and to conduct relative accuracy test audits (RATAs) on installed mercury CEM systems and sorbent trap systems (U.S. EPA 2020b). The method is intended primarily for testing at coal‐fired boilers, but can be applied to other source categories subject to mercury regulations.

The design characteristics of the sampling and analytical system used to perform the method are the same as those of an installed total vapor‐phase mercury monitoring system. Specifically, the system must provide a means for converting ionic mercury to elemental mercury and the probe, sampling line, pump, and other wetted components must be chemically inert to elemental mercury and mercury compounds. The system must include a port for dynamic spiking, to introduce a spike gas of known concentration of vapor‐phase HgCl₂ as close as possible to the inlet of the probe. The port used for system calibrations may be used for this purpose.

The method provides procedures for stratification testing, allowing single point sampling if it can be shown that mercury concentrations are unstratified over the sampling cross section. The flue gas is considered unstratified if the mercury concentration at each of 12 sampling points on the cross section differs by less than ±5% of the mean concentration or ±0.2 μg/m³.

An interference test should be conducted by the tester or the system manufacturer (on a like‐kind system) prior to the test. Calibration gases or other calibration standards that are produced from calibration gas generators should be checked to assure that the gases are traceable to NIST standards. Prior to sampling, a three‐point system calibration error test and response time test is conducted using low‐, mid‐, and high‐level Hg⁰ standards, by injecting each gas once into the system.

A system integrity test using a zero gas and either a mid‐ or high‐level HgCl₂ calibration gas is also required prior to and after sampling. An integrity test is also required after each sampling test run, but this requirement may be skipped at the risk of invalidating run data if the last conducted integrity test should fail. Calibration drift is calculated from the pre‐ and post‐run system integrity check data. Both the zero (low‐level) and upscale drift are calculated after each run. The drift over the run must be less than or equal to an absolute difference of 3% of span, or an absolute difference of ≤0.3 μm³.

Before the actual sampling is conducted, “dynamic spiking test” must be performed. This involves sampling the flue gas, and while sampling, injecting a known amount of HgCl₂ into the sample gas stream and where the spike flow rate is to ≤20% of the total volumetric flow rate. The injection is done upstream of the filter, chiller, dilution orifice, or any other sample conditioning components of the system. The concentration of the HgCl₂ must follow EPA traceability protocols. A spike is injected three times to obtain three data points.

The calibration error must be ≤ ±5.0% as a percent of the span value for each of the low‐, mid‐, and high‐level certified calibration gases, or alternatively ≤0.5 μm³ difference between the response of the monitoring system cylinder gas concentration. The mean value of the spike recovery must be 100 ± 10% and the spiked sample concentration, or ≤0.5 μm³ absolute difference between the two.

The one case in which this method was used was reported by Sjostrom and Modrak (2010). Considering the expense of purchasing an instrumented mercury monitoring system, the effort associated with transporting it to the sampling location, the necessity of supplying or generating both Hg⁰ and HgCl₂ calibration gases, and the risks involved in meeting the method performance tests, this method is seldom used by source testers to perform either compliance tests or RATAs. Method 30B, using carbon sorbent traps, is a much simpler test method and is found to have an accuracy equivalent to that obtainable by Method 30A. Consequently, it has become the preferred mercury test method.

EPA Test Method 30B – Determination of Total Vapor‐Phase Mercury Emissions from Coal‐Fired Combustion Sources using Carbon Sorbent Traps

The complexity of the Ontario Hydro method led to comparative studies of alternative methods for monitoring mercury that might be more easily performed at lower expense. The most promising of these methods was the use of carbon sorbent traps, and numerous field studies were conducted comparing the two methods (Cheng et al. 2009). When these evaluation studies showed that the sorbent trap methods could give results comparable to the Ontario Hydro method, the sorbent trap method became the method of choice, resulting in the publication of EPA Method 30B for mercury compliance testing and certification of Hg CEM systems (U.S. EPA 2020c).

Method 30B was intended for monitoring total vapor‐phase mercury in coal‐fired combustion sources, but is used also for determining compliance with mercury emission limits and certifying Hg CEM systems at other types of sources, such as cement plants and municipal waste combustors. The method is applied where low levels of particulate matter are expected, typically after particulate control equipment. In the method, flue gas is pulled through a set of paired sampling traps. The traps are glass tubes containing iodated carbon in two sections. For quality control, the first section is pre‐spiked with a known amount of mercury to determine measurement biases in the test. The second section is used to catch any mercury breaking through the first trap during a sample run. Paired traps are required in the method, so sampling is conducted using two sampling trains (Figure 12‐21).

The sampling time is based on the “minimum sampling mass,” which is based on the mercury levels expected and the breakthrough criteria. If the source mercury level is unknown, a diagnostic test run may be needed prior to formal testing. A minimum sampling time of 30 minutes is required for relative accuracy test audits, and 60 minutes for compliance determinations.

The sorbent traps are subsequently removed from the sampling system and the mercury removed from the traps by thermal desorption or by combusting the carbon directly. Alternatively, the mercury adsorbed in the tubes can be transferred into a liquid solution by acid leaching, although this method is not commonly used. Analysis of the elemental mercury is performed by using ultraviolet atomic absorption, fluorescence, or other spectrophotometric techniques.

There are a number of quality control criteria that must be met in order for the test results to be acceptable. The most important of them are (i) criteria for breakthrough to the second trap, (ii) relative deviation between the results from the paired traps, and (iii) spike recovery Table 12‐16

Figure 12‐21 Method 30B sampling train.

EPA Test Method 29 – Determination of Metals Emissions from Stationary Sources

The Ontario Hydro method was based on EPA test Method 29 (U.S. EPA 2020a); however, Method 29 is used to measure total mercury and does not speciate other than determining the particulate‐bound fraction and total gaseous mercury separately. The method is also applied for measuring 15 other metals, including chromium, nickel, arsenic, and selenium. It is often used for annual multi‐metals compliance testing for sources subject to MACT standards, where a continuous particulate monitor is not used as a surrogate method.

In contrast to the Ontario Hydro method, Method 29 does not utilize 1N KCl to collect oxidized mercury prior to the HNO₃/H₂O₂ and KMnO₄/H₂SO₄ impingers (see Figure 12‐1). In the analysis, aliquots of digested samples are analyzed for mercury and all other metals. The method specifies atomic absorption spectroscopy for the mercury analysis and inductively coupled argon plasma emission spectroscopy (ICAP), atomic absorption spectroscopy (AAS), or graphite furnace atomic absorption spectroscopy (GFAAS) for the analysis of metals other than mercury.

EPA Test Method 101A – Determination of Particulate and Gaseous Mercury Emissions from Sewage Sludge Incinerators

Method 101A is a total mercury method similar to Method 29, but is even simpler, using three impingers containing 10% H₂SO₄/KMnO₄, but no impingers containing HNO₃/H₂O₂ or KCl. The method is specified for testing at sewage sludge incinerators (U.S. EPA 2020d).

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CHAPTER 13
MONITORING HAZARDOUS AIR POLLUTANTS

Hazardous air pollutants, also known as toxic air pollutants or “air toxics,” are known to cause cancer or other serious health effects. For these pollutants, the emission control criteria, emission limits, performance test requirements, and continuous monitoring rules are found primarily in the U.S. Code of Federal Regulations under 40 CFR 63. These are also called the “MACT” standards, which are based on the emission control achieved by the single best controlled plant within a source category. This level of control is called “maximum achievable control technology” or “MACT” and must be met by any new and reconstructed plants. In this sense, the standards are based initially on what can be achieved by the best available control technology and not on the health risks of the pollutants.

PART 61 NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAPS)

Air toxics were first required by the 1970 Clean Air Act, where health‐based standards were developed. These earlier “national emission standards for hazardous air pollutants” (NESHAPs) were published in 40 CFR 61, and in contrast to the Part 63 MACT standards, are based on health risks rather than the effectiveness of emissions control technology (U.S. EPA 2020i). However, standards for sources of vinyl chloride, benzene, and arsenic were only developed in the Part 61 NESHAPs program for hazardous air pollutants.

Congress directed EPA in §112(c) of the 1990 Clean Air Act Amendments to develop further regulations for air toxic pollutants. The implementing rules written consequently by EPA were substantially completed by 2015 and incorporated in a new part to the Code of Federal Regulations – Part 63 (U.S. EPA 2020f). The task of establishing requirements for the control and measurement of 187 toxic air pollutants (U.S. Government 1990) for more than 174 industrial source categories (U.S. EPA 2020h) resulted in EPA publishing 128 Subparts in 40 CFR 63. The use of the term “NESHAPs” also applies to the standards published in Part 63; however, its use can be sometimes confusing due to its association with the previous Part 61 program.

This chapter discusses the general provisions of Part 63 as they apply to CEM systems, provides a guide to the source‐specific CEM requirements, and addresses the analyzers that are commonly used in meeting those requirements.

40 CFR 63 AIR TOXICS PROGAM GENERAL PROVISIONS

The general provisions of Part 63, as in other parts of Title 40 of the Code of Federal Regulations, apply to the source‐specific subparts that follow in the rule (U.S. EPA 2020g). Definitions, general monitoring requirements, notification and recordkeeping procedures are established to be consistent for all the subparts. However, the general provisions of one part of Title 40 may not be consistent with those of another part. That is the case in Part 63 in which definitions and general monitoring requirements are not all consistent with those of Part 60 or Part 75 (U.S. EPA 2020a). This can be a problem for stationary sources that are regulated under more than one part, which is the case for electric generating units, petroleum refineries, cement plants, and others.

Definitions (§63.7)

In Part 63, distinctions between continuous emission monitoring systems, continuous monitoring systems, and continuous parameter monitoring systems are important. The CFR Part 63 definitions are:

A continuous emission monitoring system (CEMS) means the total equipment that may be required to meet the data acquisition and availability requirements of this part, used to sample, condition (if applicable), analyzer and provide a record of emissions.

A continuous monitoring system (CMS) is a comprehensive term that may include, but is not limited to, continuous emission monitoring systems, continuous opacity monitoring systems (COMS), continuous parameter monitoring systems (CPMS), or other manual or automatic monitoring that is used for demonstrating compliance with an applicable regulation on a continuous basis as defined by the regulation.

A continuous parameter monitoring system (CPMS) means the total equipment that may be required to meet the data acquisition and availability requirements of this part, used to sample, condition (if applicable), analyzer and provide a record of process or control system parameters.

The distinction between these definitions is important and must be remembered when applying Part 63 monitoring requirements. Most importantly, note that a CMS can be either a CEMS or a CPMS, either of which can be used to demonstrate continuous compliance.

Performance Testing (§63.7)

Performance tests are reference test methods specified in each subpart that are conducted to demonstrate compliance with emission limitations. If the unit is in compliance with emission limits, process parameter values taken at the time of the test can be used to set unit or control equipment parameter limits. As mentioned in Chapter 2, performance tests should not be confused with “performance specification tests,” which are the procedures given in 40 CFR 60 Appendix B to certify continuous emission monitoring systems (see Chapter 11) (U.S. EPA 2019d).

The agency Administrator is to be notified 60 days prior to the date the performance test is scheduled. It is important to note that a site‐specific plan is required to be submitted to the Administrator prior to the test. In addition to a discussion of how the test will be performed, the plan is also required to include data quality objectives and a test quality assurance program. An adequate test plan will be specific to the anticipated test.

Monitoring Requirements (§63.8)

Part 63.8 monitoring requirements address continuous monitoring systems (CMS) generically, whether they are continuous parameter monitoring systems (CPMS), continuous emission monitoring systems (CEMS), or continuous opacity monitoring systems (COMS). The requirements are written from the point of view of CEM hardware installation and are sometimes difficult to interpret for a continuous parameter monitoring system, which can evolve to be basically a sensor management program. Nevertheless, a Part 63 CEM system (or CPMS) must meet the operation and maintenance requirements given in 40 CFR 63.8(c), paraphrased as follows:

The CMS (either a CEM system or CPMS) must be maintained and operated in a manner consistent with good practice.

A start‐up, shutdown, and malfunction plan must be developed and written.

The CMS must be installed such that emission (or parameter) measurements are representative. CEMS must be installed in locations according to the applicable performance specification.

A visual display or other indication of operation must be readily accessible on‐site for operational control or inspection by the operator.

The CMS shall be verified to be operational prior to or during the facility compliance (performance) test.

All CMS shall be in continuous operation, except when they are not.

CEMS shall complete one cycle of operation for each successive 15‐minute period. COM system for each 6‐minute period.

CEM systems shall check low‐ and high‐level calibration drifts daily.

A CEM system is out‐of‐control if the calibration drift and/or linearity drift exceed two times the applicable performance specification for the system (as per the relevant performance specification 40 CFR 60 Appendix B).

When the system is out‐of‐control, take corrective action and fix it. Repeat applicable performance tests (drift, linearity, or relative accuracy) to verify that it works.

A CMS quality control program shall be developed and implemented. As part of the quality control program a site‐specific performance evaluation test plan for the CMS performance evaluation, including procedures for the following operations.

CMS calibration

Calibration drift determination and adjustment

Preventive maintenance, including a spare parts inventory

Data recording, calculations, and reporting

Accuracy audits including sampling and analysis methods

CMS malfunction corrective action

All of these requirements are basically the same as those for a CEM system required to be installed under a Part 60 or Part 75 program. The requirement that a display of monitoring information be available for operational control (No. 3 above) is consistent with the viewpoint given to the introduction of this book (see Figure 1-2), that the purpose of a CEM system is to enable the unit operator to optimize plant and control equipment operation to be continually in compliance with emission limitations.

However, one major difference in these requirements and those given in Part 60 and Part 75 is in reporting required for out‐of‐control periods. Here Part 63.8(c)(8) requires the following:

The owner or operator of a CMS that is out of control as defined in paragraph (c)(7) of this section shall submit all information concerning out‐of‐control periods, including start and end dates and hours and description of corrective actions taken in the excess emissions and continuous monitoring system performance report required in §63.10(e)(3).

It should be noted by the plant environmental engineer or environmental compliance officer that, in contrast to Part 60 where such records are only required when CEM system availability is less than 95% [see 40 CFR 60.7(c)(3)], Part 63 requires that they be submitted for any out‐of‐control period. This requirement may necessitate training CEM technicians to provide adequate records for CEM system downtime, or may provide the impetus to take steps to reduce the number of reportable out‐of‐control periods if they occur too frequently.

Quality Control Programs [§63.8(d)]

When using a continuous monitoring system (either a CEMS or CPMS), Part 63.8(d) requires that a quality control program be developed and implemented. The requirements for the program are basically the same as those given in 40 CFR 60 Appendix F for NSPS CEMS. The monitoring plan is to include

a site‐specific performance evaluation test plan for the periodic CMS performance evaluations required in §63.8(e). The test plan is to include

evaluation program objectives;

evaluation program schedule and summary;

data quality objectives;

internal and external quality assurance program.

Written procedures for

initial calibration and calibration adjustment;

preventive maintenance;

data recording, calculation, and reporting;

accuracy audits;

corrective action.

Basically, a quality assurance manual must be written. More importantly, it must be implemented. The manual is subject to agency audit and review and must be available on‐site. Whether or not the procedures are performed as written and as scheduled can be a focus of any agency inspection.

In §63.6 “Compliance with Standards and Maintenance Requirements” of the General Provisions, the source owner or operator must also develop a written start‐up, shutdown, and malfunction (SSM) plan that describes procedures for operating and maintaining the source during those periods. This includes monitoring equipment used to comply with the relevant standard [§63.6(e)(iii)(i)]. Quality control procedures developed for the CMS should be the same for either the QA Plan or SSM Plan.

Performance Evaluation of CEMS [§63.8(e)]

The site‐specific evaluation test plan developed for the quality control program is submitted to the Administrator at least 60 days prior to a CMS performance evaluation.

Recordkeeping and Reporting (§63.10)

The recordkeeping requirements of Part 63 are more stringent than those of Part 60. CEM technicians and environmental engineers more familiar with Part 60 procedures may lack the information necessary to prepare Part 63 HAP reports if CMS maintenance records are inadequate. Records specifically required to be maintained for Part 63 CMSs are listed in §63.10(b) and 63.10(c). Specifically, for continuous monitoring systems, §63.10(c) specifies that the following records be maintained:

All required CMS measurements (even during out‐of‐control periods)

The date and time when CMS is inoperative

The date and time when CMS was out‐of‐control

The date and times of all excess emission periods, including start‐up/shutdown/maintenance periods

Nature and cause of any malfunctions

Corrective actions taken

Preventive measures adopted

Nature of repairs or adjustments to the CMS total process operating time during the reporting period

Excess emissions and continuous monitoring system performance reports are to be submitted semiannually, unless otherwise determined [§63.8(e)(3)]. For periods of excess emissions all of the information for items 2–8 above in the report. Unless CMS operation and maintenance information is well documented in logbooks, forms, or otherwise, it may take considerable time and effort on the part of the environmental engineer or other responsible party to prepare the report.

PART 63 SUBPARTS – SOURCE‐SPECIFIC HAP MONITORING REQUIREMENTS

Source‐specific monitoring requirements are given in Part 63 for both “major” and “area” sources. For the purposes of the air toxics program, major sources are defined as those that emit greater than 10 tons/year of any one of the 187 listed air toxics or 25 tons/year of multiple listed air toxics. Area sources are smaller‐size facilities that emit less than those amounts. Both are addressed in Part 63 subparts.

The Part 63 subparts extend continuous emission monitoring requirements for larger emitters such as electric utilities, cement plants, petroleum refineries, and industrial boilers. However, for the majority of effected sources, relatively few new CEM systems are required. Process and/or control system parameters such as temperatures, pressure drops, and flows are used instead to characterize source operations and control system performance. Emission sources are required to first demonstrate compliance to emission limits set for the hazardous air pollutants specified in the subpart by conducting EPA reference test methods (U.S. EPA 2020c). The parameter values recorded at the time of the compliance test can then be used in the development of a site‐specific monitoring plan.

In the Part 63 rules, a site‐specific monitoring plan is then developed. The plan describes the “continuous monitoring system” (CMS), which details how the source will demonstrate continuous compliance with the emission limitations. As an example, a site‐specific monitoring plan for facilities subject to the EGU MACT (Subpart UUUUU) must address the following items [§63.10000(d)(5)]:

Installation

Performance and equipment specifications

Schedule for conducting initial and periodic performance tests

Performance evaluation procedures and acceptance criteria

Ongoing operation and maintenance procedures

Conditions that define when the CMS is out‐of‐control

Ongoing recordkeeping and reporting procedures

Basically, whether monitoring is conducted by a CEMS or CPMS, the site‐specific monitoring plan describes how the facility will monitor its emissions, describing the units and locations from which emissions are monitored. It also describes monitoring equipment, including analyzers and/or sensors used for monitoring process or control equipment parameters. The plan should include a description of tests and procedures that will be implemented to assure for quality assured data generated from the monitoring system. In contrast to CMS quality assurance plans, the site‐specific monitoring plan should be submitted to the Administrator 60 days before the initial performance test is conducted.

Most of the Part 63 source‐specific subparts provide several options for demonstrating continuous compliance. Many of the source categories in Part 63 are small, relative to larger electric generating units and petroleum refineries. For smaller facilities, the cost of purchasing and operating a CEM system, particularly when measuring organic compounds, acids, and metals, might be considered as excessive, especially if the alternative practice of monitoring process and control equipment operating parameters is allowed. However, parameter monitoring requires development of a CPMS, which when incorporated into the site‐specific monitoring plan must describe how it will be implemented, how the sensors will be maintained, and the actions that will be taken when sensor limits are exceeded. The CPMS and plan may entail keeping track of a wide variety of sensor outputs along with the recordkeeping, necessary for the preparation of required reports.

It is perhaps apparent that standards for toxic air pollutants are replete with acronyms, some of which are contradictory and not especially useful. The Part 63 monitoring requirements themselves vary in their clarity and require detailed examination to determine CEM applicability. Numerous alternatives and options permeate the subparts, requiring attention to the following:

Applicability to existing or new and modified/reconstructed sources

Prior applicability to Part 60 requirements

Elective options between the development of a continuous parameter monitoring system (CPMS) or the installation of a CEM system

Outside of the CEM requirements for the larger emitters mentioned above, Part 63 CEM requirements do little to monitor HAPS directly, requiring opacity monitors or bag leak detectors as surrogates for monitoring metals, or parameter monitoring instead. Although not required in many subparts, CEM systems may still be included in a CMS as part of the monitoring plan as an alternative procedure when approved by the Administrator. This can be done by providing a justification, identifying the parameter to be monitored, explaining why a CEM system would be appropriate, and specifying the monitoring procedures. If approved, the monitoring procedures would be included in the monitoring plan and after which the CEM system would be operated according to the plan.

Requirements for the installation of CEM systems, COM systems, or the institution of a CPM system, a continuous parameter monitoring system (CPMS) is usually given in the text, but can also be found in the tables appending the subpart without reference to the text. Except for major, large emitters, work practice/parameter monitoring requirements predominate in the rules, allowing the tracking of process operating parameters and control equipment parameters to assure continuing compliance after facility performance tests have passed. CEMS and COMS are often options to developing a parameter monitoring program, but are more often required to monitor the performance of pollution control equipment.

Major Sources Affected by the Air Toxics Rule

The CEM implementing rules in Part 63 Subparts can be complex, being dependent upon the regulatory status of applicable units and the continuing compliance options best suited to the facility's environmental management program. Here, the CEM implementation requirements as they relate to analyzers used to measure hazardous air pollutants, are illustrated for several major source categories.

Coal‐Fired Electric Generating Units – 40 CFR 63 Subpart UUUUU – The EGU MACT

As discussed in Chapter 12, the application of 40 CFR 63 to coal‐fired electric utilities was less than straightforward. After legal challenges were resolved, coal‐ and oil‐fired electric utility steam‐generating units MACT rules were promulgated as 40 CFR 63 Subpart UUUUU on 16 February 2012. The standard was subsequently amended with corrections effective 6 April 2016. This subpart is otherwise called the “Utility MACT” or the “Mercury and Air Toxics Standards (MATS)” rule.

The rule requires the installation of continuous emission monitoring systems for particulate matter, mercury, and hydrochloric acid. For particulate matter, particulate matter parameter monitoring systems (PM CPMS) are required as a surrogate for metals monitoring. This type of monitoring has already been discussed in Chapter 9. Continuous mercury monitoring systems or sorbent trap monitoring systems are required for mercury; however, many of the affected units had installed mercury monitoring systems earlier in response to the requirements of the Clean Air Mercury Rule (CAMR), which was subsequently replaced by the MATS rule. These systems have been discussed in detail in Chapter 12. HCl monitors are also required; however, if a wet scrubber is installed to control SO₂, emissions, a CEM system installed for measuring SO₂ can be used as a surrogate for HCl monitoring. This assumes that the scrubbing system will be equally or more effective for removing HCl as it is for SO₂.

Portland Cement Plants – 40 CFR 63 Subpart LLL – The PC MACT

This subpart is otherwise known as the “PC MACT.” Monitoring requirements are given in §63.1350 and also in §63.1349. It requires, where applicable, CEM systems for PM, total organic HAPs [as THC in 63.1350(j)], Hg, and HCl. Although not applicable to cement plants that burn hazardous wastes and are subject to Part 63 Subpart EEE, these plants may petition to use CEMS instead of conducting annual performance tests for these pollutant emissions.

Particulate matter is monitored with the analyzer operating as a PM CPMS. From Chapter 9, this means that the analyzer is calibrated at an operating limit that is within compliance of the particulate emission limitation.

HCl can be monitored with the analyzer operating either as a CEM system or by using an alternative HCl CPMS method. As a CEM system, it would be subject to certification under PS‐18 and quality assurance procedure 6 in 40 CFR 60 Appendix F. As an HCl CPMS, an operating limit, which is within compliance of the HCl emission limit, is determined by conducting a three‐run Method 321 HCl stack test (U.S. EPA 2020c). The CEMS reading becomes a continuous operating parameter that must be met on a 30‐day rolling average. The alternative was provided due to the limited availability of low‐level NIST‐traceable gases at the time.

For units equipped with a wet scrubber or tray tower, an SO₂ monitor may be used in lieu of an HCl CEM system or scrubber parameter monitoring plan [40 CFR 63.1249(b)(6)(iii)]. Here, an SO₂ operating limit is established for demonstrating compliance with the HCl emission limit.

If complying with the total organic HAP emission limits, THC must be monitoring using a CEM system complying with Performance Specification 8 or 8A of Appendix B to Part 60 (U.S. EPA 2020d). If subject to an emission limitation for Hg, an Hg CEMS or an integrated Hg sorbent trap system must be installed that complies with PS‐12 or PS‐12A of Appendix B to Part 60. Mercury emissions can vary widely in cement plants, where, for example, in in‐line kiln raw mills, kiln gases are rerouted to dry incoming materials. Particulate matter and mercury vapor in the kiln exhaust are caught or condensed in the raw mill as the gas recirculates. When mill is “off” the kiln gas is not recirculated, and kiln emissions will be higher in particulate and mercury levels. Unless otherwise controlled, it may be necessary for the monitoring system to be capable of monitoring accurately at low levels typically below 10μ/m³or less with the “raw mill on” and high levels on the order of hundreds of μ/m³ with the “raw mill off”, that is, over a possible range of one to two orders of magnitude.

Petroleum Refineries – 40 CFR 63 Subpart CC and UUU – The Refinery MACT

Two subparts in Part 63 address petroleum refineries. Subpart CC, which addresses operating units such as maintenance vents, pressure relief devices, and flares, is known as MACT 1. Subpart UUU, known as MACT 2, established HAP requirements for fluid catalytic cracking units (FCCUs), sulfur recovery units (SRUs), and catalytic reforming units. Part 63 Subparts CC and LLL and the Part 60 NSPS Subparts J and Ja are known collectively as the “Refinery Sector Rule (RSR).” Part 63 Subpart CC and LLL are also known as Refinery MACT 1 and Refinery MACT 2.

Refinery MACT 1 – Subpart CC

Refinery flares are covered for HAP emissions in Subpart CC. In Subpart CC §63.670 the following requirements are established for routing regulated to the flare:

The flare pilot lights must always be on.

The flare emissions must be smokeless with 0% opacity (except for periods not to exceed a total of five minutes in any two consecutive hours).

The flare vent gas flow should be less than the smokeless design capacity.

The net heating value must be >270 Btu (determined on a 15‐minute block basis)

Combustion efficiency must be >96.5%.

These flare operating conditions consequently require monitoring the flow rate of gases, as well as supplemental gases, to the flare. To stay within the Btu operating limit, the flare gas net heating value may be determined either by

periodic eight‐hour grab sampling and analysis of the gas composition;

by continuously monitoring the gas composition using a gas chromatograph or mass spectrometer; or

installing a calorimeter (Wobbe index analyzer) to continuously measure the net heating value directly.

By monitoring the individual components of the flare gas in (1) or (2) above, the total Btu content can be simply determined from Equation 13‐1:

(13‐1)upper B t u Subscript f l a r e g a s Baseline equals sigma-summation c Subscript i Baseline upper H Subscript i

where

Btuflare gas = total heating value of the flare gas

ci = the concentration of flare gas component i

Hi = heating value of component i

The use of gas chromatographs for measuring the concentration of individual flare gas components is fairly routine at petroleum refineries; however, mass spectrometers are also applied for this purpose (Watson 2020).

Flare gas monitoring is not required for purchased pipeline natural gas or if it can be demonstrated that the gas composition can be shown to be consistent by taking daily samples for a period of two weeks, or seven samples for infrequently operated flares [§63.670(j)(6)]. Of further interest, Subpart CC also require continuous benzene monitoring at the refinery fence line to improve the management of fugitive emissions (§63.658). Here, EPA specifies Methods 325a using passive sampling tubes for sample collection and Method 325b for tube thermal desorption and analysis by gas chromatography.

Refinery MACT 2 – Subpart UUU

CEM implementing rules are given in Subpart UUU for catalytic cracking units, reforming units, process heaters, incinerators, and sulfur recovery units. Continuous emission monitoring requirements are given in the text in §63.1572, but only in a general sense. Somewhat unusual in a rule, the unit applicable monitoring requirements are given in the tables following the text. Also, Part 63 rules overlap with the NSPS rules given in Part 60 Subpart J and Ja, which add another layer of complexity (U.S. EPA 2020a).

For catalytic cracking units, opacity monitors, PM CEMS, bag leak detectors, oxygen monitors, and flow monitors are required on catalyst regenerator vents as applicable. This labyrinth of monitoring requirements can be found in Part 63 Subpart UUU Tables 1–14. As an example of applicability requirements, consider the following:

Opacity monitors are required after cyclones and ESP control devices under Part 60 Subpart J and are used to meet Part 63 Subpart UUU requirements in addition.

Particulate monitors (PMs) are required under Part 60 Subpart Ja, and are used to meet Part 63 requirements in addition.

After fabric filter baghouses, bag leak detectors are required.

Opacity monitors and PM CEMS serve to monitor particulate emissions and also serve as surrogate monitors for metals HAPS. As surrogate monitors for metals, site‐specific compliance limits are established at the time of performance testing for PM emissions and opacity (§63.1564).

Continuous O₂ monitoring is required to track the oxygen concentration limit [§63.1565(a)(5)(2)]. Flow monitoring is an option for calculating the PM coke burn‐off emission rate (§63.1564). CO₂, CO, and O₂ data are also necessary for this calculation.

Thermal incinerators after catalytic crackers if not already required to monitor CO and O₂ must do so under Part 63.

For catalytic reforming unit process vents where emissions are controlled by wet scrubbers, gas–solid adsorption systems, or internal scrubbing systems, continuous parameter monitoring systems are required in Part 63 Subpart UUU (Tables 16‐28). Flares after catalytic reforming units must meet the requirements of §63.670 of Subpart CC.

Sulfur recovery units like catalytic cracking units are subject to continuous emission monitoring requirements in Part 60 Subparts J and Ja and Part 63 Subpart UUU (Tables 29‐39) (U.S. EPA 2020b,g). Continuous SO₂ and O₂ analyzers are required to monitor total reduced sulfur (TRS) or SO₂ at 0% excess air, as applicable (Table 31).

When SO₂, TRS, CO, and O₂ CEM systems are installed, 40 CFR 60 Appendix B certification procedures and 40 CFR 60 Appendix F quality assurance procedures are normally followed (U.S. EPA 2020d,e). In Subpart UUU, these procedures are addressed further in Tables 40 and Tables 40 and 41. For example, Table 40 clarifies that RATAs are to be conducted annually instead of quarterly, and that the calibration drift performance specification for TRS monitoring systems is changed from 5% of span (Part 60 Appendix B PS‐5) to 2.5% of span. Table Tables 40 and 41 adds many design specifications for CO₂, O₂, and CO monitors used to determine coke burn‐off rates and for air flow rate sensors.

Also related to Subparts CC and LLL continuous emission monitoring, start‐up, shutdown, and malfunction (SSM) events are not exempt from emission limits and must be monitored and reported when limits are exceeded.

METHODS FOR MEASURING HAZARDOUS AIR POLLUTANTS

The analysis of hazardous air pollutants (HAPs) is not as straightforward as the measurement of the inorganic criteria pollutants such as SO₂ and NO. Because of the wide variation of properties associated with the different classes of HAPs, which include inorganic and organic compounds and metals, numerous methods are used to analyze the flue gases after they are sampled by the extractive or in‐situ systems. These methods vary from the traditional optical absorption techniques used for criteria pollutant monitoring to include techniques such as gas chromatography, mass spectrometry, and ion‐mobility spectrometry for organic and inorganic compounds and atomic emission spectroscopy for metals.

This section reviews hazardous air pollutant monitoring methods that are commercially available, describing their measurement principles. These methods include gas chromatographic techniques, mass spectroscopy, ion mobility spectroscopy, multi‐metal methods, and the special case of dioxin/furan sampling.

MONITORING FOR ORGANIC COMPOUNDS

Organic hazardous air pollutants are addressed in over 25 of the Part 63 subparts. In these subparts, continuous emission monitoring is often required; however, options are often provided to allow parameter monitoring for such parameters as temperature, pressure drop, and flow, incorporated as part of a CPMS. Using CO monitoring as a surrogate method for indicating good combustion is also an option in a few of the subparts (Jahnke and Evans 2005).

In a few cases, specific organic compounds are addressed, namely, vinyl chloride in Subpart J, ethylene oxide in Subpart O, and dioxins and furans in Subpart 7H. However, organic compounds are primarily dealt with generically, with the assumption that if all organic emissions are controlled, the individual HAPS will be controlled.

Organic hazardous air pollutants in Part 63 are variously termed, depending upon the subpart. The following expressions are used when requiring the installation of a CEM system for organic hazardous air pollutants (Table 13‐1).

This can be confusing if one thinks about it too much, but the subparts were written by different people at different times, each group having their own focus. Although the overall structure of the subparts is relatively consistent, details sometimes vary.

Due to the difficulties in analyzing multiple organic compounds in a flue gas matrix, chromatographic separation techniques are often employed to first separate the compounds. Compounds then can be measured individually by a detector such as a flame ionization detector (FID), thermal conductivity detector (TCD), or photoionization detector (PID). This is in contrast to other techniques in which separation of gaseous compounds is not performed, such as Fourier‐transform infrared (FTIR) spectroscopy or mass spectroscopy, which ideally identify and quantify all the compounds in the sample at the same time (Bartak et al. 1996; ISO 2019; Kinner and Plummer 1993; Kinner et al. 1995). A combination of separation and analytical methods such as gas chromatography and mass spectrometry (GCMS) provides for a very versatile analytical system.

TABLE 13‐1 Terms used for pollutants in Part 63 subparts

Part 63 Subpart Expression | Common Acronym
Hazardous air pollutant or volatile organic compound | HAP or VOC
Hydrocarbon | HC
Organic compounds | —
Organic hazardous air pollutant | —
Organic monitoring device | —
Total hazardous air pollutant | —
Total hydrocarbons | THC
Total volatile organic compounds | TVOC
Volatile organic compound | VOC
Volatile organic hazardous air pollutant | VOHAP

Gas Chromatography

Gas chromatography is a technique used to isolate the individual components of a mixture of organic and inorganic compounds from each other for subsequent identification and quantitative analysis. Chromatographic separation principles are used in EPA reference methods (U.S. EPA 2020c) and in installed CEM systems. As examples, a detailed gas chromatographic procedure is specified in EPA Method 106 for vinyl chloride, EPA Method 16 for total reduced sulfur (TRS) provides for the chromatographic separation of four sulfur‐containing compounds, and EPA Method 18 gives general sampling and analytical criteria for gas chromatographic testing continuously. Installed online gas chromatographs are found in the process industries where they are used for regulatory purposes as well as monitoring and controlling unit operations (Coleman et al. 1996; Villaloboos 1975).

In environmental applications, gas chromatographs are used for monitoring volatile organic compounds (VOCs) and total organic compounds (TOCs) as applicable in Part 63 air toxics rules. They are also used in petroleum refineries for monitoring H₂S in fuel gas, as Btu analyzers in gas‐fired combustion sources, and at emission sources subject to VOC emission limits.

As Btu analyzers, gas chromatographs determine both the compounds present and their concentrations in the natural gas used to fuel gas‐fired boilers and gas turbines. From these data, the fuel Btu content can be calculated to compare with the contracted fuel composition. Because the composition of natural gas can vary, this can be an important check on the heat content of the actual fuel combusted. Also, by using F factors, the flue gas flow rate can be calculated from this information (see Appendix A).

To meet ambient air standards for ozone, a cap and trade program was initiated in the Houston‐Galveston area in Texas for the control of highly reactive volatile organic compounds (HVROCs). As a result, HRVOCs are required to be monitored in the numerous petroleum refinery and chemical plant process vents in the area. Gas chromatographs capable of speciating the emissions have been applied widely to support these program requirements (Ramsey and Colville 2006).

Basic Principles of Gas Chromatography

A continuously operating gas chromatographic system consists of a sampling system, an oven containing a relatively complex valving system, a separation column, and a detector. An example is given in Figure 13‐1.

The separation column is the heart of a chromatographic system. A chromatographic column is basically a long tube packed with materials that retard the passage of different molecules through it as they are being transported by a carrier gas. Due to the effect of the packing material (or “stationary phase”), the different molecules will reach the end of the column at different times, where their arrival is detected by the detector. The design of columns, choice of packing materials, and specification of column design and operating conditions for material separations is a specialized field on which many techniques in chemistry and biochemistry are based.

Figure 13‐1 Example gas chromatograph.

Columns are made of fused silica, glass, or stainless steel and vary in diameter and length, depending upon the type of column packing used. The carrier gas, such as helium or nitrogen, sweeps the sample into the column. In the column, the moving gas phase passes over the stationary phase where the material in the stationary phase can be an active solid, an inert solid coated with a liquid, or just a liquid coating in the column. The stationary phase is chosen to either absorb or adsorb the organic molecules contained in the gas, to selectively distribute the compounds between the stationary phase and the mobile phase (carrier gas). The equilibration between the individual compounds and the column stationary phase is a function of (i) the compounds that have affinity for the stationary phase relative to the mobile phase, (ii) the temperature of the column, and (iii) the flow rate of the mobile‐phase carrier gas. Individual molecules are separated in the column by undergoing a series of equilibrations between the stationary and mobile phases (Giddings 1965). In an ideal column, operated under ideal conditions, each molecular species will exit the column at a different time to enable the separation of the gas sample into its individual components.

The detector at the end of the column ultimately produces a chromatogram, consisting of a peak for each compound eluted (Figure 13‐2), plotted as a function of signal strength vs. the retention time.

Separated peaks are identified and quantified by comparison of their peak areas to a calibration with known gas standards. For an unknown sample mixture, appropriate standards may not be known unless some prior knowledge of the flue gas composition is available. In that case, other measurement techniques such as infrared, ultraviolet, or mass spectrometry might be necessary to identify the compounds and then select the standards and perhaps, in the first place, the column.

The concentration of each component in the sample mixture can be determined from the area under the chromatogram peak produced as the compound exited (eluted) from the column. The area of each peak is compared to the total area of all the peaks to obtain the relative proportion of each component in the sample. This is usually performed automatically by the instrument microprocessor.

The Sampling System

The diameters of gas chromatograph columns are small and must be kept free of particle matter or condensed materials to avoid plugging. The capillary nature of the column also will restrict sample flow and the sample injection pressure will have to be controlled. Sampling from high‐pressure fuel‐gas lines may require special consideration in regulating the sample flow and avoiding condensation of the sample analytes as the pressure is decreased.

The sampling valve, column(s), and detector are contained in an oven, maintained at constant temperature. Gas chromatograph valves can be complex, particularly if more than one column is used for gas separation. Figure 13‐3 shows a valve for single column, where the sample gas enters a sample loop, the valve rotates to allow the carrier gas to sweep the sample into the column.

Multiport valves allow for the use of multiple columns, which may be necessary when measuring a mixture of low‐, medium‐, and high‐molecular weight hydrocarbons.

Figure 13‐2 A gas chromatogram.

Figure 13‐3 Gas chromatograph multiport rotary valve.

Detectors

The separation performed in a chromatographic column must be sensed by a detector and recorded. Any detector designed for use in a gas chromatograph system must have high sensitivity for low concentrations of organic molecules and a rapid response time. Many detectors are available that meet these requirements; the most common in source monitoring applications are flame ionization detectors (FIDs) and photoionization detectors (PIDs). In more sophisticated applications, optical spectroscopic or mass spectroscopic techniques are employed.

Flame Ionization Detectors

The flame ionization detector is capable of sensing most organic compounds and, because of its relatively high sensitivity, has become widely used in environmental applications. In an FID assembly, the column effluent enters the base of the burner, is mixed with hydrogen, and the mixture is burned in an oxygen jet at a temperature of about 2100 °C. Ions and free electrons are produced by the flame, which increases the current sensed by an electrometer. The current is approximately proportional to the number of carbon atoms entering the flame. However, the response of the detector is slightly different for different types of organic compounds. As a result, the detector must be calibrated for the compounds being studied to achieve the best accuracy (Figure 13‐4).

The FID is convenient to use in source sampling situations since it does not respond appreciably to gases such as O₂, N₂, H₂O, CO, SO₂, and NO (Nuryatini and Zaus 2015). However, organic compounds that contain nitrogen, oxygen, or halogen atoms may give a response reduced from that seen from hydrocarbons.

Figure 13‐4 A flame ionization detector.

Flame Photometric Detector

The flame photometric detector (FPD) is very sensitive and selective to sulfur‐containing molecules. However, the flame response is sensitive to the presence of hydrocarbons; hence it is necessary to separate the H₂S from the hydrocarbons. In the detector (Figure 13‐5), a flame is used to excite the sulfur atoms of the H₂S. These excited sulfur atoms emit light in a band of wavelengths centered at about 394 nm, which is specific to sulfur. The excited sulfur atoms release photons, which are observed by a photomultiplier tube and amplifier. Because the FPD has an active flame, the air‐to‐fuel ratio must be properly adjusted for the proper operation.

Figure 13‐5 A flame photometric detector.

Photoionization Detectors

In a photoionization detector, organic molecules are ionized by light in the UV region of the spectrum:

where

R⁺ = the ionized organic compound and

hv = the energy of the light having frequency v (h = Planck's constant)

Again, the major components of the flue gas such as O₂, CO, N₂, CO₂ and H₂O are not ionized. A typical PID incorporates a UV lamp and a pair of electrodes to measure a current proportional to the concentration.

Different molecules require different energies to photoionize, and the frequency, v, of the light used in the PID may not ionize all of the organic species. Low‐energy UV lamps are suitable for ionizing polyaromatic compounds, but higher energy lamps are required for aliphatic hydrocarbons. Lamps of varying energies can be used to monitor a complex mixture of organic compounds, and, consequently, some degree of selectivity for different chemical groups can be achieved.

PIDs are used in conjunction with gas chromatographs or alone as portable analyzers used in EPA Reference Method 21 for detecting leaks in petroleum refineries (Hewitt and Driscoll 1981; Hellwig et al. 1986). They offer advantages over FID detectors in that hydrogen is not required and methane (a gas that is not required to be monitored) is not ionized and therefore not detected by a PID (Hewitt and Driscoll 1981). Depending upon the instrument, compounds detected by PIDs include aliphatic and aromatic hydrocarbons, halogenated organics, alcohols, ketones, aldehydes, ethylene oxide, vinyl chloride, and inorganic compounds such as arsine, phosphine, and hydrogen sulfide. In general, compounds that have ionizable electrons can be detected.

Thermal Conductivity Detectors

Thermal conductivity detectors as used in gas chromatographs, measure changes in the thermal conductivity of the gas leaving the column compared to the thermal conductivity of a reference carrier gas flow (Figure 13‐6). In the detector block, two tubes contain wire coil or a thermistor. If the wire coils are heated, gas passing over a coil will cool it and its resistance will change. The rate of cooling is dependent upon the thermal conductivity of the gas and if the gas composition changes, the rate of heat loss from the wire will change. Consequently, the temperature and electrical resistance of the wire will change.

If helium is used as a carrier gas, the thermal conductivity will be higher for the reference helium, than for the carrier gas containing organic compounds desorbing from the column. As each compound reaches the resistance element, its resistance will change in proportion to the amount of material in the eluted gas. The resistance of the measuring element is determined using a Wheatstone bridge circuit, to provide signal peaks indicating the relative concentration of each compound.

Figure 13‐6 Operating principle of the thermal conductivity detector.

Thermal conductivity detectors can also measure noncombustible, inorganic compounds that cannot be detected using an FID. However, FIDs are more sensitive than TCDs (Budiman et al. 2015).

Electron Capture Detector

The electron capture detector (ECD) is selective for certain groups of organic compounds such as those containing halogen atoms or nitro groups. Electron capture detectors work by using a radioisotope‐treated electrode that emits high‐energy electrons as it decays (β emission). The β electrons react with the carrier gas to produce secondary, free electrons that move to a positively charged anode to generate a current through the system. When the nitrogen carrier gas contains electron‐absorbing molecules such as halocarbons, the electric current will be reduced because the flow of free electrons will be reduced by absorption.

The ECD is more sensitive for specific groups of compounds than is the FID, but the response can again vary from compound to compound. Issues associated with the transport, storage, and disposal of the radioactive materials are also of some concern.

Mass Spectrometers Used as Detectors

Increasing demands for the analysis of trace levels of toxic materials require new approaches to increase the resolving power and sensitivity of chromatographic systems. Multiple detector combinations have been used but combining the gas chromatograph with a mass spectrometer used as a detector offers one of the most powerful combinations for both identification and quantification. The gas chromatograph – mass spectrometer (GCMS) combination has been the basis for low concentration testing in air pollution monitoring and is increasingly applied (Peeler et al. 1996).

