Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers

Abstract

Recent regulations have required reductions in emissions of nitrogen oxides (NO_x) from electric utility boilers. To comply with these regulatory requirements, it is increasingly important to implement state-of-the-art NO_x control technologies on coal-fired utility boilers. This paper reviews NO_x control options for these boilers. It discusses the established commercial primary and secondary control technologies and examines what is being done to use them more effectively. Furthermore, the paper discusses recent developments in NO_x controls. The popular primary control technologies in use in the United States are low-NO_x burners and overfire air. Data reflect that average NO_x reductions for specific primary controls have ranged from 35% to 63% from 1995 emissions levels. The secondary NO_x control technologies applied on U.S. coal-fired utility boilers include reburning, selective noncatalytic reduction (SNCR), and selective catalytic reduction (SCR). Thirty-six U.S. coal-fired utility boilers have installed SNCR, and reported NO_x reductions achieved at these applications ranged from 15% to 66%. Recently, SCR has been installed at >150 U.S. coal-fired utility boilers. Data on the performance of 20 SCR systems operating in the United States with low-NO_x emissions reflect that in 2003, these units achieved NO_x emission rates between 0.04 and 0.07 lb/10⁶ Btu.     

Technology innovations and experience curves for nitrogen oxides control technologies

This paper reviews the regulatory history for nitrogen oxides (NOx) pollutant emissions from stationary sources, primarily in coal-fired power plants. Nitrogen dioxide (NO2) is one of the six criteria pollutants regulated by the 1970 Clean Air Act where National Ambient Air Quality Standards were established to protect public health and welfare. We use patent data to show that in the cases of Japan, Germany, and the United States, innovations in NOx control technologies did not occur until stringent government regulations were in place, thus "forcing" innovation. We also demonstrate that reductions in the capital and operation and maintenance (O&M) costs of new generations of high-efficiency NOx control technologies, selective catalytic reduction (SCR), are consistently associated with the increasing adoption of the control technology: the so-called learning-by-doing phenomena. The results show that as cumulative world coal-fired SCR capacity doubles, capital costs decline to approximately 86% and O&M costs to 58% of their original values. The observed changes in SCR technology reflect the impact of technological advance as well as other factors, such as market competition and economies of scale.     

Emissions of sulfur trioxide from coal-fired power plants

Emissions of sulfur trioxide (SO3) are a key component of plume opacity and acid deposition. Consequently, these emissions need to be low enough to not cause opacity violations and acid deposition. Generally, a small fraction of sulfur (S) in coal is converted to SO3 in coal-fired combustion devices such as electric utility boilers. The emissions of SO3 from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and air pollution devices being used. It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO3. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO3 and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with SCR systems and wet scrubbers. This paper investigates the factors that affect acidic mist production in coal-fired electric utility boilers and discusses approaches for mitigating emission of this mist.     

Effectiveness of emission control technologies for auxiliary engines on ocean-going vessels

Large auxiliary engines operated on ocean-going vessels in transit and at berth impact the air quality of populated areas near ports. This paper presents new information on the comparison of emission ranges from three similar engines and the effectiveness of three control technologies: switching to cleaner burning fuels, operating in the low oxides of nitrogen (NOx) mode, and selective catalytic reduction (SCR). In-use measurements of gaseous (NOx, carbon monoxide [CO], carbon dioxide [CO2]) and fine particulate matter (PM2.5; total and speciated) emissions were made on three auxiliary engines on post-PanaMax class container vessels following the International Organization for Standardization-8178-1 protocol. The in-use NOx emissions for the MAN B&W 7L32/40 engine family vary from 15 to 21.1 g/kW-hr for heavy fuel oil and 8.9 to 19.6 g/kW-hr for marine distillate oil. Use of cleaner burning fuels resulted in NOx reductions ranging from 7 to 41% across different engines and a PM2.5 reduction of up to 83%. The NOx reductions are a consequence of fuel nitrogen content and engine operation; the PM2.5 reduction is attributed to the large reductions in the hydrated sulfate and organic carbon (OC) fractions. As expected, operating in the low-NOx mode reduced NOx emissions by approximately 32% and nearly doubled elemental carbon (EC) emissions. However, PM2.5 emission factors were nearly unchanged because the EC emission factor is only approximately 5% of the total PM2.5 mass. SCR reduced the NOx emission factor to less than 2.4 g/kW-hr, but it increased the PM2.5 emissions by a factor of 1.5-3.8. This increase was a direct consequence of the conversion of sulfur dioxide to sulfate emissions on the SCR catalyst. The EC and OC fractions of PM2.5 reduced across the SCR unit.     

Emissions of Sulfur Trioxide from Coal-Fired Power Plants

Abstract

Emissions of sulfur trioxide (SO₃) are a key component of plume opacity and acid deposition. Consequently, these emissions need to be low enough to not cause opacity violations and acid deposition. Generally, a small fraction of sulfur (S) in coal is converted to SO₃ in coal-fired combustion devices such as electric utility boilers. The emissions of SO₃ from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and air pollution devices being used. It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO₃. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO₃ and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with SCR systems and wet scrubbers. This paper investigates the factors that affect acidic mist production in coal-fired electric utility boilers and discusses approaches for mitigating emission of this mist.     