The GCMS combination provides both qualitative and quantitative information since it treats each type of molecule separately as it comes off the column (Figure 13‐8). The GCMS output gives a three‐dimensional plot over time, giving information about both the type of compounds in the sample and the amount of each compound present (Figure 13‐7).

Mass spectrometers and GC mass spectrometers have been applied to monitor criteria pollutants on a continuous basis (Bartman et al. 1990) and are increasingly used in the process industries to monitor a wide range of HAPs. Their use in environmental monitoring has focused primarily on the ambient monitoring of hazardous waste sites or leak monitoring in the chemical and petroleum industries. However, GCMS systems have been used in short‐term source tests to determine baseline HAP emissions (Campbell et al. 1991; Peeler et al. 1996; Strosher 2000). These tests often point out areas where changes in process operation efficiencies can lead to emissions reductions. The design of continuous sampling and operating strategies has been a challenge in many GCMS applications, but such challenges are being met (Haile et al. 1995; Kinner and Plummer 1993).

Figure 13‐7 A total ion current chromatogram.

Mass spectrometers may also be used to determine gas concentrations directly, without applying a gas chromatograph for prior separation of the gas components. The advance of this technology from the laboratory to the field in a span of the last 50 years is remarkable, highlighting the progress made in gas analysis over that period.

Other Detectors

Other types of detectors are used in chromatographic systems applied to environmental monitoring. Many of these are species specific like the ECD. Among these are the Hall electrolytic conductivity detector (HECD) used for halogen, sulfur, or nitrogen compounds, and the alkali flame detector (AFD) used for nitrogen and phosphorous compounds.

Total Hydrocarbon Analyzers

Depending upon the process and the mixture of compounds present, a preliminary characterization of the emissions is often necessary to optimize chromatographic and other instrumentation. Although a knowledge of the types and amounts of compounds being emitted may be useful for process control and optimization, in the process industries, such information is not needed for some facilities such as incineration sources that are well within their emission limits. In these and other cases, a total hydrocarbon analyzer may be sufficient for monitoring the sum of individual VOC emissions. To satisfy regulatory requirements, the assumption is made that the total hydrocarbon emissions are below the emission limit for any one compound, then the standard for that compound will be met. In order to assure continuous compliance for HAP emissions, a number of the Part 63 subparts specify either the use or alternative use of total hydrocarbon [THC] analyzers), total volatile organic (TVOC) analyzers, or total organic carbon (TOC) analyzers (see Table 13‐1 previous).

Total hydrocarbon analyzers do not incorporate a column, but allow the sample gas to pass directly to the detector. The sampling system may be either cold or hot. The hot FID systems provide a more accurate measure of the THC content; however, care must be taken in the design and operation of the sampling system. Condensation of organic compounds due to cold spots in the sampling system leading to the analyzer can plug the flow of gas or interfere with the control of the sample pressure (Cone et al. 1990). This issue is more important when measuring VOCs than when measuring criteria pollutants, which suggests that a systems integrator experienced in VOC monitoring systems should be selected.

The FID is the industry standard for total hydrocarbon (THC) analyzers. If organic compound other than hydrocarbons are combustible in a hydrogen flame, THC analyzers that use an FID may be acceptable for TOC measurements. The use of FID detectors is required in THC monitoring systems installed in boilers and industrial furnaces that burn hazardous waste [40 CFR 266.104] and for THC analyzers installed in sewage sludge incinerators [40 CFR 503.45(a)(1) Subpart E].

Non‐methane hydrocarbon analyzers measure methane separately and subtract the concentration from a total hydrocarbon measurement. Taylor and Macak (1999) describe an installation of a continuous non‐methane J.U.M. 109A total hydrocarbon analyzer at a steel sinter plant, where the sample gas is split into two streams. In the analyzer, one stream passes directly to an FID to measure the total hydrocarbon concentration and the other gas first passes through a high‐temperature catalyst that oxidizes hydrocarbons other than methane, which is measured at a second FID. The non‐methane VOC concentration is then determined by subtracting the two measurements.

Certification criteria for approving THC analyzer installations have been simplified by eliminating relative accuracy test criteria and using audit gases to check the system performance (40 CFR 266 Appendix IX Section 2.2). No certification criteria are given for analyzers required in 40 CFR 503 Subpart E.

Mass Spectrometry

Mass spectrometers can be used to monitor gases directly without the use of a gas chromatograph to first separate the individual components for analysis. Without a chromatograph to delay the analysis of the gas components, the different compounds in the gas will ionize at the same time to create a complex combined spectra, composed of the overlapping mass spectra of the individual compounds. An analysis of relative peak heights, spectral libraries, selective ion monitoring, matrix deconvolution, and other methods are used by the mass spectrometer software to identify and quantitate individual components in the sampled gas. These methods, in conjunction with reference standards, can provide for accurate gas composition measurements.

A mass spectrometer consists of three principal components: an ion source, a mass analyzer, and a detector. In the mass spectrometry technique, molecules are ionized by high‐energy electrons or by other means such as chemical or photo‐ionization processes, and the resultant molecular ions and ion fragments are separated according to their mass‐to‐charge ratio (m/e) and detected at a detector. The separation produces a “mass spectrum” of the different ions generated from the fragmentation caused by high‐energy electron–molecule collisions. The mass spectrum is unique to the original molecule as an infrared or UV spectrum.

Mass spectrometers are distinguished by the type of mass separator used. Magnetic sector, quadrupole mass analyzers, ion‐traps, and time‐of‐flight separators have all been employed in commercial instruments applied for environmental applications. For industrial process applications, the quadrupole mass analyzer and the ion trap detector are used most commonly. A linear quadrupole mass analyzer operates by oscillating the ions in a radio‐frequency field superimposed on charged cylindrical rods (Figure 13‐8). The oscillating field of electromagnetic energy filters ions of a specific mass‐to‐charge ratio. Most of the ions will oscillate with increasing amplitude and strike the rods, but one set of rod voltages and radio‐frequencies will exist where the ions of a specific m/e ratio will be able to pass through to the detector. The radio‐frequency or rod voltage is therefore scanned to obtain the mass spectrum.

The mass analyzers used in mass spectrometer systems are operated under vacuum (1 × 10⁻⁵ to 1 × 10⁻⁶ mmHg) to minimize scattering by collision with other ions and gas molecules. This requires some type of vacuum pump and a system design that can maintain a proper vacuum. The cleanliness of the system is also important, and adsorbed materials on the walls of the analyzer can introduce interfering ions. These requirements can lead to problems in source monitoring applications and must be overcome to achieve consistent results.

For continuous monitoring applications, mass spectrometers are most widely used in petroleum refineries to monitor Btu values in flaring operations. They can measure hydrogen, sulfur species such as CS₂, H₂S, COS, and SO₂ for total sulfur emissions, as well as the range of hydrocarbons typically present in flare gases. They can provide a composition analysis in less than 20 s, whereas a chromatograph may take up to 15 minutes, the maximum sampling time allowed. Because flare gas events may be variable in terms of gas composition and duration, a rapid instrument response can be an advantage in trouble‐shooting process operations.

Calorimeters

Calorimeters or “Wobbe Index analyzers” are widely used in refineries to measure the high heating value of a gas, where the Wobbe Index is the high heating value divided by the square root of the specific gravity of the gas. The Wobbe index is typically applied to compare the combustion energy output of different gases from a combustion device. The analyzer works by mixing the sample with dry air at a fixed ratio, and subsequently heating the air/fuel mixture with a catalyst in an oven at 800 °C. The gas concentration is measured by a zirconium oxide oxygen sensor, where the residual oxygen concentration is used to calculate the combustion air requirements for the sample.

The analyzer provides an instantaneous reading and is one of the options allowed for monitoring flare gas in Part 63.670 Subpart CC (see above). It, however, does not measure the individual flare gas components, and is limited for troubleshooting process operations. In addition, high concentrations of acid gases SO₂ and H₂S can affect the zirconium oxide sensor. The ZrO₂ sensors are also limited in operation if high concentrations of hydrogen are present in the flare gas stream.

Ion‐Mobility Spectrometry

Ion‐mobility spectrometry is a technique similar to the time‐of‐flight technique used in mass spectroscopy, except that the analyzer operates at ambient pressure and the ions drift to the detector in an electric field. Commercial ion‐mobility instruments have been optimized for the measurement of HF, HBr, HCl, NH₃, hydrogen peroxide (H₂O₂), hydrocyanic acid (HCN), Cl₂, and chlorine dioxide (ClO₂). A wide range of other gases such as aldehydes, ketones, amines, polyaromatics are said to be measurable by this technique (Bacon and Reatigui 1993; Bacon and Webber 1996). The method is used in airport security screening to detect explosive materials and illegal drugs.

Figure 13‐8 A quadrupole mass analyzer.

In this method, a radioactive source ionizes the molecules, which then drift through an electric field to an electrometer (Figure 13‐9). The ionization caused by the radioactive source is “softer” than that of high‐energy electron ionization typical in mass spectrometers, so the molecules do not fragment in the ion mobility technique as they do in the mass spectrometer.

The mobility (drift velocity/electric field strength) of the ions through the field is dependent upon the charge, mass, and shape of the molecule. An electronic shutter grid is used as a “gate” to periodically allow ions to enter the drift space. Smaller ions have a greater drift velocity than the larger ions and reach the electrometer earlier. The resultant instrument signal, showing different ion signals as a function of time, appears much like a chromatogram and can be called an “ionogram.” Concentrations are determined from the peak heights.

The ions generated are therefore more directly related to the original molecules. In this apparatus, the ions move through a background gas at ambient pressure. The ion mobility therefore represents the ability of the ion to move through that background gas. This provides an advantage that a vacuum system is not required.

The ion mobility spectrometer does have some problems in discriminating between different compounds. These interference problems are resolved by several stratagems: (i) introducing chemicals (“dopants”) into the gas stream to inhibit the ionization of interfering compounds, (ii) using a permeation membrane to exclude or retard interfering compounds, (iii) changing the electric field polarity to select positive or negative ions at the detector, or (iv) scrubbing out interfering compounds before they enter the spectrometer. The research necessary to optimize the technique for specific compounds has limited application of the method.

Ion mobility spectrometry does, however, offer good sensitivity (at the ppb level) and has been optimized for gases that in the past have proven difficult to measure, such as ammonia and the acid gases, HBr HCl, and HF (Harris and Dunder 1997; Harris and Wilner 1995). Its relative simplicity and moderate cost have made it a viable alternative to optical spectroscopic techniques that require expensive modifications to analyze corrosive gases. The method, however, is not widely used in continuous emission monitoring, lacking an adequate potential client base while competing against other analytical methods.

Particle Measurement Systems currently (2020) markets ion mobility spectrometers for ammonia, acids, and chlorides in the 0–50 ppb range for detecting contamination in clean rooms, but not for CEM system applications. The company ATB Analytics supports ion mobility spectrometer CEM systems sold prior to 2007.

MONITORING FOR ACID GASES

The acid gases HCl, HBr, and HF are addressed in rules for coal‐fired electric utilities, cement plants, and a variety of chemical facilities. In the New Source Performance Standards of Part 60, HCl monitoring is required for municipal waste combustors and solid waste incinerators. Many of these source categories, however, are not actually required to install acid gas monitors, but are allowed to use them as an alternative to monitoring plant operations and control equipment parameters. Additionally, where wet or dry scrubbers are installed, an SO₂ monitoring system is often allowed as a surrogate for HCl measurement system, since most scrubbers will control HCl as effectively as SO₂. For coal‐fired electric generating units, exemptions are also provided for low emitting units, or if HCl stack tests are performed quarterly. In addition to the Part 60 and 63 federal rules, some states in their permitting processes have mandated the installation of HCl monitors for existing municipal waste and hazardous waste combustors and cement plants burning hazardous waste as supplementary fuel.

Figure 13‐9 An ion‐mobility spectrometer.

The HCl emission limits pose an special challenge for CEM system and stack test reference method measurements. These limits are on the order of 5 ppm or less. Cement plants subject to the requirements of Part 63 Subpart LLL are limited to 3 ppm (corrected to 7% O₂). Under the MATS rule, coal‐fired units are subject to a limit of 1.9 ppm (corrected to 3% O₂). In contrast, the emission limits for municipal waste combustors is 20 ppm under the Part 60 Subpart Eb New Source Performance Standards. Measuring at levels less than 5 ppm can be especially challenging, requiring expertise in acid gas transport and calibration for CEM system users and stack testers alike.

Meeting HCl monitoring requirements requirements was often achieved by using multi‐gas analyzers, such as gas‐filter correlation instruments, and later FTIR spectrometers (Rollins et al. 1990). However, at that time, performance specifications for HCl monitoring systems were not available and the accuracy of HCl calibration gases was questionable (Shanklin et al. 1989, 1990). Although HCl analyzers have been available for over 30 years (Breton 1990), the proposed MACT rules for HCl were viewed with some alarm by both the sources to be regulated and the source testing community because it was not previously demonstrated that HCl monitoring systems or even the reference methods could measure accurately at the low levels proposed for the MACT emission limits. A flurry of activity eventually led to developments in the technological base for HCl monitoring and the formulation of the PS‐18 performance specification test procedures.

Options for Monitoring Acid Gases

The reactivity and solubility of acid gases such as HCl necessitate that an acid gas analyzer be integrated into a hot‐wet extractive system, a dilution‐extractive system, or an in‐situ system (ICAC 2013). A chiller in a cool‐dry extractive system will remove HCl, a problem that disallows merely installing another instrument into an existing cool‐dry extractive system.

Photometric, gas‐filter correlation, and FTIR analyzers have been typically used in hot‐wet CEM systems for monitoring HCl. In gas‐filter correlation instruments, adding an HCl correlation cell provides a simple solution to an HCl monitoring requirement. It was once thought that HCl could not be measured by FTIR spectroscopy, due to interference from water vapor. However, Vidrine and McIntosh (1993) showed that there is minimal spectral overlap near 3.57 μm and today a number of HCl FTIR monitoring systems have been installed in cement, incineration, and utility industries.

Using a dilution‐extractive system requires coupling an analyzer that can measure at the very least levels less than 10 ppm and at best in the ppb range. The low HCl emission levels (on the order of 1 ppm) of many facilities make this issue even more problematical. A typical NDIR analyzer, either a photometer or gas‐filter correlation instrument, is limited in this respect unless redesigned, an effort that most instrument manufacturers loathe to undertake given a limited market.

The use of dilution‐extractive systems is now feasible with the introduction of laser‐based extractive gas analyzers. The cavity ring‐down and integrated cavity output spectroscopic techniques (CRDS and ICOS) have ranges of typically 0–10 ppm and have been applied in dilution‐extractive systems at dilution ratios of 100 : 1 for HCl (Gibbons 2014).

Accordingly, barring the availability of a ppb‐level instrument, the best solution is to use either a hot‐wet extractive system or in‐situ system for the measurement. Hot‐wet systems in conjunction with gas‐filter correlation instruments have been applied at many municipal waste combustor facilities, whereas hot‐wet FTIR systems are popular at cement plants.

Prior to the promulgation of the MATS rule, interest in using cross‐stack in‐situ systems revived in electric utilities with the advent of tunable diode lasers. Measuring in‐situ avoids problems associated with sample transport but raises other issues, particularly calibration issues. The usual approach to calibration is to incorporate either a sealed cell or flow‐through cell in the light path (see Chapter 6). The problems associated with the quality of the calibration gas and delivering the calibration gas to the cell without losses again arise. Because the cell is usually in the light path (see Figures 6-17 and 6-18), the calibration check will be made in addition to the stack measurement. If the stack concentration varies appreciably during the calibration check, it may be difficult for the analyzer to factor out its bias to the measurement. Additionally, because the flue gas HCl spectral characteristics are temperature dependent, corrections need to be made to compensate for the cell temperature, unless the cell is heated to a temperature equal to the stack temperature.

HCl Calibration Gases

A major issue associated with HCl and other acid gas monitoring systems is the availability of accurate low‐level calibration gases. For various reasons, NIST has not developed EPA HCl protocol gases in the concentration range required for Part 63 rules. As a solution to this problem, EPA has approved the use of an alternative method for the preparation of HCl Gas Standards. This method (ALT‐114) allows gas manufacturers to prepare gravimetric HCl standards whose concentration is calibrated by classic chemical analysis using NIST‐traceable liquid calibration standards (Johnson 2016). Once verified, this would become a “Gas Manufacturer's Primary Standard (GMPS)” that would substitute for NIST reference gases. The GMPS reference standard is then used to calibrate a reference instrument, such as an FTIR. The GMPS‐calibrated FTIR serves in turn to verify the concentration of HCl gas cylinders that are sold commercially and used in the field as “Gas Manufacturers Alternative Certified Standards” (GMACS). Cylinder gases from 1 ppm to 1%, with an uncertainty of ±4% and a shelf‐life of one year are currently available.

Another calibration gas issue is in transporting the gas from the gas cylinder to the monitoring system. Because any moisture in a calibration line will absorb HCl, the two‐stage cylinder regulator should be purged with dry nitrogen before it is attached to the gas cylinder. After it is attached, it is recommended that a cycle of opening HCl cylinder valve to pressurize the regulator, closing the valve and opening the regulator outlet valve to vent, be conducted 10 times before calibrating the system (MKS 2015). MKS also recommends high sample flow rates from 3.5 to 7 lpm.

MONITORING FOR METALS

As in the initial development of gas monitors, methods for monitoring metals are essentially laboratory techniques adapted for field use. As discussed in Chapter 12 on mercury monitoring, metals are typically measured by applying the techniques of atomic emission spectroscopy and X‐ray fluorescence spectroscopy.

Metals included in the substances classified as hazardous air pollutants in Title III of the 1990 Clean Air Act Amendments are antimony (Sb), arsenic (As), beryllium (Be), cadmium (Cd), chromium (Cr), cobalt (Co), lead (Pb), manganese (Mn), mercury (Hg), nickel (NI), and selenium (Se). Outside of the mercury monitoring requirements for coal‐fired electric generating units, cement plants, and incinerators, lead smelting under Part 63 Subpart X is the only industrial category where a continuous metals monitoring system is required under the MACT rules. Consequently, few monitoring systems for metals other than mercury have been installed in the United States.

In the early 1990s, in anticipation of MACT monitoring requirements for metals, a number of research projects were initiated to develop “multi‐metal” continuous emission monitoring systems, in addition to those focusing just on mercury (Cheng 2001). Mercury analyzers utilize the analytical techniques of atomic absorption spectroscopy and atomic fluorescence spectroscopy operate at a wavelength of 253.7 nm. Monitoring systems for multi‐metals would necessarily have to operate at multiple wavelengths – each wavelength being specific to the metal measured. This would be difficult and complicated if several metals are to be measured. Alternatively, traditional techniques of emission spectroscopy, used in analytical chemistry, can be applied to monitor more than one metal at a time.

In emission spectroscopy, if sufficient energy is provided, metals in a sample will ionize to lose electrons. As the atoms return to their ground state, light, characteristic of each element in the sample, will be emitted, with its intensity being proportional to the number of atoms in the sample. Atomic emission spectroscopic techniques differ by the manner in which the metal atoms are excited, through the use of X‐rays, a laser, a spark, a radio‐frequency plasma, or a microwave‐generated plasma. X‐ray fluorescence spectroscopy, inductively couple plasma (ICP) spectroscopy, and laser induced breakdown spectrometry (LIBS) are the excitation methods most examined for metals monitoring. Anodic stripping voltammetry is used in ambient air monitoring systems but has not been applied for source applications (Desmond et al. 1998; Somerset 2011; U.S. DOD 2002).

X‐ray Fluorescence Spectrometry

In X‐ray fluorescence spectrometry, atoms are excited by X‐rays, where inner electrons of the atoms are ejected. Electrons from higher orbitals fall into the lower energy states and release excess energy as photons, i.e. they fluoresce, emitting light at wavelengths specific for each metal.

When analyzing for metals using this technique, particulate‐bound and gaseous metals are first collected isokinetically on an activated carbon impregnated filter. The collected material is then exposed to X‐rays. Metals collected on the tape will fluoresce at their characteristic wavelengths, whereupon the intensity of light at that wavelength is measured using a solid‐state detector and the flue gas metal concentration is determined.

A monitoring system developed by Cooper Engineering for ambient and source emission measurements uses this technique and has found several commercial applications. The Cooper Engineering Xact 640 system is shown in Figure 13‐10.

In this system, flue gas is drawn isokinetically from the stack through a heated line to a stilling chamber using an ejector pump. A sample is drawn from the chamber through a chemically treated filter tape. After sufficient sample is collected, the tape is advanced and is subjected to X‐rays. The metal atoms are ionized and will fluoresce at wavelengths characteristic of their electronic structure. In 2004, Eli Lilley applied this method at a hazardous waste incinerator and installed one on a U.S. army hazardous waste incinerator, and also a lead smelter to meet the alternative monitoring requirements for metals in Part 63. The system has also been tested on a variety of other facilities (Hay et al. 2006; Peterson et al. 2008). The Xact system is one of the few commercial continuous metals emission monitoring systems available.

Laser‐Induced Breakdown Spectroscopy

In laser‐induced breakdown spectrometry, a high‐energy laser is used to excite metal atoms, both in the gaseous phase and those adhering to the surface of the particulate matter. The light emitted by the excited metal atoms is again analyzed.

A related technique is optical spark spectroscopy, where a spark formed between the sample and an electrode is used to excite the metal atoms.

Inductively Coupled Plasma Spectroscopy

In the inductively coupled plasma spectrometry technique, a radio‐frequency‐generated plasma of high‐temperature argon gas is used to heat the flue gas sample to temperatures greater than 10 000 °C. The light emitted by the metal atoms excited at this extreme temperature is then measured using a diffraction grating and photodetectors or diode array (Figure 13‐11).

Figure 13‐10 X‐ray fluorescence continuous metals emissions monitoring system.

Figure 13‐11 Atomic emission spectroscopic method for monitoring metals – inductively coupled plasma technique.

A system using this technique was demonstrated in a number of applications (Meyer and Seltzer 1997; Seltzer et al. 2001) where the sample is extracted continuously and isokinetically from the stack and is then subjected to the heat of a plasma torch.

Certifying Multi‐metal CEM Systems

Validating multi‐metal monitoring methods is often difficult, particularly in droplet‐laden wet stacks typical in waste incineration facilities (Dunn et al. 1998). The partition of metals between gaseous and solid phases introduces additional difficulties since problems of both gaseous and particulate stratification and both gas and particle sampling losses need to be overcome. The problems associated with isokinetic sampling, particle loses in the probe and sampling line, have often led to inconsistent results and frustration in providing reproducible data. Also, uncertainties associated with manual wet chemical test methods (e.g. Method 29) for metals have led to uncertainties in assessing the performance of instrumented methods.

In addition to sampling issues, convenient calibration methods and traceable standards are not as readily available as those for gases such as the criteria pollutants. However, other methods such as dynamic spiking and reference aerosol generators can be used. One such generator, the QAG (“quantitative multi‐metals reference aerosol generator”) developed by Cooper Engineering generates test gases of known concentration. It can be used to check the calibration of any extractive system–based metals monitor (Cooper et al. 2005e; Yanca et al. 2005), as well as particulate matter CEM systems.

A performance specification was proposed in 1996 for multi‐metal CEM systems, but was never promulgated (EMC 2020). With lack of an EPA certification procedure, three performance specifications specific to the X‐ray fluorescence method developed by Cooper Engineering were proposed by Cooper et al. (2005a,b,c,d). The methods are based on EPA Method 301 validation procedure and are available as “optional test methods” (OTMs), OTM‐16, OTM‐17, and OTM‐19. Quality assurance procedures for the Cooper monitoring system are given in OTM‐20. Although available for use, none of these OTMs has been promulgated as official procedures, and no further performance specifications have been proposed by EPA for multi‐metals.

The optional test methods for multi‐metals depart from the “performance‐based” standards traditionally required by EPA. They may serve as guidelines for validating other metal monitoring systems; however, their applicability may be limited due to their inherent bias for the Cooper Xact monitoring system.

Particulate Matter Surrogate Monitoring

With the assumptions that metal emissions are primarily associated with particulate matter, particulate monitoring devices have been used as surrogates for metals monitors. EPA regulations have allowed the use of particulate monitors to track the performance of emission control exhausts, especially in the Part 63 air toxics rules, where bag leak detectors (BLDs), and sometimes opacity monitors, are required to be installed after baghouses. Any type of particulate monitor could be used as a bag leak detector; however, triboelectric sensors are the most common. When referring to bag leak detectors, it is generally assumed, unless otherwise noted, that low‐cost triboelectric devices will be used for this application. A description of the operating principles of triboelectric BLDs is already given in Chapter 9. This section discusses regulations acssociated with their use in the Part 63 air toxics program.

Bag leak detectors are addressed in over 25 of Part 63 subparts for major sources and area sources. In Part 63, the BLD output is included in the discussion of continuous parameter monitoring systems (CPMS) as merely another parameter akin to pressure drops, temperatures, or flow rates. As discussed in Chapter 9, bag leak detectors provide an alarm when a leak or break occurs in the fabric of a bag in the baghouse. Outside of setting an alarm point, a triboelectric bag leak detector is not usually applied to continuously monitor particulate concentration, although this has been done (Tacelli et al. 1993). In Part 63, BLDs are not correlated to particulate concentration as a PM CEM through the procedures of Performance Specification 11, nor are they correlated to the particulate compliance value as a PM CPMS. As mentioned, for the purposes of Part 63, bag leak detectors are not considered CEM systems and are treated as sensors, whose signal (alarm or otherwise) is to be included as part of a CPMS used as a continuous monitoring system (CMS).

For many smaller sources, particularly area sources, the only instrumented monitoring requirements or options are those where fabric filter baghouses are used to control particulate matter emissions. Bag leak detectors can be installed in the baghouse outlet duct, stack, or in the compartments of multi‐compartment baghouses (Figure 13‐12).

Triboelectric bag leak detectors are more sensitive to small leaks than are opacity monitors but are less quantitative. When opacity monitors are required, bag leak detectors can be used to complement them, which are able to alarm for small leaks before an opacity violation might occur. The primary purpose of installing bag leak detectors is to have a means of detecting relative changes in the baghouse exhaust particulate loading, where deviations from the baseline established during normal operation may indicate bag leaks or breaks that require maintenance attention. The facility Part 63 site‐specific “monitoring plan” should then specify that maintenance be performed or that the problem otherwise addressed to assure continuous compliance with emissions requirements.

BLD design and performance specifications are given in each Part 63 subpart where they are required to be installed. Specifications include the following:

The system must be certified by the manufacturer to be capable of detecting particulate matter concentrations at 10 mg/m³.

The system must provide an output that can indicate relative changes in particulate matter concentration.

The system must be equipped with an alarm that will sound when the output exceeds a preset level.

A BLD that works based on the triboelectric effect must be installed, operated, and maintained in a manner consistent with the guidance given in the EPA Fabric Filter Bag Leak Detection Guidance document (U.S. EPA 1997).

For additional assistance in specifying BLD design and performance characteristics, ASTM Standard Practice ASTM D7392 provides guidance for BLD applications in cement plants (ASTM 2020).

The Part 63 site‐specific monitoring plan is required to incorporate a written BLD quality assurance plan, which includes the standard operating procedures for the monitoring system. The plan is to include the following:

Details on the installation of the bag leak detection system

A description of the operation of the system

Figure 13‐12 A bag leak detector installation.

A description of the maintenance procedures, including routine maintenance schedules and a spare parts list

A description of data recording and archiving procedures

A description of the method used to determine the instrument baseline and alarm set point.

Triboelectric bag leak detectors typically come with a scale range from 0 to 100, on which the baseline is initially set. The baseline should be set at normal baghouse operating conditions. The instrument should show the signal spikes from the baseline during cleaning cycles, which should return to the baseline after the cleaning cycle is completed. Alarm levels can be set at the operator’s discretion but should include a caution level and an alarm level below that which would correspond to an opacity violation (Wesselman and Askins 2005). If different baghouse rows are cleaned sequentially, the sensor signal pulse, monitored for each row during the cleaning cycle, can provide an indication of the relative condition of the bags. The instrument signals can also be compared over time to indicate diminishing performance. In addition, after bags have been replaced, the bag leak detector can indicate whether they have been fitted properly.

POLYCHLORINATED DIBENZODIOXINS AND POLYCHLORINATED DIBENZOFURANS

Polychlorinated dibenzodioxins (PCDDs) and dibenzofurans (PCDFs) are a group of related chlorinated biphenyls, which are byproducts in combustion processes. Considering the biphenyl structures, there are a large number of compounds possible, depending upon the number of chlorine atoms in the molecule. The terms dioxin and furan refer to a larger class of heterocyclic compounds containing a dioxin or furan ring, to which the chlorinated dibenzo dioxins and furans belong. The physical and chemical characteristics of dioxin and furan isomers vary, depending upon the number and position of the chlorine atoms on the aromatic rings. These possibilities are shown in Figure 13‐13.

For the PCDD structure, there are 75 possible compounds (congeners) and 45 for the PCDF structure. The compound 2,3,7,8‐tetrachlorodibenzo‐p‐dioxin (TCDD where there are chlorines at the 2, 3, 7, and 8 positions) is the most toxic of this group, with other congeners having similar biological effects, but to a lesser degree. These compounds do not appear singly in the flue gas of combustion sources, but as a mixture of congeners, some of which are toxic. Because of this complexity, dioxin/furan emissions are often reported on the basis of their toxicity. Here, toxicity of the dioxin/furan congeners is weighted relative to TCDD, which is defined as having a Toxic Equivalency Factor (TEF) of 1.0. The TEF of each congener is multiplied with its concentration, and summation of these values provides the total toxicity of the sample in ng TEQ/m³ (ng Toxic Equivalents/m³).

Dioxin/Furan Continuous Emission Monitoring Options in Part 63

In the United States, commercial solid waste incinerators in the City of Baltimore are required to install dioxin/furan monitoring systems; however, there is otherwise little demand in the United States for continuous dioxin monitors. However, the Part 63 subparts for combustors and incinerators allow for the optional installation of dioxin/furan monitoring systems instead of conducting manual performance tests for these compounds. States may also require dioxin/furan monitoring systems on a case‐by‐case basis through state permitting processes. In Europe, Belgium, Italy, and France have instituted dioxin/furan monitoring requirements, and monitoring requirements are expanding in Asia ─ Taiwan, China, and Japan. Reinmann (2012) estimates that worldwide approximately 500 systems have been installed.

One problem is that the option to use continuous automated dioxin/furan sampling systems takes effect “on the date a final performance specification applicable to dioxin/furan monitors is published in the Federal Register, or on the date of approval of a site‐specific monitoring plan.” There are at present no U.S. EPA Performance Specifications or relative accuracy test procedures for PCDD/PCDF continuous automated dioxin/furan sampling systems, so if this option is chosen, a site‐specific monitoring plan would have to be developed. In this regard, the European Union has standardized certification procedures for PCCD/PCFF measurements in a five‐part standard, EN‐1948‐(1‐5) (CEN 2006a,b,c,d, 2015). EN‐1948‐5 gives specifications and procedures for continuous dioxin/furan sampling systems, which could be referenced in the development of such a monitoring plan.

Figure 13‐13 Chemical structures of PCDDs and PCDFs.

Continuous Emission Monitoring for Dioxin/Furans

Measuring PCDD and PCDF emissions from stationary sources is one of the more difficult endeavors in source testing and analysis. Because of the similar structures of the these compounds, sophisticated analytical methods such as high‐resolution gas chromatography and mass spectrometry are necessary to distinguish between the toxic and non‐toxic cogeners. Controlled to low levels in most combustion processes today, these emission measurements are all the more difficult to measure accurately when dealing with uncertainties associated with both sampling and analysis (Rivera‐Austrui et al. 2011).

Continuous emission monitoring systems for dioxin/furans are not continuous in the usual sense for gas monitors where hourly averaged emissions values are obtained. The methods utilize auto isokinetic sampling techniques, where a sample cartridge, containing an adsorbant material, collects samples over a programmable period that extends typically to two weeks (Environment Agency 2006). The “monitoring” systems do not analyze the sample; they merely provide a collection mechanism for the sample.

Reference Methods

Reference test methods for PCDDs/furans have been published in a number of countries. The European method EN1948, U.S. EPA Method 23, and Japanese authorized method (JIS K0311) are the most pertinent to continuous PCDD monitoring systems (JIS 2005). The methods are all similar, where the particulate matter is collected on a filter and the PCDD/furans in the gas stream are collected on an adsorptive material, such as XAD‐2 resin. The sampling train for EPA Method 23 is illustrated in Figure 13‐14. The materials are recovered, treated, and then analyzed according to the same procedures employed in the reference test method, EPA Method 23 or EN1948 in Europe. The PCDD/PCDF compounds extracted are by high‐resolution gas chromatography and identified and quantified by high‐resolution mass spectrometry. The analytical procedures are based upon the isotopic dilution technique, using internal standards labeled with ¹³C₁₂. Steps performed in conducting the analysis are summarized in Figure 13‐15.

Semicontinuous Sampling Systems

Dioxin/furan semicontinuous sampling systems were developed in Europe and have found their primary market there in response to Europe legislation requiring the continuous monitoring of PCDDs/PCDFs emissions.

Dioxin/furan monitoring systems are basically automated sampling platforms similar to carbon trap continuous monitoring systems developed in the United States for mercury and mercuric chloride from coal‐fired power plant flue gases. Several dioxin/furan sampling systems are available commercially today, provided by the companies Envea (formerly Becker Messtechnik GmbH), Deutschland (Germany), Monitoring Systems GmbH (Austria), and Tecora (Italy).

Figure 13‐14 U.S. EPA Method 23 sampling train for dioxins and furans.

Figure 13‐15 Steps in test methods for PCDDs/furans.

As implied, the commercial dioxin/furan monitoring systems are basically automated versions of the reference sampling methods (U.S. EPS Method 23 or CEN Method EN1948), with the sample analysis being virtually the same. These systems can sample on a continuous basis over programmable time periods, from four hours to six weeks. The advantage of longer sampling times is that more sample and therefore more of the PCDD and PCDF analytes, can be collected for analysis to reduce measurement uncertainty. The continuous “long‐term” measurements provide a more realistic assessment of the plant emissions than the short‐term reference method tests, which typically are conducted over an 8‐hour period only once or twice a year. A long‐term sampling system can monitor emissions during start‐ups and shutdowns, or periods of unstable operation. By sampling under all operating conditions, the plant performance, and emission control systems can be better evaluated and subsequently optimized with respect to PCDD/PCDF emissions (Reinmann 2002a,b, 2004; Reinmann et al. 2010).

After samples are collected, the cartridges are removed and sent to an analytical laboratory for analysis by GC/mass spectrometry. The range of concentrations that can be measured is dependent upon the sampling time. For a 8 hour sample, PCDD/PCDF levels of 0.01 to 100 ng TEQ/m³ can be measured. For a six‐week sample, it is possible to measure levels down to from 0.001 TEQ/m³with the accumulation of measurable quantities over time.

Sampling Approaches

Three approaches can be used for sample collection: (i) the filter/condenser method, (ii), the dilution method, and (iii) the cooled‐probe method. Irrespective of the approach, the flue gas sample is withdrawn isokinetically, at a probe velocity that is the same as the flue gas velocity to collect a particulate sample representative of that in the stack. The options are as follows:

In the filter/condenser method, particulate matter is first removed from the sample gas maintained at a temperature of 125 °C to avoid condensation. The filter can be a cyclone, flat filter, or packed glass wool. After the filter, the sample is cooled to 20 °C and then enters a trap, where the PCDD/F compounds (and other organic compounds) are adsorbed and removed from the sample stream. The adsorbent is typically XAD‐2 resin. EPA Method 23 specifies the use of the filter/condenser method.

In the dilution‐extractive method, the flue gas is sampled through a heated probe and then diluted with clean, dry filtered air, to a temperature below 40 °C. The dilution allows the subsequent collection of the sample components without having to condense the moisture. However, the sample is still a “wet” sample, but has a dew point low enough that condensation is avoided.

In the cooled‐probe method, a water‐cooled probe is used, where flue gas moisture will condense in the probe, the sample exiting the probe at a temperature of 20 °C or lower. Condensation inside the probe can serve to wash deposited particulate matter into the collection system.

Sample Recovery and Analyte Extraction and Cleanup

After the flue gas sample is obtained, the sample is recovered. The filter and the XAD‐2 trap or a polyurethane foam (PUF) substrate are removed and the nozzle, probe, and front half of the filter holder are rinsed with acetone, methylene chloride, and toluene, the rinses being collected in various containers. The filter and the XAD‐2 trap or PUF substrate and rinses are then taken to a laboratory and analyzed in the same manner as that of Method 23 samples.

As in the reference methods, the XAD‐2 cartridges are spiked with ¹³C₁₂ PCDD/PCDF standards. After the sample is run for typically two weeks, the quartz wool and XAD‐2 are refluxed in a large‐volume Soxhlet extractor. In typical operation of this system, only the adsorption unit contents are analyzed. The sample is cleaned up and concentrated as in the reference method, with the ¹³C₁₂ spiking levels adapted to the volume of the flue gas sampled. The final concentrate is analyzed by high‐resolution gas chromatography and high‐resolution mass spectroscopy.

Commercial Systems

Three systems are presently available commercially for the collection of dioxin/furan samples. All three are based in Europe and serve primarily the European market.

ENVEA

The Envea AMESA dioxin monitoring system was developed by the German companies GfA and Becker Messtechnik in the mid‐1990s. The AMESA dioxin monitoring system was the first commercial system, and numerous papers have been published to document its ability to provide long‐term data useful for identifying operational problems at municipal waste combustors. A number of these systems were installed in municipal waste combustors facilities in Belgium, where continuous dioxin monitors were first required in 2000. The Envea AMESA system uses a water‐cooled titanium probe, essentially following the cooled‐probe method discussed earlier. The system was evaluated by Battelle in EPA's Environmental Technology Verification (ETV) program (Battelle 2006b). See also Horie et al. (2007).

TECORA

The Dioxin Emission Continuous Sampling (DECS) system was developed by TECORA in Italy in 2006. A heated titanium probe is used in this system instead of a water‐cooled probe.

The system follows the filter/condenser method of EN1948 (similar to Method 23) where moisture in flue gas sample is condensed before the XAD‐2 cartridge rather than after the cartridge as in the ENVEA AMESA system. Particulate matter is first removed in a heated quartz thimble, after which the sample enters a condenser, where it is cooled to a temperature less than 20 °C. A cartridge containing quartz wool and XAD‐2 follows, where the organic compounds are adsorbed.

Gasmet

The Gasmet GT 90 Dioxin system (formerly, the Monitoring Systems GmbH [Austria] DMS system) utilizes the dilution sampling method of EN1948 in contrast to the cooled‐probe method used by the ENVEA and the filter/condenser method used by TECORA (Battelle 2006a). The system became available in Europe in 2000 and was the second commercial system to be developed. Besides using the dilution sampling method, it is unique in using polyurethane foam as an adsorbent for organic gases, employs null sampling nozzles, and utilizes two titanium sampling probes to obtain a more representative particulate sample. The system was evaluated by Battelle in EPA's Environmental Technology Verification (ETV) program (Battelle 2006b).

Accuracy of the Commercial Systems

To determine uncertainties associated with the DMS measurements, Kahr (2004) used the basic EU propagation of error technique using “estimated” variances associated with reference material, blank values, volume measurement, isokinetic sampling, probe stack position, the recovery standard, and particulate inhomogeneity. An uncertainty of 30.5% was calculated for a sample taken over an eight‐hour period. For a sample taken over a one‐week period, an uncertainty of 16.9% was determined.

Uncertainties associated with the peripheral measurements of the system were estimated by Bergmans (2007) and are shown in Table 13‐2. With these estimates, an extended uncertainty was estimated at 30–40%. Bergman's conclusion was that main uncertainties arise from the analysis step and the representativeness of the sample.

TABLE 13‐2 Propagation of Error in Continuous Dioxin Monitors

Source: Data from Bergmans et al. (2007).

Contributing Factors | Uncertainty
Volume | 4.6%
O₂% (for O₂ diluent corrections) | 5%
No representative sampling | 10%
Isokinetic sampling variation | 1.3%
Extraction/Purification | 1.3%
Analysis | 6–15a

a At the 16 pg/u level depending upon the congener.

Current Status of Dioxin/Furan Sampling Systems

It is clear from the European experience that continuous dioxin sampling systems provide a valuable tool for monitoring the ability of combustion facilities to either come into compliance or remain in compliance with PCDD/PCDF emission levels. The data can be sufficiently reliable to see trends in emissions and can periodically be checked with the reference test method to provide some assurance to its validity. The main problem is that for their application in the United States there are no performance standards developed to assess what constitutes acceptable data.

Real‐Time Dioxin/Furan Monitoring Methods

It can be argued that long‐term sampling of two to four weeks does not allow the plant operator to respond to dioxin/furan emissions on a real‐time basis. This may be true, however, many of the conditions that lead to dioxin/furan formation can be monitored by other instrumentation, such as temperature sensors and oxygen monitors. Nevertheless, attempts have been made to develop real‐time dioxin/furan monitors. One continuous system developed utilizes a wavelength‐tuned UV laser to selectively excite dioxin/furan congeners, which can then be separated by mass in a time‐of‐flight mass spectrometer (Uchimura 2005; Zimmerman et al. 1999). The simultaneous detection by wavelength and mass leads to high selectivity, providing the capability to discriminate between compounds of similar chemical structures. In contrast to the pre‐concentration/separation techniques discussed above, this technique, “jet expansion with Resonantly Enhanced Multiphoton Ionization (jet‐REMPI),” allows the detection of multiple organic compounds within seconds.

The method can measure a range of aromatic compounds to parts per billion and part per trillion levels. However, the toxic PCDD/PCDF congeners are beyond the detection limits (100 ppt) of the technique. To produce a workable instrument for the measurement of toxic PCDD/PCDF congeners, the higher concentration surrogates, or indicator compounds, are measured instead to “infer” their concentration (Gullet et al. 2012). Also, because of its complexity, high cost, and questionable accuracy (Battelle 2006c,d), further development work appears necessary.

SUMMARY – MEASURING HAPS

The regulation of a large number of source categories designated as emitters of hazardous air pollutants, having the potential to emit one or more of 186 designated different HAPs, has been a daunting task that took over 15 years to complete. Continuous monitoring systems (CMSs) provide a means of assuring continuous compliance with emission limitations; however, the rules do not say that each pollutant must be monitored using CEM systems. Where referenced in the subpart, initial compliance is shown by conducting EPA reference methods in performance tests for each applicable pollutant, but continuous compliance can often be demonstrated by using continuous parameter monitoring systems or by monitoring a surrogate instead of the actual HAP, using a CEM system.

For many of the affected source categories, individual organic compounds do not have to be speciated, but may be measured with an analyzer that can monitor their emission as total hydrocarbon or total volatile organic carbon. Instead of installing multi‐metal monitors, particulate monitors may serve as a surrogate, with the assumption that the metals are emitted as particles or are bound to particles. For HCl in particular, SO₂ can serve as a surrogate if the unit emissions are controlled using a wet or dry scrubber. The many options available for monitoring limit the application of CEMS for most sources, except for electric generating units, cement plants, petroleum refineries, and a few others.

In most cases, CEM systems can still be chosen as an alternative to CPM systems, a choice that may be driven by the sheer weight of tracking and validating the myriad sensors incorporated into a parameter‐based monitoring plan. The correlation of process and/or control equipment parameters to operating limits that correspond to emission limits is basically the same strategy taken with the development of a predictive emission monitoring system (PEMS), but without having to do the statistics of Performance Specification 16.

This chapter has attempted to provide an overview of the salient features of Part 63 that relate to continuous emission monitoring systems. As in the Part 60 New Source Performance Standards, requirements for installing a CEM system may depend upon whether the source is existing or new, the size of the source (as relating to output), whether control equipment is used to limit emissions, and the regulatory options allowed for demonstrated continuous compliance with emission limits. In general, sources with emission control equipment are more likely to be required to install some type of analytical monitoring system. A summary of analytical monitoring options for major HAP categories is given in Table 13‐3.

TABLE 13‐3 Summary of Analytical Monitoring Options for Major HAP Categories

Pollutant
Analytical Methods
Surrogates
Reference Methods
CEM Performance Specifications

Hydrocarbons/organic compounds
GC, MS, NDIR, NDUV
THC
TVOC
RM18, RM 106
301
ISO 13199
ISO 20264

Acid gases (HCl, HBr, HF)
NDIR, FTIR
SO₂ after scrubbers
RM 26
PS‐18

Mercury
AAS, AFS

RM 12A, RM 12B, RM 29, RM 101a, b, RM 102
ASTM D6784
PS‐30A/PS‐30B

Multi‐metals
XRF
Opacity, PM, PM CPMS
RM 29
OTM 16‐20

Particulate matter
Beta radiation attenuation
Loaded oscillator
Light extinction
Light scattering

RM 5, RM 17
ISO 9096
ISO 12141
PS‐11
ISO 10155

Opacity monitors
Light attenuation

N/A
RM 9 and ASTM 7520 N/A to COMS
PS‐1
ASTM D6216
(Design Specs)

Bag leak detectors
(BLDs)
Probe electrification (Triboelectric effect)

N/A
ASTM 7392‐07
(Design Specs)

Dioxin/furans
Periodic sampling and GC/MS
Temperature CO, O₂
RM23
EN‐1948

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CHAPTER 14
GREENHOUSE GAS MONITORING

The reality of radiative forcing by gases such as CO₂, CH₄, and N₂O has been of considerable concern to the scientific community for over 35 years (Hansen 1986). The increased atmospheric concentrations of these and other gases has led to changes in the atmospheric energy balance through the greenhouse gas effect and a consequent increase in the global temperature. Atmospheric carbon dioxide measurements taken at the Hawaiian Mauna Loa observatory showed a rise in CO₂ concentration from 315 ppm in 1958 to 411 ppm in 2020. These concentrations are in contrast to levels of approximately 280 ppm prior to the industrial revolution of the late 1700s and have not been seen in the fossil record for 800 000 years. After noting a rise in global temperature of 0.8 C since 1880 (Goddard Institute for Space Studies), further global temperature is projected to increase from 2 to 3 °C by 2100 if steps are not taken to reduce greenhouse gas emissions. Programs designed to reduce carbon and other greenhouse gas emissions must first evaluate their magnitude and then continue to track them to evaluate the progress of mitigation activities.

Irrespective of the promulgation or lack thereof, of government programs to reduce national levels of greenhouse gas emissions, industries recognize that the realities of climate change must be addressed in long‐term planning. The public response to carbon neutrality has already had and will have future consequences for the use of fossil fuels. The increasing use of solar power and wind power has led to the closure of older coal‐fired power plants with gas turbines or gas‐fired boilers being favored for new or supplemental generation. This leads to reductions in CO₂ emissions from the power sector, but there are other industries where the goal of carbon neutrality is difficult, if not impossible to achieve –steel production requires carbon, making cement emits carbon, plastics are made from petroleum products. However, increases in efficiencies, the development of new processes, or the use of alternative materials can lead to CO₂ reductions even in these industries. In either case, monitoring and reporting activities are necessary to assess progress in meeting mitigation targets.

Emissions reporting programs have been instituted by more than 40 developed countries identified in the United Nations Framework for Climate Change (UNFCCC 1992a, b) including the United States, Canada, EU member countries, Japan, Australia, and New Zealand and over 150 other countries. The source‐specific data obtained through these programs can inform greenhouse gas mitigation policies and programs, such as carbon pricing, carbon trading, or other carbon reduction strategies. With the promulgation of the mandatory greenhouse gas reporting rule (EPA 2009), reporting greenhouse gas emissions in the United States began in earnest for sources that emit more than 25 000 tons per year. Two basic approaches are taken in this program for reporting emission data: (i) measuring the emissions using gas monitoring instrumentation or (ii) calculating the emissions using fuel usage data, process data, and/or emission factors. This chapter addresses both approaches.

METRICS USED IN REPORTING GREENHOUSE GAS EMISSIONS

The reporting and treatment of greenhouse gas data has become a specialized field onto itself, with the development of measurement and reporting standards, report preparation, and data review and auditing. Accordingly, the field has adopted various ways of quantifying greenhouse gas emissions, which regulatory control programs use to set goals and track progress. These metrics typically express CO₂ emissions using some other parameter in addition to the CO₂ concentration, where the parameter must be a known value, or a given value, to calculate tons of CO₂.The following metrics are among those used:

Gas Concentration (%, ppm): The gas concentration measured by an analyzer. CO₂ ambient air concentrations are expressed in parts per million (ppm). CO₂ emissions from carbon‐based fuel combustion sources is expressed in percent by volume.

Pollutant Mass Rate (tons/hr, tons/year, tonnes/year): The mass emission rate of a pollutant calculated as the product of the gas concentration and the flue gas volumetric flow.

Global Warming Potential (GWP): A relative term used to compare the warming impact of one ton of a compound in the atmosphere, compared to one ton of CO₂ over a 100‐year timeframe. Carbon is assigned a global warming potential of 1, as the reference gas.

Carbon Dioxide Equivalent (CO₂e): Based on the global warming potentials of different gases, a metric used to express the global warming potential of a set of different greenhouse gases in terms of the amount of CO₂ that would have the same potential.

Carbon (Emission) Intensity of Energy Use (C.I.) (g CO₂/MJ, tons CO₂/gdp): The emission rate of CO₂ relative to the intensity of a given activity. For energy consumed, the emission intensity is the ratio of amount of CO₂ emitted per MMBtu (kgCO₂/MMBtu or g CO₂/MJ). Carbon intensity can also be expressed as the ratio of tons of carbon emissions per $1000 of gross domestic product.

Per Capita CO₂ Emissions: Annual tons of emissions per person, usually given by country.

All these metrics are used in discussions on greenhouse gas emissions. Gas concentration and pollutant mass rate are the most pertinent to continuous emission monitoring systems, whereas carbon intensity and per capita emissions are used to discuss trends in CO₂ emissions, but in some cases are used to obfuscate them. Global warming potential addresses the fact that compounds other than CO₂ contribute to the greenhouse gas effect at various levels. These terms are discussed in more detail next.

Gas Concentration

Gas concentration measurements are typically measured in volume percent or parts per million by volume, i.e. the ratio of the volume of the gas of interest to the total volume. CO₂ source emission concentrations are measured in percent, whereas ambient air concentrations are measured in units of parts per million. Because source emission levels of CH₄ and N₂O are typically low, emission levels are expressed in parts per million and atmospheric concentrations in parts per billion.

Pollutant Mass Rate

The equation for stationary source pollutant mass rates was given as Equation 7‐1 in Chapter 7 in conjunction with flow monitors. Multiplying the concentration of a pollutant in a gas stream by the volumetric flow rate of that stream, gives the amount of pollutant released to the atmosphere per unit of time. For CO₂ emissions, the mass rate can be expressed as

(14‐1)normal p m normal r Subscript upper C upper O 2 Baseline equals normal c Subscript upper C upper O 2 Baseline times upper Q Subscript s

where

p m r Subscript upper C upper O 2 = CO₂ pollutant mass rate (tons/yr, kg/hr, lbs/hr)

normal c Subscript upper C upper O 2 = CO₂ concentration (percent as a fractional value)

Qs = stack volumetric flow rate (m³/hr, ft³/hr)

s = stack

Using CEM systems, this rate is measured and recorded hourly, from which an annual CO₂ emission value can be easily calculated. Pollutant mass rates can also be determined by using fuel usage data, high heating values, emission factors, or mass balance calculations. Various options are allowed in the tier approach taken by the U.S. EPA mandatory gas reporting rule, which is discussed later in this chapter.

Tons of CO₂ emitted per year is typically used for establishing regulatory limits and tracking progress. It is used in environmental assessments, climate change models and is the metric best understood by the public when discussing global warming issues.

Global Warming Potential (GWP)

Global warming potential is an expression without units, It is an expression of the ability of a compound to absorb infrared radiation relative to CO₂ over a specified period of time. Because some compounds decompose faster in the atmosphere than others (for example, methane decays after 12.4 years), global warming potentials are calculated over various time periods from 20, 100, to 500 years, although 100 years is the most commonly used. This point is important since for the emission of a fixed amount of gas into the atmosphere, a gas like methane will have a higher global warming potential over a 20‐year period, than over a 100 year period, a time period over which it has been largely decomposed. Global warming potentials for several greenhouse gases are listed in Table 14‐1.

TABLE 14‐1 Global Warming Potentials for Greenhouse Gases*

Compound
Lifetime (yrs)
20 Year GWP
100 Year GWP
100 Year GWP
CAD US

Carbon dioxide (CO₂)
Variable
1
1
1

Methane (CH₄)
12 ± 3
84
28
25

Nitrous oxide (N₂O)
121
264
298
298

Perfluoromethane (CF₄)
50 000
4950
7350
7390

SF₆
3200
16 300
23 500
22 800

Water (H₂O)†
<2 weeks
−0.004 to +0.002
−0.001 to +0.0005

* UNFCCC (2021).

† Sherwood et al. 2018.

Note: These values vary between the Intergovernmental Panel on Climate Change (IPCC) assessment reports, which are dependent upon updated data and refinements in the calculations (IPCC 2013). Values cited are without climate‐carbon feedbacks.

Carbon Dioxide Equivalent (CO₂e)

Carbon dioxide equivalent is a metric used to express the global warming impact of a set of different greenhouse gases as a single number. Taking into account the GWP of each gas, CO₂e is defined as the amount of CO₂ that would give the same impact. The metric essentially weighing the contributions of each gas relative to CO₂ is expressed as follows:

(14‐2)upper C upper O 2 normal e equals sigma-summation Underscript i equals 1 Overscript n Endscripts p m r Subscript i Baseline times upper G upper W upper P Subscript i

where

CO₂e = carbon dioxide equivalent (tons/year)

pmri = mass emissions (pollutant mass rate) of each greenhouse gas, metric tons/year

GWPi = global warming potential for each greenhouse gas

n = number of greenhouse gases emitted

The number is useful in incorporating the contribution of gases other than CO₂, to radiative forcing without having to list them individually. In the U.S. EPA greenhouse gas reporting program, annual emissions from the gases listed in Table 14‐2 are required to be reported as CO₂e.

TABLE 14‐2 Reported Greenhouse Gases

Carbon dioxide | CO₂
Methane | CH₄
Nitrous oxide | N₂O
Fluorinated compounds |
 Hydrofluorocarbons | HFCs
 Perfluorocarbons | PFCs
 Nitrogen trifluoride | NF₃
 Sulfur hexafluoride | SF₆
 Halogenated ethers |
 Others |

Carbon (Emission) Intensity

Emission intensity is used to compare greenhouse gas contributions from different fuels or activities, or the relative contributions between different sources. For example, carbon intensity expressed as emission rate per kilowatt‐hour can be used to compare emissions between different sources of electric power or if expressed as emissions per mile traveled, the relative contribution of emissions between different vehicles. The ratio of greenhouse gas emissions to gross domestic product can illustrate relative greenhouse contributions between different national economies, but has also been interpreted as indicating progress in reducing greenhouse emissions when CO₂/gdp ratios decrease.

Per Capita CO₂ Emissions

Per capita CO₂ emissions are expressed as the annual metric tons of CO₂ attributed to an individual. Per capita emissions for a country are calculated by dividing the total amount of CO₂ consumption and production activities of the country by the country's population. Per capita emissions are a useful way of comparing the relative contribution of CO₂ per person between different countries. They can also be calculated for other geographical areas.

Decreasing per capita emissions might at first indicate progress in reducing CO₂ emissions; however, as with carbon intensity, the net CO₂ emitted is dependent upon other conditions, in this case, the country's population. If per capita CO₂ emissions remain the same, increasing birth rates can lead to increased annual CO₂ emissions. Also, immigration into a country from populations having lower per capita emissions will lead to higher global CO₂ emissions.

As a straightforward example of the use of these metrics, the tons of CO₂ emitted from a coal‐fired power plant can be calculated by multiplying the total energy content of the fuel used during the year and the energy intensity. To calculate the annual CO₂ emissions of a country, the per capita CO₂ emissions is multiplied by the number of people in the country. However, just as lower per capita CO₂ emissions do not necessarily mean annual national emissions are decreased if the population has increased, a lower carbon intensity does not necessarily imply lower overall CO₂ emissions in a burgeoning economy.

Metrics and Their Implications

The metrics given above each have a purpose and are reported and utilized in various regulatory control programs. Measuring gas concentrations and pollutant mass rates, along with the calculation of global warming potentials and carbon dioxide equivalents, are a means of keeping track of emissions and their effect on the environment. The metrics for carbon intensity and per capita emissions are often used for comparative purposes to show relative contributions or trends between countries, different industries, or other entities. Yet again, as Nordhaus (2013) points out, the multipliers are important. The higher the gdp or the higher the population, the higher the total emissions.

DIRECT MEASUREMENT AND ESTIMATION METHODS FOR GREENHOUSE GAS EMISSIONS

The direct measurement of emissions from stacks, flues, tailpipes, or other emission points using analytical equipment is often considered the most accurate method of measurement. This may be true when determining the gas concentration; however, the metrics discussed above are by and large based upon emission rates, where a volumetric flow rate is required in addition to determine pollutant mass rates. The problems associated with measuring flue gas volumetric flow using CEM systems are discussed in Chapter 7 and have been well known since the 1990s, when they were largely resolved (see, for example, Cashin et al. 1996; Lieberman and Schakenbach 1997).

When CO₂ monitoring is required in a CEM system, CO₂ infrared analyzers are typically incorporated into an extractive system. Because measurements are made at percent levels, the analyzers do not have to be as sophisticated as those measuring low part per million levels. NDIR techniques such as gas‐filter correlation and spectrophotometric methods are commonly used. NDIR techniques can be used for monitoring CH₄ as well as N₂O, although these measurements are at part per million levels and require analytical techniques that are not subject to interferences from H₂O, CO₂, and/or other gases. Greenhouse gases such as perfluorocarbons, sulfur hexafluoride, and other halogenated compounds have few commercial analyzers dedicated to their measurement. They are typically not measured with continuous monitoring systems; however, FTIR analyzer, gas chromatographs, or mass spectrometers can be used for their analysis.

Due to the expense of continuous monitoring and a wide variety of sources and emission points, the direct measurement of greenhouse gases using continuous emission monitoring systems is rarely feasible for preparing comprehensive emission inventories. Where available, quality assured CEM system data can be used as a resource; however, estimation methods are generally used. These methods are detailed by the Intergovernmental Panel on Climate Change (IPCC) in the 2006 IPCC Guidelines for Greenhouse Gas Inventories (IPCC 2006). In the simplest method, an emission factor is multiplied by activity data characteristic of the emission source, as expressed in Equation 14‐3:

(14‐3)upper E m i s s i o n s equals upper A upper D times upper E upper F

where

Emissions = tons of a ghg/year

AD = activity data

EF = emission factor (tons ghg/unit of activity data)

Activity data may be the amount of fuel combusted by a process boiler and the emission factor is the tons of CO₂ emitted per ton of coal. The emission factor could be a default value given in the IPCC Guidelines for the type of coal combusted, or a lot‐specific emission factor determined by a carbon content analysis of each lot of coal. The certainty of the emissions values reported can be improved by increasing the complexity of the reporting procedure. Multiple samples could be obtained from each lot, corrections could be made for carbon losses in fly ash, or quality control procedures could be instituted. This leads to the tier system utilized by the IPCC, where a tier represents a level of methodological complexity, where a Tier 1 method represents a basic method, a Tier 2 method is intermediate in complexity, and a Tier 3 method is the most complex, typically requiring site or unit‐specific data obtained at specific frequencies. The assumption is that the higher the tier procedure that is used, the lower the level of uncertainty of the emissions data. The emission factor method is also called the “standard methodology” to be more inclusive, incorporating oxidation factors, conversion, and other factors appropriate for the application (CEC 2004).

Countries following the IPPC guidelines will adopt some type of tier approach in their own national procedures but may differ in how they are applied. In selecting a procedure from a tier, a key category, an emission category that contributes significantly to the country's total greenhouse gas emissions, should use a higher‐tiered method.

In the process industries, where hydrocarbons or other raw materials may be used as chemical feedstocks and/or combusted to supply energy, and where carbon may be incorporated in the product, lost in slag, or otherwise transferred in the process as a by‐product fuel, a mass balance approach may be more suitable than using the emission factor method for estimating greenhouse gas emissions. In this method, the balance of carbon entering and leaving a unit or process is calculated, as illustrated in Equation 14‐4.

(14‐4)

where

Emissions = tons of a ghg/year

f = factor for converting the molar mass of carbon to CO₂ = 3.664 t CO₂/t C

Cinput = tons of carbon entering process

Coutput = tons of carbon leaving process in product, as by‐product fuel, or other

As an extension of the emission factor method, the mass balance method can be expressed in terms of activity data as follows:

(14‐5)

where

ADi = activity of material (Plus (+) for ith ghg materials entering process. Minus (−) for materials leaving process (tons material)

EFi = emission factor for ith material (tons ghg/unit of activity data)

The difficulty in preparing a national greenhouse gas emission inventory is that the emissions sources vary from stationary sources, to landfill and area sources, vehicles, leaks, and fugitive sources, and to agricultural and livestock operations. It is important that the emissions data from each category follow certain principles of data quality to be considered useful for the purposes of the inventory. In this regard, the IPCC recommends that methods following good practice be used, where the elements of good practice are as follows:

Transparency: Documentation is sufficient so that it can be understood how emissions are determined from each source and how the inventory is compiled.

Completeness: Emissions estimates are reported for all applicable sources within a source category.

Consistency: Emissions are calculated in the same manner each year so that trends and fluctuations from year to year are meaningful and do not reflect changes in procedure.

Comparability: Inventory data should be reported in an internationally consistent format so that they can be compared with the inventory data of other countries.

Accuracy: Reported estimates should not overestimate or underestimate actual emissions. Efforts should be made to remove all possible biases from the data reported.

As will be seen in Chapter 15, these quality assurance objectives are the same as the quality objectives for any analytical laboratory.

IPCC EMISSION INVENTORY PROCEDURES

In the United Nations Framework Convention on Climate Change (UNFCCC), inventory procedures are outlined in the 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC 2006). The document is readily available on the Web and is readily downloadable in five volumes:

Volume 1: General Guidance and Reporting

Volume 2: Energy

Volume 3: Industrial Processes and Product Use

Volume 4: Agriculture, Forestry, and Other Land Use

Volume 5: Waste

The guidelines offer direction for the development of national inventory procedures. Individual countries may interpret the guidelines broadly; however, they do offer a framework for providing consistency in estimating greenhouse gas emissions from different sectors of national economies. The most important of these sectors is the energy sector, addressed in Volume 2 of the guidelines, which covers stationary and mobile sources as well as fugitive emissions.

For stationary sources, the “tier” approach is used, where guidelines are given for the data inputs to the mathematical methods applied to estimate net greenhouse gas emissions. In this approach, the calculation methods are based on the availability and costs associated with the data inputs. The tiers range from default data in Tier 1 to plant‐specific data in Tier 3. Correspondingly, the quality of the emission estimates should increase from the lower to the higher tiers. The Guideline requires that: “…the selected tier shall reflect the highest level of accuracy that is technically feasible and does not lead to unreasonably high costs,” with the assumption that emission estimates will increase in accuracy at the higher tiers.

Tier 1: Amount of Fuel Combusted × Default Emission Factors

In Tier 1, all that is needed is activity data (the amount of fuel combusted or the amount of carbon contained in process input materials) and a generic emission factor specified in Tables 2‐2–2‐5 of volume 2 (IPCC 2006).

Tier 2: Amount of Fuel Combusted × Country‐specific Emission Factors

In Tier 2, activity and averaged country‐specific emission factors are applied for fuels commonly used in the country.

Tier 3: Amount of Fuel Combusted × Source‐specific Emission Factors

Tier 3 is the most data‐centered of the tiers, where source‐specific emission factors are calculated from variables that might influence the emission calculation. These variables might include the fuel type used, combustion and control technology, and other factors.

It is notable that continuous emission monitoring was recommended, but with some caveats in the 2006 IPCC document.

Continuous emissions monitoring (CEM) of flue gases is generally not justified for accurate measurement of CO₂ emissions alone (because of the comparatively high cost) but could be undertaken particularly when monitors are installed for measurement of other pollutants such as SO₂ or NOx. Continuous emissions monitoring is also particularly useful for combustion of solid fuels where it is more difficult to measure fuel flow rates, or when fuels are highly variable, or fuel analysis is otherwise expensive. ().

IPCC 2006 §2.3.1.3

Originally, the EU viewed using CEM system data as a lower‐tier approach, where the use of a CEM system first had to be justified to give a higher accuracy than the relevant calculation base methodology applying a combination of the highest tiers. However, with the implementation of the European Trading Scheme and the increased confidence in CEM systems, in particular flow monitoring systems, CEM systems are recommended by the European Monitoring and Reporting Regulation for the inventory when already installed (EC 2009). In the EU Monitoring and Reporting Regulation (MRR), CEM systems are specifically recommended for the measurement of N₂O and CH₄ (EC 2009).

In contrast, with extensive experience with CEM systems and flow monitoring in fossil‐fuel‐fired steam generators since the implementation of the acid rain program in 1990, CEM data are considered in the United States as the most accurate available. In the preparation of greenhouse gas emission inventories, CEM CO₂ emissions data are required to be reported when CEM systems are already installed.

The tier approach is interpreted differently by different countries, but in general, it tends to be expanded to address different options that may be applied within each tier. In developing emission inventories, countries often apply considerable effort to bolster the IPCC guidelines with technical details, but still remain within the framework. This chapter focuses on U.S. inventory procedures for combustion and industrial sources given in 40 CFR 98. Contrasting procedures for Canada and the European Union will be touched on; however, details of inventory methods used in other countries should be sought from the appropriate national regulatory bodies. Guidance for choosing greenhouse gas calculation methods can be found in Gillenwater (2005) and other sources.

REPORTING GREENHOUSE GAS EMISSIONS – U.S. MANDATORY GREENHOUSE GAS REPORTING RULE

The United States is a party to the United Nations Framework Convention on Climate Change and as such is committed to prepare an emissions inventory of sources of greenhouse gases. More than 190 countries are party to the agreement, where its stated goal in Article 2 is:

to stabilize greenhouse gas concentrations in the atmosphere that would prevent dangerous anthropogenic interference with the climate system (Source: ).

UNFCCC 1992a

The long‐term goal is to reduce greenhouse gas emissions to levels such that global temperature increase due to radiative forcing will be limited to 1.5 °C below preindustrial levels.

The United States signed and ratified this international environmental treaty in 1992 and since 1997 has submitted an annual inventory report to the UNFCCC secretariat. The inventory is prepared by assembling national data obtained using estimation and measurement techniques consistent with the methodologies recommended in the 2006 IPCC Guidelines (IPCC 2006). The annual reports are prepared following UNFCCC reporting guidelines, so that the data are presented in a format common to the other signatories to the UNFCCC.

To aid in the preparation of the inventory, the U.S. EPA established a mandatory Greenhouse Gas Reporting Program (GHGRP), which was published and codified in 2009 as Part 98 of Title 40 in the U.S. Code of Federal Regulations (40 CFR 98) (U.S. EPA 2009, 2020a). Part 98 requires annual reporting at the facility level, which is often the responsibility of the plant environmental engineer. The GHGRP source‐specific data are used as a resource in the preparation of the annual inventory report, which is drafted in keeping with the UNFCCC format. Additionally, activity data and site‐specific emission factors submitted in the Part 98 report can be used for program enhancements and quality control cross‐checks.

Part 98 is an extensive document addressing mandatory reporting for 42 source categories and providing comprehensive procedures for reporting greenhouse gas emissions. Where CEM systems are installed, the CEM CO₂ emissions data are required for reporting, otherwise the mass balance, process input, and emission factor procedures recommended by the IPCC are utilized. Procedures range from the use of CEM systems to the use of estimation methods, including default emission factors, each with their associated uncertainties. The application of a method or estimation procedure is specific to the source, emission levels, type of gas, and/or other factors. Preparing the annual report requires careful reading of Part 98 and is beyond the scope of this discussion. Salient features of the reporting options for several source categories subject to the Part 98 requirements are given next to provide appreciation of the range of methods utilized in greenhouse gas reporting.

The Tier Approach: Part 98 Subpart C – Calculating CO₂ Emissions from Fuel Combustion

Subpart C applies to facilities that combust fossil fuels and serves as a template for other source categories that may incorporate operating units that use fossil fuels. Combustion sources addressed by Subpart C include boilers, simple and combined‐cycle combustion turbines, engines, incinerators, and process heaters. Emergency generators and flares are not subject to this subpart. Subpart C illustrates the approach taken in Part 98 to allow the use of a variety of methods for reporting CO₂ emissions.

A tier approach is taken, where each successive tier requires more measurements and the application of fewer emission factors, with the assumption that the higher the number of the tier, the higher the accuracy of the reported data. Table 14‐3 outlines basic criteria given in the Part 98 tier approach.

The basic idea here is that at least for fuel combustion, the higher the tier, more actual measurements and fewer assumptions are made, resulting in higher accuracy for the annual CO₂ data reported. A higher tier may be used than the minimum tier allowed.

Tier 1 – Measuring Fuel Use

The first tier of Subpart C applies to small combustion units that have a heat input of less than or equal to 250 mmBtu/hr and use a fuel listed in Table C‐1 of Part 98, which includes a listing of coals, distillate and residual fuel oils, combustible gases, and ten biomass fuels. It also applies to municipal solid waste (MSW) combustors of any size that do not produce steam or those that do produce steam but burn no more than 1000 tons of municipal solid waste per year and natural gas units that determine gas consumption from billing records expressed in therms or mmBtu. The following equation is used to calculate annual CO₂ emissions in metric tons/year:

TABLE 14‐3 The Tier Approach for Reporting Annual CO₂ Emissions from Fossil‐Fuel Combustion

Tier
Unit Allowed
Monitoring Method

Tier 1

≤250 mmBtu

MSWs

Natural gas units

Annual fuel use
Company records + Emission Factor (EF)

Tier 2

≤250 mmBtu

Units with listed fuel

Units with HHV data

MSWs producing steam (mandatory)

Annual fuel use
Company records

Annual High Heating Value (HHV) + Emission Factor (EF)

Tier 3

≥250 mmBtu using listed fuel: except

Gas, oil, biomass

MSW

If Tier 4 required

≥250 mmBtu using non‐listed fuel at > 10% of annual HI

Annual fuel use:
Solid – company records
Liquid and gaseous – flow meter or billing meter

Carbon content (solid & liquid)
Content + MW (gas) + Emission Factor

Tier 4
Unit has a CEMS
Unit > 250 mmBtu/hr
Uses solid fuel
Annual operation. 1000 hrs
Flow meter installed
CEMS undergo QA testing
Or
When referenced by another Part 98 Subpart

CEM system

CO₂ monitor

Flow monitor

(14‐6)upper C upper O 2 equals 1 times 10 Superscript negative 3 Baseline upper F u e l times upper H upper H upper V Subscript d Baseline times upper E upper F

where

CO₂ = annual CO₂ mass emissions (metric tons) for a particular type of fuel

Fuel = mass or volume of fuel combusted during the year (tons, scf, gal)

HHVd = default high heating value of fuel (gross calorific value [GCV]) (mmBtu per mass or volume of fuel)

EF = fuel‐specific default CO₂ emission factor from Table C‐1 of Part 98 (kg CO₂/mmBtu). Emission factors for common fuels are given in Table 14‐4.

1 × 10⁻³ = conversion factor from kilograms to metric tons.

Tier 2 – Measuring Fuel Use and High Heating Value (HHV)

Tier 1 units that have a heat input of less than or equal to 250 mmBtu/hr and use a fuel listed in Table C‐1 can also use Tier 2 for reporting. Tier 2 can also be applied by units of any size that burn distillate oil or natural gas. Equation 14‐7 is used to calculate annual CO₂ emissions in metric tons/year. It differs from Equation 14‐6 in that an annual high heating value (HHVm) is calculated from periodic fuel sample analyses (monthly, quarterly, semiannually, or by lot).

(14‐7)upper C upper O 2 equals 1 times 10 Superscript negative 3 Baseline upper F u e l times upper H upper H upper V Subscript m Baseline times upper E upper F

where

HHVm = annual measured high heating value of fuel (gross calorific value [GCV]) (mmBtu per mass or volume of fuel) determined by periodic sampling and analysis of the fuel

The catch to Tier 2 is that if routine samples of the fuel are already being analyzed for high heating value or if the fuel supplier provides monthly or more frequent fuel analyses, then Tier 2 must be applied. Tier 2 also applies to MSW combustors that produce > 1000 tons of steam/year.

For coal and fuel oil delivered in lots, each fuel lot must be sampled and analyzed. For other solid fuels, weekly fuel sampling and monthly analysis of a composite sample are required. Other liquid fuels and fossil‐fuel‐derived gas fuels, and biogas, not delivered in lots, must be sampled and analyzed quarterly.

Tier 3 – Measuring Fuel Use and Carbon Content

Tier 3 applies to sources larger than 250 mmBtu that have not been required to install a CEM system. Tier 3 is not allowed for use for units combusting municipal solid waste, which must use instead Tier 1, 2, or 4. Units burning natural gas, distillate oil, or biomass fuels listed in Table C‐1 are not required to use Tier 3 and may use either Tier 1 or 2.

Tier 3 sources are required to monitor fuel use and may use company records for solid fuels, but for liquid and gaseous fuels, a fuel flow meter or billing meter are required for obtaining the fuel use data. Fuel flow meters are required to be calibrated and are subject to a 5% accuracy requirement, specified in Subpart A of Part 98. Equation 14‐8 is used to calculate annual Tier 3 CO₂ emissions for a unit using solid fuel. Similar equations are given for liquid and gaseous fuels:

TABLE 14‐4 Emission Factors for Fossil Fuels from 40 CFR 98

HHVd
mmBtu/ton
(EF)
(kg/mmBtu HHV)

Type of Fuel

CO₂
CH₄
N₂O

Coal (anthracite)
25.09
103.69
1.1 × 10⁻²
1.6 × 10⁻³

Coal (bituminous)
24.93
93.28
1.1 × 10⁻²
1.6 × 10⁻³

Coal (subbituminous)
17.25
97.17
1.1 × 10⁻²
1.6 × 10⁻³

Lignite
14.21
97.72
1.1 × 10⁻²
1.6 × 10⁻³

Municipal solid waste
9.35
90.7

HHVd
mmBtu/gal

Distillate fuel oil #2
0.138
73.96

Propane
0.91
62.87

LPG
0.092
61.71

(14‐8)upper C upper O 2 equals StartFraction 44 Over 12 EndFraction times upper F u e l times upper C upper C times 0.9078

where

CO₂ = annual CO₂ mass emissions (metric tons)

Fuel = annual mass of fuel combusted (short tons)

CC = annual fractional carbon content of the solid fuel

44/12 = ratio of molecular weights, upper M upper W Subscript upper C upper O 2 Baseline slash upper M upper W Subscript upper C

0.9078 = conversion factor from short tons to metric tons

For Tier 3, samples must be obtained and analyzed at the same frequencies given for Tier 2 HHV samples.

Tier 4 – Continuous Emission Monitoring

CEM systems are used for Tier 4 reporting, where annual emissions are calculated as a pollutant mass rate times operating time. The pollutant mass rate is calculated as follows:

(14‐9)p m r Subscript upper C upper O 2 Baseline equals 5.18 times 10 Superscript negative 7 Baseline times normal upper C Subscript upper C upper O 2 Baseline times upper Q Subscript a

where

p m r Subscript upper C upper O 2= pollutant (CO₂) mass rates (metric tons/hr)

CCO2w= wet‐basis hourly average CO₂ concentration (% CO₂)

Qa = hourly average stack gas volumetric flow rate (scfh)

5.18 × 10⁻⁷ = conversion factor (metric tons/scf/%CO₂)

Each hourly value for the CO₂ pollutant mass rate is multiplied by the operating time to calculate tons. Hourly mass emissions are summed to calculate both quarterly and annual totals. If the CO₂ concentration is measured on a dry basis instead of a wet basis, a default moisture content appropriate for the type of fuel, or a site‐specific default moisture value can be used to correct to a wet basis.

TABLE 14‐5 Tier 4 Applicability Conditions for the Use of CEM Systems

Any unit
Tier 4 may be used for a unit of any size combusting any type of fuel. Tier 4 may be used for any group of fuel combustion units that share a common stack or duct.

Large units
Tier 4 calculation procedures shall be used if all of the following six applicability conditions are met [§98.33(4)(ii)(A–F)]:

The unit has a heat input capacity of >250 mmBtu/hr or maximum, rated input capacity of >600 tons/day of municipal solid waste

The unit combusts solid fuel or municipal solid waste as the primary fuel

The unit operated > 1000 hours in any calendar year since 2005

The unit has a CEM system installed that is required by federal or state regulation or the unit's operating permit

The installed CEM system includes a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both, and the monitors have been certified in accordance with the requirements of either Part 60, Part 75, or a State CEM program.

The monitoring system undergoes required, periodic QA testing in accordance with the requirements of either Part 60, Part 75, or a State CEM program

Small units
Tier 4 calculation procedures shall be used for units that have a heat input capacity of ≤ 250 mmBtu/hr or maximum, rated input capacity of ≤ 600 tons/day of municipal solid waste if all of the following three applicability conditions are met [§98.33(4)(iii)(A–C)]:

The unit has installed both a stack gas volumetric flow rate monitor and a CO₂concentration monitor

The unit meets the conditions ii (B–D) of this table (above):

The unit combusts solid fuel or municipal solid waste as the primary fuel

The unit operated > 1000 hours in any calendar year since 2005

The unit has a CEM system installed that is required by federal or state regulation or the unit's operating permit

The CO₂ monitor and stack gas volumetric flow rate monitor meet the condition of ii (E–F) of this table (above):

The monitors have been certified in accordance with the requirements of either Part 60, Part 75, or a state CEM program

The monitors undergo required, periodic QA testing in accordance with the requirements of either Part 60, Part 75, or a state CEM program

The Tier 4 calculation methodology is used for units subject to the applicability conditions [§98.33(4)] given in Table 14‐5.

Subpart C – CH₄ and N₂O Reporting Methods

Methane and nitrous oxide emissions are reported using default emission factors for fuels listed in Table C‐2 of Part 98.

(14‐10)upper C upper O 2 equals 1 times 10 Superscript negative 3 Baseline upper F u e l times upper H upper H upper V Subscript d Baseline times upper E upper F

where

CH₄ or N₂O = annual CH₄ or N₂O mass emissions (metric tons) from the combustion of a particular type of fuel

Fuel = mass or volume of fuel combusted during the year (tons, scf, gal)

HHVd = default or actual high heating value of fuel (gross calorific value [GCV]) (mmBtu per mass or volume of fuel)

EF = fuel‐specific default CH₄ or N₂O emission factor from Table C‐2 of Part 98 (kg CH₄ or N₂O/mmBtu). For coals, the EF for CH₄ is 1.1 × 10⁻² (kg/mmBtu) and for N₂O is

1.6 × 10⁻³ (kg/mmBtu)

1 × 10⁻³ = conversion factor from kilograms to metric tons

Subpart C – Quality Assurance/Quality Control

For Tier 2 and Tier 3 fuel sampling, it is expected that sampling be representative and that samples be taken at frequencies that provide a sample representative of the fuels combusted, particularly for fuel blends (§98.34). Sampling frequencies, procedures, and analysis methods are to be documented in a required monitoring plan.

Tier 2 and Tier 3 oil and gas flow meters and transmitters must be calibrated initially [§93.3(i))] and recalibrated periodically at frequencies specified in the Part 98 Subparts.

Tier 4 CEM systems must be certified. The calibration error (U.S. EPA 2020a) and relative accuracy certification criteria may be used from either Part 75 Appendix A, Part 60 Appendix B Performance Specifications 3 and 6 (U.S. EPA 2020b, c), or the provisions given in a state CEM program. For ongoing quality assurance, either Part 60 Appendix F or Part 75 Appendix B procedures are to be followed, which basically require the performance of quarterly cylinder gas audits and an annual RATA for the monitoring system. Hourly average data requirements are the same as those given in 40 CFR 60.13(h)(2).

Other expressions are given when using gas billing records, generating steam, blending fuels, combusting biomass, or using combined and/or bypass ducts. The tier approach becomes quite prescriptive in its application requirements; however, it is beyond the scope of this discussion to detail the intricacies of Part 98. It should be clear from this outline of the tier approach, and it will become obvious from other examples given below that annual greenhouse gas emissions are allowed to be calculated by applying different methods, using a variety of emission factors and a variety of parameters; some for which either default or measured values are used. In complex facilities, the uncertainty of the reported CO2, CH₄, and N₂O emissions can increase as the number of inputs increase, particularly if many of them are not measured, but are assumed default values.

Approaches to Reporting – Examples

Depending upon the industry, different approaches are taken in reporting greenhouse gases. Where CEM systems are already installed, the direct measurements are typically preferred. However, there are many sources of CO₂ and other greenhouse gases in industrial facilities where it is impractical to monitor emissions continuously. Here alternative approaches principally using mass balance and/or emission factor calculations are used.

Example 1: Subpart D – Electricity Generation

Part 98 Subpart C addresses electric generating units subject to the requirements of the acid rain program and other sources required to monitor CO₂ mass emissions according to 40 CFR 75.

Because of the U.S. EPA acid rain program, which became effective in 1990, all electric utility sources greater than 25 MW capacity were required to install CEM systems (see Chapter 2) (U.S. EPA 2020b). In the majority of installations, dilution‐extractive systems were installed, which incorporate CO₂ monitors to account for dilution air and calculate lbs/mmBtu emissions by F‐factor methods (see Appendix 2).

Reporting CO₂ emissions from electric generating units with already installed CEM systems is relatively straightforward. CEM systems commonly demonstrate relative accuracies better than 5% for both CO₂ analyzers and flow monitors. This is fortunate in the respect that the gas volumes emitted by fossil‐fuel electric generating units are larger than most other sources and even the smallest of inaccuracies can become significant in greenhouse gas reporting. CO₂ emissions are reported, and multiplying the polluant mass rate (pmr), by the operating hours of the unit (t), the CO₂ mass emission rate is calculated using Equation 14‐11

(14‐11)

where

ti = operating time (1 or fraction of hour)

i = hour

n = number of operating hours

If heat input is determined from the gross calorific value of the fuel and the fuel feed rate, CO₂ emissions may also be calculated from the heat input (HI), using the procedures given in Part 75 Appendix G and Appendix F. From 40 CFR 60 Appendix G, the pollutant hourly CO₂ mass emission rate using the heat input is given as

(14‐12)

where

p m r Subscript upper C upper O 2 = CO₂ emitted from combustion, tons/hr

Fc = F factor (1040 scf/MMBtu for natural gas, 1420 scf/mmBtu for oil)

HI = hourly heat input in mmBtu as calculated using procedures given in 40 CFR 75 Appendix F

Uf = 1/385 scf CO₂/lb‐mole at 14.7 psia and 68 °F

upper M upper W Subscript upper C upper O 2 = molecular weight of carbon dioxide (44.0 lb/lb‐mole)

ti = operating time (1 or fraction of hour)

i = hour

n = number of operating hours

For CH₄ and N₂O emissions, Subpart D for electric generating units references back to the combustion source methods given in Subpart C of Part 98, where fuel‐specific emission factors are used in conjunction with fuel feed rates. Similarly, for biogenic CO₂ emissions, reference is made back to Subpart C.

Example 2: Subpart H – Cement Production

Cement is made from calcium carbonate (limestone), which is heated with other materials to 1450 °C in a rotary kiln where the carbonate is calcined to produce CaO and generate CO₂. CO₂ emissions are produced from both the fuel combusted to heat the kiln and the calcination process (the process CO₂). Cement plants contribute to approximately 8% of worldwide greenhouse gas emissions being second to electricity generation in stationary source emissions (Andrew 2018). Fossil fuels are generally used to heat cement kilns; however, combustible waste or biogenic materials are used in some plants as supplements to them.

Cement plants are required to install CEM systems to monitor SO₂, NOx, particulate matter, and volumetric flow rate under Subpart F of the 40 CFR 60 New Source Performance Standards. Cement kiln pollutant emission standards are expressed in lbs pollutant/tons clinker. Installing a CO₂ analyzer in the system would be relatively straightforward for an existing system if one is not already installed.

Cement kilns that meet the Tier 4 applicability conditions [§98.33(b)(4)(ii)(A–F)] are required to use CEM systems for reporting CO₂ emissions (see Table 14‐5). Cement kilns that do not meet the Tier 4 conditions may still use CEM systems as long as they follow the Tier 4 calculation methodology [§98.33(a)(4)], or may use mass balance calculations for carbonate‐base materials.

For CH₄ and N₂O emissions, Subpart H for cement kilns references back to the combustion source methods given in Subpart C, where fuel‐specific emission factors are used in conjunction with fuel feed rates.

If a CEM system is used to measure CO₂ emissions, the following information must be reported in addition:

Monthly clinker production from each kiln.

Annual facility cement production

Number of kilns and number of operating kilns

For all cement kilns using mass balance calculations for carbonate‐based materials, using ASTM methods, the following data must be reported in addition:

Monthly determination of weight fraction of total CaO and total MgO in clinker from each kiln

Quarterly determination of weight fraction of total CaO and total MgO in cement kiln dust not recycled to the kiln from each kiln

Annual organic content of raw materials or a default organic carbon factor (0.2% of raw material weight)

The quantity of clinker produced monthly by each kiln by direct weigh measurement

The quantity of cement kiln dust not recycled to the kiln, for each kiln

The annual quantity of raw kiln feed, or each category of raw materials consumed by the facility

The monthly non‐calcined CaO and MgO that remains in the clinker in the form of CaCO₃

The quarterly non‐calcined CaO and MgO that remains in the cement kiln dust in the form of CaCO₃

Example 3: Subpart N – Glass Production

CO₂ process and combustion emissions must be reported for each glass plant continuous glass melting furnace. Glass furnaces typically combust natural gas to melt a variety of materials in the glass‐making process, including silica (sand and recycled glass [cullet]), sodium carbonate, calcium carbonate, and other fluxes and stabilizers. CO₂ is produced from combustion of the natural gas used to heat the furnace and is also generated as a product of the carbonate reactions in the glass‐making process. CEM systems are usually installed to monitor NOx and/or SO₂ emissions as a permit requirement to monitor compliance to emission limits expressed in terms of lbs NOx or SO₂/tons glass pulled, or lbs NOx or SO₂/hr or tons NOx or SO₂/yr. Depending upon the operating permit, a CO₂ or O₂ monitor and/or a flow monitor may be installed.

Glass furnaces that meet the Tier 4 applicability conditions [§98.33(b)(4)(ii)(A–F)] or the conditions of [§98.33(b)(4)(iii)] are required to use CEM systems for reporting CO₂ emissions. Glass furnaces that do not meet the Tier 4 conditions may still use CEM systems as long as they follow the Tier 4 calculation methodology [§98.33(a)(4)], or may use mass balance calculations for carbonate‐based materials. For all glass furnaces, ostensibly for quality assurance purposes, the following data must be reported in addition:

Annual quantity of each carbonate‐based raw material charged (tons)

Annual quantity of glass produced

Example 4: Subpart Q – Iron and Steel Production

Greenhouse gas emissions must be reported for each of the applicable process units at the plant. These may include a basic oxygen furnace, a coke oven battery and electric arc furnace, decarburization vessel, or direct reduction furnace, depending upon the plant design. Annual CO₂ emissions must be reported for each plant process. Two methods may be used: (i) following the Tier 4 procedures of Subpart C by installing and operating CEM systems, or (ii) by calculating CO₂ emissions from material inputs and outputs. In calculating emissions by the second method, either a mass balance method or a site‐specific emission factor method can be used.

Mass Balance Method

Material inputs and outputs along with their respective carbon contents are required to be determined in this method. For an electric arc furnace, the annual mass of ferrous scrap iron, flux, coal, coke, steel, gaseous fuel, etc. must be measured, and an annual analysis of the respective carbon fraction of the material is performed. Material mass values may be obtained from weigh hopper data, weigh belt feeders, weighted purchased quantities, etc. Carbon content is either based on analysis data provided by the supplier or the analysis of three samples of a material using ASTM or other standard methods as specified.

Site‐Specific Emission Factor Method

An annual site‐specific emission factor is determined by conducting performance tests, measuring CO₂ emissions from all exhaust stack as the feed rate or production rate is being measured. The CO₂ emission rate in tons/hr is calculated on a dry basis from the CO₂ concentration and flue gas volumetric flow rates measured during the performance testing. The site‐specific emission factor is calculated by dividing the CO₂ emission rate by either the average hourly feed or production rate. Annual CO₂ emissions are calculated by multiplying the emission factor and the total amount of production or feed during the year.

The input/output calculation methodologies may not be used for units that use a Tier 4 CEM system procedures to report CO₂ emissions.

Example 5: Subpart Y – Petroleum Refineries

Reporting annual greenhouse gas emissions from a petroleum refinery is challenging due to the large number and variety of emission sources employed in process operations. It is easiest to sum these procedures into two tables: Table 14‐6, which applies to units that have CEM systems or other monitoring systems installed, and Table 14‐7, which applies to units where CO₂ emissions are calculated using default emission factors and other estimation methods.