Technology Innovations and Experience Curves for Nitrogen Oxides Control Technologies

Abstract

This paper reviews the regulatory history for nitrogen oxides (NO_x) pollutant emissions from stationary sources, primarily in coal-fired power plants. Nitrogen dioxide (NO₂) is one of the six criteria pollutants regulated by the 1970 Clean Air Act where National Ambient Air Quality Standards were established to protect public health and welfare. We use patent data to show that in the cases of Japan, Germany, and the United States, innovations in NO_x control technologies did not occur until stringent government regulations were in place, thus “forcing” innovation. We also demonstrate that reductions in the capital and operation and maintenance (O&M) costs of new generations of high-efficiency NO_x control technologies, selective catalytic reduction (SCR), are consistently associated with the increasing adoption of the control technology: the so-called learning-by-doing phenomena. The results show that as cumulative world coal-fired SCR capacity doubles, capital costs decline to ~86% and O&M costs to 58% of their original values. The observed changes in SCR technology reflect the impact of technological advance as well as other factors, such as market competition and economies of scale.     

Recent increases in nitrogen oxide (NOx) emissions from coal-fired electric generating units equipped with selective catalytic reduction

The most effective control technology available for the reduction of oxides of nitrogen (NO_x) from coal-fired boilers is selective catalytic reduction (SCR). Installation of SCR on coal-fired electric generating units (EGUs) has grown substantially since the onset of the U.S. Environmental Protection Agency’s (EPA) first cap and trade program for oxides of nitrogen in 1999, the Ozone Transport Commission (OTC) NO_x Budget Program. Installations have increased from 6 units present in 1998 in the states that encompass the current Cross-State Air Pollution Rule (CSAPR) ozone season program to 250 in 2014. In recent years, however, the degree of usage of installed SCR technology has been dropping significantly at individual plants. Average seasonal NO_x emission rates increased substantially during the Clean Air Interstate Rule (CAIR) program. These increases coincided with a collapse in the cost of CAIR allowances, which declined to less than the cost of the reagent required to operate installed SCR equipment, and was accompanied by a 77% decline in delivered natural gas prices from their peak in June of 2008 to April 2012, which in turn coincided with a 390% increase in shale gas production between 2008 and 2012. These years also witnessed a decline in national electric generation which, after peaking in 2007, declined through 2013 at an annualized rate of ?0.3%. Scaling back the use of installed SCR on coal-fired plants has resulted in the release of over 290,000 tons of avoidable NO_x during the past five ozone seasons in the states that participated in the CAIR program.

Implications: To function as designed, a cap and trade program must maintain allowance costs that function as a disincentive for the release of the air pollutants that the program seeks to control. If the principle incentive for reducing NO_x emissions is the avoidance of allowance costs, emissions may be expected to increase if costs fall below a critical value, in the absence of additional state or federal limitations. As such, external factors as the cost of competing fuels and a low or negative growth of electric sales may also disincentivize the use of control technologies, the continuation of desirable emission rates will be best maintained by the implementation of performance standards that supplement and complement the emissions trading program.     

Effect of NOx control processes on mercury speciation in utility flue gas

The speciation of Hg in coal-fired flue gas can be important in determining the ultimate Hg emissions as well as potential control options for the utility. The effects of NOx control processes, such as selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR), on Hg speciation are not well understood but may impact emissions of Hg. EPRI has investigated the reactions of Hg in flue gas at conditions expected for some NOx control processes. This paper describes the methodology used to investigate these reactions in actual flue gas at several power plants. Results have indicated that some commercial SCR catalysts are capable of oxidizing elemental Hg in flue gas obtained from the inlets of SCR or air heater units. Results are affected by various flue gas and operating parameters. The effect of flue gas composition, including the presence of NH3, has been evaluated. The influence of NH3 on fly ash Hg reactions also is being investigated.     

电厂NO_x控制政策与技术：美国的经验及对我国的启示

我国NOx排放的快速增长导致其环境和生态影响日益加剧,已经引起全球关注,但是现行的NOx污染控制技术和政策远远落后于实际需求。为减少酸雨、臭氧和颗粒物带来的环境问题,美国采取排放控制和排污交易等方式削减了燃煤电厂的NOx排放。系统分析了美国NOx污染控制法规、标准、规划和控制技术应用情况,总结了其NOx控制的成功经验,进一步提出了符合我国国情的NOx控制对策和技术选择。     

Investigation of selective catalytic reduction impact on mercury speciation under simulated NOx emission control conditions