CEM systems are installed on practically all catalytic crackers, either through 40 CFR 60 New Source Performance Standards Subpart J and Ja requirements or through the consent decrees handed down by the U.S. courts since 2000. Where installed, CEM systems are required to be used for greenhouse gas reporting. The petroleum refinery operating units subject to Part 98 reporting requirements and the reporting options available are summarized in Tables 14‐6 and 14‐7.

The other class of monitoring requirements using feed rates, emission factors, and/or mass balance calculations are applied to process vents, leaks, loading operations, and other aspects of petroleum refinery operations where greenhouse gases are released to the atmosphere, but the application of continuous emission monitoring systems to monitor them is not practical or not possible. These are listed in Table 14‐7.

TABLE 14‐6 Petroleum Refinery CEM System Greenhouse Gas Monitoring Requirements and Options

§98.253
Unit Type
Gas
Conditions
Method

(b)
Flares
CO₂
CH₄
N₂O
Must use flow rate,
HHV, and/or carbon content data available, otherwise use engineering calculations, company records, estimates, and/or default emission factors

CO₂ = Flow × CC, or/EF or
CO₂ = Flow × HHV × default EF, or
CO₂ = Annual flare gas volume for normal operation × HHV × default EF + start‐up shutdown events × average carbon content or engineering calculations

CH₄ = CO₂ rate from 1 × default EF

N₂O = CO₂ rate from 1 × default EF

(c)
Catalytic cracking units
CO₂
CH₄
N₂O
Must use CEMs if installed in stack
(If no CEMS and <10 000 bbl/day then use 2)
(If no CEMS and > 10 000 bbl/day then
use 3)

CEMS – Tier 4 methodology
CO₂ = CO₂ + CO concentrations times volumetric flow rate

Monitor CO₂, CO, and O₂ and monitor or calculate volumetric flow rates at least hourly at regenerator or coking unit, prior to stack

Monitor CO₂, CO, and O₂ and monitor or calculate volumetric flow rates at least daily at regenerator or coking unit, prior to stack. If gases are not monitored, multiply annual throughput of unit, coke carbon content and carbon burn‐off factor.

CH₄ = CO₂ emission rate from 1) × default EF

N₂O = CO₂ emission rate from 1) × default EF

(d)
Fluid coking units
CO₂
CH₄
N₂O
For fluid coking units using flexi coking design
Use procedure 3) from (c) above.

(e)
Catalytic reforming unit
CO₂
CH₄
N₂O
Procedures 1) and 2) given for catalytic reforming unit.
Procedure 3) for
catalyst regenerator unit

CEMS – Tier 4 methodology
CO₂ = CO₂ % times volumetric flow rate

If no CEMS, use procedure (c) (3) above

Coke burn‐off quantity × carbon content from engineering estimates

(f)
Sulfur recovery plants
CO₂
Must use data if CEMS/flow/composition
Monitor if installed, if not use flow and composition

CEMS – Tier 4
Fuel Use + Composition
Monitor used to calculate CO₂

Monitor or estimate feed flow monitor and carbon content

(g)
Coke calcining units
CO₂
CH₄
N₂O
Must use CEMS if operate CEMS, others, use 2). All do 3)

CEMS – Tier 4

CO₂ = Annual mass green coke × Carbon content − Pet Coke out as carbon content − Dust

For CH₄ and N₂O, use CO₂ from 1) or 2) above times either a unit‐specific or default emission factor

TABLE 14‐7 Petroleum Refinery Mass Balance/Emission Factor Greenhouse Gas Monitoring Requirements and Options

§98.253
Unit Type
Gas
Conditions
Method

(h)
Asphalt blowing operations
CO₂
CH₄

Uncontrolled

Controlled & not already accounted

Annual quantity asphalt blown × default EF

Annual quantity asphalt blown × site‐determined EF

(i)
Delayed coking units (coke drum)
CH₄
Use 1) if H₂O added

Use process vent method in (j) + Opening emissions equation

Opening emissions equation

(j)
Other process vents
CO₂
CH₄
N₂O
Vents not covered in (a)–(i) above. If >2% CO₂
>0.5% CH₄
>0.01% N₂O
(j) Process Vent Method:
Annual emissions = Venting flow rate × time × mole fraction of ghg – for each ghg

(k)
Blowdown systems
CH₄
Uncontrolled

Methods in (j) above or

Quantity crude oil × default EF

(l)
Equipment leaks
CH₄
Process‐specific data or no. units

EPA‐453/R‐95‐017 or

∑Unitsi × Noi × EFi

(m)
Storage tank leaks
CH₄
>0.5% CH₄

AP‐42§7.1

Quantity × default EF

Vent gas measurement

(n)
Loading operations
CH₄
>0.5% CH₄
AP‐42§5.2

Subpart P
Refinery hydrogen plants

40 CFR 98 Subpart P

Example 6: Subpart AA – Pulp and Paper Manufacturing

For pulp and paper plants, greenhouse gas emissions are reported for chemical recovery furnaces at Kraft and soda mills and sulfite facilities, lime kilns, and systems adding calcium and sodium carbonate makeup chemicals. Biogenic material incorporated in spent pulping liquor is used in the chemical recovery units. Both biogenic and fossil CO₂ emissions are required to be reported.

CO₂, CH₄, and N₂O emissions from fossil fuels are calculated from the measurement of fossil fuels combusted at the facility, using default emission factors using the Tier 1 procedures given in Part 98 Subpart C (see Equation 14‐6). Tiers 2 and 3 (see Equations 14‐7 and 14‐8) may be used if proper quality assurance procedures are implemented for fuel sampling analysis given in Subpart C.

Biogenic CO₂ emissions and emissions of CH₄ and N₂O from spent liquor are calculated using measured quantities of spent liquor solids fired in the recovery boiler. For chemical recovery units located at Kraft or soda facility, biogenic emissions are calculated using Equation 14‐13:

(14‐13)

For chemical recovery units located at a sulfite or stand‐alone semichemical facility, biogenic emissions are calculated using Equation 14‐14:

(14‐14)

where

Biogenic CO₂= annual CO₂ mass emissions for spent liquor solids combustion (metric tons per year)

Solids = annual or annual average carbon content of the spent liquor solids made with an online measurement system and analyzed using ASTM D5373‐21 for the determination of the carbon content (short tons/year) (ASTM 2021)

Emission factors for Kraft pulping liquor (kg/mmBtu HHV) are given in Table 14‐8.

For lime kilns, fossil CO2, CH₄, and N₂O emissions are calculated from the direct measure of fossil fuels consumed, default HHV values, and default emission factors using Tier 1 procedures. CO₂ emissions from CaCO₃ and Na₂CO₃ makeup chemicals are determined from the quantities of materials used by mass balance calculations.

TABLE 14‐8 Emission Factors for Wood

| Kraft Pulping Liquor Emission Factors (EF) (kg/mmBtu HHV)
Type of Wood | CO₂ | CH₄ | N₂O
North American hardwood | 94.4 | 0.0019 | 0.000 423
North American softwood | 93.7 | 0.0019 | 0.000 423

Uncertainties

The above examples are provided to show the wide range of procedures employed to report greenhouse gas emissions. They are not given here to provide a reference for those preparing greenhouse gas inventories (40 CFR 98 itself serves that purpose), but to illustrate the use of continuous emission monitoring system data in the U.S. inventory. In the United States, when available, data from CEM systems are the first option. Where not available, the second option is to use process input data or other company data, with periodic measurements of parameters such as carbon content or high heating value. Further options resort to the use of default emission factors and qualified assumptions. In the tier approach, as discussed, a higher level of uncertainty is associated with the lower number of the tier, and a lower level of uncertainty with the higher number of the tier. See Chapter 3 of the IPCC Guidance for an extended discussion of uncertainties associated with the method (IPCC 2006).

In reporting greenhouse gas emissions, the emissions from various units are reported separately, but eventually get lumped together into various categories: emissions from like units, total plant emissions, national emissions for the source category, national emissions, and, eventually, global emissions. The results of all of this comprised a total of 6.5 billion tons of U.S. CO₂e emissions in 2017 (5.74 after sequestrations) compared to 2018 global emissions of over 54 billion tons CO₂e, of which 33 billion are from CO₂ alone. Each piece of contributing datum to these totals has its associated uncertainty. The estimated uncertainty of several national totals is 9% for the U.S. inventory, 8% for Canada, and 7% for the EU (Sanchez et al. 2012). The global totals are estimated to have an uncertainty of ±10%. In contrast, the U.S. EPA acid rain program mandated a ±10% relative accuracy requirement between CEM SO₂ measurements and the reference test method, which was sufficient to lead to that program's success.

Among the largest emission sources reporting in the United States, many sources, including fossil‐fueled plants and cement plants, have previously installed CEM systems, which can be used or augmented for greenhouse gas reporting. The other approach to use “activity‐based” methods, i.e. fuel consumption and emission factors, as discussed, provides an alternative. The question arises as to which method is the most accurate, which sometimes gets confused with the question as to which method has greatest certainty. This question has been addressed in a number of studies (Ackerman and Sundquist 2008; Borthwick et al. 2011; Evans et al. 2009; Quick 2014), each of which used varying data sets and approaches.

In a comparison between 2009 CEM data from the EPA Clean Air Markets Division (CAMD) Acid Rain Program and fuel consumption data from the U.S. Energy Information Administration (EIA), Quick (2014), from 210 plants, showed that there was a less than 1% difference between the totals of the two data sets, but for individual plants, the annual CO₂ emissions varied by 10.8% between the two methods. In a similar study comparing CAMD and EIA data from 1066 boilers, Borthwick (2011) found the CEM data to be, on average, 1.5% higher than data obtained from fuel consumption. For individual plants, Borthwick found that CEM measurements compared to EIA calculations, the differences had a standard deviation of about 8%. In contrast to these studies, Lee (2014) conducted an uncertainty analysis for each method on a single plant, by estimating the variance associated with all uncertainty components that are thought to affect the calculation or measurement. He found the uncertainty associated with CEM systems (flow + gas analyzers) for CEM systems CO₂ and N₂O measurements to be ±4.0 and ±4.5% for CH₄. For the IPCC fuel consumption methods, Lee calculated an uncertainty for CO₂ emissions of ‐24 to +19% using default emission factors, ±6.0% using a site‐specific net calorific value for Equation 14‐7, and ±3.4 % using a site‐specific value for fuel carbon content and Equation 14‐8. Lee also found the CEM averages to be higher than those calculated from fuel consumption.

There is some concern on the part of the authors of the above referenced papers that the directly measured CEM system emissions values are in general higher than those estimated from fuel consumption. This is often viewed as a new discovery but has been well known in the source measurement community since the 1990s and is, in fact, discussed in Chapter 7 of this book, and previously in its second edition. As discussed earlier, flow monitors tend to be biased high because they are essentially calibrated using EPA reference Test Method 2, which is prone to positive biases (Cashin et al. 1996). As these biases are removed, the two methods come closer in agreement (McRanie et al. 1997). The problem is that removing the biases may require performing Test Method 2F, using 3‐dimensional probes, using Test Method 2H to correct for wall effects, and/or using automated reference probes for calibrating flow monitors (Whitaker and Gentry 2019). Not all owners of flow monitoring systems will wish to decrease flow monitoring uncertainty unless there is an explicit economic value for doing so. When it matters, necessary research will be conducted to determine causes for the difference: biases, systematic errors, rather than a calculated imprecision. If a carbon tax, allowance prices, or some other greenhouse gas control mechanism result in a significant cost for each ton of CO₂ emitted, continuous emission monitoring data and data from activity‐based methods will become increasingly accurate, as has already been seen in the U.S. acid rain program.

REPORTING GREENHOUSE GAS EMISSIONS – CANADA

Canada's greenhouse gas inventory is prepared in accordance with the UNFCCC guidelines, where the inventory procedures are determined by the Pollutant Inventories and Reporting Division of Environment Canada, methods developed by the IPCC, or other methods developed by industry and previously published data. Quantification requirements are similar to those of the United States (Environment Canada 2018). For sources having CEM systems already installed, CEM CO₂ and flow data may be used for CO₂ reporting but are not required. Reporting mandates for specified sources are given in the Canada Gazette (Government of Canada 2019).

In comparison to the United States, the 2017 CO₂e emissions from Canada were 0.716 billion tons with 46% coming from stationary combustion sources and 7.5% from industrial processes (ENVC 2018).

REPORTING GREENHOUSE GAS EMISSIONS – EUROPEAN UNION

In Europe, greenhouse gas monitoring and reporting is necessary to serve the purposes of two programs: (i) the annual UNFCCC greenhouse gas emission inventory and (ii) the European Union Emissions Trading System (EU ETS).

The European Union has adopted an approach consistent with the UNFCC but has expanded it to support the EU Emissions Trading Scheme (ETS) (CEC 2004). The rules for monitoring and reporting are given in the Monitoring and Reporting Regulation (MRR), which is applicable both to the trading program and the annual IPCC Emission Inventory Report. There are some minor differences between the procedures given in the MRR and those recommended by the IPCC. These differences are addressed by correcting the MRR‐compliant data, where applicable, when reporting inventory data to the UNFCC.

The 2017 CO₂e emissions from the EU were 4.33 billion tons, excluding land use, land use change, and forestry (EEA 2019). CO₂e emissions from electricity and heat production were 1 billion tons, or 23% of the total, and 9% (0.38 billion tons) was attributed to emissions from industrial processes.

INTERNATIONAL STANDARDS ORGANIZATION (ISO) GREENHOUSE GAS STANDARDS

The International Standards Organization has prepared a three‐part standard, ISO 14064 for the management of greenhouse gas accounting and verification. The standard establishes principles for conducting greenhouse gas inventories and identifies principles for developing an inventory program. The standards are intended for use by organizations or countries wanting to follow internationally agreed‐upon procedures for preparing and validating emission inventories.

The three‐part standard developed by ISO consists of the following:

ISO 14064‐1 specifies the principles and requirements, with guidance, at the organization level for the quantification and reporting of greenhouse gas emissions and removal (ISO 2018).

ISO 14064‐2 illustrates the principles and requirements and provides guidance at the project level for the quantification, monitoring, and reporting of greenhouse gas emission reductions or removal enhancements (ISO 2019a).

ISO 14064‐3 provides a guide for those validating reports, which include the quantification and monitoring and accounting complying with ISO 14064‐1 or ISO 14064‐2 (ISO 2011a, 2013a, 2019b; Wintergreen and Delany 2007).

ISO 14064 can be used jointly with the 2006 IPCC procedures to develop national or local environmental policies and strategies (Bastianoni et al. 2014).

The measurement, inventory, and control of greenhouse gas emissions must necessarily be an international endeavor. Although the IPCC has detailed the estimation methods that can be used to provide inventory data from both area and stationary sources, the organization has not provided similar details for CEM systems, which, as a direct measuring method, can also serve to provide input to the inventories. Continuous emission monitoring standards are left to the reporting countries, which may have fully standardized procedures, such as the United States, Canada, and the EU. However, other countries may not have the resources or interest to standardize their own procedures; or countries that do have CEM standards may not have written procedures specific to the monitoring of greenhouse gases. For example, the continuous monitoring of N₂O is not addressed in either U.S. or EU measurement standards.

To fill this gap, the International Standards Organization (ISO) has standardized methods for the manual and automatic measurement of N₂O, CH₄, CO₂, and flow that may be used or adapted by any country. The standards are written by experts from the international community, who start from the methods already in use, seek out the best practices among them, and prepare standards that can be agreed‐upon by the member countries. The published ISO measurement standards are given in Table 14‐9. Standards listed as EN‐ISO standards are prepared jointly by ISO and the European Union (where EN stands for “European Norm”). The European Union has also standardized greenhouse gas estimation methods for energy‐intensive industries (iron and steel, cement, lime, aluminum, ferroalloy) that are more extensive than the IPCC procedures (see Bibliography).

TABLE 14‐9 ISO Measurement Standards

Standard | Subject of Standard | Ref.
ISO 12039 | AMS CO, CO₂, O₂ | ISO 2001
ISO 10396 | AMS sampling systems | ISO 2007
ISO 21258 | N₂O reference method | ISO 2010a
EN‐ISO 25140 | CH₄ AMS‐FID | ISO 2010b
EN‐ISO 25139 | CH₄ AMS‐GC | ISO 2011b
EN‐ISO 16911‐1 | Velocity/volumetric flow – reference method | ISO 2013b
EN‐ISO 16911‐2 | Velocity/volumetric flow–AMS | ISO 2013c
ISO 14385‐1 | GHG – AMS calibration | ISO 2014a
ISO 14385‐2 | GHG – AMS QC | ISO 2014b
ISO 18466 | Biogenic fraction CO₂ | ISO 2016

SUMMARY

The uncertainty of inventory data is understandably variable, and as such, when implementing control programs, care should be taken in providing for the fungibility of the data. In emissions trading programs, trading emissions between sources reporting at different levels of certainty can lead to a loss of confidence in the fairness of the program and perhaps to its failure. In emissions compliance programs, accurate data are sought to monitor compliance with emission limits and withstand legal challenges. However, when using greenhouse gas inventory data to assess the effect of a greenhouse gas control program, the absolute accuracy is perhaps not as important as it is in serving as a benchmark monitoring differences in greenhouse gas emissions between an industrial unit, sectors, or nations. In fact, most summary reports on greenhouse gas emissions emphasize relative changes in greenhouse gas emissions rather than in their absolute values.

Although data accuracy may be viewed as a central concern in an analytical laboratory, operating a continuous monitoring system, or preparing an emissions inventory, the level of accuracy required depends upon the regulatory control program and how that data will be used (Fuller and Font 2019). Accurately tracking emissions up to a limit without resolving an emissions problem accomplishes little. When emission limits are not sufficiently stringent, the limits may be met, but the problem will persist. This was seen in the acid rain program 15 years after the program was initiated, that SO₂ emissions would need to be reduced by an additional 75% to reach critical load. The issue arises again with respect to greenhouse gas emissions – how accurate must the data be to track incremental reductions in CO₂ emissions when instead, action other than counting is needed? This point is clearly stated in Principle 3 of the 1992 Rio di Janeiro Earth Summit: “Where there are threats of serious or irreversible damage, lack of full scientific certainty shall not be used as a reason for postponing cost‐effective measures to prevent environmental degradation.” (UNFCCC 1992a).

REFERENCES

In view of the importance of greenhouse gas issues and climate change, many publications and reports regarding climate change and greenhouse gases are readily available on the Web for free. To inform the public and to provide information resources for study and research, national and global inventories are all available for download and review, as are reports and publications of the U.S. EPA, European Commission, UNFCCC, and IPCC. However, standards published by the International Standards Organization and ASTM International are sold as a means of supporting the activities of these nonprofit voluntary consensus bodies.

Ackerman, K.V. and Sundquist, E.T. (2008). Comparison of two U.S. power‐plant carbon dioxide emissions data sets. Environmental Science & Technology 42: 5688–5693.

Andrew, R.M. (2018). Global CO2 emissions from cemetn production. Earth System Science Data 10: 195–217.

ASTM International (ASTM) (2021). ASTM D5373‐21 Standard test methods for instrumental determination of carbon, hydrogen and nitrogen in analysis samples of coal. 2021 Annual Book of ASTM Standards. Volume 5.06. West Conshohocken, PA: ASTM.

Bastianoni, S.M.M., Marchi, D., Caro, D. et al. (2014). The connection between 2006 IPCC GHG inventory methodology and ISO 14064‐1 certification standard‐ a reference point for the environmental policies at sub‐national scale. Environmental Science & Policy 44: 97–107.

Borthwick, R.P., Whetstone, J., Yang, J.C., and Possolo, A. (2011). Examination of United States carbon dioxide databases. Paper Presented at Electric Power Research Institute User’s Group Meeting, Chicago. (June). https://www.nist.gov/publications/examination‐united‐states‐carbon‐dioxide‐emission‐databases (8–10 June 2011).

Cashin, M.G., Love, J.E., and Miller, J.D. (1996). Resolving the difference – Mass Balance vs CEM Air emission estimates. Paper Presented at the EPRI CEM Users Group Meeting, Kansas City (8–10 May 1996). Palo Alto: Electric Power Research Institute.

Commission of the European Communities (CEC) (2004). Commission decision of 29/01/2004 establishing guidelines for the monitoring and reporting of greenhouse gas emissions pursuant to directive 2003/87/EC of the European parliament and of the council.

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European Commission (EC) (2009). Guidance Document – The Monitoring and Reporting Regulation General guidance for installations. MRR Guidance document No. 1. Version of 16 July 2012.

European Environment Agency (2019). Annual European Union greenhouse gas inventory 1990‐2017 and inventory report 2019 – Submission under the United Nations Framework Convention on Climate Change and the Kyoto Protocol. Report No. 6/2109. https://www.eea.europa.eu/publications/european‐union‐greenhouse‐gas‐inventory‐2019.

Evans, S., S. Deery, and J. Bionda. (2009). How reliable are GHG combustion calculations and emission factors? Air & Waste Management Association. Paper presented at the First International Greenhouse Gas Measurement Symposium, San Francisco, CA (22–25 March).

Fuller, G.W. and Font, G. (2019). Keeping air pollution policies on track. Science 365 (6451): 322–323.

Gillenwater, M. (2005). Calculation tool for direct emissions from stationary combustion. https://ghgprotocol.org/sites/default/files/Stationary_Combustion_Guidance:final_1.pdf (accessed 8 November 2021).

Government of Canada (2019). Government Notices. Department of the Environment: Notice with respect to reporting of greenhouse gases (GHGs) for 2018. Canada Gazette, Part I, Volume 153, Number 3. http://publications.gc.ca/collections/collection_2021/eccc/En81‐28‐2020‐eng.pdf (accessed 8 November 2021).

Hansen, J.E. (1986). The Greenhouse Effect: Projection of Global Climate Change. In: Ozone Depletion, the Greenhouse Effect, and Climate Change. Hearing before the subcommittee on Environmental Pollution. Ninety‐Ninth Congress. Superintendent of Documents, 78–97. Washington, D.C.: U.S. Government Printng Office.

Intergovernmental Panel on Climate Change (IPCC). (2006). 2006 IPCC Guidelines for National Greenhouse Gas Inventories. IPCC Task Force on National Greenhouse Gas Inventories. https://www.ipcc‐nggip.iges.or.jp/public/2006gl/.

Intergovernmental Panel on Climate Change (2013). Climate change: the physical science basis. In: Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (ed. T.F. Stocker, D. Qin, G.‐K. Plattner, et al.). Cambridge: Cambridge University Press. Chapter 8 Table 8‐7.

International Standards Organization (ISO) (2001). ISO 12039: Stationary source emissions – determination of carbon monoxide, carbon dioxide and oxygen – performance characteristics and calibration of automated measuring systems. Geneva, Switzerland: ISO Standard 12039. Central Secretariat.

International Standards Organization (ISO) (2007). ISO 10396: Stationary source emissions – sampling for the automated determination of gas concentrations. Geneva, Switzerland: ISO Standard 10396. Central Secretariat.

International Standards Organization (ISO) (2010a). ISO 21258: Stationary source emissions – determination of the mass concentration of dinitrogen monoxide (N2O) – reference method: non‐dispersive infrared method. Geneva, Switzerland: ISO Standard 21258. Central Secretariat.

International Standards Organization (ISO) (2010b). EN‐ISO 25140: Stationary source emissions – automatic method for the determination of methane concentration using flame ionisation detection (FID). Geneva, Switzerland: ISO Standard 25140. Central Secretariat.

International Standards Organization (ISO) (2011a). ISO 14066: Competence requirements for greenhouse gas validation teams and verification teams. Geneva, Switzerland: ISO Standard 18466. Central Secretariat.

International Standards Organization (ISO) (2011b). EN‐ISO 25139: Stationary source emissions – manual method for the determination of methane concentration using gas chromatography. Geneva, Switzerland: ISO Standard 25139. Central Secretariat.

International Standards Organization (ISO) (2013a) ISO 14065: Requirements for greenhouse gas validation and verification bodies for use in accreditation or other forms of recognition. Geneva, Switzerland: ISO Standard 14065. Central Secretariat.

International Standards Organization (ISO) (2013b). EN‐ISO 16911‐1: Stationary source emissions – manual method and automatic determination of velocity and volume flow rate in ducts – part 1: manual; reference method. Geneva, Switzerland: ISO Standard 16911‐1. Central Secretariat.

International Standards Organization (ISO) (2013c). EN‐ISO 16911‐2: Stationary source emissions – manual method and automatic determination of velocity and volume flow rate in ducts – part 2: automated measuring systems. Geneva, Switzerland: ISO Standard 16911‐2. Central Secretariat.

International Standards Organization (ISO) (2014a). ISO 14385‐1: Stationary source emissions – greenhouse gases – part 1: calibration of automated measuring systems. Geneva, Switzerland: ISO Standard 14385‐1. Central Secretariat.

International Standards Organization (ISO) (2014b). ISO 14385‐2: Stationary source emissions – greenhouse gases – part 2: ongoing quality control of automated systems. Geneva, Switzerland: ISO Standard 14385‐2. Central Secretariat.

International Standards Organization (ISO) (2016). ISO 18466: determination of the biogenic fraction of CO₂ in stack gas using the balance method. Geneva, Switzerland: ISO Standard 18466. Central Secretariat.

International Standards Organization (ISO) (2018). ISO 14064‐1: Specification with guidance at the organization level for quantification and reporting of greenhouse gas emissions and removals. ISO Standard 140641. Central Secretariat, Geneva, Switzerland.

International Standards Organization (ISO) (2019a). ISO 14064‐2: Specification with guidance at the project level for quantification, monitoring and reporting of greenhouse gas emission reductions or removal enhancements. Geneva, Switzerland: ISO Standard 14064‐2. Central Secretariat.

International Standards Organization (ISO) (2019b). ISO 14064‐3: Specification with guidance for the verification and validation of greenhouse gas statements. Geneva, Switzerland: ISO Standard 14064‐3. Central Secretariat.

Lee, S., Choi, Y., Woo, J. et al. (2014). Estimating and comparing greenhouse gas emissions with their uncertainties using different methods: a case study for an energy supply utility. Journal of the Air & Waste Management Assoc. 64 (10): 1164–1173.

Lieberman, E. and Schakenbach, J. (1997). The flow measurement puzzle – putting the pieces together. In: Proceedings – Acid Rain & Electric Utilities II. Air & Waste Management Association, 313–322. Pittsburgh.

McRanie, R.D., Norfleet, S.K., and Dene, C.E. (1997). The electric power research institute continuous emissions monitoring heat rate discrepancy project – an update report. In: Proceedings – Acid Rain & Electric Utilities II. Air & Waste Management Association, 351–363. Pittsburgh.

Nordhaus, W. (2013). The Climate Casino – Risk, Uncertainty, and Economics for a Warming World. New Haven: Yale University Press.

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BIBLIOGRAPHY

Comité Europeén de Normalisation (CEN) (2016a). Stationary source emissions‐ Determination of greenhouse gas (GHG) emissions in energy‐intensive industries – Part 1: General aspects. EN 19694‐1. Brussels.

Comité Europeén de Normalisation (CEN) (2016b). Stationary source emissions‐ Determination of greenhouse gas (GHG) emissions in energy‐intensive industries – Part 2: Iron & steel industry. EN 19694‐2. Brussels.

Comité Europeén de Normalisation (CEN) (2016c). Stationary source emissions‐ Determination of greenhouse gas (GHG) emissions in energy‐intensive industries – Part 3: Cement industry. EN 19694‐3. Brussels.

Comité Europeén de Normalisation (CEN) (2016d). Stationary source emissions‐ Determination of greenhouse gas (GHG) emissions in energy‐intensive industries – Part 4: Aluminum industry. EN 19694‐4. Brussels.

Comité Europeén de Normalisation (CEN) (2016e). Stationary source emissions‐ Determination of greenhouse gas (GHG) emissions in energy‐intensive industries – Part 5: Lime industry. EN 19694‐5. Brussels.

Comité Europeén de Normalisation (CEN) (2016f). Stationary source emissions‐ Determination of greenhouse gas (GHG) emissions in energy‐intensive industries – Part 6: Ferroalloy industry. EN 19694‐6. Brussels.

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CHAPTER 15
QUALITY ASSURANCE PROGRAMS FOR CEM SYSTEMS

A quality assurance (QA) program is necessary for a CEM system to provide quality data on a continuous basis. Without the institution of a quality assurance program, a source's CEM data may not be of adequate quality to meet regulatory requirements and can be easily questioned. A quality assurance program is basically a management program developed to assure that quality control activities are performed. A CEM quality assurance program should be designed so that objectives for the following are met:

Representativeness

Accuracy

Precision

Availability

Comparability

Representative samples are obtained by following EPA standardized procedures for equipment installation and measurement. Assuring that those procedures have been followed begins with the purchase of the monitoring equipment and continues in its day‐to‐day operation. Quality control activities, such as daily calibration and quarterly audits, are the procedures conducted to assure that the data generated from the system are both accurate and precise. Other program objectives are designed to provide high system availability and data comparability from plant to plant.

Quality assurance programs are mandated under Appendix F of 40 CFR 60 (U.S. EPA 2020c). Similar requirements are included in the 40 CFR 75 acid rain CEM rules (U.S. EPA 2020d), which are somewhat more stringent than those of Appendix F. In Canada, quality assurance requirements are incorporated in the Environment Canada CEM Guidelines (Environment Canada 2005) and the Alberta CEMS Code (AEP 2021). European quality assurance requirements for automated measurement systems (AMS), as CEM systems are termed by the European Union, are given in the EU standard EN 14181 (CEN 2014).

Although Appendix F applies only to NSPS sources that require CEM systems for compliance purposes, many states have since either adapted Appendix F or incorporated it by reference in their regulations or through permit processes. It, therefore, has a wider applicability than originally stated.

Whatever rule is applied, the purpose of a CEM quality assurance program is to implement a management system that will assure that the quality assurance objectives will be met over the years of operation of the CEM system. This chapter will discuss the basic elements of a CEM system quality assurance program in addition to specific CEM quality assurance regulatory requirements.

A QUALITY ASSURANCE FRAMEWORK

Ideally, quality control activities should be conducted in all phases of a CEM system project. Beginning with the original purchase specifications, to certification, and system performance years after installation, quality control is important. Figure 15‐1 summarizes the phases of a CEM program in which quality control activities are recommended.

Figure 15‐1 CEM system quality assurance framework.

The three important phases in the development of a CEM system are as follows:

Purchasing the system

Installing and certifying the performance of the system

Providing mechanisms for the continuous operation of the system

The procurement and certification of a monitoring system occurs before data can be reported to the regulatory agency. After certification, only quality assured data may be reported. The source assumes the responsibility to assure the ongoing data quality of the CEM system and develops a quality assurance program as a means to achieve performance objectives mandated by the agency.

Quality control procedures can be applied to each of the phases shown in Figure 15‐1. Most agencies will require that a quality assurance program, or plan, be developed and may review and approve it after development. After its development, the role of the plant is to implement the plan. The role of the agency is to see that the plan is implemented. An agency may inspect or audit the CEM system on a periodic basis to assure, in its own right, that quality data are being generated.

PROCUREMENT QUALITY CONTROL

A source required to install a CEM system will want to install the “best system” at the “best cost.” The “best system” must be considered with respect to limitations of the installation site, flue gas conditions, and other plant‐specific requirements such as workforce limitations and data processing requirements. As has been emphasized in this book, it cannot be stated categorically that any one system is better than another. A system operating well at one plant may be totally unsuited for installation at another. Also, the system offering the “best cost” does not necessarily mean “low bid.” Purchasing a “low bid” system may doom a facility to excessive continuing costs for maintenance and repair. Therefore, a balance must be achieved between system quality and cost. For these reasons, CEM system selection and evaluations should always be made on a case‐by‐case basis.

An orderly procedure should be developed for the procurement of source monitoring systems; see, for example, Jahnke and Peeler (1997) and ICAC (1998). Details of system procurement procedures, including flow‐charts for decision‐makers, are given in this document; see also EPRI (1993), Radigan (1994), and Brown (1992). Basically, there are three areas where quality control should be exercised when purchasing a system:

Prepurchase evaluation/selection

Writing system technical specifications

Recordkeeping

Each of these areas will be discussed in turn.

Prepurchase Evaluation/Selection

Before purchasing a CEM system, an assessment should be made of systems that are currently commercially available. It is possible for the plant to design and construct a system from basic components (analyzers, pumps, probes, etc.); however, this is not often done today. Instead, the plant will consider the systems offered by “turn‐key” vendors, who can design, construct, install, and certify the system. The information that has been provided in the previous chapters should assist in the assessment of the literature and sales claims of the various vendors. Such an assessment should include the following activities:

Comparing instrument specifications

Evaluating operational design with respect to the installation site

Contacting operators who installed and certified similar systems

Field testing (if possible – recommended for multiple system purchases)

An ordered program of information gathering and evaluation should be conducted in this step of the process. Vendor literature and relevant publications should be obtained. This information should be reviewed to determine the specifications of the analyzers and systems. These specifications include such parameters as response time, instrument range, temperature limitations, voltage requirements, etc. If design specifications are mandated for an instrument (e.g., opacity monitors), it is important to document that the instrument is advertised as meeting them. If the vendor does not advertise these features, the instrument may not be designed for regulatory applications.

As discussed in Chapter 11, in the European Union, CEM systems must meet the design and performance requirements of EN 15267 (CEN 2009) and QAL1 of EN 14181 (CEN 2014).

The intent of these evaluation programs is to demonstrate whether a CEM system is suitable for use in the intended application, following both laboratory and field evaluation. Instrument models and sampling systems are submitted to the test laboratory for evaluation by the manufacturer, who must pay for the service. The analyzers are tested in conjunction with a sampling system in testing programs conducted by Technischer Überwachungsverein (TÜV) (VDI 2007) in Germany or the Environment Agency MCERTS program (Environment Agency 2021) in the U.K.

It might be assumed that a system “approved” by the TÜV or MCERTS should be suitable for applications in the United States and that it would not be necessary to make any other assessments before purchasing such a system. Although such certifications may be useful in choosing between vendors, CEN requirements have no bearing on U.S. requirements and an assessment must still be made whether a proposed monitoring system can meet the specifications of Part 60 or Part 75. But more importantly, an assessment must be made whether the system is suitable for the given application. As stated in the introduction of this book, “there is no one ‘best’ system for all applications.” However, efforts must still be made to assess the merits of different monitoring systems before one is purchased.

Accordingly, before reaching a purchase decision, the operational design features of different systems should be evaluated. Methods used for monitoring the sample gas (extractive or in‐situ), type and length of sample line, conditioning requirements, vulnerability to vibration and temperature, and data processing options should all be considered with respect to the installation site, and data requirements.

Current users of commercial systems should also be contacted. Individuals who have been involved in similar monitoring programs should be consulted both for their experiences and suggestions. Although an existing installation may be quite different from the projected one, operating experience from it may be quite useful in an evaluation. Also, numerous papers have been published on CEM system analyzers and their applications, as well as on comparative studies undertaken to evaluate different systems. This has especially been the case for flow monitors, continuous mercury monitoring systems, tunable diode laser systems, and HCl analyzers.

Quite frequently, a corporation may wish to standardize on one CEM system design for all of its plants. Before entering into a major contract for multiple systems, it is recommended to either conduct a comparative study between systems offered by different vendors or to install one system on an approval basis. In either case, information can be gained regarding a system's suitability for companywide application.

CEM System Technical Specifications

After soliciting advice, presenting information before management, and meeting to discuss various options, a consensus should be reached as to the desired features of the system (extractive, in‐situ, dilution, nondilution, NDIR, NDUV, etc.). At this point, a detailed set of CEM system technical specifications should be prepared. These specifications should then be sent to at least three or four CEM system vendors, who will submit technical and cost proposals for the work.

Writing a complete set of specifications is a crucial quality control activity in the procurement of the system. Good specifications provide a basis for the purchaser to obtain the system desired and a basis for legal action if it is not. Through either a lack of CEM system knowledge or a wish to expedite a purchase, the plant may merely issue a purchase order or modify standard instrument specifications for this purpose. Procuring a CEM system in this manner may severely limit recourse if the system proves inadequate for the installation.

Typical CEM system specifications incorporate the following:

Purpose. A brief statement of where the CEM system will be installed, the number of units that will be monitored, and the regulatory requirements applicable to the installation.

Scope of Work. An outline of hardware and services to be provided by the vendor. This section may include a basic system configuration, a list of the number of analyzers required, and data acquisition/control requirements; if desired, it may specify brand names of analyzers or components. Vendor‐furnished services may include complete system engineering, installation, and start‐up, if desired.

Equipment and Services Provided by Others. A listing of equipment and services that the vendor is not expected to provide. This may include equipment or supplies such as elevators, ports, catwalks, platforms, electrical supplies, foundations, and calibration gases. Services provided by plant personnel or others may include system installation, wiring, IT support, and certification.

Description of Operating Conditions. A description of environmental and flue‐gas conditions at the sampling locations. Diagrams of sampling ports and access conditions should be provided here or referred from here to the appendix of the specifications. Flue gas characteristics such as moisture content, velocity, and temperature and the expected composition and concentrations of pollutants in the flue gas should be supplied. This information is critical to the vendor for the design of the system.

Design Criteria and Construction. A detailed description of the system on which the bid is to be prepared. The intent is not to provide all design data, but to provide the vendor with an understanding of the system requirements from both regulatory and operational aspects. Design requirements include adherence to standards, codes, and regulations. They also include specifications for instrument range, drift, and response time. They may include specifications for sample conditioning, interfacing with other plant systems, and data acquisition requirements and reporting formats.

This section will constitute the bulk of the specifications; however, care must be taken not to “over‐specify” the system. Vendors must be allowed leeway in the design to use their own experience in CEM systems for the job. If the requirements are too stringent, either no one will bid on the system or they will be ignored in the systems offered.

Vendor‐Furnished Services. A listing and description of services desired from the vendor. These may include total project management, installation, training, or ongoing maintenance services.

Inspection and Testing. A listing of certification guarantees and warranties expected from vendor. These may include factory checkout and certification provisions, a factory acceptance test (FAT), performance specification test guarantees, and system availability requirements.

Equipment Delivery Requirements. A statement of progress report requirements, delivery dates, and shipping requirements.

Engineering Data and Documentation. A listing of required system documentation. This should include accurate system schematics and wiring diagrams, operating manuals, maintenance instructions, and DAHS operating instructions and documentation.

The technical specification may also include specification fill‐in sheets, plant schematics, the plant operating permit, and copies of applicable regulations. Care should be taken in the use of specification fill‐in sheets, since if not directed otherwise, the vendor may merely fill in the sheets and submit them as the proposal for the job.

The set of technical specifications will normally be accompanied by a set of “standard terms and conditions” prepared by the company contracts department. This document will include legal requirements for insurance, limits of liability, remedies, disputes, etc. Attorneys prepare these things, but again they should not be made so restrictive that no one would wish to bid on the system.

The Electric Power Research Institute (2011) has developed a model to use when writing CEM technical specifications for applications to fossil‐fuel‐fired utilities affected by 40 CFR 75. These documents also provide review procedures for the evaluation of vendor proposals.

Record Keeping

Quality control applied to this phase of a monitoring program includes recordkeeping. A separate file should be started at the beginning of the evaluation process and should be continued over the lifetime of the system. Vendor literature, phone and e‐mail records, meeting notes, and financial records should be part of this file. Later, performance specification test data, copies of quarterly excess emission reports, instrument logbooks, and maintenance reports should also be retained. Therefore, in the case of failure of memory or changeover in personnel, to some extent, the experience gained in the monitoring project may be retained by the company.

Proposal Evaluations

After the receipt of the CEM system technical specifications, each vendor will prepare a proposal and bid on the project. The evaluation of these bids is central to the purchase of the system. The proposal evaluation should be a stepwise, methodical process. The goal is to choose the best system for the intended application. Central factors of design, materials/components, ease of use, and relative risk need to be considered in the program developed to accomplish this goal (Walker 1996; White 1995a). These factors apply equally to extractive, in‐situ, or predictive emission monitoring systems. Cost is always a constraint, but cost is not necessarily related to system quality or performance. The proposals should be evaluated on their technical merits as well as on their cost. If the low‐bidder is automatically assured of the contract award, the whole technical specification process becomes merely an empty exercise.

Evaluations should first be made on a technical basis to determine whether the proposed system can meet regulatory criteria. Costs should then be normalized between options available so that cost comparisons are made between equivalently performing systems (Brown 1992). If the system is inappropriate to the application, costs associated with the initial resource investment and noncompliance with monitoring requirements must be considered. It is difficult to make generalizations regarding CEM systems costs since they are dependent upon the application requirements and the current system and analyzer prices. EPA has developed a costing model spreadsheet, which is outdated but still provides a summary of contributing cost factors (U.S. EPA 2007). Cost estimates for CEM systems compliant with the EU EN 14181 standard have been given by Curtis (2014).

Sufficient information should be available to evaluate the various monitoring options. Each will have its own advantages and disadvantages, but the merits of each option must be considered in terms of the application. A common technique used in evaluating proposals is to prepare a matrix of various evaluation factors and to assign a maximum possible score to each factor. For example, in the matrix approach illustrated in Table 15‐1, each bulleted item could be used as an evaluation criterion and assigned a maximum score of 10. The matrix would then be composed of nine criteria evaluated for each proposal received. The level of detail of the matrix may vary, and some schemes break down each of the categories given above into levels that address instrument parts and function (Electric Power Research Institute 1993). This further breakdown can create several problems because vendors may not provide information this specific in the proposal. The resultant microanalysis may become confusing rather than productive. The maximum scores in the matrix may also vary, depending upon a preliminary assessment of the importance of each criterion.

An evaluation committee, composed of personnel experienced in CEM systems, data acquisition systems, and instrumentation, should be formed to assess the proposals. Each member of the committee should complete the matrices for each vendor independently and total the scores for each category (technical, risk, cost). A good technique to employ is to then meet as a committee and reach a scoring consensus on each evaluation criterion of the matrix. Each member of the committee should justify his or her score until agreement is reached. The use of an outside consultant or CEM expert from another plant to provide an independent, objective review of the proposals may also be helpful.

An ostensibly systematic evaluation can also be distorted and biased to validate one's preconceptions. Arguments that extractive systems are better than in‐situ, that CEM systems cost more than PEM systems, that continuous particulate monitors do not work, or that parameter monitoring is the lowest cost approach may be promoted to serve other agendas than to provide the best system for the application. A case in point is the coupling of plant air pollution control or plant operational parameters to emissions in PEM systems. Costs incurred in correlating emissions with parametric data may have to be repeated with each process modification. This is in contrast to instrumented monitoring systems having operational lifetimes of 10–30 years. The life‐cycle costs of a monitoring approach can be as important in an evaluation as a consideration of the initial capital costs.

CERTIFICATION QUALITY CONTROL

The performance specification test for gas monitoring systems can be considered to be a set of scientific experiments, where an unknown physical value (e.g., the concentration of the pollutant or diluent gas in the flue gas) is determined by two independent methods: a reference test method and the CEM method, compared against it. The reference method and CEM system are both making measurements on continually varying, unknown quantities – pollutant and diluent flue gas concentrations. The main difference between the methods is that in the RATA, data from the reference method is regarded as “truth,” against which the CEM system is to be compared. In good scientific practice, quality control activities are performed throughout an experiment. Accordingly, quality control activities should also be conducted throughout a performance specification test.

TABLE 15‐1 Simplified Example Matrix Evaluation

Bid 1
Bid 2
Bid 3
Bid 4

TechnicalReview

Adherence to technical specifications

System/component Quality

Proposal Quality

Riskevaluation

Past performance

Potential performance

Strength of guarantees

Costs

Capital

Maintenance

Intangibles

The Source Testing Company

The performance specification test may be conducted in part or in its entirety by a source testing company. Plant personnel may conduct the daily calibration drift and linearity tests, but typically, a source testing company will perform the RATA required for the system certification. Most commercial stack testing companies and corporate environmental organizations today use instrumented test vans or trailers to perform CEM Relative Accuracy Tests and audits (Chapman 1990; Noland and Reynolds 1990; Peeler and Deaton 1981). These vans usually incorporate instrumentation equivalent in quality to that of installed CEM systems. Data obtained from such systems can be of high quality if the requirements of the automated Reference Methods such as 6C and 7E are met.

The U.S. EPA required that after 27 March 2012, any source testing company performing relative accuracy tests, under a program subject to Part 75, must conform to the quality assurance practice of ASTM D7036 (ASTM 2021b). This practice, derived from the ISO standard ISO 17025 (ISO 2017), provides quality assurance guidelines for source testing companies [air emission testing bodies (AETBs) as defined in the practice]. The testing body is also required to have on site a “qualified individual” (QI), experienced in the methods being conducted, to oversee and supervise the test over its entire duration.

Requiring a testing body to follow the ASTM D7036 practice offers greater assurance that the testing will be conducted properly and that quality control procedures will be followed as specified in the reference methods and ASTM D7036. Testing that is conducted under other programs, such as Part 60 or Part 63, is not required to conform to the D7036 practice; however, it is highly recommended that D7036 conformance be written into any contract with a source testing company to assure that quality data results from the test.

The Performance Specification Test Plan

To coordinate activities between the plant and source testing personnel, it is highly recommended that a test plan be prepared by the source testing firm prior to the test. A test plan may be required by the regulatory agency, but if it is not, it is recommended that the plant still include such a requirement as part of the testing contract. The test plan should include the elements listed in Table 15‐2:

The preparation of such a plan can help to assure parties involved that the test procedures will be adequately quality controlled if the test plan is followed. The test plan should be reviewed and agreed to prior to the test. Any questions or outstanding issues regarding the plan, responsibilities, or procedures should be discussed at a pretest meeting.

Test plans should be site and project specific; accepting generic test plans should be avoided. The test plan only serves a purpose when both plant and testing personnel use it as guide for quality control and adhere to the procedures detailed within the plan. An initial certification test may involve more parties than a routine source test since there is significant self‐interest in the test for everyone involved. The cast for an initial certification may include:

CEM system integrator personnel

Plant environmental specialist and engineers

The test team leader and source testers

An agency observer

An independent consultant/test observer

The role of each individual present at the test should be understood before the test is initiated. If the organization of the test and activities associated with the participants are clearly stated, less confusion will occur when the test is conducted.

Performance Specification Test Quality Assurance Recommendations

Many techniques can be applied before, during, and after a performance test to help assure that quality data will be reported. Source tests are often conducted under less‐than‐optimal conditions, and are dependent upon the capability of those performing them. A well‐performed test will be conducted by experienced source testers, who have properly planned the test and who follow test procedures as specified in the test methods. Test observers can provide oversight to assure the integrity of the tests and consultation if issues arise during the test. The following listing provides quality control techniques that might be considered when a performance test for an initial system certification is conducted.

TABLE 15‐2 Typical Elements of a Source Testing Plan

Project description

Project organization, personnel conducting the tests and responsibilities

Schedule

Summary of test methods and description of equipment and techniques to be used (hot‐wet extractive, cool‐dry extractive, etc.)

Description of data reduction methods

Description of the source test company quality assurance program and site‐specific quality control procedures

Documentation and reporting procedures

Safety policy and procedures (both plant and source testing company)

The source testing firm should incorporate its own quality control checks in its testing procedures. For automated reference methods, additional instrument verification checks such as linearity and interference checks may be applied.

If the source owns a portable (or “transportable”) gas analysis system, this may be used to check the system performance prior to the relative accuracy test. CEM system voltages, test points, pressures, flow settings, etc. may also be checked prior to the test.

Another good technique to follow prior to conducting the relative accuracy test is to compare the calibration gases used to span the CEM system with the gases used to calibrate the source tester's reference method instrumentation. This comparison will help to determine systematic errors attributable to calibration gas values. Protocol gases are required when conducting instrumental analyzer procedures such as Method 7E (U.S. EPA 2020a).

During the testing, the plant should operate either under normal conditions or at emission levels close to the emission standard. Because of the peculiarities of the U.S. EPA relative accuracy test calculations, the higher the reference method test value (RM), the easier it will be to pass the test. Because of the presence of agency personnel during the test, a unit operator might wish to reduce pollutant emissions to levels lower than normal. Such a practice will make it more difficult to pass the relative accuracy test.

During the test, conditions for representativeness in terms of plant load conditions, sampling conditions, procedures for treating data in case of plant shutdown, and so on should be addressed. Reference test data and CEM system data should be taken at the same time and compared over the same period, particularly when emissions are varying rapidly. Corrections may be necessary for CEM system measurement times for systems having long averaging times, long sampling lines, or slow response times.

During the test, the plant environmental engineer, agency observer, or auditor should verify that all pre‐ and post‐run calibration verifications are performed for all runs conducted. It should also be assured that there are no leaks in the source test sampling system.

If EPA Method 2 is conducted, the plant environmental engineer, agency observer, or auditor should verify that the test probe has been calibrated and that a default calibration factor (cp) is not being used. He or she should also verify that the sampling points over the stack cross section have been determined correctly and have been compensated for stack insulation and/or brickwork. It should also be assured that the test is conducted carefully, that the probe is inserted normally to the stack flow, that yaw and pitch are minimized, and that probe differential pressures are measured accurately.

Especially during an initial performance test, the plant environmental engineer and agency observer should, together, periodically review printed DAS output. It should be noted whether the data are raw data, corrected data, and/or averaged data. Both the source tester and agency observer should annotate emission values obtained during the relative accuracy test period, note full‐ scale values, any zero offsets, calibration values, and emission values at that time. These simple steps can minimize questions that may arise when the raw data are reviewed in the test report and recollection of offset and span values have been forgotten.

Calculations in the final test report should be reviewed thoroughly. Because errors frequently occur in source test calculations, it is imperative that the calculations be either recalculated or spot‐checked under any review. Ideally, raw test data should be entered into computer programs developed specifically for such quality control checks. Note that even though the source tester will have programmed relative accuracy test calculations into their computer, this does not necessarily mean that the results will be correct. For example, cases in which incorrect expressions for standard deviation are programmed into the DAS are common. Check carefully whether relative accuracy is calculated correctly for the applicable rule, i.e. in parts per million or units of the standard (lbs/mmBtu, kg/hr, corrected to 12% CO₂, etc.). Check for round‐off errors – verify that valid rounding methods were used. When moisture or diluent data are used to correct the pollutant emissions data, check that they were obtained over the same time period.

When reviewing the final test report, the entire test report should be reviewed, not just the executive summary. The source test equipment described in the report should be checked to see that it corresponds to equipment used in the test. Raw source test and raw CEM data should be included in the report. Certifications for calibration gases, pitot tubes, and dry gas meters calibrations should be attached.

Other quality control techniques may be instituted by the plant or source test contractor when conducting the performance specification tests. The actual performance tests are, however, quite well defined and, if followed carefully, should produce quality results.

CONTINUING OPERATION – QUALITY ASSURANCE PROGRAMS

After a CEM system is certified, its future performance will be dependent upon the quality control and quality assurance activities instituted at the plant. Concern with system performance cannot end after the system passes the performance specification test, but must be an ongoing commitment over the lifetime of the system. Quality data from a CEM system can be best obtained by instituting a CEM system quality assurance program for its continuing operation.

The U.S. EPA has mandated CEM system quality assurance programs for sources that use CEM systems for monitoring compliance with emissions standards and also for CEM systems installed under the acid rain program. In Canada, quality assurance programs are encouraged through CEM guidelines (Environment Canada 2005) and required by provincial codes (Alberta Environment and Parks 1998). These requirements provide direction for the development of a quality assurance plan, which incorporates both quality control and quality assurance procedures.

Appendix F of 40 CFR 60 and Appendix B of 40 CFR 75 require that a minimum set of quality control procedures be developed and implemented by the plan. Quality control procedures specified for inclusion in the plan by these two regulations include the following:

Procedures for the determination of calibration drift/error and linearity

Methods used for the adjustment of calibration drift/error and linearity

Preventive maintenance procedures

Data recording, calculation, and reporting procedures

Corrective action procedures for malfunctioning systems

Procedures for conducting performance audits, such as the cylinder gas audit (CGA) or linearity checks and the relative accuracy test audit (RATA)

These procedures must be written and described in detailed, complete, step‐by‐step operations. Other procedures can be instituted to further assure the accuracy and precision of CEM system data. The list of quality control procedures or “standard operating procedures (SOPs)” given here in Section 2 of Table 15‐3 is more comprehensive, addressing additional procedures necessary for assuring that the CEM system data are defensible.

Writing the Quality Assurance Manual

Writing a quality assurance manual requires considerable effort and should be assigned to someone who has both the aptitude and time to write it. Because writing a manual is often viewed by management as a “nonproductive” task, necessary management support in terms of time and resources is not always available to plant personnel for such a project. Regulations do require that a CEM system quality assurance manual be available for review on site so other options might be considered to produce a suitable document.

Options for Writing the Manual

The first option is to develop the manual internally, assigning the project either to a quality assurance department, a corporate environmental engineer, the plant environmental engineer, or someone who might have time to devote to the project. Internal development of a CEM manual is often not practical. Most plants do not have quality assurance departments, and if they do, they are more concerned with the quality control of manufactured products rather than with continuous emission monitoring systems. Corporate and plant engineers may have the knowledge necessary to develop the plan, however, in this author's experience, it takes at a minimum, approximately 80 hours to prepare a QA manual for a single CEM system. This time is usually not available to environmental engineers seeking to keep the corporation or plant in compliance and generate the numerous reports required by state and federal agencies.

Another option is to contract the work to an environmental consultant or contractor, an architectural and engineering firm, or the CEM system integrator/vendor. Environmental consultants or contractors do this type of work and if active in the field of continuous emission monitoring, can readily develop CEM plans for their clients. The problem here, however, is that the manual produced may be relatively expensive, and not being prepared by plant personnel, may not adequately reflect actual plant procedures. Architectural and engineering (A&E) firms, the firms building a plant, might include a CEM system and its corresponding QA manual in a plant construction project. However, the business of A&E firms is plant construction and not necessarily CEM systems. It should be determined before this option is agreed on whether the firm has the necessary experience to develop a CEM manual. The CEM system integrator or vendor may offer to supply a QA manual with the system, or to offer it “free” as part of the project. These plans may be quite good if the plan is written for the actual system delivered. However, they may often be a prepackaged product that lacks the management and regulatory details specific to the plant installation.

TABLE 15‐3 Outline for a CEM System QA Manual

Section 1: System description

Plant description

Applicable rules and emission limitations

The monitoring system and analyzers (design, model numbers, and serial numbers)

Plumbing/installation diagrams – system description

Analyzers – principles of operation

Control system

Data acquisition system

Spare parts list

Section 2: The quality assurance plan – quality assurance policies

Quality policy and objectives

Document control system

Organization and responsibilities

Quality control – calibration verification and adjustment

Quality control – preventive maintenance

Quality control – corrective maintenance

Quality assurance – performance audits

Cylinder gas audits/linearity tests

Opacity or PM monitor audits

Relative accuracy test audits

Quality assurance – system audits

Reports

References

Section 3: Standard operating procedures

Start‐up and operation

Calibration procedures

Unit operator procedures

Daily CEM system inspection

Preventive maintenance procedures

Corrective maintenance procedures

Audit procedure 1 – cylinder gas audits

Audit procedure 2 – relative accuracy test audit

Audit procedure 3 – flow monitors

Audit procedure 4 – opacity/PM monitors

Systems audit – inspection procedures

Data back‐up procedures

Training procedures

CEM system security

Data reporting procedures

Managing change – recertification

Appendices:

Blank forms

Facility operating license (as pdf)

Applicable CEM performance specifications and rules (as pdf)

Reference test methods (as pdf)

CEM system and analyzer operation and maintenance manuals (as pdf)

Perhaps the easiest way to prepare a CEM QA manual is to copy someone else's or use a prepackaged “canned” plan and modify it. In this option the basic format and, if appropriate, rules and methods are provided and one can then incorporate information to the installed system, plant management policies, responsibilities, and other details. Care should be taken in modifying the manual since it may be embarrassing if the name of another plant or equipment not installed at the facility should appear in the manual.

Writing the Manual

Although writing a CEM system QA manual may appear daunting from the previous discussion, the task can be accomplished by approaching it in a systematic manner.

The first step is to meet with all of the parties involved with the CEM program and discuss the reasons for writing the manual and implementing a quality assurance program (the simplest reason is that it is required). CEM system technicians, the environmental engineer, unit operators, and supervisory personnel should attend the meeting. Each of these individuals should be interviewed and asked what their responsibilities are with regard to the CEM system. Their responses can provide the basis for many of the standard operating procedures in the manual.

The next step is to acquire the information necessary to write the manual. This may actually approach the level of a scavenger hunt, but it includes assembling documentation such as a system description, system and instrument manuals, forms currently in use (inspection, maintenance, linearity, audit, etc.), example reports, an organization chart, and lists of personnel responsibilities.

If not already familiar with the CEM system, the CEM system itself should be inspected from the probe installation, analyzers, and data output. Equipment serial numbers and operating parameters such as pressures, temperatures, flow rates, and so on should be documented for each gauge or meter of the system and cross‐checked with operating specifications given in the operation and maintenance manuals. Analyzer operating ranges should be documented and verified and instrument alarm indicators noted. If allowed, photographs should be taken as a reminder of observations when writing the manual and for inclusion in the manual itself. Photographs will make the QA manual more interesting and can provide visual information that may simplify writing the manual. They can also be useful in training new technicians or explaining monitoring issues without having to visit the system.

During the inspection of the CEM system, information regarding the system should be obtained from the CEM system technician conducting the tour. Calibration verification and adjustment procedures can be discussed, as well as preventive maintenance procedures and their frequencies. Documentation practices for periodic inspections and corrective maintenance events can be noted, as well as activities performed for, or in preparation for, performance audits. A copy of any form currently used should be included and incorporated into the manual. If no forms are in use, forms may be developed to assist in the documentation of quality control activities; however, no single form should be greater than one page and the number of forms should be kept to a minimum. Documentation practices that are viewed as too onerous may become viewed as “make‐work” activities and become counterproductive to the development of a successful quality assurance program.

Writing the Manual – Guide to the Sections

The Quality Assurance/Quality Control manual should be a reference document for the management of the continuous emission monitoring program. The goal of the program should be to provide accurate, precise, and complete data through the implementation of an effective set of quality control and quality assurance procedures. Some of these procedures are mandated by monitoring regulations, but others may be optional, applied in the program as “best practices” from the quality assurance profession.

Various formats for quality assurance manuals have been developed. One commonly used format is found in U.S. EPA (1976). Another format is given here in Table 14-2. The Environment Canada CEM system guidelines (Environment Canada 2005) provides some of the best regulatory guidance for writing a CEM system QA/QC manual and gives an expanded outline similar to that provided here in Table 14-2. However, no specific formats are required in the United States or Canada, allowing some flexibility when writing the manual.

The manual should be considered a working document and should constitute company policy regarding CEM system performance. It should be reviewed annually and revised as company policies and procedures change and when the CEM system is modified. A review and/or revision is best performed prior to an annual RATA, a systems audit, or agency inspection. A well‐running CEM system may lead to some complacency with regard to manual revision; however, it should be understood that a manual that has not been revised in 10 years is never regarded favorably by an inspector.

The outline given in Table 15‐2 is divided into four sections: (i) the system description, (ii) the quality assurance plan, (iii) standard operating procedures, and (iv) appendices.

System Description

By way of introduction, the system description should include an overview of the plant operations and its emissions control equipment, a table of flue gas characteristics, and a listing of applicable emissions rules and emission limitations. At a minimum, the system description should provide a plumbing diagram of the CEM system, a diagram of the placement of the system components (probe, flow monitor, shelter, calibration gases, etc.), and a listing of model and serial numbers for each analyzer installed. A discussion of analyzer operating principles, the data acquisition system configuration, and any special design features should be included. Principles of operation may be obtained from the analyzer operation and maintenance manuals, or in a less optimal approach, reference might merely be made to appropriate sections in the manuals. A spare parts listing may be appended to this part with the understanding that a current listing is maintained on a plant or warehouse computer, as is usually the case.

As noted previously, photographs are useful in this section of the manual, as a teaching tool for new technicians and management. Photographs also make the manual more readable by personnel who may not be directly involved with the system.

Vendor analyzer operation and maintenance manuals have improved significantly since the beginnings of CEM programs. However, much less can be said about system operation and maintenance manuals provided by CEM systems integrators. Few integrators spend the time to write manuals explaining how their site‐specific systems actually work. Plumbing diagrams are usually obtainable from the installation schematics, but are not often incorporated into a separate operations and maintenance document. A binder incorporating analyzer and plumbing part manuals does not constitute a system operation and maintenance manual.

The QA Plan

The QA plan gives the source's philosophy and approach to the quality assurance program. It is important because it establishes the implementation procedures for the quality control activities. The QA plan sets the goals for precision, accuracy, and completeness required for the monitoring program. These objectives are typically defined by regulation; however, more stringent goals may be set in the plan if desired.

The quality assurance plan is essentially a management plan and accordingly requires a discussion of how the monitoring program will be managed. This is usually accomplished by developing an organization chart specific to the continuous monitoring program, along with a listing of CEM responsibilities for each category or person included in the chart. For example, the responsibilities of the CEM technicians, who provide the central functions for the continuous operation of the system, may include those listed in Table 15‐4:

The next sections of the plan may be somewhat difficult to write, in that they are to provide a summary discussion of basic elements of the program, such as document control, calibration verifications, periodic inspection, maintenance, audits, and so on. They define the plant's understanding of what it takes to meet the quality assurance objectives previously stated. For some sections, a simple restatement of regulatory requirements for daily calibration verification, quarterly audits, and annual audits may be all that is necessary.

TABLE 15‐4 CEM System Technician Responsibilities

Assures that the CEM system and analyzers are operating properly at all times

Assures that all CEM system analyzers meet their daily calibration drift/linearity requirements

Performs CEM system periodic checks (daily/weekly) and records observations in accordance with corresponding checklists

Reviews CEM system data for consistency and comparability

Performs scheduled preventive maintenance in accordance with procedures given in the CEM QA/QC manual and system/analyzer operation and maintenance manuals

Performs corrective action as necessary and seeks out causes that made action necessary

Informs his/her supervisor when monitoring system problems occur

Records in the CEM system logbook the performance of preventive maintenance activities, the performance of audit activities, the performance of any adjustments, and any observations specific to the system that are not already included on applicable forms

Records in the CEM system logbook corrective maintenance performed, a description of the problem requiring corrective maintenance, reasons for the problem, actions taken, and suggestions for preventing the problem from reoccurring

Ensures that all required calibration gases are on hand

Requests approval for any service contract assistance

Assures spare parts are available – initiates purchase for equipment, calibration gases, spare parts, and supplies as necessary

Supports and assists source testers during monitoring system performance evaluations and correlations studies

Recommends monitoring system/DAS changes and upgrades as necessary

Standard Operating Procedures (SOPs)

Standard operating procedures are detailed, step‐by‐step procedures that instruct the CEM technician, operator, or environmental engineer how to perform their tasks associated with the continuous monitoring system. Standard operating procedures may be either quality control activities or quality assurance activities. Many procedures will be unique to the plant monitoring program (such as inspection and maintenance procedures); others (such as linearity tests and annual audits) will be required by regulation and are already detailed in rules or guidelines.

Different people may need to be consulted to write the SOPs. For example, an SOP for daily calibration verification and manual calibration may require asking the CEM technician the sequence of steps that must be followed on the controller, DAS, or analyzer to initiate a manual calibration verification or to recalibrate the analyzer. On the other hand, the facility “planner” may have written a “Maintenance Procedure” that technicians must follow when issued a CEM‐related work order. Such maintenance procedures are usually quite detailed and are typically available on the plant computer network. These can be copied and incorporated into the SOPs of the QA/QC manual, or they may merely be referenced to the network by their appropriate identification number. Also, for detailed maintenance procedures such as replacing a lamp or detector, a simple reference to the section and page number of the analyzer operation and maintenance manual is acceptable.

An SOP for the unit operators should also be prepared. Some plants require operators to log CEM system trouble alarms in the operations log. Others do not. Plant procedures for calling out CEM technicians on evenings, weekends, and holidays likewise need to be specified.

In writing the SOPs, forms can be useful in documenting work, particularly for periodic (daily or weekly) inspections or periodic maintenance (quarterly, annual). Filling in a form provides verification that a task has been done; in this sense it is better to write in a number than to just check “yes” or “no.” Each form should be signed, dated, and archived. Note that an auditor or inspector retains the right to ask to see each of the fifty‐two forms if a weekly inspection form is to be completed.

Because a quality assurance manual is considered an organic document, procedures may be changed if it is found that the quality assurance objectives are not being met. They can also be changed if it is found that the quality assurance objectives can still be met if inspection frequencies and the number of forms can be reduced.

CONTINUING OPERATION – ELEMENTS OF QUALITY CONTROL

There are many quality control methods that can be instituted in a CEM system quality assurance program and, when implemented, can be incorporated into the quality assurance manual as standard operating procedures. Mandated and optional quality control methods used in many CEM programs include the following:

Daily calibration verifications

Periodic system inspections

Preventive maintenance

Corrective maintenance

Managing change and obsolescence planning

Logbook documentation

These are the most common quality control methods that are used in well‐managed CEM programs. Daily calibration verification and adjustment procedures and preventive and corrective maintenance programs are mandated in the United States and Canada. Other methods may be applied to the program depending upon plant or corporate management policies. When the quality control activities are conducted, the CEM data obtained from the system should meet the performance objectives for accuracy, precision, and completeness defined for the monitoring program. Failure to meet the performance objectives might mean that the quality control procedures are inadequate, or that they are not being followed. Each of the quality control methods listed above will be discussed in turn with the view that they should be incorporated as standard operating procedures within the CEM system QA/QC manual.

Daily Calibration Drift Verifications

Required daily calibration checks are a fundamental part of U.S. CEM regulatory programs. Meeting daily calibration drift requirements provides confidence that a monitoring system is operating properly and is a principal concern of most CEM system technicians and plant environmental engineers. Failing a daily calibration check can put a system “out‐of‐control” and lead to missing data and reduced data availability.

In the United States, the calibration of most gas monitoring systems is checked typically once every 24 hours using calibration gases. This is normally initiated automatically by the CEM system controller or computer. The calibration check is conducted at two levels: at a low‐level value (zero or at a value between 0 and 20% of the span value) and at a high‐level value (between 50 and 100% of the instrument span value). Opacity and flow monitor low‐ and high‐level values are also required to be checked once daily. In opacity monitors, neutral density filters may be used for this purpose; although these are not independent reference standards. Likewise in flow monitors, the daily electronic and transducer checks are part of the system or its operation and are not independent from it.

Calibration drift and calibration error are two terms often used interchangeably. Calibration drift is defined in 40 CFR 60 as the difference in an analyzer output reading from a reference value as a percent of span after a period of operation during which no unscheduled maintenance, repair, or adjustment took place (see Equation 11‐3). This reference value can be that of a calibration gas, gas‐filled cell, or optical filter. It is not required to be traceable to NIST standard reference materials. In contrast, calibration “error,” as defined in 40 CFR 75, is the calibration drift determined using cylinder gases traceable to NIST standard reference materials only. Also, the calibration gas must pass through all filters, scrubbers, conditioners, and other monitor components used during normal sampling and through as much of the sampling probe as is practical (this requirement is not prescribed in Part 60). This check of the system is superior to merely injecting calibration gas at the analyzer port, since it checks the extractive system as well as the analyzer.

In Europe, the calibration of CEM systems are not required to be checked every day. The checks are required typically only after a “period of unattended operation” during which it is assumed that the system does not exceed drift specifications. This period can be a few weeks or extend beyond a month or more. Internal gas cells and electronic methods are, however, used to check analyzer performance more frequently. The European EN 14181 quality assurance procedures require less frequent calibration checks than U.S. regulation relying more heavily on the “type‐testing” and performance assurances provided by vendors. This has led to reduced costs in the operation of the equipment, but has created problems when European designs are marketed in the United States.

Before continuing this discussion, it should be noted that semantics is important when speaking about calibration with regard to CEM systems. Simply:

“To calibrate” an analyzer is usually interpreted as “adjusting the analyzer's calibration” to a known reference value.

“Checking or verifying the calibration” means introducing a calibrations gas (or filter) and comparing the response to a known reference value without making any adjustments either before or after the check.

An instrument should only be “calibrated” if the response from a “calibration check” does not meet calibration quality control specifications.

Tolerance and Out‐of‐control Conditions

The instrument operator should not have to “re‐zero” or recalibrate the system every 24 hours when the values are checked. Small values for drift may be due merely to system noise. Quality control chart procedures should be developed where drift limits are established for the physical adjustment of the analyzer calibration. Under 40 CFR 60 Appendix F, these limits are to be set at twice the performance specification for drift. Because the drift specification is 2.5% of the span value for SO₂ and NOx CEM systems, these systems do not have to be adjusted until the drift exceeds 5% of the span value. For example, if the span value is 500 ppm, drift adjustments would not be required unless the drift exceeded ± 25 ppm. The specifications are tighter under the acid rain program (40 CFR 75 Appendix B) and Environment Canada Guidelines (2005) where adjustments are to be made if the low‐ or high‐level calibration drift value exceeds the drift specification itself (e.g. 2.5% of span). These specifications are summarized in Table 15‐5.

TABLE 15‐5 Daily Calibration Drift/Error Criteria – U.S. and Canada

U.S. 40 CFR Part 60 App F
U.S. 40 CFR Part 75 App B
Canada EPS 1/PG/7

Adjustment Criteria
Adjustment Criteria
Adjustment Criteria

Adjust when zero or high‐level calibration drift is
>5.0% for SO₂ & NOX
>1.0% O₂/CO₂

>2 × PS for other gases

Adjust when zero or high‐level calibration error is
>2.5% for SO₂ & NOX or >│15 ppm│
>0.5% O₂/CO₂
>3.0% for flow of H₂O
Adjust when zero or high‐level calibration error is
>2.5% for SO₂ & NOX or >│2.5 ppm│
>0.5% O₂/CO₂

Out of Control Criteria
Out of Control Criteria
Out of Control Criteria

System is out of control when:

Fifth consecutive calibration drift (CD)

>5.0% for SO₂ & NOX
>1.0% O₂/CO₂
>2 × PS for other gases
or
>10% for SO₂ & NOX
>2.0% O₂/CO₂>4 × PS for other gases

For any one day

System is out of control when calibration error (CE):
>5.0%
or
>10 ppm if span < 200 ppm)
>1.0% O₂/CO₂
>6.0% for flow of H₂O
System is out of control when calibration error (CE):
>5.0%
or
>│5.0 ppm│
>1.0% O₂/CO₂

Out‐of‐control conditions for excessive calibration drift are also defined in CEM rules. For example, in the 40 CFR 60 Appendix F requirements, if either the low‐level (zero) or high‐level calibration check result exceed twice the PS drift specification for five consecutive days or four times the drift specification for any one day, the system is said to be out‐of‐control. In 40 CFR 75 and Environment Canada CEM guidelines, the system is out‐of‐control if the drift exceeds twice the drift performance specification. During an out‐of‐control period, the data are not acceptable as compliance data for the agency.

A monitoring system is “unavailable” for monitoring when it is out‐of‐control. The time the system is out‐of‐control cannot be counted in meeting any system availability requirements. Availability requirements will be discussed later in this chapter.

For CEM systems that automatically correct for calibration drift, unadjusted concentrations must be recorded prior to any automatic adjustments. Also, the amount of adjustment is to be recorded. Issues associated with systems merely correcting computer‐generated data have been discussed in Chapter 10. Here, after the calibration check, the software will automatically correct subsequent data. This is a computer correction and does not involve the adjustment of the analyzer zero or span. As a result, analyzer meter readings will not be corrected and will differ from the printed computer‐adjusted readings. Quality control procedures should be implemented in such systems to track the drift from the initial calibration, and a computer‐generated alarm should be incorporated into the system to alert the operator that action is necessary when the uncorrected drift exceeds 5% or two times the performance specification (PS) for daily drift.

Control Charts

The record of daily values for zero and calibration drift provides an opportunity for evaluating the ongoing performance of a monitoring system. By simply plotting the daily drift as a function of time, patterns are often revealed that might not be observed by just checking to see if the system passed or failed the check each day. This plot is called a quality control chart and can be easily generated either manually or automatically. Figure 15‐2 illustrates a typical quality control chart, presented as a percent drift (as a percent of span) versus day.

Good performance is exhibited when the drift tracks closely to the zero line. If an upward or downward drift is followed by a steep drop to the center line, one can assume that the analyzer was recalibrated at that point. Quality control charts are useful in detecting nonrandom patterns in the daily calibration check. They can give an indication of system or analyzer malfunction, system degradation, calibration biases, and changes in ambient conditions. The charts in Figure 15‐3 illustrate some possible trends that might indicate problems with the system.

In Europe, EN 14181 requires that the control chart be more statistically sophisticated, requiring that Shewhart or Cusim charts (used in analytical laboratory quality control) are generated instead of a simple drift plot. Most technicians, however, can readily identify problems from patterns such as those illustrated in Figure 15‐3, without having to resort to a statistical analysis. A recommended approach to the use of quality control charts is to check the system out when:

One or more data points are beyond one of the upper alarm limits

Three consecutive data points are beyond one of the warning limits

Figure 15‐2 An example quality control chart for daily calibration drift.

Eight consecutive points are on the same side of the center line

Six consecutive points are either increasing or decreasing

Periodic System Inspections

Periodic inspection are those procedures that are performed on a routine basis, generally daily or weekly, to determine whether the system is functioning properly. These procedures will include visual checks of system operating indicators such as vacuum and pressure gauges, rotameters, control panel lights, and alarms. Checks are also made for possible problems such as leaks, electrical shorts, controller/DAS communication issues, and environmental problems caused by failed heaters or air conditioners. A good technician will be attuned to the health of the monitoring system by being observant of often subtle changes to the monitoring system as it operates in the unforgiving stack environment.

Figure 15‐3 Quality control chart examples indicating possible problems.

Maintenance

Several approaches may be taken in maintaining an instrumentation system. Preventive maintenance may be scheduled and performed periodically to minimize failures, predictive maintenance anticipates failures that may happen, proactive maintenance is performed before failure can occur, and corrective maintenance is performed after failure occurs. Predictive and proactive activities should be incorporated into the overall preventive maintenance program to minimize system downtime and maximize system availability. The goal of a CEM preventive maintenance program is to avoid problems that will require corrective maintenance.

Preventive Maintenance

A preventive maintenance program is defined by EPA as an orderly program of positive actions (checking, adjustment, reconditioning, and/or replacement) for preventing failure of monitoring systems during their use (U.S. EPA 2020c). Excessive drift, inconsistent data, excessive downtime, and/or the failure of performance tests may indicate the lack of sufficient maintenance. Frequent failures of a system are often blamed on the equipment. However, with CEM systems, inadequate system performance is more often associated with the failure to perform recommended maintenance on the equipment. In everyday experience, if an automobile is not maintained, at some point it will not run. It is the same with CEM systems.

Preventive maintenance is performed at regular intervals. It is usually considered “fixed time maintenance” (Idhammer 1997), where maintenance activities are scheduled by the plant time management planner and incorporated into the CEM QA/QC manual. Activities may include inspecting, leak checking, replacing filters, reconditioning pumps, replacing lamps, etc. Major activities, such as pulling and inspecting the probe, replacing sampling line, and so on, are typically scheduled during plant outages. Recalibration and other “tune up” procedures are often conducted before the performance audits, the RATA and linearity tests.

The weekly inspection is usually conducted using a checklist. Inspecting a CEM system by merely walking into a CEM shelter and seeing if all of the lights are working is not a satisfactory approach to preventive maintenance. An effective maintenance program requires that checks and observations be documented so that (i) it can be verified that each parameter to be checked was, in fact, checked and (ii) information from the inspection can be used for troubleshooting problems that occur in the future. Table 15‐6 gives an example of a weekly checklist.

The weekly (or daily) checklist requires the CEM technician to inspect the system and check off or write in the values of monitored system parameters. These include flows, system pressures, cylinder gas pressures, temperatures, calibration verification values, and emissions readings at the time of the inspection. Many technicians will choose to conduct the inspection at the time of the daily system calibration verification. At this time, flows through the zero air and calibration gas flow meters (rotameters) can be checked and adjusted if necessary. Observations and checks made to see if systems are functioning, as well as calibration adjustments and part replacements, all serve to keep the system from failing.

Preventive maintenance activities performed on a less frequent basis (monthly, quarterly, semiannually, or annually) involve more than checking the system. The activities conducted depend upon the type of system installed. They can include cleaning optics, changing filters, scrubbers, desiccants, catalytic materials, calibration gases, and so on. Semiannual or annual activities may include more involved procedures such as refurbishing sample pumps, checking/replacing solenoids, replacing lamps, and replacing peristaltic pump tubing.

Predictive Maintenance

Instead of adhering to a strict schedule of maintenance and replacement activities, replacement costs may be reduced by incorporating a system of predictive maintenance within the preventive maintenance program. Many of today's analyzers incorporate diagnostic programs that monitor parameters associated with key components such as lamps and detectors. These programs should be run periodically (monthly or quarterly) and the parameter values recorded. By trending these values, the performance of the analyzer components can be tracked and impending problems flagged. Although today's analyzers may track 20 or more different internal parameters, when those parameters never change, interest in this activity wanes and reliance is placed on set points to provide for reactive maintenance rather than predictive maintenance.

Parameters associated with the system itself can also be programmed to predict usage rates and performance trends. For example, calibration gas bottle replacement can be anticipated by installing a pressure transducer on the gas cylinder and trending the daily usage into the DAHS. Tracking stack and probe umbilical line temperatures, vacuums and pressures, sample flow rates, chiller temperatures, and so on can monitor trends in the system as well as to alarm for failure if set points are exceeded. Trending this information may allow for scheduling maintenance during windows of opportunity: periods when the plant is down or prior to the annual RATA, when a RATA would be required after a maintenance procedure.

Continually monitoring system and analyzer parameters is not a substitute for conducting the routine preventive maintenance activities such as inspection, filter changeouts, and pump refurbishing. These should be scheduled procedures, and should not be extended to imminent failure.

TABLE 15‐6 Example Weekly CEM Checklist

 Week | Week 1 | Week 2 | Week 3 | Week 4
 Date/Time |  |  |  |
 Initials |  |  |  |
Main Stack Extractive System and Analyzers |  |  |  |
 Sample Flow   1.0 lpm |  |  |  |
 Cal Gas Flow   6.0 lpm when on |  |  |  |
 Bypass Flow   0.5 lpm |  |  |  |
 Sample Pressure   10 psi |  |  |  |
 Cal gas Pressure   30 psi when on |  |  |  |
 Sample Pump O.K.? |  |  |  |
 Peristaltic pumps/tubing. O.K.? |  |  |  |
 NOx reading reasonable? |  |  |  |
 UPS – No. of battery LED lights lit |  |  |  |
 Flow reading reasonable? |  |  |  |
 Flow monitor pressure O.K.? |  |  |  |
 All cal. gas bottle cylinder pressures > 150 psi? |  |  |  |
Boiler #1/#2 Extractive Systems and Analyzers | #1 | #2 | #1 | #2 | #1 | #2 | #1 | #2
 NOx Sample Flow   1.0 lpm |  |  |  |  |  |  |  |
 O₂ Sample Flow   0.2 lpm |  |  |  |  |  |  |  |
 CO Sample Flow   0.6 lpm |  |  |  |  |  |  |  |
 Cal Gas Flow   6.0 lpm when on |  |  |  |  |  |  |  |
 Bypass Flow   0.5 lpm |  |  |  |  |  |  |  |
 Sample Pressure   11 psi lpm |  |  |  |  |  |  |  |
 Cal gas Pressure   30 psi when on |  |  |  |  |  |  |  |
 Sample Pump O.K.? |  |  |  |  |  |  |  |
 Peristaltic pumps/tubing O.K.? |  |  |  |  |  |  |  |
 UPS – No. of battery LED lights lit |  |  |  |
  NOx reading reasonable? |  |  |  |  |  |  |  |
  CO reading reasonable? |  |  |  |  |  |  |  |
  O₂ reading reasonable? |  |  |  |  |  |  |  |
 All cal. gas bottle cylinder pressures > 150 psi? |  |  |  |
Are the CEM work spaces clean? |  |  |  |
Check the DCS for CEM alarms. Any alarms? If yes, note here and in logbook. |  |  |  |

Proactive Maintenance

Proactive maintenance identifies a monitoring problem, seeks out the root cause, and prevents the problem from reoccurring. This often requires decisive action and resources to research the problem and modify, repair, or replace components of the system. However, rather than fixing the problem, procedures might instead be instituted to manage the problem. This may lead to the additional, continual maintenance, straining the CEM technician’s time and plant resources that might be better applied elsewhere.

For proactive maintenance, a problem and its root cause must be first understood to affect a real solution. The analysis of a problem may develop into a research project, where consultation with the system vendor, or collaboration with other users of similar equipment, may be necessary. Although the project might consume more resources than budgeted or intended, its resolution may eventually reduce costs of personnel and materials associated with the monitoring system.

Corrective Maintenance (Nonroutine Maintenance or Reactive Maintenance)

Corrective maintenance is performed when the system or part of the system fails. A failure may be due to a lack of preventive maintenance, a random event, a process upset, an improper repair, or other cause. Random events such as lightning strikes or a component “burn‐out” cannot be avoided; but once understood to be a problem, steps can be taken to minimize their occurrence in the future by being proactive, as discussed above

A failure not indicated by an alarm might be uncovered during a systems inspection, while conducting routine maintenance, or it may be discovered during a performance audit. Experience, along with an implemented preventive maintenance program, should enable the CEM technician to predict failure rates of system components and replace parts before they fail, instead of running them to failure in the future. The number of system failures should decrease if the preventive maintenance schedule is changed routinely to establish component replacement dates consistent with their failure rates. See Jahnke (1994) and Jahnke (2003) and Berry (1999) for discussions of suggested routine maintenance procedures, typical CEM system problems, and possible corrective actions that can be taken.

Outside events such as process upsets or accidents are more common than one might expect – things happen. For example, a process upset may plug a sample line. As a result, no data are available during a period where emission limits might be exceeded, presenting a defensibility problem when reporting the data. Here, the problem is due to both the failure of the monitoring system to handle a process upset and the failure of the process or the unit operator to control the process. A resolution of the problem in this case may require working both with the monitoring system and process engineers.

Troubleshooting a monitoring system or analyzer problem should proceed in a detailed and systematic manner. Troubleshooting diagrams or tables are provided by most analyzer vendors in their operation and maintenance manuals to assist in finding and eliminating problems. Also, microprocessors in today's analyzers allow sequencing through series of diagnostic steps. However, as mentioned previously, detailed manuals and troubleshooting guidance for the system itself are not always provided by CEM system integrators. When troubleshooting, actions should be centered around finding clues to the root cause of the problem by checking readings or testing system components. A good technician is a good detective and needs detective skills to be efficient in his or her work. Unfortunately, when a systematic approach does not appear to be working, or an inexperienced technician is tasked with resolving the problem, the temptation to start replacing parts begins to appear as a viable option. Walking into a CEM shelter and seeing the system deconstructed on the shelter floor is never an encouraging sign. At some point, it might be better to seek assistance from another technician or call for outside help from the vendor or a consultant.

Managing Change

Maintenance for a CEM system differs from that for process analyzers because CEM system maintenance is subject to many regulatory conditions. Under 40 CFR75, any maintenance that “significantly affects the ability of the system to accurately measure or record” may trigger a recertification of the system. Maintenance activities that require a recertification are well defined for Part 75 systems in 40 CFR 75.20(b) and the Part 75 Emission Monitoring Policy Manual – Section 12. Part 60 system recertification criteria are not well defined and may be defined at the discretion of the state or local agency administrator.

The Part 75 policy manual provides a programmatic approach that reduces the ambiguity associated with recertification after conducting maintenance or completing repairs on a CEM system. Although the policy applies only to Part 75 systems, it can also be used with Part 60 systems, where it may be necessary to invoke the Part75 precedent. The policy manual distinguishes between two types of tests, namely:

The Diagnostic Test – the tests required to verify that a CEM system is operating accurately following certain preventive or corrective maintenance procedures.

The Recertification Test – the tests required to recertify a CEM system or system component following a major repair, replacement, or modification.

Diagnostic tests are conducted when the maintenance performed does not significantly affect the ability of the system to measure accurately. The maintenance may be the replacement of a filter, repair of a moisture removal system, or reconditioning of a pump. The diagnostic test itself is simply the performance test that would be conducted as part of a daily or quarterly quality assurance cycle such as calibration verification, a linearity test, or a response time test, etc. A major modification or repair to the system such as a change out of a sampling line would warrant conducting a RATA.

The recalibration of a monitoring system is a relatively minor maintenance activity. A good practice to follow is to conduct a calibration verification after an analyzer has been adjusted to verify that the system is back in control. This practice is required in Part 75. Although not required in Part 60, conducting a calibration verification after maintenance is nevertheless recommended.

Declaring Obsolescence

Maintenance may become more frequent as a monitoring system ages. A CEM system is expected to last from 10 to 20 years before replacement or upgrade, although some have been in operation for over 30 years without major modification. Typically, a monitoring system or analyzer is not declared obsolete and replaced until parts are no longer available from the vendor or monitoring requirements change. An effective maintenance program may induce some complacency with regard to upgrading a system and system components. Warning signs indicating that it may be time to either upgrade or replace the system are given in Table 15‐7.

Aging systems tend to require increasing levels of maintenance. System and analyzer components that have operated well for 10 years suddenly fail or the sampling system begins to leak from corrosion. Other problems begin – warehoused parts have deteriorated and replacement parts have become unavailable. Stockpiling parts obtained from colleagues who have since replaced their systems is a sign of desperation rather than planning. Simply, a system should be declared obsolete when the level of effort necessary to maintain it cannot be sustained.

Analyzer vendors will upgrade their products approximately every 10 years. In each cycle the analyzers improve. They incorporate fewer components; smaller, more efficient components are incorporated; and performance improves. Analyzers become more stable, less prone to maintenance, less subject to interferences, and more powerful with respect to monitoring internal parameters and data processing. Similar to replacing a car or a computer, newer analyzers or systems become more reliable by incorporating the latest advances in technology. It is understandable that the vendor at some point will no longer wish to work with its outdated products.

Another area of concern is when systems or analyzers are abandoned when a competitor purchases the original manufacturing company. Products will often be discontinued to remove competition from the new owner's product line, or a marginal sales performance may not be consistent with the company's goals.

Changes in regulations or the reductions in emissions levels may cause a monitoring system to be unable to meet mandated specifications for precision and accuracy. Measuring pollutant concentrations from 1 to 5 ppm is more difficult than measuring them from 0 to 100 ppm and may require changes in both the sampling system and the analyzer.

Logbook Documentation

Any work performed on a monitoring system should be documented for later reference and to support the defensibility of the data and the QA management program when the site is inspected by the regulatory agency. Bound ledgers have been used traditionally for this purpose; however, electronic logbooks are increasingly more common. The logbook is essentially a diary about the life of the CEM system. Annotations are typically made when routine and nonroutine maintenance is conducted. When inspections, preventive maintenance, or performance audits are conducted, annotations may refer to forms or other records, such as work order numbers issued for the activity. However, when nonroutine maintenance is performed, the logbook serves to record observations, maintenance problems, and details of corrective maintenance conducted.

When corrective maintenance becomes necessary, the logbook may be the only accessible record describing the event. Writing down what happened and what was done may avoid having someone else to repeat the troubleshooting process if the problem reoccurs in the future. Logbook documentation should be sufficient for an auditor, the management, or a new technician not familiar with the original event to understand what the problem was and what was done to achieve its resolution.

Basically, any reader of the logbook should be able to reconstruct the events described without having to ask someone for an explanation. A typical corrective maintenance logbook entry should include the following:

Date

A statement of the problem or action

A discussion of activities performed

As found and as left values

TABLE 15‐7 Warning Signs for Obsolescence

System/Equipment Obsolescence
Failure Warning Signs

Aging systems

Increasing maintenance

Lack of vendor support

Difficulty in finding spare parts

Stockpiling parts

Vendor upgrades

Upgrade replaces earlier systems

Vendor notice for discontinued parts

Service personnel not trained in previous products

Discontinued systems

Competitor purchases original company – eliminates product line

Regulations/reporting requirements change

Emissions level change

A discussion of possible causes of the problem (if possible or appropriate)

Actions suggested to prevent a reoccurrence of the problem

Signature or initials of person(s) involved

Technicians will not commonly include this level of detail into a logbook unless instructed by management to do so. Once expectations for monitoring system documentation are expressed, most technicians will comply, particularly when electronic logs are used. With electronic logs, information can be rapidly typed. Data, tables, and graphs can be pasted‐in, and the logbook information can be made more easily available to other technicians, engineers, and plant management. Although security may be a concern, there are numerous techniques available to protect both the information and access. Security concerns should not be used as an excuse for avoiding enhancements in CEM system documentation procedures.

CONTINUING OPERATION – AUDIT PROCEDURES

An audit is a review of the CEM system by a team or an individual not responsible for its day‐to‐day operation. The principal objective of an audit is to determine how well the system is working. There are two basic types of audit procedures that can be applied to continuous monitoring systems: the performance audit and the systems audit.

A performance audit is a quantitative evaluation that would be conducted by a source testing contractor, plant quality assurance personnel, or a trained agency inspector. The performance audit involves testing the system using manual reference methods, instrumental reference methods, an independent set of certified cylinder gases, or other audit materials such as calibrated filters. The performance audit requires a set of audit equipment and materials and is a “hands‐on” activity. Its purpose is to provide a quantitative assessment of problems that might affect the accuracy of the system.

A systems audit is a qualitative evaluation of the monitoring program that would normally be conducted by a state or federal agency inspector, a corporate auditor, or a consultant. Here, the operational status of the monitoring system is evaluated, personnel associated with the monitoring program are interviewed, and records and data are reviewed. This is not a “hands‐on” activity, but is instead, a comprehensive examination and evaluation of system operation and system management practices.

Performance Audits

The main idea behind the performance audit is that it provides an assessment of the monitoring system accuracy. Daily calibration drift determinations and routine maintenance do not necessarily guarantee that data will be accurate. However, an independent assessment using an appropriate auditing technique can provide an indication of data validity.

Performance audits are conducted either on a regularly scheduled basis as part of a quality assurance program or when the findings of the systems audit indicate that information of a more quantitative nature is necessary to evaluate data accuracy. Performance audits are typically applied quarterly and employ similar tests as those used for the original certification: abbreviated check procedures, correlation techniques, and alternative measurement methods. This section assumes that the CEM system has been already certified and that the first‐time issues such as system setup and stratification have already been addressed. The primary purpose of conducting the performance tests discussed here is to assess whether the system continues to meet the specifications to which it was originally certified.

Performance audits are required by regulation and are specified in the U.S. 40 CFR Part 60 and Part 75 rules. They also incorporated in the Environment Canada EPS 1/PG/7 guidelines as well as in the European Union EN 14181 requirements. For gas monitors, the U.S. EPA Part 60 Appendix F requirements specify that a performance audit be conducted at least once each quarter, using one of the following:

Cylinder Gas Audit (CGA): A challenging of the monitoring system with cylinder gas of known concentration (NIST traceable gases).

Relative Accuracy Test Audit (RATA): A repeat of the relative accuracy test procedures as defined in 40 CFR 60 Appendix B Performance Specifications (U.S. EPA 2020b).

Relative Accuracy Audit (RAA): An audit similar to the RATA, except that only three sets of measurement data (instead of nine) are taken.

Part 60 Appendix F requires that at least one of the quarterly audits be a RATA, and either the CGA or RAA can be used for the other three quarters. Appendix B of Part 75 requires that a linearity check be conducted once every quarter, even in a quarter where a RATA is performed. If excessive inaccuracies occur for two consecutive quarters, as evidenced by the audits, Appendix F requires that the CEM quality control procedures be revised. Appendix B of Part 75 requires that two RATAs be conducted every year, although the frequency can be reduced to once a year if the relative accuracy is less than 7.5%.

The quarterly audits are intended to alert the CEM system operator to problems that might be occurring with the system. Many problems can develop that may not be indicated by the day‐to‐day calibration check routines. For example, leaks, pollutant scavenging by filtered particulate matter, failed NO₂ converters, and so forth are not always identified by the daily calibration verifications. Although most monitoring systems operate well, the fact that they are operating in harsh and varying environments can lead to the development of unanticipated problems. Conducting some type of periodic, independent performance assessment is one means of detecting issues that might affect data quality. Recognition of this observation is reflected in the performance audit requirements incorporated into source emission monitoring rules.

The Cylinder Gas Audit (CGA)

The most common method of conducting a performance audit of gas monitoring systems is to challenge the system with certified audit gases different from those used in the daily calibration verification. This, and similar procedures, are called the cylinder gas audit (CGA, Part 60), linearity check (Part 75), the cylinder gas test (CGT, Environment Canada), or the quarterly gas audit (QGA) for mercury monitoring systems (Part 60). The test does provide an independent assessment of system, in the sense that it uses a separate set of certified gases, but does not necessarily assess the accuracy of the monitoring system.

The cylinder gas audit or linearity check is conducted by challenging the CEM system with audit gases that are traceable to National Institute of Standards and Technology (NIST) standard reference materials (SRMs). Sources regulated under the Part 75 program must use protocol gases that meet standards prepared by procedures G1 or G2 given in the EPA Traceability Protocol (U.S. EPA 2012). The audit gases are required to be introduced at the sampling probe and pass through all components of the sampling system.

Set‐Up Configuration

The method used to introduce the gas at the probe depends on the design of the probe and the monitoring system. Techniques for probe calibration checks (“probe cal.”) for extractive systems are illustrated in Figure 12-1a and b. For fully extractive systems, gas may be injected at the probe for either an external filter (Figure 15‐4a) or an internal filter (Figure 15‐4b) design. The cylinder gas flow rate is increased until a maximum, stable reading is obtained. Audit gas must be provided at a rate necessary to overcome the absolute static pressure of the stack gas at the probe. At this pressure, stack gas will be flushed away from the probe so that an undiluted audit gas concentration can be obtained. Excess gas is exhausted into the stack as the extractive system withdraws the sample through the probe at its normal flow rate. A probe calibration can be conducted at an external filter if a probe sheath is used. However, large volumes of gas may be necessary to flush out the stack gas. A somewhat more effective method is to flood the annulus around an internal probe filter, as shown in Figure 15‐4b. This may require less calibration gas since the space is more confined.

Figure 15‐4 Probe calibration check technique for (a) an external filter using a sheath and (b) an internal filter.

It is relatively easy to conduct a probe CGA or linearity check for a dilution probe because the inner space of the probe can be flooded with audit gas (see Figures 3-19, 3-22–3-24). Because this space is smaller than that encountered in most fully extractive systems, the volumes of audit gas required are correspondingly smaller.

The techniques just discussed have been referred to as probe vent audit techniques (Reynolds 1989). Another technique, termed the external atmospheric vent audit technique, is used when the probe system cannot be flooded with audit gas. This less complete check of the probe system can be conducted by using a three‐way valve and a rotameter as shown in Figure 15‐5. In this method, the probe system is essentially shut off and audit gas is vented through a rotameter. The sample system withdraws the audit gas, at atmospheric pressure, at the valve. Care must be exercised to supply enough gas to vent through the rotameter, otherwise ambient air will dilute the sample. If a three‐way valve is not part of the installed system, an auditor may ask the CEM system operator to disconnect the sample line at the probe and connect the audit sample line and rotameter directly to the line. This technique obviously does not check the probe and probe filter, but can assist in evaluating the integrity of the sample line. For CEM systems that pull gas through the sample line under vacuum (negative pressure), the check should not be conducted without the vented rotameter. The system will otherwise be pressurized and the audit will do little to check for leaks in the line.

Performing a cylinder gas audit on a point in‐situ analyzer is similar to conducting a probe vent audit for an extractive system. Audit gas can be used to flood the sample chamber to a pressure greater than the stack static pressure, as discussed in Chapter 6 and shown in Figure 6-3 and the probes illustrated in Figure 6-2c–f. It is possible to over‐pressurize the chamber in analyzers that incorporate a ceramic filter to prevent fouling from particulate matter. At higher pressures, the audit gas concentration will be higher than true and lead to incorrect readings. The audit gas flow rate should be increased 0.5 lpm over the manufacturer's recommended value to determine if such an effect is occurring [see Reynolds (1989) for detailed procedures].

A cylinder gas audit can also be conducted on an in‐situ path analyzer if a flow‐through gas cell is incorporated into the measurement system. Figure 15‐6 illustrates one such design.

In this single‐pass system, the measuring light beam passes through the gas cell contained in an external unit and to the detector by means of an optical fiber. Here, the flow‐through gas cell serves as a sort of “pseudo‐stack.” For flow‐through gas cells, consider again the concept of “optical depth,” where to obtain an equivalent response from the gas cell, the optical depths of the duct and the cell must be comparable:

(15‐1)left-parenthesis upper O p t i c a l d e p t h right-parenthesis Subscript c e l l Baseline equals left-parenthesis upper O p t i c a l d e p t h right-parenthesis Subscript d u c t

(15‐2)normal c Subscript c e l l Baseline times upper P a t h l e n g t h Subscript c e l l Baseline equals normal c Subscript d u c t Baseline times upper P a t h l e n g t h Subscript d u c t

Figure 15‐5 Audit method for probes that cannot be flooded. The “external atmospheric vent” technique.

Figure 15‐6 In‐situ monitoring system external flow‐through gas cell.

Cylinder gases at higher concentration are necessary to obtain an optical depth that corresponds to that of the actual duct measurement path length. For example:

If the analyzer monitors a gas concentration of 100 ppm SO₂ over a total distance of 1.0 m in a duct, the optical depth will be 100 × 1.0 = 100 ppm‐m.

If the flow‐through gas cell has an internal measurement path of 10 cm (0.1 m), a cylinder gas would have to have a concentration of 100/0.1 = 1000 ppm for equivalent optical depth.

The use of external gas cells for path in‐situ system cylinder gas tests must be considered carefully for each application. In optical absorption instruments, the molecular absorption characteristics are temperature dependent, and the cell must either be heated to the flue gas temperature or the absorption signal corrected for temperature. Also, the technique is not always applicable when the measured gas concentration is measured at percentage levels. Consider the example:

If the analyzer monitors a gas concentration of 15% CO₂ over a total distance of 1.0 m in a duct, the optical depth will be 15% × 1.0 m = 15%‐m.

If the flow‐through gas cell has an internal measurement path of 10 cm (0.1 m), a cylinder gas would have to have a concentration of 15%‐m/0.1 m = 150% for equivalent optical depth.

A concentration of 150% would require that the gas cell be pressurized. Because this is not practical and even if attempted, NIST traceability would be difficult, some other solution would be necessary, such as decreasing the measurement path, increasing the cell pathlength, or both.

With single‐pass in‐situ systems, because the stack gas is in the light path and is being measured, a flow‐through gas cell will give an incremental reading added onto the stack gas values. Data resulting from such measurements becomes difficult to interpret when the stack gas concentrations are varying rapidly. One method of avoiding this is to place a pipe through the duct, which can be closed off and flushed first with ambient air to obtain a zero baseline. The pipe can then be flushed with a high‐level certified gas. The problem here is that the pipe will generally have a relatively large volume, which will require correspondingly large volumes of calibration gas. Although feasible, this technique may be neither cost‐effective nor practical.

Another technique that has been used in single‐pass units is to block off the measurement light beam and use an auxiliary light source to send a beam through an internal audit cell. Obviously, this scheme does not check all of the normally operating active components of the system. However, it will serve to check the detector and primary electronics. In a double‐pass system, a zero mirror can be used without the use of an auxiliary light source, to reflect the light from the system light source to the detector for a check of the transceiver optics and electronics.

Performing the Audit

The concentrations of the gases used to conduct a gas audit are specified in the applicable rule. For example, a Part 60 Appendix F cylinder gas audit is conducted by challenging the CEM system with two audit gases: one having a value 20–30% of span; the other with a value 50–60% of span. In contrast, a Part 75 linearity check is conducted by challenging the system with three gases: with values 20–30%, 50–60%, and 80–100% of span (span as defined in 40 CFR 75 Appendix A §2.1.1.3). In the Environment Canada EPS 1/PG/7 guidelines, a CEM system is challenged with gases at concentration values 0–20%, 40–60%, and 80–100% of full scale. The CEM system is challenged alternately, three times with each audit gas. Sufficient time should be allowed for each injection until the concentration reading stabilizes. For integrating instruments, it may be necessary to monitor several measurement cycles to determine when the reading is stabilized. Obviously, audit readings must not be included in the facility emission averages.

The accuracy calculation for the CGA is given by

(15‐3)upper A equals StartFraction c Subscript m Baseline minus c Subscript a Baseline Over c Subscript a Baseline EndFraction times 100

where

A = CGA accuracy of the CEM analyzer (in terms of parts per million or percentages)

cm = average analyzer response during the audit

ca = certified value of the audit gas

The accuracy calculation for the Part 75 Linearity Error (LE) is calculated in the same way, except for using different symbols (LE for the accuracy, R for the certified value of the audit gas, and A the average analyzer audit response).

In an Appendix F CGA, the CEM system is “out‐of‐control” if A exceeds ±15% of the audit gas value.

In Part 75, it is out‐of‐control if LE exceeds 5.0% of the audit gas value. The out‐of‐control period begins at the time of completion of the audit. State or regional quality assurance guidelines may require other procedures (Peeler 1990). Typical variations are:

Using a zero gas in addition to two audit gases

Using an audit gas at a concentration corresponding to the emissions standard

Using an audit gas corresponding to the average stack gas concentration of the pollutant

Generating variable gas concentrations using a dilution system

Challenging the system only twice with each gas

Challenging the analyzer with audit gas at the analyzer calibration port

Variations No. 1 and No. 6 are particularly useful in troubleshooting a CEM system. It should be noted that a cylinder of zero gas may not always be necessary since, for example, an NOx audit gas reading may serve as a zero reading for an SO₂ channel. In variation 6, challenging an analyzer at its calibration port (instead of at the probe) is a simple method of checking the audit gas against the span gas used to calibrate the analyzer. If the audit gas reading obtained on the analyzer differs widely from its certified value, it may indicate that the span gas has deteriorated or its tag value is incorrect. If the probe audit results are unsatisfactory, this check may distinguish between calibration gas discrepancies and system problems.

Using different audit gas concentrations other than those specified in Appendix F (40 CFR 60) is either a matter of other regulatory requirements or technical preference [e.g. Butler (1987); Butler and Willenberg (1990)]. Using an audit gas corresponding to the average pollutant concentration readings can give additional confidence in the emission measurements, if the audit results are otherwise satisfactory.

Audit Gases

Cylinder gases used for calibrating and auditing continuous emission monitors have improved significantly over the past 20 years. In the early 1970s, it was not uncommon to find pollutant gas concentrations differing from the tag values by over 10%, even when the accuracy was stated by the producer as being between 2 and 5% of the pollutant value (note: some reactive gases still have this problem). This, of course, led to considerable uncertainty in CEM system measurements and often led to the failure of initial performance specification tests. Because accurate standards are needed in any measurement program, steps were taken by EPA to improve the quality of cylinder gases.

In 1978, the U.S. EPA published a traceability protocol that could be used to reference a prepared cylinder gas to the National Bureau of Standards [(NBS), now NIST] Standard Reference Materials (SRMs). The protocol was subsequently revised in 1983, 1993, 1997, and again in 2012 [see U.S. EPA (2012)]. Gases prepared under this protocol using procedure G1 are known as protocol gases. Due to the limited supply and high cost of SRMs, intermediate standards may also be used by the gas vendor when preparing Protocol 1 gases. An intermediate standard may be either an NIST Traceable Reference Material (NTRM) or a Gas Manufacturer's Intermediate Standard (GMIS) [see EPA (2012)]. Table 15‐8 summarizes the differences between these standards.

All of the gases are assayed using analyzers that have been calibrated with certified gases. Calibration procedures, linearity response, and adjustment procedures are strictly defined in Procedure G1. When purchasing a protocol gas, the buyer should obtain a certificate from the vendor that contains the mandated certification data (Table 15‐9).

TABLE 15‐8 Differences Among Standard and Certified Gases

SRM | Standard Reference Material | Prepared and sold by NIST
NTRM | NIST Traceable Reference Material | Prepared by the gas vendor. Referenced directly to an SRM. Nominal concentration within ± 1% of an SRM concentration. Analyzed after preparation. Analyzed again 30 days after first analysis. Two samples analyzed by independent laboratory.
GMIS | Gas Manufacturer's Intermediate Standard | Prepared by the gas vendor. Referenced to an SRM or CRM. Nominal concentration within 0.3 and 1.3 times the concentration of the SRM. Must be assayed 3 times over a three‐month period. Assays must agree to within 1.0%. Must be recertified every three months.
Protocol gas | Prepared by the gas vendor. Referenced to an SRM, CRM, or GMIS Nominal concentration between 0.3 and 1.3 times the concentration of the SRM, CRM, or GMIS. Assays must agree to within 1.5%. Reactive gases must be re‐assayed after seven days.

TABLE 15‐9 Required Documentation for Protocol Gases

No. | Documentation Required
 1. | Cylinder identification no.
 2. | Certified concentration
 3. | Balance gas in the mixture
 4. | Cylinder pressure at certification
 5. | Date of certification
 6. | Expiration date
 7. | Reference standard data (SRM no., cylinder no., etc.)
 8. | Statement that certification followed procedures according to the protocol
 9. | Analytical method used in the assay
10. | Identification of laboratory where assayed and certified
11. | Chronological record of all certifications for the standard
12. | If applicable, a statement that concentration is corrected for interferences
13. | An estimate of the total uncertainty associated with the assay of the standard

The certification applies for a maximum period of eight years for a concentration from 20 ppm to 1%, contained in aluminum or stainless‐steel cylinders. For NO in nitrogen at a concentration from 0.5 to 20 ppm contained in aluminum or stainless‐steel cylinders, the certification applies for three years. For other cylinder materials and gas mixtures, the certification period varies from one to eight years. If sufficient gas remains after its certification limit, the gas may be recertified, but the recertified value must be within 5% of the original certified value.

If the cylinder gas pressure should decrease below 150 psi, the protocol gas should not be used.

When contracting or conducting a cylinder gas audit, attention is paid to obtaining the certification information. Because the quality assurance results are intended to be ultimately traced to NIST standards, the quarterly report will establish traceability to NIST with this documentation.

Suppliers of protocol gases are required to enter the Protocol Gas Verification Program (PGVP) (U.S. EPA 2020e). In this program, gas vendors undergo periodic blind audits of their protocol gases, where the gases are analyzed by NIST. The results of these audits are published by EPA and provide a means of selecting between gas suppliers.

In Europe, the Van Swinden Laboratorium (VSL), the National Metrology Institute of the Netherlands, has a cooperative relationship with NIST and prepares gas standards that are equivalent to NIST standards (U.S. EPA 2012). Also, the International Standards Organization has prepared detailed standards for the preparation of calibration gas mixtures (ISO 2009).

The Relative Accuracy Test Audit (RATA)

As mentioned earlier, for gas monitoring systems, the cylinder gas audit is not completely independent of the monitoring system. In fact, most CEM installations can easily pass EPA‐established criteria for the gas audits and linearity tests. In most cases, the exercise is merely a comparison between the audit gases and the system span gases when the daily calibration verification is conducted at the probe in the same manner as the cylinder gas audit.

Repeating the RATA (see Chapter 11) is the ultimate audit technique, because the regulatory acceptance of the CEM system is based on the results of this test. In the United States, this is required once a year for sources regulated under Part 60 Appendix F. For sources participating in allowance trading programs, under Part 75, the RATA is required to be performed twice a year. Part 75 does provide an incentive, however, in that, if a relative accuracy of 7.5% is achieved instead of the specified 10% (for gas monitors), the RATA may be conducted only once a year. Similar incentives are provided in the Environment Canada guidelines.

For sources regulated under Appendix F of Part 60 and Part 75, the acid rain program, the RATA is repeated annuallly or semiannually. Seven‐day calibration drift tests and response time tests are not required to be repeated in either program. A CEM system is said to be “out‐of‐control” when the relative accuracy is greater than the relative accuracy specification for the parameter monitored. If the CEM system is “out‐of‐control,” corrective action must be taken and the RATA must be redone to determine if the system is again operating properly.

The Relative Accuracy Audit (RAA)

According to Part 60 Appendix F, an abbreviated RATA can be conducted by reducing the number of runs that are normally required in a relative accuracy test. Instead of performing nine runs, as is normally done, only three runs are done in the relative accuracy audit (RAA). The effect of reducing the number of runs on the statistical acceptability of the data has been discussed in detail by Jernigan (1986). Reducing the number of runs can save time, but not necessarily expense. Because much of the cost associated with a stack test or audit program is associated with travel, setup, quality assurance, and reporting, a few hours saved at the site will not save much money.

The RAA relative accuracy calculation differs from that of the RATA by the elimination of the confidence coefficient term. The contribution of the confidence coefficient to the RA is essentially compensated for by changing the “out‐of‐control” criterion from 20% in the RATA to 15% in the RAA. The RAA procedure is used only for those sources subject to the requirements of Appendix F. It is not applicable to Part 75 sources.

During the ”out‐of‐control” periods determined by an Appendix F performance audit, data may not be used for emission compliance purposes nor does the time out‐of‐control count toward system availability. These restrictions are the same as those given for excessive calibration drift. Table 15‐10 summarizes the out‐of‐control conditions for performance audits discussed in this chapter.

Alternative Quarterly Audit (Canada)

Canada has developed an alternative to the quarterly cylinder gas test for monitoring systems that do not have the ability to accept NIST audit gases; or in some cases, those that can accept them but cannot be calibrated against them. In‐situ path or point monitors, particularly those marketed by European vendors, may incorporate internal calibration gas cells; however, no NIST traceability procedures have been established for these cells. This creates difficulty in meeting quarterly audit requirements in both the United States and Canada.

To resolve this problem, Canada provides an alternative method that allows the use of portable monitors to conduct a quarterly check, called the “alternate quarterly audit” (Environment Canada 2005). Traceability to NIST SRMs can be established by first calibrating the portable monitor with protocol gases and then using the portable monitors to conduct an abbreviated RATA similar to the RAA. The test differs from the RAA by requiring six runs instead of the three runs of the U.S. EPA RAA. Also, instead of sampling for one‐half hour in each run, which is typical for a RATA, a sampling period of six minutes is allowed after the flue gas measurement made by the portable monitor has stabilized. The relative accuracy is calculated in the normal manner using Equation 11‐17, including the confidence coefficient, which the RAA method does not. The relative accuracy criteria for the method is 15% of the reference method value or 12 ppm absolute difference for gas monitors (or 0.5% O₂ or CO₂ for O₂ or CO₂ analyzers).

The U.S. EPA specifies the use of portable monitors to conduct RAAs in PS 16, the performance specification for predictive emission monitoring systems. In this case, the monitors must meet the requirements of ASTM D6522, which addresses their application to measuring NO and NO₂, CO, and O₂ from natural gas‐fired engines, combustions turbines, boilers, and process heaters (ASTM 2021a). The use of a portable monitor enables plant personnel to conduct the RAA and does not necessarily require a mobile van with the rack‐mounted equipment used by source testers. Today portable monitors are relatively inexpensive, and if operated properly, can measure accurately. The monitors are generally light weight and operate using electro‐optical sensors, electrochemical cells, or both. The cost can be further justified when the monitor is used for stratification studies, troubleshooting, or for back‐up of an installed CEM system, if it has been previously certified in a RATA.

Summary of Out‐of‐Control Criteria for Gas Monitors

If the performance limits for quarterly and semiannual/annual quality assurance performance audits cannot be achieved, the analyzer or CEM system is deemed out‐of‐control. Table 15‐10 summarizes the out‐of‐control criteria for gas monitor performance audits mandated by the principal U.S. and Canadian CEM programs.

TABLE 15‐10 Out of Control Criteria for Performance Audits in the United States and Canada

U.S. 40 CFR Part 60 App F
U.S. 40 CFR Part 75 App B
Canada EPS 1/PG/7

RATA
Out‐of‐Control Conditions
RATA
Out‐of‐Control Conditions
RATA
Out‐of‐Control Conditions

RA > 20% of RM
or
>10% of the standard (whichever is greater)
>15% of the standard for standards between 130 and 86 ng/J, or 0.30 and 0.20 lbs/10⁶ Btu
20% of the standard for standards below 86 ng/J
RA > 10% (SO₂, NOx, CO₂, O₂ monitor or SO₂/NOx diluent combination
or
>15.0 ppm for low emitters or
>0.03 lb/mmBtu (SO₂)
or
>0.02 lb/mmBtu (NOx) (0.20 lbs/10⁶ Btu)
>10% for flow monitors
or
2.0 fps for RM ≤10.0 fps
RA > 10% (SO₂, NOx, CO₂, O₂) monitor or SO₂/NOx diluent combination
or
>8.0 ppm or
>0.5% O₂ or CO₂
Bias ≤ 5% of full scale or 5 ppm avg. absolute difference

Cylinder Gas Audit
Out‐of‐Control Conditions
Linearity Error
Out‐of‐Control Conditions
Cylinder Gas Test
Out‐of‐Control Conditions

>15% of reference gas value
>5% of reference gas value
>5.0% of FS or 5.0 ppm

Abbreviated Test (RAA)
Out‐of‐Control Conditions
Abbreviated Tests
Out‐of‐Control Conditions
Alternate Quarterly Audit
Out‐of‐Control Conditions

≤15% of RM
or
≤7.5% of the emission standard
None allowed
>15% of RM or 12 ppm
>For O₂ or CO₂
>15% of RM or
0.5% O₂ or CO₂

Availability

An out‐of‐control period begins with the hour of a failed audit and ends with the hour of the completion of the same type of audit, after the monitoring system or analyzer has been repaired. During this period, any data obtained are not considered to be “quality assured” and the system is viewed as unavailable. Percent downtime is reported for CEM systems subject to 40 CFR 60 Subpart A requirements, whereas percent availability is reported for CEM systems subject to 40 CFR 75. A general percent availability calculation is given in Equation 15‐4.

(15‐4)

Here, availability is defined as the ratio (expressed as a percentage) of the CEM system operating time divided by the unit operating time, over a defined period. The defined period may be an hour, a month, a quarter, or a year, depending upon the rule. For example, in Part 60 downtime (unavailability) is calculated and reported quarterly or semiannually. It is calculated hourly for Part 75 affected sources, and annually when following the EPS 1/PG/7 guidelines.

Periods of calibration or audit may be exempt from the calculation of data availability, depending upon the rule. One method of allowing time for calibration without loss of availability is given in Part 60, which specifies that one hour out of each 24 hours may be composed of two 15 min averages instead of four, the other two 15‐minute periods being devoted to system calibration.

Curiously, there are no minimum availability (or maximum downtime) compliance requirements in the U.S. EPA rules. Under § 60.7 of Part 60, if the downtime is greater than 5% of the operating time, more data must be submitted than otherwise in the quarterly report. However, many state agencies view downtime greater than 5% as a reason to initiate a site inspection or other action. States may also incorporate availability requirements in their own rulemaking or in source operating permits.

Under Part 75, missing data substitution values are calculated based on the percent availability. In the Part 75 missing data routines, as the percent monitoring availability decreases, data substituted becomes more punitive. For example, if the availability drops below 80%, the source is required to substitute the maximum potential value for the SO₂ emission rate (lbs/hr). Data substitution at this level is rarely necessary because Part 75 sources typically attain hourly availabilities greater than 98%.

In contrast to U.S. rules, Canada mandates that availability control limits be met. Environment Canada Guidelines specify an annual availability of 95% after the first full year of operation, whereas in Alberta, a monthly availability of 90% is required.

Other Techniques

Other techniques used to conduct performance audits are specific to the parameter being monitored, such as opacity, flue gas flow rate, or particulate matter. Many of these methods have already been discussed in chapters devoted to those subjects.

Opacity Monitor Filter Audits

A quarterly calibration error test procedure is given in 40 CFR 60 Appendix F Procedure 3 §8.1 (3)(ii) for opacity monitors. This three‐point calibration error test uses an external calibration audit device and three calibrated attenuators neutral density filters. The linearity error (LE) requirement is that LE < 3% opacity computed as │d│ + │cc│ according to the calibration error procedure given in 40 CFR 60 Appendix B Performance Specification 1.

Particulate Monitor Audits

Four independent audits are given in 40 CFR 60 Appendix F Procedure 3 §10.3. As discussed in Chapter 12, these are the absolute correlation audit (ACA), sample volume audit (SVA), response correlation audit (RCA), and relative response audit (RRA) (Table 15‐11).

An ACA is required quarterly unless an applicable federal regulation or state operating permit specifies that an RRA and/or RCA is to be conducted during the year. In this case, an ACA is not conducted in a quarter in which an RRA is conducted, and neither an RRA nor an ACA is conducted in a quarter in which an RCA is conducted.

ACA > 10%

>10% of average audit value or 7.5% of applicable standard

TABLE 15‐11 Particulate Monitor (PM) Audits

Audit | Effort/Expense | Method | Frequency
ACA | Low | Three reference standards | Quarterly
SVA | Moderate | Independent volume measurement device | Quarterly
RRA | Moderate | 3 run reference method | As per rule or permit
RCA | High | 12 run reference method | As per rule or permit

SVA > 5% of average sample volume audit value (applicable only for PM monitors determined by PM concentration using a mass/volume relation)

RRA: At least two of the three monitor response values must lie within a ±25% × (Emission Limit Value) offset from the regression line.

RCA: At least 9 of the 12 monitor response values must lie within an offset from the correlation regression line of ±25% × (Emission Limit Value)

Flow Monitor Audits

Flow monitor audits are required for sources reporting emission mass rates (kg/hr, tons/year) using flow monitors subject to the rules of 40 CFR 75 or the Environment Canada Guidelines EPS 1/PG/7. The flow‐load (output) tests specified in these rules correlate the monitor values to the plant output (Megawatts [MW] or Gross Heat Rate [GHR] for electric utilities). Because the flue gas flow rate increases proportionally to load, the flow rate at a given load should remain relatively constant if the same type of fuel is burned. As discussed previously in Chapter 7 of this book, in Part 75, the flow‐to‐load ratio, Rref, is established at the time of a normal‐load RATA. Hourly flow‐to‐load ratios, Rh, are then compared to the reference ratio for each hour of the quarter for loads within ±10% of the operating load when Rh was determined.

NOx Correlations

In the electric utilities, correlations can also be made between NOx emissions and load. Part 75 Appendix E gives procedures for developing NOx‐to‐load correlations for gas and oil‐fired peaking units having a capacity factor of less than 10%. A more sophisticated correlation could be made by incorporating the flue gas oxygen concentration and operating parameters. Although Appendix E is a regulatory option, if a unit has already installed a NOx monitoring system, the development of a NOx‐to‐load correlation could serve to compare the CEM data against the correlation, either continuously or periodically, as an additional reality check.

Predictive Emission Monitoring (PEM) Systems

Correlations, such as a NOx‐to‐load correlation or a flow‐to‐load ratio, give emissions data as a predetermined function of some parameter. They essentially predict emissions in the future to correlate two sets of data, based upon some data obtained in the past; hence, they are similar to “predictive emission monitoring (PEM) systems.” Although not discussed as such, the correlations developed for particulate monitors according to Performance Specification 11 are basically PEM system models. Also, the K factors established for flow or moisture monitors are factors based upon past data, correcting present data given from the analyzer (the sensor) to give a more accurate result.

Developing correlations leads from a single sensor (e.g. a particulate monitor or flow monitor response) to the field of predictive emission monitoring systems. As has been discussed previously in Chapter 10 with regard to data acquisition systems, it is possible to correlate plant process or operational parameter data, from multiple sensors, with source test emission data to develop emissions models. Pressures, temperatures, fuel flow rates, steam flow rates, water pressure, ambient humidity, and so on may affect the emissions and can be input into a model to predict emissions. Predictive models weight the importance of each parameter to the emissions measured by a source tester, or an installed CEM system, over a range of plant operating levels.

Phenomenological models, least squares techniques, and neural net models have all been used to develop predictive emission monitoring systems. The most straightforward method is to derive an equation based on the phenomenological factors that characterize the operation of the process, or “first principals,” to calculate the emissions. A mass balance calculation is the simplest example of such a technique. However, in more complicated cases, more than one or two variables may have an effect on the emission, and the effects of these variables may not all be well understood. It may then be necessary to correct the equation, using source test data, to develop a semi‐empirical model instead.

Least squares regression and neural network techniques, for which computer software is commercially available, are more commonly applied when developing predictive emission models. In practice, it is not necessary to completely understand how the least squares or neural net modeling techniques work; but it is necessary instead to know how to use the software.

A PEM system can provide a quality assurance check on CEM system data, if the CEM system should fail or if its operation becomes inconsistent or questionable. Additionally, the PEM system could provide alternate (substitute) data during periods of CEM system downtime. If the predictive model passed the statistical evaluation criteria of 40 CFR 7 Subpart E, the PEM system data could even be used as a back‐up “monitor” for a Part 75 installed CEM system.

If a PEM system operates concurrently with an installed CEM system, data would be available to train the PEM system under a full spectrum of plant operating conditions as long the operating parameter values were documented concurrently with the CEM values. With a sufficiently robust correlation, the PEM and CEM systems could then allow the PEM system to back‐up the CEM system, or vice versa. This interplay of quality control in the CEMS–PEMS combination was previously illustrated in Chapter 10, Figure 10-4.

Various system vendors market this approach as a quality check to complement installed CEM systems. A PEM system model could also be developed by the owner of a CEM system by using commercially available software. If a CEM system is already installed, the effort of developing the model might be an interesting exercise for the engineer seeking to enhance the quality assurance program.

PEM systems can provide an option to the use of CEM systems in some applications such as gas turbines and internal combustion engines. They are best applied to sources that operate in a consistent manner. However, when fuel inputs or process operations are variable, PEM models may not be sufficiently robust to account for the variations. Using sets of past performance data to predict present data may not be valid if the data were obtained under different operating conditions. This is in contrast to CEM systems that provide measurements that are relatively independent of the process and its past history.

Emission sources subject to Part 75 can obtain approval for an alternative monitoring system such as a PEM system, if they demonstrate that the PEM system provides data that are of comparable accuracy and precision to that obtained using a CEM system, in accordance with Subpart E of 40 CFR 75. Under this rule, a minimum of 720 hours of training data are required in developing the PEM system model. The model must pass three statistical tests, a correlation test, and F‐test, and a one‐tailed t‐test for bias. After certification, the PEM system must pass a daily QA/QC test, monthly RAAs, and a semiannual or annual RATA. One approach to conducting the daily QA/QC test is to input a set of operating parameters obtained during a passed RATA, and compare the daily test PEM system outputs to the output at the time of the RATA. A significant difference between the two would indicate a problem with the system software.

For sources subject to New Source Performance Standards under 40 CFR 60, 61, or 63, PEM systems can be certified if they meet the requirements of 40 CFR 60 Appendix B Performance Specification (PS) 16. In this performance specification, the PEM system must have three or more input variables and a sensor evaluation system. The model must pass three statistical tests, as in Part 75: a correlation test, an F‐test, and a one‐tailed t‐test for bias. The PEM system must also pass a RATA for the initial certification. In contrast to Part 75, in Part 60 PS16, all sensors providing inputs into the model must be validated daily. Three quarterly RATAs using a portable monitor and one annual RATA are also required.

Many sources have successfully met the Part 75 and Part 60 PEM certification criteria and continue to meet the ongoing QA/QC requirements. The main concern with models used for reporting emissions is that the past data on which it is based may not continue to be valid for determining present emissions. Although changes caused by unit aging or sensor degeneration might be detected by the RAA and RATA performance tests and sensor validation routines, the effects of “lurking variables” can be problematical. Anyone familiar with the use of weather or stock market models is aware of the uncertainty associated with their predictions.

As with other types of models, models used to predict emissions cannot incorporate every operational scenario when it is developed. Normally, model training is conducted under a specific regimen of operating conditions that are within the emissions compliance limits of the facility. Failures in unit or control equipment operation are, in general, not incorporated into PEM system models, but it is precisely these failures that are the concern of regulatory agencies. Failures in the plant may lead to excess emissions, but it may be difficult to quantify the emissions during those failures, other than to substitute “missing data” over the failure period. Failure of a PEM system is somewhat like a failure in CEM system when it goes off‐scale or the probe plugs up during a scrubber upset. There is no real data.

In either case, this may not be a significant problem in trading programs where “missing data” can substituted and the emissions annual average is more important than short‐term data. However, in other programs, primarily those overseen by state and local agencies, the documentation of hourly data and reporting of emissions exceedance lies at the core of most enforcement programs. As a consequence, state agencies are somewhat more reluctant to consider compliance reporting using PEM systems.

CONTINUING OPERATION – SYSTEMS AUDITS/AGENCY INSPECTIONS

The purpose of the systems audit is to determine how well the system is operating and to obtain some assessment of the reported data quality, without conducting any independent performance tests. A well‐conducted systems audit will give plant management and/or the agency an indication of how the CEM program is operating and an indication of the level of confidence that can be given to the data. For a more quantitative assessment of data quality, a performance audit can follow from a systems audit or as part of a regular schedule of audit activities.

As discussed in Chapter 10, the Clean Air Markets Division (CAMD) of the U.S. EPA requires the submittal of a quarterly electronic data report that contains hourly data plus the results of daily calibration error checks and other quality control and performance data. Electronic “ad hoc” audits are conducted on these submittals, to look for suspect data, repetitive values, QA tests conducted offline, and proper coding of the data (Frushour 2019). One technique favored by CAMD is that of “control charting.” For example, hourly CO₂ emissions can be plotted for each operating quarter. A baseline for the CO₂ data for the most frequently reported load is within 30 days after the last CO₂ RATA. Control limits are then set at three times the standard deviation of the daily CO₂ concentration averages found in the baseline. Thereafter the daily CO₂ averages at that load are plotted. If seven or more consecutive daily averages are below the lower control limit, they are considered as evidence of a potential CEM extractive system leak. Similarly, flow and heat input data can be control charted. The point here is that with the volumes of data submitted in a Part 75 EDR, the data can be mined by CAMD in ad hoc audits to target facilities for conducting field audits. When data appear questionable, this targeting tool enables inspectors to focus on those sources where field audits may be necessary to check up on their CEM program management.

In Canada, an annual systems audit is required for facilities subject to the Environment Canada EPS 1/PG/7 Guidelines (Environment Canada 2005). This requirement serves as a means of assuring that Environment Canada Guidelines are being followed. Section 6.5.2 of the Guidelines states the following:

The CEM system and the QA/QC program must be evaluated by an independent inspector every 12 months ±2 month.

The inspector must review the QA/QC manual, the CEM system operation, reports, and other associated records to determine if the procedures in the QA/QC manual are being followed. The inspector must also note any changes in the system or the procedures since the last yearly evaluation and ensure that these have been included in the QA/QC manual.

The inspector must report the findings and observation to the CEM system management and the appropriate agency within 30 days after the evaluation is completed. This report may include recommendations for improvements in the CEM system or its operation.

Alberta has a similar requirement given to the Alberta Environment and Parks CEMS Code (AEP 2021).

In the United States, 40CFR 60, 63, and 75 do not require that periodic CEM systems audits be conducted. Although CEM systems audits may appear to be irrelevant in the United States, some companies schedule them routinely to assure management that their facilities are compliant with monitoring rules.

To provide an objective overview of the monitoring program when conducting a systems audit, the auditor should be independent from the day‐to‐day operation of the CEM program and performance testing of the CEM system. As a case in point, the source testing company performing the annual RATA should not be providing an auditor for an audit. Although they may be familiar with the CEM system, their objectivity with regard to evaluating the performance of the RATA would be questionable. If the audit is conducted internally, an environmental engineer from another plant, or an engineer in the same plant, not associated with the CEM program, may be able to provide a relatively objective assessment.

A CEM systems audit can also be conducted by the regulatory agency, either separately or as part of an agency source inspection. A regulatory agency compliance inspection that examines multiple aspects of plant environmental compliance often includes only a cursory inspection of the CEM system. However, to be properly reviewed, a minimum of one day should be scheduled by the agency for a CEM system inspection. In this case, the activity is viewed by most as being an agency CEM “inspection,” a somewhat more threatening term than “audit” or “evaluation.”

There are many ways a CEM systems audit can be conducted, but the depth of the audit rests primarily on two factors, (i) the experience of the auditor and (ii) the time available to conduct the review. A systems audit for one or two CEM systems can normally be conducted in one day. In facilities that have multiple systems, such as petroleum refineries, a review may take over a week.

The inspector or auditor should be familiar with the design and operation of CEM systems, in addition to being familiar with CEM system regulatory requirements applicable to the facility being inspected. A beginning auditor should at a minimum understand CEM rules and specifications. Technical experience with CEM systems will increase as more facilities are inspected. Although the first audit one conducts may be somewhat superficial, as more experience is gained, audits will become more detailed and insightful. An auditor experienced in CEM systems and auditing procedures should be able to identify issues where the monitoring program is not in compliance with monitoring requirements, but should also be able to provide recommendations for improvements to the CEM system operation or its quality assurance program.

The facility CEM system QA/QC manual is a good place to start when preparing for an audit. If possible, it should be requested for review by the auditor, prior to the audit. When on site, one of the primary goals should be to check that the procedures given in the manual are actually being implemented and are not in the manual just because the manual is supposed to have “procedures.” In a well‐managed CEM program, the QA manual should be revised at least once a year. This may be done by the plant environmental engineer a week before the audit; but this is fine, since the audit has then served its purpose to remind the plant to think about the manual and its procedures. If the manual has not been revised in years, does not reflect current procedures, describes a system or analyzers other than those installed, or otherwise lacks any indication of having been implemented, it is “open season” for the auditor. In rules requiring that a “QA manual be implemented,” which is the case for most CEM rules in the United States, a notice of violation (NOV) could, in fact, be issued for nonimplementation, depending upon the policies of the regulatory agency.

A CEM systems audit incorporates an examination of all major parts of the monitoring program. The following sections may be helpful to an agency inspector or outside auditor when conducting an audit. They could also be reviewed by the plant environmental engineer or CEM technician in preparing for the audit. Prior to the audit, the facility should have readily available or otherwise accessible CEM documentation such as logbooks, reports, inspection forms, calibration gas certificates, and other supporting information such as the quality assurance manual and operation and maintenance manuals. A typical CEM audit includes the following activities:

Entrance briefing

Site tour

Interviews/discussions

Record review

Writing the audit report

The audit should be conducted as a formal, systematic review of the status of the CEM system. It should be a defined activity and should not be conducted as an afterthought in conjunction with other business at the facility. The audit should begin with a preliminary briefing and continue with a facility tour, data gathering, discussions with plant personnel, and other evaluations. It should conclude with an exit briefing. Throughout the audit, the auditor should take notes that are sufficiently detailed to support the findings that are subsequently reported.

The CEM system quality assurance manual can be used as a guide in conducting the audit. Using the manual, the auditor can systematically go from section to section and determine if each of the quality control procedures are being followed, while asking for corroborating data documenting that the procedures are indeed performed. Documentation might include inspection sheets, logbook entries, management reports, and test reports. The greatest gaps in the quality assurance program will usually be found in documentation for preventive and corrective maintenance activities. Often, suggestions can be made for improving recordkeeping associated with these activities.

When time is available for an in‐depth review of CEM system records, recorded data in the DAHS can be cross‐checked with internal and external reports, logbook entries, calibration reports, and other performance data. The objective in such a review is to establish whether the data are defensible, that is,

to determine whether the performance data and records are consistent with the internal and external reports.

Entrance Briefing

The entrance briefing is typically a formal introduction to the facility personnel who will be involved in the audit. Those in attendance may be just the auditor, the environmental engineer and a CEM technician, or in the case of a corporate audit or agency inspection, it may include in addition, the plant manager, maintenance and operations supervisors, the planner, IT personnel, and if really serious, an attorney. The auditor should explain the purpose of the audit and present the audit schedule. Any safety instructions or security concerns not already addressed should also be discussed at this time. The entrance briefing should take less than 15–30 minutes, and should end by providing an estimated time (or date and time) for the exit briefing.

CEM System Site Tour

The tour of the CEM system installation is aimed at familiarizing the auditor with the system and its operation. All aspects of the installation, from probe to final data output should be inspected. The auditor should have a basic understanding of the system prior to the tour, obtained from an earlier review of the quality assurance manual or available records such as a monitoring plan, performance specification test reports, and excess emission reports. The plant may provide additional information prior to the audit visit or in the briefing held before the tour.

There are many items to address on the tour and checklists are often developed to assist new auditors or refresh the memory of experienced auditors. With respect to the CEM system installation tour, the checklist should provide an assessment that responds to questions suggested in the listings in the following sections. Not all of the items will be relevant to a particular CEM installation; however, the example questions and suggestions are provided to assist auditors in the development of site‐specific checklists. The U.S. EPA has developed example checklists in its Part 75 CEMS Field Audit Manual (Boze 2003). A discussion of factors that can contribute to biases in CEM system data can be found in An Operator's Guide to Eliminating Bias in CEM Systems (Jahnke 1994, 1995). Also, detailed discussions of maintenance practices can be found in Continuous Emission Monitoring (CEM) System Application and Maintenance Guide (Jahnke 2003) and Optimizing CEMS Performance Through Advanced QA/QC Practices (Berry 1999). An understanding of this material will assist the auditor in formulating his or her own questions to probe system performance and discuss possible system problems.

Care should be taken in the use of checklists. If they are too detailed with pages of questions with boxes to be filled in, the audit will begin to appear like a “scavenger hunt” and the time will be spent recording minutiae that are not particularly important to understanding how well the monitoring program is being managed or determining whether the reported data can be considered defensible.

A better approach to conducting the audit is to ask insightful questions that evoke a response. Leading questions should be avoided, but naïve questions can be useful in starting a discussion that can indicate how well facility personnel understand their responsibilities, as well as add to the auditor's own understanding of the program. Throughout the inspection, the auditor should ask for corroborating records documenting that the procedures were actually performed and performed at the frequencies specified in the manual. These records should then be reviewed in detail as part of the records review. Verbal explanations are not considered sufficient in verifying concerns that may arise during an audit. Verification can only be provided from a written or electronic record, or retrievable data. With these comments in mind, the following questions might be among those asked by an auditor or inspector during a CEM systems audit.

System Configuration

The auditor should review the design of the system from the system monitoring plan (if available) or the CEM system quality assurance manual.

Is the system configured as it was when it received initial approval?

Is the system configured as it was when it was certified for monitoring?

Are there any modifications to the system that may significantly affect its performance?

Are there any major components that have been replaced since the certification or since the last audit? Are the analyzers the same (check serial numbers)?

Is the system description in the quality assurance manual consistent with the system that is actually installed? If there are differences, check when the manual was last updated.

System Condition – Stack/Duct Installation Points

The auditor should request plant personnel to open protective coverings, instrument cabinets, etc., when feasible. The auditor should never touch any piece of apparatus or open anything.

What are the access and site conditions?

Is it difficult to access the site? Is the elevator working? Would plant maintenance personnel be willing to inspect the site once a day, once a week, never?

Is the site protected? Between liner and chimney? On the catwalk? Can maintenance personnel perform repairs at the site during inclement conditions?

Does the site show evidence of being visited?

Is the flue gas temperature higher or lower since the last audit?

Is vibration at the location higher or lower since the last audit?

What is the stack static pressure?

Are there puddles of water at the site? Does it rain on the apparatus, or does water drip onto the system?

Has fly ash sifted into piles near the installation?

What is the condition of the ambient air? Is it laden with blowing fly ash? Is the odor of SO₂ or other gases present? Are ambient pollutants affecting the CEM installation?

How does the probe or monitor installation look? Clean? Dirty? Well maintained?

Do significant quantities of dust or fly ash cover the unit?

Are bolts rusted tight on the mounting flange? Is there evidence that the probe or unit has been recently removed?

Is the unit corroded?

What is the condition of plastic or rubber components such as gaskets, heat‐traced line protective coverings, hoses, electrical cables, and so on?

How does the probe itself look? (If possible, look at the probe through another port)

Is agglomerated, sticky particulate matter adhering to the probe?

Is the probe or flow monitor probe sagging?

Is the probe oscillating with the stack flow?

What is the condition of stack‐mounted instrumentation?

For blowers (in‐situ gas monitors or opacity monitors), are the filters clean? Is a supply of air being provided to the windows?

For opacity monitors or other in‐situ monitors, what is the status of the following:

Alignment – check from the bull's eye sight or monitor panel display

Condition of purge air hoses (cracked, loose)

Condition of purge air motor (motor noise, vibration)

Condition of purge air filter system

Condition of electrical cables

Status of shuttering system. Are any protective shutters tripped?

What is the status of warning lights or operation indicators at the site?

For meters at the site, record meter values and note times to correlate the information with previous records or data recorded in the control room.

Record any pressure gauge, vacuum gauge, temperature, or flow readings for meters located at the stack or duct location.

For dilution‐extractive systems, inquire about the following:

How often is the probe removed and inspected?

What is the frequency of particulate filter replacement?

Has the critical orifice ever plugged? If yes, what was done to prevent a future occurrence?

What else can be observed? Is trash strewn about the site? Are tools, instrument manuals, source test apparatus, at the site?

System Condition – Umbilical Lines and Electrical Cable

The auditor should note the following when walking from the probe stack/duct installation to the CEM system analyzer shelter or CEM system room:

Is there a minimum slope of 5° from the probe to conditioning system?

Are there any loops or kinks in the umbilical line?

Does the umbilical line coil back on itself or overlap itself on another umbilical at any point?

Are there any unheated sections (e.g. where two umbilicals are spliced together, or just after the probe assembly, or just before the conditioning system)?

Are electrical cables properly routed and protected?

Are the cables located near or bundled with power lines, electric motors, or equipment generating strong electromagnetic fields?

For both heated and unheated umbilical lines, what is the condition of the line from the port to the conditioning system? Is it corroded, brittle, or dirty? Has it been damaged, spliced, or otherwise repaired?

Is the umbilical line well supported from the stack to the shelter? Are plastic tie wraps used? If so, has the plastic deteriorated. Are metal support clamps corroded or missing?

If the umbilical line is heated, is it warm to the touch?

Calibration and Audit Gases

Have any gas cylinders expired? The auditor should record cylinder number and tag information – ppm or % values, type of certification, gas vendor, date of analysis for several cylinders (do not do them all). (Note: this activity may be considered unnecessary because most gas cylinders do not expire until eight years from their certification. However, it is still worth doing for a sampling of cylinders to see if the cylinder gas certifications are available.)

What are the regulator pressures for each cylinder? What are the tank pressure and supply pressure?

Are the regulators corroded? Are proper fittings used for acid gases?

What is the condition of the gas supply lines and fittings? Are the fittings damaged or corroded?

Are the gas cylinders protected from the weather? Are they contained within a cabinet? If not, is there an overhang to protect them from the rain? In colder climates, is the cabinet heated during the winter or other steps taken to prevent stratification in the cylinders (particularly for SO₂)?

Auditing in the CEM Shelter

The CEM system installation tour will usually end (or begin) in the CEM room or CEM shelter. This room generally contains the sample conditioning system (for some extractive systems), analyzer control panels, and/or analyzers. When scheduling the audit activities, the visit to the CEM shelter should coincide with the start of the daily calibration verification for the gas analyzers. Flows through the calibration gas rotameters, instrument responses to the zero and span gases, as well as the DAS output can be observed to verify the proper operation of the system. This can also be done by asking for a manual calibration verification; however, this may be inconvenient for the technician and may result in the loss of some availability.

The auditor should determine the proper methods of the system's operation from either the manufacturer's written instructions, or preferably, the standard operating procedures provided in the CEM quality assurance manual. The best time for the plant CEM system technician to explain entries in the instrument maintenance log and describe the routine system maintenance procedures is while in the shelter. Maintenance activities related by the technician can be cross‐checked in the maintenance log and quality assurance manual at this time to determine if established procedures are being followed. For the part of the audit conducted in the CEM system shelter, the following questions might be asked to aid in understanding the design and operation of the system:

System Operational Procedures

Who has been assigned responsibility for the CEM system operation and maintenance? Ask questions such as the following?

How many hours a week are spent operating and maintaining the system?

What has given the most trouble since the last audit?

Has the CEM system vendor in emergency service response been satisfactory? Are spare parts readily available?

Can a daily calibration verification be conducted? The auditor should either observe the daily automatic system calibration verification or ask the CEM technician to perform a manual verification. (It should not be requested that the system be “calibrated.” This would be asking to make adjustments to the system, which is not necessary unless daily drift adjustment criteria are exceeded). During the verification a zero or low‐level gas will be introduced into the system, followed by injection of an upscale calibration (span) gas. While the verification is proceeding, the auditor writes in the audit notebook the response of each analyzer being checked. The values will trend down or trend up depending on whether a zero or span value is being checked. The final value should be written down before the system is switched to the next gas. Writing down the trending values helps to keep focused on the verification, rather than being distracted by other issues. The following questions should be addressed during the process:

How familiar is the technician with automatic or manual verification procedures?

How is it determined whether the system is or is not in calibration?

How does the technician annotate the data (in a logbook, from a DAHS printout, or not at all)?

Are quality control charts used? Is the technician familiar with the use of quality control charts?

The auditor should record the calibration verification results and obtain copies of the DAHS calibration verification report, if possible.

Either at this point or when more time is available, the auditor should cross‐check observed procedures with written procedures given in the plant CEM system quality assurance manual.

System Condition – Conditioning System (for Extractive Systems)

Either before the calibration verification has been conducted, or after, the following questions should be asked while in the CEM shelter:

Through what system components does the flue gas pass from the end of the umbilical line to the analyzers (chiller, filter, etc.)? In particular, note the following:

Does sample gas enter the conditioning system under pressure or under vacuum?

What is the technique used for removing water from the sample gas? How is condensed water removed from the conditioning system? If a peristaltic pump is used, when was the pump tubing last replaced?

What is the probability of pollutant gas being absorbed in the condensed water? Locate the drain pipe for the condensed water. If the pipe drains to the outside, can the outlet freeze up during the winter?

Does the system incorporate a moisture breakthrough sensor? Does it work?

Can condensed liquid be seen in any of the Teflon lines?

Is the tubing neatly arranged or haphazard? Are there indications of ad hoc plumbing changes?

Are the fittings, valves, and so forth corroded or leaking?

How often is the fine particulate filter changed? When was it last replaced? Is ita clean or dirty?

What is the condition of the sample pumps? Are they corroded, noisy, leaking? When were the diaphragms and bearings last replaced? (Verify in the maintenance log.)

Note system gas flow (rotameter) readings, pressure, and vacuum readings. Are they consistent with values on the plant daily/weekly inspection sheet or the values specified in the quality assurance manual?

Is a manifold used for gas distribution to different analyzers?

Where does sample gas exhaust from the system?

For dilution‐extractive systems:

When were the scrubbing materials last replaced in the air clean‐up system? Do preventive maintenance procedures for this part of the system exist?

What is the value of the dilution ratio?

What are the readings on the pressure and vacuum gauges on the dilution system control panel? Are they consistent with values on the plant daily/weekly inspection sheet or the values specified in the quality assurance manual?

How stable is the dilution air pressure? Does the operator know?

Is the dilution system compensated for stack pressure, temperature, or flue gas or calibration/audit gas molecular weight effects? If so, how is the correction performed? (Determine the equation that is used – is it a theoretical or empirical equation?)

Is the stack total pressure monitored to compensate for pressure effects?

System Condition – Analyzer Control Panels/Analyzers

What is the status of the control panel lights/indicators, alarms, etc. for each analyzer?

The auditor should record instrument readings exhibited by each analyzer during the visit to the shelter, such as the current concentration, opacity, or flow readings, in addition to the time the reading was obtained. These may be useful later when examining the DAS output.

Any alarms present at the time of the audit should be questioned in depth by the auditor. Because most audits are announced, it would be expected that any system or analyzer problems would have been resolved before the audit. The occurrence of an alarm during an audit would consequently receive special attention from an auditor.

For opacity monitors, what is the value of the stack exit correlation factor value and how is it set in the monitor? Is the nominal value of the filter been corrected by this factor? (See Chapter 9.) Other questions following may be asked:

Was the flange‐to‐flange distance used to determine the monitor path length? (The inner stack diameter should be used.)

How was the stack exit diameter determined?

Was a single‐pass value or double‐pass value used for the opacity monitor path length? (Which one is used depends on the manufacturer.)

What is the value of the internal span filter value? The auditor should subsequently look up the specified value in the appropriate regulation, and determine if a filter with the correct value has been installed.

What are the values of the audit jig filters and when were they last certified?

When was the last clear path zero adjustment conducted?

For flow monitors, what is the current value of the K factor(s) and when was it last changed? What was the K factor value in the previous year?

For moisture monitors, what is the current value of the K factor(s) (if any) and when was it last changed? What was the K factor value in the previous year?

Unit Operator(s) Interview

At some time during the audit, unit operators should be interviewed with respect to their CEM responsibilities. Such interviews tend to be awkward because operators often view outside auditors with some suspicion. It is recommended that the plant environmental engineer first inform the operators of the impending interview and explain the purpose of the audit. If a standard operating procedure for the CEM system has been included in the CEM QA/QC manual, the operator should be asked to review it before the interview. After a formal introduction by the environmental engineer, the auditor should ask the following questions:

When an emissions limit is exceeded, what action is taken to reduce emissions to within regulatory limits?

Who is informed when an emission limit is exceeded?

What action is taken when a daily calibration drift/error limit has been exceeded?

Who is informed when a daily calibration drift/error limit has been exceeded during the work week? During the weekend or on holidays?

What action is taken when a CEM alarm occurs?

Who is informed when a CEM alarm occurs during the work week? During the weekend or on holidays? Note: CEM technicians are the first to complain when an operator does not inform them of a CEM problem occurring during the weekend.

Are exceedances, drift alarms, or maintenance alarms documented in either the operations log or alarm log (hard copy or electronic)? If CEM alarms are documented, the auditor should at this point select one or several cases identified from the CEM logbook, where a CEM system malfunction led to an alarm. The operations log should then be examined to see if the CEM malfunction alarm was indeed documented by the operations staff.

For plants with several units, at least two operators should be interviewed to gain some perspective as to how well they have been trained with regard to their CEM responsibilities. The interviews should take no more than 10–15 minutes. Although it may be viewed that such interviews are beyond the scope of a CEM audit, the unit operators occupy an essential role in the CEM quality assurance program. Their understanding or lack of understanding of that role can indicate to the auditor how well the program is managed.

Spare Parts Inventory

To relieve some of the tension of an audit, an inventory of spare parts can be an interesting and useful exercise. 40 CFR 60 Appendix F § 3requires maintaining a spare parts inventory as part of the preventive maintenance procedures. An audit of the inventory can be useful in determining the capability of the plant to maintain CEM system availability by replacing parts and supplies in a timely manner.

The simplest way to conduct the review is by selecting ten parts from the spare parts list, either at random or by purposely choosing items that require frequent replacement. The spare parts listing may be included in the CEM QA/QC manual, but more commonly is found on the warehouse computer as part of the spare parts inventory. The auditor should ask the warehouse manager to locate each item on the listing, and write down the part's location, the maximum and minimum stocking numbers, and the current number on hand. The task is then merely to find the parts and see if the number found agrees with the number given in the computer inventory.

Deficiencies in inventory management can surprisingly be found by taking a relatively small random sample of the parts. If a part cannot be found, or if only one part is found but six are listed in the inventory, questions are raised that follow with recommendations for improvement.

Review of Records and Data

Records and previous data should be reviewed in a location that is free from interruptions and is relatively comfortable. Several hours should be devoted to this activity. Depending on the complexity of the CEM installation and on the skill and patience of the auditor, the review may take longer. A thorough review of a facility having multiple systems, such as a petroleum refinery may take several days or possibly several weeks. Both internal records, such as logbooks and inspection sheets, and external records, such as RATA and emission reports submitted to the agency, should be reviewed. If the inspection is conducted by a state or federal agency, the submitted RATA and emission reports should be reviewed before coming to the site. Any questions regarding the report can be included in the discussions held during the audit.

Internal Records

Internal records might include inspection sheets, logbook entries, management reports, or test reports. This is where the auditor will find the greatest gaps in the quality assurance program and where suggestions can usually be made for improving documentation regarding the operation and maintenance of the monitoring system. The following records should be available for review:

Previous systems audit report

Logbooks

Forms: Calibration verification, Preventive maintenance, Corrective maintenance

Work orders and PMs

Archived data

Previous Systems Audit Report

If a CEM systems audit or agency inspection was conducted in the previous year, the auditor should request to see the audit report. For any findings or recommendations, the auditor should inquire how the findings were resolved and if the recommendations were followed. Failure of a facility to address issues noted in previous audits or inspections may indicate that the CEM quality assurance program is not being taken seriously and that significant problems exist in the management of the monitoring program.

Logbooks

The CEM system logbooks should be carefully reviewed for corrective maintenance activities, parts replacements, and unusual occurrences. For gas monitoring systems, gas cylinders change‐out dates, and entries for new gas concentrations should be noted. For opacity monitors, the frequency of blower filter changes, the frequency of window cleaning and lamp replacement, and linearity tests using the audit jig should be documented. Recurring failures should be noted.

At a minimum, entries made over the past three months, or if time is available, entries made since the last audit should be reviewed. The following should especially be noted:

Are logbook entries consistent with those found on the daily inspection forms, maintenance requests, or work orders?

Are logbook comments or notes on the inspection forms rudimentary or do they provide a discussion of system problems and actions taken to resolve the problems? Can the CEM technician explain what happened when CEM system problems occurred? Is the explanation consistent with the logbook entries? Or are the logbook entries incomplete and has the technician forgotten what happened or what was done to resolve the problem?

Are there any discussions in the logbook regarding what caused problems and what could be done to prevent them from reoccurring (i.e. was a “root‐cause” analysis conducted)?*¹

The auditor can use logbook entries as keys to evaluating data and other documentation. For example, if the CEM system was malfunctioning for 16 hours, the following questions could be asked:

Was the downtime reflected in the monthly or quarterly report?

Were the reasons for the downtime given in the report consistent with the logbook entries?

If a missing data algorithm was used, is the missing data procedure given in the QA manual? Are the substituted data flagged as substituted data?

Do the rejected data remain in the database and are they flagged as non‐quality‐assured data?

Is reference made to the downtime period in the daily inspection forms?

Did the unit operator report the CEM system problem? Did the unit operator enter an alarm in the operations log or alarm report? (Ask the Unit operator.)

Forms – Calibration Verification, Inspection, Preventive Maintenance, Corrective Maintenance

Forms are typically single‐page check sheets that are assembled in three‐ring binders found in the CEM shelter, instrument shop, or environmental engineer's office. The forms should be reviewed for completeness and consistency with system logbooks. Forms are more useful if parameter data are entered, rather than checked. If meter or gauge values are entered, erratic values or upward or downward trends from the parameter values expected should be noted. If a form is to be completed weekly, the auditor should count to see whether 52 forms were completed over the past year. A CEM technician might be surprised that someone should actually be so detailed; however, if forms for only 40 out of 52 weeks were found, the next audit will generally find improvements in record keeping.

Counting the number of forms is one way of checking whether procedures in the CEM quality assurance manual have been implemented. If it is commented that there are too many forms or that they have to be filled out too frequently, it should be noted that the quality assurance manual can always be revised, if the quality assurance objectives can be still attained.

Work Orders and PMs

Many plants use work orders to manage the maintenance activities of technicians. In this type of program, a planner will develop preventive maintenance (PM) procedures, which are then called out on work orders issued at the appropriate maintenance frequencies.†² In some cases, the work order will only include the PM identification number; in others, the work order will include the number and include a list of the activities that are to be performed. After the work has been completed, the technician signs the work order and returns it either to a supervisor or the office that manages facility work orders.

Completing a work order form might entail commenting on the work performed. The same type of information that might be put into a logbook or maintenance form may instead be entered into the work order. However, the use of work orders becomes problematical when they are the only means of documentation for CEM system maintenance. After a completed work order is submitted, the information is often difficult to retrieve unless the technician makes a copy of the completed work order and retains it in his or her own files. Finding a specific work order, much less attempting to review work orders to assure that all maintenance procedures were performed over an audit period can be a daunting task for the auditor. They somehow seem to disappear in the plant information management system and take too much time to retrieve relative to the time scheduled for the audit.

Archived Data

Archived data from the DAHS database can also be reviewed but may require assistance from someone who is familiar with the DAHS software. If time is available, it is recommended that the data record for the past 30 days or over the period in which any excess emissions or missing data were reported be reviewed. Check the zero and span verification values obtained closest to the time of any exceedances. Note if any annotations in the logbook are reflected in the database. When reviewing the data record, also be observant for the following:

Missing data

Unusually noisy or “flat” data

Inconsistent trends in readings

Flags for monitor and source downtime

Flags for exceedances

Other fault or warning codes (identify)

The U.S. EPA requires that a source retain data records for a period of two years. Inquire how the data are stored and how often the CEM system data are backed up.

Other Records

Other records, such as reports of quarterly internal quality assurance audits, performance audits, off‐stack zero checks, or repeats of calibration error or drift tests, may also be retained. This documentation should be available for review when logbook entries or corrective maintenance issues might require a more detailed examination.

External Reports

The records review should examine reports submitted to the regulatory agency. If the CEM program is subject to the requirements of 40 CFR 60, the following reports should be reviewed, as applicable:

Quarterly cylinder gas audit reports

Opacity monitor quarterly audit reports

Quarterly/semiannual excess emission reports (as per 40 CFR 60.7)

RATA reports

Monthly, quarterly, and/or annual reports as required by state permit

Under Part 75, the electronic data reports (EDRs) are sent to the EPA Clean Air Markets Division and are reviewed by the agency. Reports are not accepted by EPA if there are deficiencies, so there is little point for the auditor to review them during an on‐site visit. However, other information submitted to the division should be examined. As applicable, reports such as those following, should be reviewed:

Quarterly linearity test reports

RATA reports

Quarterly flow monitor flow‐to‐load ratio test reports

Annual span/range evaluation report

Flow monitor K factor test reports

Part 75 Appendix D quarterly fuel flow monitor accuracy tests and primary element inspections

Part 75 Appendix D fuel flow to load testing for fuel flow monitors (as applicable)

Part 75 Appendix E NOx emission rate/load correlation test report

In Canada, for sources subject to the Environment Canada EPS 1/PG/7 guidelines and/or Provincial requirements, the following reports should be reviewed.

Quarterly cylinder gas test reports/alternate quarterly audit report

Daily drift quality control charts for each analyzer

RATA/bias test reports

Quarterly stack gas flow test report

Availability report

Provincial monthly, quarterly, or annual reports

Whether in the United States or Canada, the reports should be reviewed primarily to determine if the CEM systems were in compliance with the applicable rule over the audit period. Failure to meet an availability criterion, a failed linearity test, a failed RATA, or other failure where the plant is not in compliance with the monitoring rule is regarded as a “finding” and is identified as such in the audit report. Results of performance tests such as linearity and relative accuracy should be summarized in the audit report to show that the auditor has looked at the reports to verify the compliance status of the facility.

RATA reports, especially, should be reviewed for accuracy and completeness. The auditor should spot‐check the calculations starting from the raw data, which should be included in the report. For a RATA report, as a minimum, the relative accuracy should be calculated from the mean difference │d│, confidence coefficient │cc│, and average reference method value ModifyingAbove upper R upper M With bar. This simple exercise will give some feel for the data and may uncover calculation and rounding errors.

Performance audit reports should also be examined for supporting quality assurance data. Pitot tube and dry gas meter calibration certificates should be included in the reports, as well as copies of cylinder gas certificates for gases used in linearity tests or used to calibrate reference method analyzers.

RATA reports should include a description of the monitoring system and analyzers used to conduct the test reference methods. A generic diagram of the source tester’s mobile van is not adequate in this respect because a knowledge the type of system (cool‐dry, dilution, etc.) used may be important in evaluating the report.

The Exit Briefing

Facility personnel will have a genuine concern about what an auditor will find during the course of an audit. For this reason, an exit briefing is necessary to discuss preliminary audit findings or recommendations. Those attending the briefing will primarily consist of those who attended the entrance briefing.

Discussed at the meeting will be issues that will be included in the audit report, so that if the auditor has misperceived an issue, it can be clarified or re‐examined. It is useful to separate audit issues into “findings” and “recommendations,” where “findings” are issues where the facility is not in compliance with regulatory requirements, and “recommendations,” which, if addressed, will lead to improvements in the monitoring program. As much as possible, any findings or recommendations identified during the audit should be addressed at the meeting, rather than appearing by surprise in the audit report.

The exit briefing may last from a half an hour to an hour, depending upon the interest and concern of the attendees. The briefing ends by providing a date when the audit report is expected to be submitted.

The Audit Report

The audit report organizes and coordinates in a usable manner the information gathered during the audit. It is the compilation of factual information and professional judgment resulting from the audit. Information in the report must be accurate, relevant, complete, objective, and clear. The report also serves to record the procedures used in gathering the data and gives factual observations and evaluations from the audit. It is imperative that the report be clear and concise. A discussion of general topics should be avoided and all compliance issues should be directly linked to regulatory requirements. All problems discussed in the report should include supporting data or other information. Hearsay without verification should never be included in an audit report. Also, for consultants conducting audits, issues should not be avoided for fear of losing a client; for in‐house auditors, issues should not be avoided for fear of management reprisal.

An agency inspection report may focus on the compliance status of the facility and how well the quality assurance plan is being implemented, whereas an independent outside auditor may also be tasked with providing recommendations for the improvement of the system and/or the management program. In this case, the recommendations for improvement constitute an important part of the report. An audit report may have few noncompliance findings, but may have half a dozen or more recommendations depending upon the maturity of the program. An example outline for an audit report is given in Table 15‐12.

The Quality Assurance Cycle

Most problems noted in CEM system audits are associated more with program management problems rather than with inadequate equipment. Failure to maintain equipment, failure to document maintenance activities, or failure to pass performance audits are ultimately a failure of the quality assurance program itself. The adequacy of a quality assurance program can be evaluated by conducting audits, both performance audits and systems audits. By noting failures or problems through the audits, the quality assurance program can subsequently be improved. Standard operating procedures can be revised, management changes can be made, new equipment can be purchased, new procedures can be added, or training can be conducted. After program improvements are made, the QA/QC manual is revised and then re‐implemented. A quality assurance program develops and improves by going through a cycle of planning, implementation, assessment, and corrective action (Figure 15‐7).

TABLE 15‐12 Example Audit Report Table of Contents

Introduction

Audit activities

Observations and notes

Unit 1 CEM system inspection

Unit 2 CEM system inspection

Panel operator interviews

Spare parts review

Records review

Quality control chart review: tolerance and out‐of‐control limit exceedances

Inspection forms/preventive and corrective maintenance activity review

Logbook review

Semi‐annual relative accuracy and bias test report review

Relative accuracy test audit report review

CEM system and analyzer availability review

QA/QC plan and manual review

Review of response to previous CEM system annual evaluation reports

Summary and recommendations

Audit observations and discussion

Exception findings

Recommendations

Figure 15‐7 The quality assurance cycle.

It is important to remember, that by applying the management and quality control procedures discussed above, the purpose of the program is to assure that the quality assurance objectives are met. The objectives again, are for

Representativeness

Accuracy

Precision

Availability

Comparability

If the objectives are not being met, the quality assurance cycle of planning, implementing, assessment, and corrective action needs to be instituted. If the objectives are being met, but it is viewed that the quality control procedures have become onerous, making work and reducing efficiency, they can always be changed, provided the objectives are still reached after the change.

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Notes

1 Note: such an analysis should be encouraged and recommended in the audit report, if the practice is not followed by the CEM system technicians.

2 Note: PM procedures are sometimes included in the CEM QA manual as standard operating procedures, but more often are only accessible from the plant computer.

APPENDIX A
UNITS OF THE STANDARD AND F FACTORS

The form in which emissions standards are expressed can dictate the choice of analyzers or the type of CEM system that is purchased. These forms are given implicitly in the emissions limits that an overall industry or specific facility must meet. For example, for waste incineration, emissions limits are usually expressed in parts per million, corrected for dilution to a specified O₂ or CO₂ concentration. Electric utilities, however, are required to report emissions in terms of mass per heat input (nanograms per joule [ng/J]) or pounds per million British thermal units (lb/mmBtu) and/or in terms of a pollutant mass rate (kilograms per hour, pounds per hour). The form of the emission standard, as well as the types of analyzers necessary to calculate emissions in the units of the standard, will affect the uncertainty of the reported emissions.

For example, using an Fc factor to report emissions in lb/mmBtu (ng/J), in a dilution‐extractive system, the effects of pressure and temperature on the dilution ratio will cancel. However, if an Fd factor is used to report emissions in lb/mmBtu (ng/J), they will not cancel and remedies such as those discussed in Chapter 3 may be necessary.

As another example, reporting pollutant mass emission rates in lbs/hr (kg/hr) or tons/yr (tonnes/yr), the overall uncertainty of the reported data is dependent upon both the pollutant concentration measurement and the flue gas flow measurement. Here, the accuracy of the flow measurement is as important as the gas concentration measurement, a reality that has not always been appreciated. Factors affecting this measurement have been discussed in detail in Chapter 6.

This appendix reviews the types of units in which emissions standards are expressed and the equations applied to emissions data for demonstrating compliance to those standards. See also Aldina and Jahnke (1979) and U.S. EPA (2013). Typical emissions standards are given in Table A‐1.

CONCENTRATION‐BASED STANDARDS

Concentration‐based standards are relatively simple and require the installation of a pollutant analyzer, with perhaps ancillary measurements of moisture pressure, temperature, and moisture content if the measurements are to be reported under dry, standard conditions. In flue gases, pollutant gas concentrations are diluted, due to the necessary use of excess air for proper combustion and/or air in leakage through a preheater or other ductwork.

A typical concentration‐based standard requires that emissions be reported in parts per million, on a dry basis corrected to 12% CO₂ or 6% O₂. However, the CO₂ or O₂ value to which the concentration is corrected can vary, depending upon the rule or type of emission source, and is defined by regulation. As long as the same correction equation is used by sources in a given source category, data will be comparable among them and the emissions standard will be uniform. To report emissions on this basis, either a CO₂ or an O₂ analyzer would be required. The terms “dry basis” and “wet basis” are important and will be a major factor in the design of a CEM system that provides data in “units of the standard.”

TABLE A‐1 Typical Emission Standards

Type of Standard | Example Units
Concentration based | ppm., ppb, mg/m³, μg/m³, %
Pollutant mass rate | lbs/hr, kg/hr, tons/yr, tonnes/yr
Process emissions weight rate | lbs/ton product, kg/tonne product
Emission rate (thermal) | ng/J, lb/mmBtu

The Basic Concentration Measurements (ppm, Percent)

Most pollutant gas analyzers, such as SO₂, NOx, or HCl, will measure in units of part per million by volume (ppmv). Others such as the diluent O₂ and CO₂ analyzer and opacity monitors measure in percent (%). On the other hand, particulate matter emission limits are expressed in mg/m³ and mercury emissions in units of μg/m³.

A part per million measurement is a volume‐to‐volume measurement independent of temperature and pressure. A mass per volume measurement (e.g. μ/m³) is dependent upon temperature and pressure, but is typically expressed at a set of standard conditions, where EPA standard conditions are 20 °C and 1 atmosphere (29.92 mm Hg, 101.325 kPa). A conversion can be made between the two by using the following expression:

(A‐1a)

(A‐1b)

For example, for SO₂, with a MW of 64, at atmospheric pressure and Tstd = 298.16, concentrations can be converted as follows:

ppm SO₂ = 375.86 μ/m³

μ/m³ SO₂ = 0.00266 ppm

ng/m³ SO₂ = 2.66 ppm

Correcting Concentration Measurements to a Dry Basis

To report on a dry basis, either a dry‐basis extractive system could be installed or a wet‐basis system with a moisture analyzer could satisfy the reporting requirement. In some cases, a wet‐basis system without a moisture analyzer can be used if the H₂O content is allowed to be assumed or approximated. The moisture correction is given as

(A‐2)c Subscript d Baseline equals StartFraction c Subscript w Baseline Over left-parenthesis 1 minus upper B Subscript w s Baseline right-parenthesis EndFraction

where

c = concentration

Bws = moisture content (fractional basis)

d = subscript for “dry”

w = subscript for “wet”

When an assumed value for Bws is allowed, it may be the moisture value obtained during a RATA or performance test. Alternatively, when considering the day‐to‐day variation in the moisture content, but yet to assure compliance with emission standards, the highest value of Bws obtained during the test or a series of test conducted over a specified period will only be allowed.

Correcting Concentration Measurements to Standard Conditions

Gas concentration will be measured at stack temperature for in‐situ systems, or at the cell temperature of either a hot‐wet or cool‐dry extractive system. These concentrations can be corrected to EPA standard conditions by the following expression derived from the ideal gas law:

(A‐3)

where

cstd = gas concentration – corrected to standard conditions

ca = gas concentration – measured under actual conditions (stack or cell)

Ta = stack (flue) gas temperature in absolute units (K, R)

Tstd = standard temperature in absolute units (293.2 K. 527.4 R)

Pa = stack pressure (absolute; mmHg, kPa)

Pstd = standard pressure (29.92 mm Hg, 101.325 kPa)

a = subscript for “actual”

EPA standard conditions for temperature are 20 °C (68 °F) and one atmosphere (29.92 mmHg or 101.325 kPa). Other jurisdictions may have different standard conditions for temperature (25 or 0 °C).

CO₂ Correction (Corrected to 12% CO₂)

Here the concentration is corrected to a value corresponding to the flue gas having a CO₂ concentration of 12%. The correction equation is as follows:

(A‐4)

The monitoring system can measure on either a wet or a dry basis as long as both the pollutant and CO₂ concentration are measured on the same basis. A regulatory agency could specify that the correction be made to some other concentration, other than 12.

O₂ Correction (Corrected to 6% O₂)

Some regulations, such as those for pulp and paper mills, require that emissions be reported on a dry basis corrected to 6% O₂. The expression for this correction is given in Equation A‐5.

(A‐5)

where x% is the percent correction and 20.9 is the oxygen percentage in ambient air. Again, the value of 6% is given as an example, and is defined by regulation. If the oxygen concentration is measured on a wet basis, it must first be corrected to a dry basis before being substituted into the formula.

Excess Air Correction

Excess air is the air above that needed for theoretical, stoichiometric combustion. Most combustion source cannot operate stoichiometrically and need more air for complete combustion. Fuel in a combustion zone of a boiler will deplete the immediate region of oxygen and new fuel entering the region will lack enough oxygen to burn completely, hence the need for excess air. A value of 50% excess air has been chosen as a reference in some standards since at one time many boilers operated at this condition; however that number has been significantly reduced in today's boilers. When burning fossil fuels using 50% excess, the %CO₂ in the combustion products will be around 12% and the %O₂ around 6%.

(A‐6)

where %E is the percentage of excess air, which is calculated as

(A‐7)

The percentage of CO is usually negligible, so this calculation would require a dry oxygen measurement or wet oxygen measurement corrected to a dry basis.

POLLUTANT MASS RATE STANDARDS

Mass rate standards express emissions in terms of kilograms or pounds per hour or year and thus provide a direct determination of the amount of pollutant emitted into the atmosphere over a given period of time. For regulatory control purposes and ambient air modeling exercises, this information is more useful for the emission data expressed in concentration units. Discussed also in Chapter 6 with respect to flow monitors, the pollutant mass rate (pmrs) is expressed as follows:

(A‐8)p m r Subscript s Baseline equals c Subscript w Baseline upper Q Subscript w Baseline equals c Subscript d Baseline upper Q Subscript d

where

pmrs = pollutant mass rate (kg/hr, lb/hr, tons/year, tonnes/yr)

Qw = wet‐basis stack (flue) gas volumetric flow rate (ft³/hr, m³/hr)

Qs = dry‐basis volumetric flow rate corrected to standard conditions (ft³/hr, m³/hr)

As = area of the stack cross section at the measurement location (ft³, m³)

vs = stack gas velocity at the measurement location where As is determined, always measured on a wet basis (f/s, m/s, ft/hr, m/hr)

To perform this calculation, a wet‐basis pollutant measurement is desirable; otherwise, a determination of the moisture content is necessary. Flue gas velocity is always measured on a wet basis. This is one of the reasons why dilution‐extractive and hot/wet extractive systems, as well as in‐situ systems, are preferred in trading programs where allowances are expressed on a tons/year basis. If a dry‐basis pollutant CEM system is used, the volumetric flow rate must be corrected to dry‐basis standard conditions. This introduces another instrument into the system and an extra avenue for error in the mass rate determination.

If the pollutant gas concentration is measured on a dry basis, the volumetric flow rate must be corrected to dry‐basis conditions. The expression for correcting a wet volumetric flow rate to dry standard condition is

(A‐9)

where

Ts = stack (flue) gas temperature in absolute units (K, R)

Ts = standard temperature in absolute units (293.2 K. 527.4 R)

Ps = stack pressure (absolute; mmHg, kPa)

Ps = standard pressure (29.92 mm Hg, 101.325 kPa)

PROCESS EMISSIONS WEIGHT RATE STANDARDS

Process emissions weight rate standards are applied typically in the process industries. The U.S. New Source Performance Standards of 40 CFR 60 for nitric acid plants, sulfuric acid plants, primary aluminum reduction plans, glass plants, phosphate fertilizer plants, among others, are expressed in this manner. The calculation is performed by determining the pollutant mass rate of Equation A‐8 and dividing this by the production rate. For example, the Part 60 standard for nitric acid plants (U.S. EPA 2020c) is given as follows:

(A‐10)upper E prime equals StartFraction p m r Subscript s Baseline Over upper P upper K EndFraction equals StartFraction c Subscript s Baseline upper Q Subscript s Baseline Over upper P upper K EndFraction

where

E′ = stack (flue) gas temperature in absolute units (K, R)

Ts = standard temperature in absolute units (293.2 K. 527.4 R)

Qs = volumetric flow rate of effluent gas (scm/hr, scf/hr)

P = acid production rate (metric tonne/hr, ton/hr) of 100% nitric acid)

K = conversion factor (1000 g/kg)

EMISSION RATE FOR COMBUSTION SOURCES: THERMAL

For combustion sources, the pollutant mass rate can be expressed with respect to the amount of energy generated, e.g. in nanograms per joule (ng/J) or pounds per million British thermal units (lb/mmBtu). This is similar to the process weight rate expression, except in this case, the product is energy.

(A‐11)

where

E = thermal emission rate (ng/J, lb/mmBtu)

pmrs = pollutant mass rate (kg/hr, lb/hr)

QH = heat Input rate (J/hr, Btu/hr)

Rf = fuel feed rate (kg/hr, lb/hr, m³/hr, ft³/hr)

GCV = gross calorific value (high heating value of the fuel (the total heat obtained from the complete combustion of a fuel referenced to a set of standard conditions) (J/kg, Btu/lb)

s = subscript for “stack”

For CEM systems, the determination of emissions by using Equation A‐11 is cumbersome because measurements for the pollutant concentration, flue gas velocity, fuel feed rate, and fuel heating value must be made on a continual basis. Errors associated with each of these parameters can combine to give a result that may be neither sufficiently accurate nor precise to serve regulatory or technical purposes.

EMISSION RATE FOR COMBUSTION SOURCES: THERMAL – F‐FACTOR APPROACH

F factors provide another way of calculating flue gas emissions in terms of the emission rate, E, expressed in ng/J or lb/mmBtu. F factor methods were developed to simplify the calculation by considering the known stoichiometry associated with combusting fuels (Shigehara et al. 1973; Neulicht 1975; U.S. EPA 2020a, b, see also, Aldina and Jahnke 1979). These methods, the so‐called F‐factor methods, can be used to calculate flue gas emissions in terms of the thermal emission rate, E, expressed in nanograms per joule or pounds per million Btu. The F‐factor methods can be characterized in the general form

(A‐12)upper E equals c Subscript s Baseline upper F upper D Subscript c o r r

where

F = an F factor (in dscm per joule or dscf per cubic foot)

Dcorr = a dilution correction factor

s = subscript for “stack”

The expression is obviously dimensionally correct since (g/dscm) × (dscm/J) gives the thermal emission rate in grams per joule (g/J). An F factor is merely the ratio of the theoretical volume of gas generated by the complete combustion of a quantity of the fuel to the amount of heat produced by the fuel upon combustion. F factors are calculated from a consideration of the theoretical chemical equations of combustion and the laboratory determination of the gross calorific value of the fuel (Shigehara et al. 1973). The utility of F factors lies in the fact that their values are very consistent for a given fuel category. Once determined for bituminous coal, oil, or natural gas, they can be assumed for that fuel category without recalculation. There are several types of F factors: Fd or dry F factor; the Fc factor, and Fw, the wet F factor, each of which is discussed in this appendix.

The Oxygen‐Based Dry F Factor, Fd

The dry F factor, Fd, is the ratio of the theoretical volume of dry gases, Vt, given off by complete combustion of a known amount of fuel to the gross calorific value of the burned fuel:

(A‐13)

The values of the constituents in the F factor are determined by fuel analysis. There are two types of fuel analyses: proximate analysis and ultimate analysis

Proximate Analysis. A fuel analysis procedure that expresses the principal characteristics of the fuel as follows: (i) percentage of moisture, (ii) percentage of ash, (iii) percentage of volatile matter, (iv) percentage of fixed carbon, (v) percentage of sulfur, (vi) heating value, and (vii) ash fusion temperature.

Ultimate Analysis. The determination of the exact chemical composition of the fuel without paying attention to the physical form in which the compounds appear. The analysis is generally given in terms of the percentage of hydrogen, carbon, sulfur, nitrogen, and oxygen.

The data generated in an ultimate analysis of a fuel allow the calculation of an Fd factor based on the composition of the fuel constituents. The individual chemical components are included in the theoretical volume as uncombined elements. Each contributes to the total volume, Vt, based on the percentage present in the fuel. An F factor can then be calculated for any fuel when the percentage composition of each constituent is known:

(A‐14)

(A‐15)

Units for the conversion factors in the expressions are 10⁻⁵ kJ/J and 10⁶ Btu/million Btu for GCV expressed in kilojoules per kilogram and in Btu per pound, respectively. The constants in the expressions are given in standard cubic meters per kilogram (e.g. 22.7 scm/kg) and standard cubic feet per pound (e.g. 3.64 scf/lb) for %H.

The preceding equations account for only a stoichiometric amount of oxygen – the amount of oxygen necessary to oxidize the fuel completely to its combustion products. An industrial facility burning large quantities of fuel adds a stoichiometric amount of air (oxygen and nitrogen) and some excess air to ensure complete combustion of the fuel. The volume of the combustion products is related to the excess air as follows:

(A‐16)upper V Subscript t Baseline equals upper Q Subscript s Baseline times upper D i l u t i o n a i r c o r r e c t i o n t e r m times t i m e

The stoichiometric amount of oxygen present would be consumed during the combustion of the fuel. The remaining oxygen present in the combustion gasses is, therefore, an excess amount and dilutes the volume of gas generated by combustion. As a result, the value of Qs would be higher if more excess air is used, and must be corrected in order to calculate Vt. For dry air containing 20.9% oxygen, this correction term is

(A‐17)upper D i l u t i o n a i r c o r r e c t i o n t e r m equals left-bracket StartFraction 20.9 minus percent-sign normal upper O Subscript 2 d Baseline Over 20.9 EndFraction right-bracket

Then

(A‐18)upper V Subscript t Baseline equals upper Q Subscript s Baseline times StartFraction 20.9 minus percent-sign normal upper O Subscript 2 d Baseline Over 20.9 EndFraction times t i m e

Because the heat released by the fuel is not affected by the dilution air and where QH = RfGCV, Equation A‐13 becomes

(A‐19)

or

(A‐20)

Therefore, from Equation A‐11

(A‐21)upper E equals c Subscript s d Baseline upper F Subscript d Baseline left-bracket StartFraction 20.9 Over 20.9 minus percent-sign normal upper O Subscript 2 d Baseline EndFraction right-bracket

The dry F factor is used for emission rate calculations when both the pollutant gas and the oxygen concentrations are measured by the CEM system on a dry basis. If the moisture content of the flue gas Bws, is either measured, assumed, or otherwise known, the dry F factor can be used by modifying Equation A‐20:

(A‐22)

where

cw = pollutant concentration measured on a wet basis

%O2w = oxygen percentage measured on a wet basis

The Oxygen‐Based Wet F Factor, Fw

In‐situ and dilution CEM systems measure flue gases on a wet basis. If oxygen is measured for the dilution correction, the flue gas moisture content must be known to determine E, when using Fd. For accurate measurements in sources where moisture content fluctuates, a moisture monitor or a monitoring system is, therefore, necessary. This is an added expense and can contribute to the uncertainty associated with the emission rate calculation. Under certain conditions, however, another F factor – the wet F factor – can be used (Shigehara and Neulicht 1978).

The wet F factor, Fw, is defined as the ratio of the quantity of wet effluent gas generated by combustion to the gross calorific value (GCVw) of the fuel determined for the fuel on an “as received” or “as fired” basis. GCVw includes the free water in the fuel.

(A‐23)

(A‐24)

The H₂O percentage can be omitted if the oxygen and hydrogen from the water are included in the values for %H and %O₂.

Because the excess air used for combustion may include ambient moisture, an ambient moisture fraction, Bwa, must be included in the emission rate calculation. The expression is

(A‐25)

Any of the following may be used for Bwa in the expression:

Fixed constant value of 0.027

Continuous measured value

Monthly value based on previous history

Annual value based on previous history

Although the value or Bwa may be approximate, its contribution to the overall expression is relatively small. The estimates should not introduce a negative error greater than −1.5%. However, positive errors (overestimation of emissions) of as much as 5% have been noted in some geographic locations (U.S. EPA 2020a). The expression cannot be used in any process in which water is introduced into or removed from the flue gas stream. It is, therefore, not applicable to CEM systems installed after wet scrubbers.

The Carbon Dioxide‐Based F Factor, Fc

If a carbon dioxide analyzer is use in a CEM system, the carbon dioxide F factor, Fc, can be used (Neulicht 1975). Fc is the ratio of the theoretical volume of carbon dioxide produced during the combustion of a given amount of fuel to its gross calorific value

(A‐26)upper F Subscript c Baseline equals StartFraction 2.0 left-parenthesis percent-sign normal upper C right-parenthesis Over upper G upper C upper V EndFraction m e t r i c u n i t s

(A‐27)upper F Subscript c Baseline equals StartFraction 0.321 left-parenthesis percent-sign normal upper C right-parenthesis Over upper G upper C upper V EndFraction upper E n g l i s h u n i t s

The emission rate can be determined for analyzers measuring either on a dry basis or a wet basis, as long as both the pollutant analyzer and CO₂ analyzer are measuring on the same basis. That is, if cd and %CO2d or cw and CO2w are determined, the thermal emission rate can be calculated by either

(A‐28)upper E equals c Subscript d Baseline upper F Subscript c Baseline left-bracket StartFraction 100 Over percent-sign upper C upper O Subscript 2 d Baseline EndFraction right-bracket

or

(A‐29)upper E equals c Subscript w Baseline upper F Subscript c Baseline left-bracket StartFraction 100 Over percent-sign upper C upper O Subscript 2 w Baseline EndFraction right-bracket

Fc factor calculations are very useful when using in‐situ CEM systems, dilution systems, or hot/wet extractive systems that measure CO₂. The equations are very forgiving for dilution systems because changes in pressure, temperature, and molecular weight, which affect the flow of the sample gas through the critical orifice, will bias the pollutant and CO₂ measurements equally. Because the two are ratioed, the biases will cancel.

When the pollutant concentration is measured on a wet basis and the CO₂ percentage is measured on a dry basis, the moisture content must be known when using the Fc factor in the following equation:

(A‐30)

If the reverse is true, the following expression is used:

(A‐31)

Tabulated F Factors and Conversion Factors

Because most pollutant analyzers express emission concentrations in terms of parts per million (ppm), the analyzer values must first be converted into units of nanograms per standard cubic meter or pounds per standard cubic foot before substitution in the F‐factor expressions.

F factors have been calculated and tabulated by the U.S. EPA using data obtained from the literature. The F factors have been found to be quite consistent within a given fuel category. For example, the maximum percentage deviation from the midpoint Fd factor for bituminous coal was found to be 3.1% (Shigehara et al. 1978). For natural gas, the deviation of the Fd and Fw factors was found to be within ±2.5% of the Method 19 averages (Shigehara 1999). The F factors may be determined by the plant using the appropriate equations given previously. However, they should lie within 2–5% of the EPA tabulated values; see Shigehara and Schiff (1998) for maximum deviations. The EPA‐tabulated F factors are given in Table A‐2.

TABLE A‐2 F factors for Various Fuels*

Source: Adapted from U.S. Environmental Protection Agency (U.S. EPA) (2020a, b).

| F d | F w | F c
Fuel Type | dscm/J | dscf/10⁶ Btu | wscm/J | wscf/10⁶ Btu | scm/J | scf/10⁶ Btu
Coal |  |  |  |  |  |
Anthracite** | 2.71 × 10⁻⁷ | 10 100 | 2.83 × 10⁻⁷ | 10 540 | 0.530 × 10⁻⁷ | 1970
Bituminous** | 2.63 × 10⁻⁷ | 9780 | 2.86 × 10⁻⁷ | 10 640 | 0.484 × 10⁻⁷ | 1800
 Lignite | 2.65 × 10⁻⁷ | 9860 | 3.21 × 10⁻⁷ | 11 950 | 0.513 × 10⁻⁷ | 1910
Oil† | 2.47 × 10⁻⁷ | 9190 | 2.77 × 10⁻⁷ | 10 320 | 0.383 × 10⁻⁷ | 1420
Gas |  |  |  |  |  |
 Natural | 2.43 × 10⁻⁷ | 8710 | 2.85 × 10⁻⁷ | 10 610 | 0.287 × 10⁻⁷ | 1040
 Propane | 2.34 × 10⁻⁷ | 8710 | 2.74 × 10⁻⁷ | 10 200 | 0.321 × 10⁻⁷ | 1190
 Butane | 2.34 × 10⁻⁷ | 8710 | 2.79 × 10⁻⁷ | 10 390 | 0.337 × 10⁻⁷ | 1250
Wood residue | 2.48 × 10⁻⁷ | 9240 |  |  | 0.492 × 10⁻⁷ | 1830
Wood bark | 2.58 × 10⁻⁷ | 9600 |  |  | 0.516 × 10⁻⁷ | 1920
Municipal solid waste | 2.57 × 10⁻⁷ | 9570 |  |  | 0.488 × 10⁻⁷ | 1820

* Determined at U.S. EPA standard conditions: 20° (68 °F) NS 760 MMhG (29.92 in. Hg).

** As classified according to ASTM D388‐77.

† Crude, residual, or distillate.

F w factors for wood, wood bark, and municipal solid waste are not included in the tables due to high variability of free moisture content in the materials. Because the composition of municipal solid waste is also highly variable, some care should be taken in the application of F factors for waste fuel.

For sources using a combination of fossil fuels, a combination F factor may be determined from the general expression:

(A‐32)upper F Subscript m Baseline equals sigma-summation Underscript i equals 1 Overscript n Endscripts x Subscript i Baseline upper F Subscript i

where

Fm = F factor for the fuel mixture

xi = fraction of total heat input from each type of fuel

Fi = appropriate F factor for each type of fuel (Fd, Fw, or Fc)

n = number of fuels being burned in combination

Other Uses of F Factors

F factors can be considered as a shorthand method for performing combustion calculations. They essentially summarize chemical combustion formulae in a manner where ad hoc combustion calculations can be done in the field. Some uses for F factors other than calculating emissions values in units of ng/J or lb/mmBtu are given below.

Cross‐checking O₂ and CO₂ Data

F factors provide a convenient means of performing certain checks and cross‐checks of combustion and emissions data. For example, if both oxygen and carbon dioxide are measured on a dry basis, another factor, the Fo factor, can be derived from Equations A‐21 and A‐28:

(A‐33)

Because Fd and Fc are relatively constant for a given fuel category, the Fo factor will also be relatively constant. The substitution of O₂ and CO₂ data into the right‐hand side of the equation should then give a value close to the left‐hand side of the equation. The expression is useful in checking CEM data, as well as in checking stack testing data during a performance test or RATA.

By rearranging Equation A‐30, the CO₂ percentage in a flue gas can be determined when an oxygen analyzer is used in a CEM system, or the oxygen concentration (dry basis) is otherwise known:

(A‐34)percent-sign upper C upper O 2 equals StartFraction left-parenthesis 20.9 minus percent-sign normal upper O 2 right-parenthesis Over upper F Subscript o Baseline EndFraction

Calculating Flue Gas Flow Rate from F factors

If QH is known by other means, (e.g. from the fuel feed rate, Rf, and GCV), and by using the tabulated value for Fd and the measured value for %O2d, the flue gas volumetric flow rate can be obtained:

(A‐35)

This is basically a material balance check that is consistent with the combustion stoichiometry.

Similar expressions can be used if a wet‐basis oxygen analyzer or a carbon dioxide analyzer is used in the CEM system and the heat rate, QH, is known by other means:

(A‐36)

or

(A‐37)

As seen in Chapter 7, Equation A‐37 is a convenient way of determining flue gas volumetric flow rates, especially for gas‐fired combustion sources, where Rf is normally metered and the GCV is available either from the gas supplier or measured by a gas chromatograph.

Calculating Heat Rate QH from F Factors

If Qs is known from flow monitors or other means, then the heat input rate can be calculated as follows:

(A‐38)

Calculating Moisture Content Bws from F factors

The wet and dry F factors can be manipulated to obtain the flue gas moisture content, Bws, if the oxygen is measured on a wet basis (McGowan 1976). This is an interesting derivation because it allows the application of in‐situ analyzers after wet scrubber systems without requiring the installation of a moisture monitor. This expression is given as

(A‐39)

A similar expression can be derived if wet‐basis oxygen and carbon dioxide measurements are made by the CEM system (Aldina 1985):

(A‐40)

It should be noted that there are a number of variables in equations given above, each having its own accuracy and precision. The adequacy of using F‐factor equations to calculate Bws should certainly be cross‐checked by measuring Bws using an analyzer or appropriate test method.

Calculating F Factors

If the flue gas volumetric flow rate, Qs, and the heat input rate, QH, are known, the Fd factor can be determined:

(A‐41)

(A‐42)

(A‐43)upper F Subscript c Baseline equals StartFraction upper Q Subscript s Baseline Over upper Q Subscript upper H Baseline EndFraction StartFraction percent-sign upper C upper O 2 Over 100 EndFraction

Greenhouse Gas Reporting

Coming full circle on F factor calculations, F factors can be used to determine CO₂ emissions through the simple calculation derived from Equations A‐8 and A‐37:

Substituting Equation A‐37 into A‐8, when expressed in percent, the CO₂ concentration cancels

When the fuel feed rate Rf and GCV are known, the result gives the pollutant mass rate without having to measure the CO₂ concentration:

(A‐44)

This should, of course, be obvious from the definition of the Fc factor: “the ratio of the theoretical volume of carbon dioxide produced during the combustion of a given amount of fuel to its gross calorific value.”

Errors and Problems in the Use of F Factors

Tabulated F factors do have a certain degree of imprecision since the values only represent midpoint values from a finite set of information. In general, however, maximum deviations from the midpoint value should be on the order of 3%

The F factors assume complete combustion of the fuel. Incomplete combustion can cause an error, but can be corrected if CO concentrations are determined. Corrections can be performed by adjusting the O₂ or CO₂ percentages as follows:

(A‐45)left-parenthesis percent-sign normal upper O 2 right-parenthesis Subscript a d j Baseline equals percent-sign normal upper O 2 minus 0.5 percent-sign upper C upper O

(A‐46)left-parenthesis percent-sign upper C upper O 2 right-parenthesis Subscript a d j Baseline minus percent-sign upper C upper O 2 plus percent-sign upper C upper O

In most cases, CO levels are on the order of a few 100 ppm and do not require any significant adjustment.

SUMMARY

The conversion of analyzer data into units of an emission standard can be simple when correcting merely for dilution effects, but can become more complicated when data are expressed in thermal units. Table A‐3 summarizes the common units of the standard discussed in this appendix. From the third column of the table, it can be seen that the form of the emission standard will define the type of analyzers that will be required for a monitoring system.

Before the advent of allowance trading programs, more emphasis was placed upon the accuracy of the pollutant measurement than on, at that time considered, ancillary diluent or flow measurements. Because of the critical importance of the accuracy of pollutant mass rate (pmr) measurements in the allowance trading programs, considerable emphasis has been placed upon reducing the uncertainty of the flow measurement, both in the United States, and worldwide, as discussed in Chapters 2, 6, and 14.

F factors can be used in CEM system and source test programs to cross‐check emissions data, in particular, the diluent O₂ and CO₂ data that are often taken for granted. They can be a valuable tool in the toolbox of the plant environmental engineer, as well as the toolbox of a CEM system auditor or agency inspector.

TABLE A‐3 Summary: Common “Units of the Standard”

Emissions Standard
Symbola
Units
Form of the Calculation*
Analyzers
Required for Calculation

Concentration
(dry)
c d
ppm
μ/m³
c Subscript d Baseline equals StartFraction c Subscript w Baseline Over left-parenthesis 1 minus upper B Subscript w s Baseline right-parenthesis EndFraction
Wet‐basis pollutant analyzer
Moisture monitor

Concentration
(dry, standard)
c d, std
ppm

Pollutant analyzer
T, P Sensors

Concentration
(12% CO₂ corr,)
c d,(12 %CO2)
ppm

Dry‐basis pollutant analyzer
CO₂ Analyzer

Concentration
(6 % O₂ corr.)
c d,(6% O2)
ppm
c Subscript d left-parenthesis 6 percent-sign upper O 2 Baseline equals c Subscript d Baseline StartFraction 14.9 Over 20.9 minus percent-sign upper O Subscript 2 d Baseline EndFraction
Wet, dry pollutant analyzer
Wet, dry O₂ Analyzer

Pollutant Mass Rate
pmr
mass/time
(lb/hr, kg/h)
pmr s = csQws
Pollutant analyzer
Flow monitor

Process Weight Rate
E’
mass/mass of product
upper E prime equals StartFraction p m r Subscript s Baseline Over upper P upper K EndFraction
Pollutant analyzer
Production process data

Thermal Emission Rate
E
mass/heat input
upper E equals StartFraction p m r Subscript s Baseline Over upper Q Subscript upper H Baseline EndFraction

or

E = csFDcorr
Pollutant Analyzer
Flow monitor
Fuel Feed Rate Monitor
Lab GCV data
or
Pollutant analyzer
CO₂ or O₂ analyzer

* See text for symbol nomenclature

REFERENCES

Aldina, G.J. (1985). Private communication.

Aldina, G. and Jahnke, J. (1979). APTI Course 450 Source Sampling for Particulate Pollutants ‐ Student Manual. EPA 450/2‐79‐007.

McGowan, G.F. (1976). Alternative Methods for the Reduction of Dry and Wet Based Measurement Data. Lear Siegler, Inc. Technical communication.

Neulicht, R.M. (1975). Emission correction factor for fossil fuel‐fired steam generators: CO₂ concentration approach. Stack Sampling News 2 (8): 6–11.

Shigehara, R.T. (1999). Deviations of natural gas F‐factors from method 19 averages. Source Evaluation Society Newsletter 23 (1): 22–26.

Shigehara, R.T. and Neulicht, R.M. (1978). Derivation of equations for calculating power plant emission rates, O₂ based method wet and dry measurements. In: Stack Sampling Technical Information‐A Collection of Monographs and Papers, vol. I (ed. U.S. EPA Emissions Standards and Engineering Division), 20–28. EPA Air Emission Measurement Center (EMC) Technical Information Document TID‐020.

Shigehara, R.T. and Schiff, H. (1998). Determining F‐factors from gas chromatographic analysis. Source Evaluation Society Newsletter 22 (2): 7–11.

Shigehara, R.T., Neulicht, R.M., and Smith, W.S. (1973). A method for calculating power plant emissions. In: Stack Sampling Technical Information‐A Collection of Monographs and Papers, vol. I (ed. U.S. EPA Emissions Standards and Engineering Division), 1–9, EPA 450/2‐78‐0426. EPA Air Emission Measurement Center (EMC) Technical Information Document TID‐020.

Shigehara, R.T., Neulicht, R.M., Smith, W.S., and Peeler, J.W. (1978). Summary of F factor methods for determining emissions from combustion sources. In: Stack Sampling Technical Information‐A Collection of Monographs and Papers, vol. I (ed. U.S. EPA Emissions Standards and Engineering Division), 29–43, EPA 450/2‐78‐0426. EPA Air Emission Measurement Center (EMC) Technical Information Document TID‐020.

U.S. Environmental Protection Agency (U.S. EPA). (2013). Course 450: Source Sampling for Pollutants Student Guide. Research Triangle Park. Air Pollution Training Institute.

U.S. Environmental Protection Agency (U.S. EPA) (2020a). Method 19 – determination of sulfur dioxide removal efficiency and particulate matter, sulfur dioxide and nitrogen oxides emission rates. U.S. Code of Federal Regulations. 40 CFR 60 Appendix A.

U.S. Environmental Protection Agency (U.S. EPA) (2020b). Acid rain program: continuous emission monitoring – Appendix F – conversion procedures. U.S. Code of Federal Regulations. 40 CFR 75 Appendix F. Washington, DC: Office of the Federal Register.

U.S. Environmental Protection Agency (U.S. EPA) (2020c). Standards of Performance for New Stationary Sources – Subpart G – Standards of Performance for Nitric Acid Plants. 40CFR60.74. Washington, DC: Office of the Federal Register.

APPENDIX B
CONVERSION FACTORS AND USEFUL INFORMATION

CONSTANTS

Avogadro's number | 6.02 × 10²³ atoms per gram‐atom
Faraday constant | 9.65 × 10⁴ Coulombs per mole
Gas constants | 82.05 atm⋅cm³/(g‐mol⋅K)
| 1.987 cal/(g‐mol⋅K)
| 10.731 ft⋅lb⋅in²/(lb‐mol⋅R)
| 0.732 ft³⋅atm/(lb‐mol⋅R)
1 g‐mol | 22.4 liters ideal gas at standard temperature and pressure (STP)
1b‐mol | 359 ft³ ideal gas at STP
ln 10 | 2.3026
Natural log base e | 2.7183
Planck's constant | 6.62 × 10⁻²⁷ erg‐s
Speed of light | 3.0 × 10¹⁰ cm/s
Speed of sound | 343 m/s in air at 20 °C (1125 ft/s)

IUPAC STANDARD TEMPERATURE AND PRESSURE (STP)

T std = 0 °C (32 °F)

P std = 101.3 kPa (1 atm), 29.92 in. Hg, 760 mm Hg, 1 atm atmosphere

EPA STANDARD CONDITIONS

T std = 20 °C (68 °F)

P std = 101.3 kPa (1 atm), 29.92 in. Hg, 760 mm Hg, 1 atm atmosphere

Molecular Weights and Gas Concentration Units

To convert parts per million (ppm) to milligrams per cubic meter (mg/m³) at a set of standard conditions (Tstd):

At EPA standard conditions of 293.16°:

Ammonia | NH₃ | 17.03 g/mol | 100 ppm NH₃ = 71 mg/m³
Carbon Monoxide | CO | 28.01 | 100 ppm CO = 116 mg/m³
Carbon Dioxide | CO₂ | 44.01 | 100 ppm CO₂ = 182 mg/m³
Hydrochloric Acid | HCl | 36.46 | 100 ppm HCl = 163 mg/m³
Hydrogen Sulfide | H₂S | 34.08 | 100 ppm H₂S = 141 mg/m³
Methane | CH₄ | 16.04 | 100 ppm CH₄ = 67 mg/m³
Nitrogen | N₂ | 28.01 | 100 ppm N₂ = 116 mg/m³
Nitrogen Dioxide | NO₂ | 46.01 | 100 ppm NO₂ = 191 mg/m³
Nitric Oxide | NO | 30.01 | 100 ppm NO = 125 mg/m³
Oxygen | O₂ | 32.00 | 100 ppm SO₂ = 133 mg/m³
Propane | C₃H₈ | 44.10 | 100 ppm C₃H₈ = 183 mg/m³
Sulfur Dioxide | SO₂ | 64.06 | 100 ppm SO₂ = 266 mg/m³

Atomic Weight

Mercury
Hg
200.59
100 ppm Hg = 834 mg/m³

CONVERSION EXPRESSIONS

Temperature

CONVERSION FACTORS

Length

1 in. = 2.54 cm

1 ft = 0.305 m

Volume

1 ft³ = 0.0283 m³ = 28.32 l

1 m³ = 35.314 ft³ = 1000 l

1 Barrel (U.S.) = 42 gallons (U.S.)

Mass

1 g = 0.0022 lb

1 lb = 453.6 g

1 grain (gr) = 0.0648 g = 0.000 143 lb

1 ton = 0.907 tonne

1 tonne = 2205 lb

Mass per Unit Volume

1 g/m³ = 0.0283 g/ft³

1 lb/ft³ = 16.02 kg/m³

1 gr/m³ = 2.29 g/m³

1 ng/scm = 1.602 × 10¹³ lb/scf

Velocity

1 ft/s = 0.3048 m/s

1 ft/min = 0.005 08 m/s

1 m/s = 3.281 ft/sPressure

Energy

1 Btu = 1055 J

1 Btu = 2.93 × 10⁻⁴ kWh

1 J = 10⁷ erg

1 J = 1 N⋅m = 1 Pa⋅m³ = 1 kg⋅m²/sec² = 9.478 31 × 10⁻⁴ Btu

Power

1 watt = 1 joule/sec = 10⁷ erg/sec

1 Btu/h = 0.293 W

1 kilowatt = 3412 Btu/hr = 1.341 hp

1 MW = 3,412,000 Btu/hr

1 hp(mech) = 0.746 kW = 2545 Btu/h

1 W = 1 J/s

Power Estimation Factors

INDEX

Absolute correlation audit (ACA) for PM monitors, 245, 420–421

Absorption coefficient applications

Beer‐Lambert law, 79–80

infrared analyzers, 94, 105

ultraviolet analyzers, 106–109

Accessories, 67

Accreditation methods

MCERTS, UK, 302, 397

suitability tests, Germany, 11, 278, 301

Accumulated mass sensors

beta radiation sensor, 227–229

inertial micro‐balance method, 229–230, 239–240

Acid gases, monitoring for, 101, 106, 205–206

Acid Rain Control Program, 2, 8, 20–22

Acoustic velocimetry, see Ultrasonic flow monitors

Activity Data (AD), 378–379

Advantages/limitations, 144, 154–155, 333

Air Emission Testing Body (AETB), 288

Air toxics program, 19, 348–349

Alberta CEMS code, 30, 294, 395

Alignment indicator, 190, 193

Allowance, definition, 13, 20–21, 163

Allowance trading, 20–22, 258, 269, 418

American Society for Testing and Materials (ASTM) standards

ASTM D3154, Type‐S pitot tube design, 164

ASTM D3796, Type‐S pitot tube calibration, 165

ASTM D6216, Opacity monitor design specifications, 188–196

ASTM D6331, Low‐level particulate testing, 122

ASTM D6522, Portable analyzer use in testing, 121, 419

ASTM D6784, Manual method for mercury, 337–338

ASTM D6831, Inertial microbalance particulate method, 222

ASTM D7036, Source testing QA, 288–289, 400

ASTM D7392, Bag leak detector guidance, 364

ASTM D7520, Visible emissions by digital camera, 4

Ammonia, monitoring for, 116–119

Analytical techniques, listing, 6

Angle of projection, 191

Angle of view, 191

Appendix F, see Part 60 Appendix F

Atomic absorption spectroscopy, 316–317

Atomic emission spectroscopy, 361–363

Atomic fluorescence spectroscopy, 320

Audit filters, for opacity monitors, 192–193, 203–204

Audit gases, 417‐418

Audits

performance, 413–419

systems, 423–432

Automated monitoring systems (AMS), 30, 177, 301

Availability, 260, 420

Averaging probes for velocity, 167–169

Back scattering, 233–235

Bag leak detector (BLD), 241–242, 363–365

Band‐pass filters, 98, 107, 112

Beer‐Lambert law, 79–81

Beta‐radiation attenuation, 227–229

Bias adjustment factor (BAF), 293–294

Bias tests, 292–294

Block average, 263–264

Blowback, 45

Boiler and Industrial Furnace (BIF) requirements, 23

Bouguer’s law, 83, 231

By‐pass installation, for in‐situ path monitor, 146

Calibration checks, 406

automatic correction for, 261–262

out‐of‐control conditions, 272, 296, 346–347, 406–407, 417, 419

Calibration drift test

definition (U.S.), 210–211, 284–286, 406–407

Environment Canada test procedures for flow monitors, 179

EPA flow monitor specifications, 177

EPA gas monitor, 157

ISO test procedures for, 298–299

Calibration error test

Opacity monitors, 178, 209–212, 420

Part 75 gas monitors, 284–286

Calibration function (EU), 179–180, 302–304

Calibration techniques

Beer‐Lambert law, and, 81–82

dilution extractive systems, 61–67

extractive systems, 43–46, 48, 67

flow monitors, 175–177, 178–181

hydrochloric acid monitoring, 360–362

in‐situ systems, 138–141, 144–145, 147–149, 157

mercury monitors, 324–329

opacity monitors, 192–196, 203, 209–212

particulate monitors, 219–224, 226

Canada

CEM Guidelines (EPS 1/PG/7), 277, 297

greenhouse gas reporting, 389–390

implementing rules, 29–30

mercury monitoring requirements, 314

performance specification test procedures, 284, 286

reporting, 267

Carbon dioxide equivalents, 376–378

Carbon (emission) intensity, 376–378

Cavity ringdown spectroscopy (CRDS), 87, 99–101

Cement plants, monitoring for, 15, 30, 225, 287, 313–314, 349, 369, 385

Chemical desiccants, 52

Chemiluminescence analyzers, 113–118

Chillers, losses in, 50–52

Clean Air Act Amendments of 1990, 2, 8. 18–19, 25, 312, 345

Clean Air Mercury Rule (CAMR), 312–313, 349

Close‐coupled systems, 4, 55

Coal‐fired power plants, 4, 20–21, 137, 163, 312–314

Code of Federal Regulations (CFR), 13

Cold vapor atomic absorption spectroscopy (CVAAS), 316

Cold vapor atomic fluorescence spectroscopy (CVAFS), 323–324, 359–360

Combiner equation (opacity monitors), 204

Comité Europeén de Normalisation (CEN) standards

EN 14181, AMS certification 30, 176, 301–305

EN 15267, Type testing, 301‐302

EN 16911, Flow monitoring, 166, 179–180

Compliance assurance monitoring (CAM), 19, 32, 35

Compliance indicating system, 32–33

Compliance monitoring systems, 34–36

Computers

computer control, 254–255

data acquisition and handling, 256–268

programming principles, 256–257, 270–272

Concentration calculations

conversion to units of the standard, 162, 437–431

wet versus dry, 65–67, 438

Condensers, see Coolers

Confidence coefficient, 194, 292

Constants, 447

Contact charge transfer, 241–242

Continuous emission monitoring (CEM) implementing programs

compliance, 32–36

discretionary, 27

international, 29–31

public perception, 12–13

state, 24–27

U.S. Federal, 13–24

Continuous mercury monitoring systems (CMMs), 320–324

Continuous monitoring system (CMS), 35, 296–297, 346–347

Continuous parameter monitoring system (CPMS), 5, 19, 32–33, 346–349

Continuous particulate monitoring systems (PM CEMS), 217–247

Control systems, 254–256

Conversion factors, 448

Coolers, for sample gas

compressor, 49–50

pollutant gas losses, in, 50–52

thermoelectric (Peltier), 49

Corrective maintenance, 410–411

Correlation method for particulate monitor calibration, 219–224

Credible evidence, 35–36

Cross state air pollution rule (CSAPR), 26–27

Cyclonic flow, 206, 280

Cylinder gas audits (CGAs), 18, 157–158, 414–417

audit gases, 417–418

Data acquisition and handling systems, 253–269

data display, 265

data recording, 265

data reporting, 265–267

data transfer, 267–268

Data averaging, 263–265

Dataloggers, 255–256

Derivative spectroscopy, 95, 152–154

Design specifications

gas monitoring systems, 281–282

opacity monitoring systems, 188–193, 195

Detectors

photo diode array, 86, 141

photoacoustic, 95–96

photomultiplier tube, 86, 106–107, 112–115

pneumatic, 92–94

solid state, 86

Differential absorption spectroscopy extractive system analyzers

atomic absorption, 316, 319

infrared, 94–96

ultraviolet, 106–111

Differential absorption spectroscopy in‐situ path system analyzers

infrared, 141–143, 151

ultraviolet, 139–141, 150

Differential pressure sensing

flow test methods, 164–166

probes, 167–169

Diffraction gratings, 85–86

Dilution air for dilution systems, 57–58, 63–65

Dilution air in flue gas, correcting for, 442–443

Dilution extractive systems, 55–67

corrections for, 62–65

external, 58–62

probe, 56–57

theory of, 56–57

wet measurement by, 65–67

Diode array, see Linear photodiode array detectors

Diode lasers, 85–86, 94–95, 109, 119, 137, 151, 173, 360

Dioxins/furan monitoring systems, 366–369

Discretionary programs, 27

Dispersive analyzers, 5, 106, 150

DOAS, see Differential absorption spectroscopy

Double‐pass systems, 145, 148–149

Drones, 4–5, 127

Dynamic spiking (method of standard additions), 155–158, 286–288, 336

Electric Generating Units (EGUs), monitoring for, 218, 338, 349

Electric Power Research Institute (EPRI), 65, 152, 321, 396

Electroanalytical methods

electrocatalysis, 119, 122–123, 143–144

polarography, 119–120

potentiometry, 119, 122

Electrodynamic induction, 242

Electromagnetic spectrum, 76–77, 190

Electronic data reports, 267–269

Embedded microprocessors, 256

Emission factor (EF), 22–23, 270, 378–389

Emission limit value, EU, (ELV), 301–305

Emissions accounting, 12

Emissions trading, in U.S., see Allowance trading

Emissions trading scheme (ETS), in European Union, 390

Enforcement policies, 32–36

Environment Canada CEM Guidelines, 297

European Union, 30, 267, 301–305, 390

Excess emission reports, 32–34

External audit device (opacity monitors), 192–193

Extinction coefficient, 83–84, 201, 231–232

Extractive systems

close‐coupled, 4, 55

cool/dry, 41–54

dilution, 3, 41, 55–67

hot/wet, 41–42

Federal Register, 13

F factors, 441–446

Fick’s law of diffusion, 120

Filters

coarse, 43–44

fine, 53

inertial, 44–45

sintered, 43

Flame photometric detector, 354

Flow monitors

differential pressure sensing, 167–169

engineering calculations, 174, 444

stack venturi, 173–174

thermal sensing, 169

time‐of‐flight, 172–173

ultrasonic, 170–172

Flow‐through gas cells, for in‐situ systems, 147–151, 415–416

Flow‐to‐load ratio test, 180–181

Fluorescence analyzers, 111–113, 320–321

Fossil fuel‐fired steam generators, monitoring requirements, 11, 15, 24, 26

Fourier transform infrared (FTIR) spectroscopy, 102–106

Fuel cell methods, see Electrocatalytic analyzers

Gas cells

external audit cells, 149

flow‐through, 147–150, 415–416

gas filter correlation, 97–99

reference cell, 92–94

Gas chromatograph detectors

electron capture, 356

flame ionization, 353–354

mass spectrometers as detectors, 356–357

photoionization, 354–355

thermal conductivity, 355–356

Gas chromatography, 351–357

Gas filter correlation analyzers

extractive, 97–99

in‐situ, 141–143, 151

Gas manufacturer’s intermediate standard (GMIS), 417

Germany, federal regulation, 11, 205, 277, 312, 314

Glass furnaces, monitoring requirements, 16, 30, 243, 386

Global warming potential, 376–377

Gold traps, for mercury monitoring, 321–323

Greenhouse Gas Reporting Program (GHGRP), U.S., 380–381

Hazardous air pollutants (HAPs), 348–369

Hydrochloric acid, monitoring for, 122, 349, 359–361

Implementing rules, 12–27, 29–31

Inductively‐coupled plasma, 328, 362–363

Inertial microbalance, 229–230, 239–240

Infrared analyzers

extractive, 91–106

in‐situ, 106–111

In‐situ systems, gases

advantages and limitations, 154–155

integrated path, 145–157

point, 138–145

PS‐18 certification test criteria, 155–157

Inspection of CEM systems, see Audits

Installation criteria

gas monitoring systems, 279–281

opacity monitoring systems, 206–209

Integral performance characteristic, ISO, 300–302

Integrated Path in‐situ monitors

flow monitors, 170–173

gas monitors, 145–158

opacity monitors, 189, 195–200

Interference effects, synergistic, 287, 299

Interferogram, 102–106

Intergovernmental Panel on Climate Change (IPCC), 377–380

International Organization for Standardization (ISO)

calibration gas preparation standards, 418

field test procedures, 300–301

laboratory test procedures, 299–300

performance characteristics, 299

International Organization for Standardization (ISO) standards

ISO 7935, SO₂ monitoring, automated method, 294, 298–299

ISO 10155, Particulate monitoring, automated method, 205, 219–223

ISO 12414, Particulate sampling, manual method, 222

ISO 14064, Greenhouse gas reporting, 390

ISO 25597, Particulate manual sampling dilution method, 240

International rules

Asia, 30

Canada, 29–30

Europe, 30

Latin America, 30–31

Ion‐mobility spectrometry, 358–359

Ion‐selective electrodes, 122

K‐factor (flow), 164, 176‐177, 179

Lamps, see Radiation sources

Lasers, 85

gas monitor applications, 87, 95–96, 99–102, 111, 151–152

opacity monitor applications, 200–201

particulate monitor applications, 233–240

Lidar, 188, 201

Light

absorption of, 76–79

transmission of, 79–81, 83–84, 187

Light emitting diode (LED), 84–85

Light scattering by particles

geometric optics, 81–83

Mie, 81–82, 231–237

Rayleigh, 81–82, 232

Linearity, 245, 285–286, 297–300, 334–336

Linear photodiode array detectors, 106, 109–111

Loaded oscillator, see Inertial microbalance

Low concentration measurements, 51, 86, 101, 115–116, 154, 238, 286

Lower detection limit, 299

Low NOx measurement, 115–116

Luminescence methods, 111

chemiluminescence, 112–118

fluorescence, 111–113, 320–321

Maintenance, 260, 409–411

Manual stack testing, see Source testing

Manufacturer’s certificate of conformance, 195

Mass spectrometers, 356–358

Maximum achievable control technology (MACT), 19, 345

Measurement error, 155–157, 285–286, 334–336

Measurement locations, 146, 207

Mercuric chloride (HgCl₂) calibrators, 326–328

Mercury and air toxics (MATS) rule, 313, 336–337

Mercury (elemental Hg) calibrators, 324, 326

Mercury calibrator traceability protocol, 328–329

Mercury monitoring methods

atomic absorption spectroscopy, 316–317

atomic fluorescence spectroscopy, 320

x‐ray fluorescence spectroscopy, 361–362

Mercury monitoring systems, commercial

Durag, 325

Sick, 325

Tekran, 321–323

Thermo‐Fisher Scientific, 324–325

Mercury test methods, 337–340

Metals monitoring, 361–363

Microelectromechanical systems (MEMS), 96, 128

Microsensors, 128–129

Microsystems, 67–68, 128–129

Mie scattering, 81–82, 231–237

Miniature analyzers, 128–129

Mini‐systems, 67–68

Missing data, 258–260

Moisture removal methods, 48–52

condensation, 49–50

permeation dryers, 50

Monitoring and certification scheme (MCERTS), 302, 397

Monitoring and reporting rule (MRR), for greenhouse gases in the EU, 390

Multi‐gas analyzers, 5, 94, 109–110, 126–128

Multi‐metal methods, 361–363

Multi‐path gas sample cells, 86–87

Municipal waste combustors (monitoring requirements), 15, 314, 360, 368

Nafion driers, 50–52

National emission standards for hazardous air pollutants (NESHAPS), 14, 345

National Institute of Standards and Technology (NIST), 29, 48, 177

mercury calibrators, 324–329

NIST traceable gases, 29, 277, 417–418

standard reference materials (SRMs), 29, 277

Nernst equation, 120

New sampling system initiative (NeSSITM), 68–70, 128

New Source Performance Standards, 13–18

Nondispersive infrared analyzers, 92–99

Nondispersive ultraviolet analyzers, 106–111

Off‐axis integrated cavity output spectroscopy (OA‐ICOS), 101–102

Office of Air Quality Planning and Standards (OAQPS), 13, 19

Office of Solid Waste, 223

Ontario Hydro method (for mercury), see ASTM D6784

Opacity, definition, 83, 187

Opacity‐mass correlations, 204–205

Opacity monitors

basic design, 188–189

calculations, 201–205

certification field test, 209–210

design specifications, 188–195

field performance specifications tests, 209–210

installation guidelines, 206–209

Opacity monitors, commercial

Ametek‐Land, 198

Durag, 198–200

Mip Oy, 200

Sick, 197–198

Teledyne‐Monitor Labs, 196–197

Operating limit, for particulate monitors, 225

Operational test period, 209–210

Optical density, 83–84

Optical depth, 145–146, 148, 425–426

Optical fiber, use of, 147–148, 150–151, 200, 236, 416

Optical filters, 86

Optional test method (OTP) for metals, 363

Orifice meters, for fuel flow, 175

Out‐of‐control criteria

Canada EPS 1/PG/7, 419

Part 60 Appendix F, gases, 272, 419

Part 60 Appendix F, HCl, 158

Part 60 Appendix F, Hg, 335–336

Part 75 Appendix B, 419

Oxygen monitors

magnetodynamic, 123–124

magnetopneumatic, 124

polarographic, 119–122

thermomagnetic (magnetic wind), 124

Paramagnetic methods (for O₂), see Oxygen monitors

Parameter monitoring systems, 5, 32, 224–225, 346

Part 51 Appendix P CEM SIP requirements, 24–25

Part 60 Appendix B Performance Specifications, 278–286

Part 60 Appendix F CEM quality assurance, 402–419

Part 63.8 Monitoring requirements, 296–297

Part 75 Appendix A Performance Specifications, 178–180

Part 75 Appendix B Quality assurance, 402–419

Particle extinction coefficient, see Extinction coefficient

Particle sizing analyzers, 236–237

Particulate matter continuous parameter monitoring systems (PM‐CPMS), 218, 224–225

Particulate matter measuring techniques (PM‐CEMS), 228–242

Pathlength correction factor (PLCF), 191–192, 202–203

Peak response, 84, 190

Peltier cooler, 49, 54

Percent breakthrough, in sorbent traps, 332

Performance specifications, 277–305

European Union EN14181 standard, 301–304

gas monitor monitoring systems, 278–292

hazardous air pollutants, table, 369

ISO performance characteristics, 297–301

mercury monitoring systems, 333–335

opacity monitoring systems, 205–210

Part 63.8 specifications, 296–297

Part 75 specifications, 296–297

particulate monitoring systems, 219–224

quality control for tests, 399–402

Periodic monitoring, 36

Petroleum refining, monitoring requirements

greenhouse gas reporting, 386–388

Part 60 NSPS requirements, 17

Part 63 Refinery MACT, 349–351

particulate monitoring, 288

Photoacoustic spectroscopy, 95–96, 127

Photopic region, 188, 190

Pitot tubes, 164–166

Plane of the bend, 207–208

Plank‐Einstein relation, 76

Plasma torch, 363

Point in‐situ monitors, gases

advantages and disadvantages of, 156–157

analytical methods applied in, 139–144

probe design, 138–139

Polarographic analyzers, 119–122

Pollutant mass rate, 21, 42, 163, 376, 383, 440

Potentiometric analyzers, 122

Predictive emission monitoring systems (PEMS), 260–261

Pre‐RATA, 176–177

Prevention of Significant Deterioration (PSD), 25

Probe calibration check, 43–44, 414

Probe electrification devices, 241–242

Probes, 43–45, 56–62

Procurement, CEM systems, 396–399

Programmable logic controllers (PLCs), 255–256

Proportional sampling, 331–332

Proposal evaluation, 398–399

Protocol gas, 29, 417–418

Protocol gas verification program (PGVP), 29, 418

Public perception monitoring, 12–13

Pulp and paper plants

greenhouse gas reporting, 386–388

Part 60 requirements, 16

Pumps

diaphragm, 52–53

ejector, 53

Qualified individual (QI), 288, 400

Quality assurance for the DAHS, 268–269

Quality assurance levels in EN 14181

QAL 1 Fitness for use, 301–302

QAL 2 Calibration and uncertainty verification, 301–304

QAL 3 Ongoing quality assurance, 301, 304–305

Quality assurance manual, 402–405

Quality assurance plan

bag leak detectors, 364

opacity monitors, 210–211

parts 60 and 75, 402–403

writing, 404–405

Quality assurance requirements, U.S.

Part 60 Appendix F, 29, 210, 226, 244, 334, 395, 407, 319

Part 63.8, 336–337

Part 75 Appendix B, 29, 278, 407, 419

Quality control, 395–396

certification quality control, 399–402

continuing operation, elements of quality control, 405–408

procurement quality control, 396–398

Quality control charts, 270, 407–408

Quenching, in luminescence analyzers, 113–116, 320–321, 323–324

Quincke analyzer, 124

Radiation sources, 84–85

Range, analyzer, see Span

Rayleigh scattering, 81–82, 232

Received light modulation, 231–232

Recording and reporting data, 261–268

Reference methods for performance specification testing

instrumented (automated) methods, 282, 288, 299–300

location and traverse points, 166–167, 206, 289–291

manual methods, 1, 222, 282, 299

Refrigerated condensers, 49–50

Regulations, national

Canada, 29–30

China, 30

European Union, 30

Germany, 12, 277

Latin America, 30–31

U.S., 12–27

Relative accuracy audit (RAA), 413, 418–419

Relative accuracy (RA), calculation, 291–292

Relative accuracy test

alternate procedure, 294–295

quality control of, 399–402

test calculations, 291–295

test report, 295

Relative accuracy test audit (RATA), see Relative accuracy test

Relative response audit (RAA) for PM monitors, 245–246, 420–421

Remote sensors, 4–5

Reporting

Canada, 267, 389

greenhouse gases, 22, 347, 380–381, 389–390

U.S., 32–34, 253–267, 347

Resource Conservation and Recovery Act (RCRA), 23

Response correlation audit (RCA) for PM monitors, 246–247, 420–421

Response time

Canada/Part 75 requirements, 286, 300

opacity monitor requirement, 194, 209

PS‐18, 157

Routine (preventive) maintenance, 214, 409–411

Sample probes, 43–45, 56–57

Sample pumps, 52–53

Second‐derivative spectroscopy, 152–154

Sewage sludge incineration, rules for, 23–25

Side scattering, 233, 235

Simulated zero, 192–194, 210

Single‐pass systems, 145, 147–148, 188–189

Site tour, 424–429

Slotted tubes, 138–139

Software for CEM DAHS, 256–267, 270–272

Sorbent trap, Hg

monitoring systems, 329–333

test method 30B, 339–340

Source‐level extractive systems

cool‐dry, 42–55

hot‐wet, 41–42

Source testing, 219–223, 288–289, 400–401

Span, 281–282

Specific mass extinction coefficient, 84, 231

Spectral response (opacity monitors), 84, 190–191, 195

Stack exit correlation, 202–203

Standard conditions (EPA), 438, 447

Standard reference materials (SRMs), 226, 417, 438

State agency CEM programs

discretionary, 27

federally delegated programs, 26–27

operating permits, 25–26

state implementation plans (SIPs), 24–25

Stratification

gas, 146–147, 279–281

particulate matter, 206–208, 279–281

velocity, 167–169, 280

Suitability test, 11, 278, 301–302

Synergistic effects, 287, 299

Systems

close‐coupled, 4, 55

control, 254–256

cool/dry, 42–55

data acquisition and handling, 253–269

dilution, 55–67

hot/wet, 41–42

in‐situ, 137–159

Systems audit, 413, 422–432

audit report, 432

records review, 429–431

site tour, 424–429

Technical specification, writing of, 397–398

Technischer Überwachungsverein 302, 397

Temperature responsive drift, 300

Thermal conductivity detector, 49, 124–125, 355–356

Thermal mass flowmeters, 169

Thermomagnetic methods, 124

Three‐dimensional pitot tubes, 165–166

Tier approach, in greenhouse gas reporting, 22–23, 380–384

Time‐of‐flight methods (flow)

Infrared correlation, 173

Optical scintillation, 172–173

Time‐share systems, 254, 271, 290

Total hydrocarbon analyzers, 357–358

Traceability protocols

gases, 29, 414, 417

mercury calibrators, 328–329

Tracer gas dilution method (flow), 166–167

Transmissometers, see Opacity monitors

Transmittance, 80, 83, 92, 150

Traverse points, for test methods, 166–167, 206, 289–291

Triboelectric devices, see Probe electrification methods

Tunable lasers, 151–152

Turn‐key vendors, 41, 396

Type testing, see Suitability testing

Ultrasonic flow monitors, 170–172

Ultraviolet analyzers, 106–111, 139–141, 150

Umbilical sample line, 4, 45–48, 426

United Nations Environmental Program (UNEP), 311

United Nations Framework Convention for Climate Change (UNFCCC), 375, 379–381

Units of the standard

block average, 263–264

concentration‐based, 437–440

data conversion, 262

pollutant mass rate, 440

process weight rate, 440

rolling average, 263–265

thermal, 440–444

Unmanned aerial vehicles (UAVs), 5

U.S. Acid Rain Control Program, see Acid Rain Control Program

U.S. Code of Federal Regulations, 13

Vane anemometers, 166

Variability test (EU), 303–304

Velocity monitors, see Flow monitors

Venturi flowmeters, 164, 173–175

Vibrational energy levels, 77–78

Visible emissions observer, 4, 35, 86, 188, 190, 192, 202

Wall‐effect measurements (flow), 166, 177, 389

Waste to energy plants, see Municipal waste combustors

Wavelength modulation, 95

Wave nature of light, 75–76

Wavenumber, 76

Wet stacks, particulate monitoring in, 240–241

X‐ray fluorescence spectrometry, 361–362

Yaw nulling method, 166

Zeeman effect, 317–320

Zero alignment (opacity monitors), 210–213

Zero and span drift, see Calibration drift

Zero compensation (opacity monitors), 211

Zero jig, see External audit device

Zirconium oxide sensor, 122–123, 143–144

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