Selective catalytic reduction (SCR) technology increasingly is being applied for controlling emissions of nitrogen oxides (NOx) from coal-fired boilers. Some recent field and pilot studies suggest that the operation of SCR could affect the chemical form of mercury (Hg) in coal combustion flue gases. The speciation of Hg is an important factor influencing the control and environmental fate of Hg emissions from coal combustion. The vanadium and titanium oxides, used commonly in the vanadia-titania SCR catalyst for catalytic NOx reduction, promote the formation of oxidized mercury (Hg2+). The work reported in this paper focuses on the impact of SCR on elemental mercury (Hg0) oxidation. Bench-scale experiments were conducted to investigate Hg0 oxidation in the presence of simulated coal combustion flue gases and under SCR reaction conditions. Flue gas mixtures with different concentrations of hydrogen chloride (HCl) and sulfur dioxide (SO2) for simulating the combustion of bituminous coals and subbituminous coals were tested in these experiments. The effects of HCl and SO2 in the flue gases on Hg0 oxidation under SCR reaction conditions were studied. It was observed that HCl is the most critical flue gas component that causes conversion of Hg0 to Hg2+ under SCR reaction conditions. The importance of HCl for Hg0 oxidation found in the present study provides the scientific basis for the apparent coal-type dependence observed for Hg0 oxidation occurring across the SCR reactors in the field.     

Control strategies of atmospheric mercury emissions from coal-fired power plants in China

Atmospheric mercury (Hg) emission from coal is one of the primary sources of anthropogenic discharge and pollution. China is one of the few countries in the world whose coal consumption constitutes about 70% of total primary energy, and over half of coals are burned directly for electricity generation. Atmospheric emissions of Hg and its speciation from coal-fired power plants are of great concern owing to their negative impacts on regional human health and ecosystem risks, as well as long-distance transport. In this paper, recent trends of atmospheric Hg emissions and its species split from coal-fired power plants in China during the period of 2000-2007 are evaluated, by integrating each plant's coal consumption and emission factors, which are classified by different subcategories of boilers, particulate matter (PM) and sulfur dioxide (SO2) control devices. Our results show that the total Hg emissions from coal-fired power plants have begun to decrease from the peak value of 139.19 t in 2005 to 134.55 t in 2007, though coal consumption growing steadily from 1213.8 to 1532.4 Mt, which can be mainly attributed to the co-benefit Hg reduction by electrostatic precipitators/fabric filters (ESPs/FFs) and wet flue gas desulfurization (WFGD), especially the sharp growth in installation of WFGD both in the new and existing power plants since 2005. In the coming 12th five-year-plan, more and more plants will be mandated to install De-NO(x) (nitrogen oxides) systems (mainly selective catalytic reduction [SCR] and selective noncatalytic reduction [SNCR]) for minimizing NO(x) emission, thus the specific Hg emission rate per ton of coal will decline further owing to the much higher co-benefit removal efficiency by the combination of SCR + ESPs/FFs + WFGD systems. Consequently, SCR + ESPs/FFs + WFGD configuration will be the main path to abate Hg discharge from coal-fired power plants in China in the near future. However advanced specific Hg removal technologies are necessary for further reduction of elemental Hg discharge in the long-term.     

Flue gas desulfurization: the state of the art

Coal-fired electricity-generating plants may use SO2 scrubbers to meet the requirements of Phase II of the Acid Rain SO2 Reduction Program. Additionally, the use of scrubbers can result in reduction of Hg and other emissions from combustion sources. It is timely, therefore, to examine the current status of SO2 scrubbing technologies. This paper presents a comprehensive review of the state of the art in flue gas desulfurization (FGD) technologies for coal-fired boilers. Data on worldwide FGD applications reveal that wet FGD technologies, and specifically wet limestone FGD, have been predominantly selected over other FGD technologies. However, lime spray drying (LSD) is being used at the majority of the plants employing dry FGD technologies. Additional review of the U.S. FGD technology applications that began operation in 1991 through 1995 reveals that FGD processes of choice recently in the United States have been wet limestone FGD, magnesium-enhanced lime (MEL), and LSD. Further, of the wet limestone processes, limestone forced oxidation (LSFO) has been used most often in recent applications. The SO2 removal performance of scrubbers has been reviewed. Data reflect that most wet limestone and LSD installations appear to be capable of approximately 90% SO2 removal. Advanced, state-of-the-art wet scrubbers can provide SO2 removal in excess of 95%. Costs associated with state-of-the-art applications of LSFO, MEL, and LSD technologies have been analyzed with appropriate cost models. Analyses indicate that the capital cost of an LSD system is lower than those of same capacity LSFO and MEL systems, reflective of the relatively less complex hardware used in LSD. Analyses also reflect that, based on total annualized cost and SO2 removal requirements: (1) plants up to approximately 250 MWe in size and firing low- to medium-sulfur coals (i.e., coals with a sulfur content of 2% or lower) may use LSD; and (2) plants larger than 250 MWe and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

The Potential of Pulse-Jet Baghouses for Utility Boilers. Part 2: Performance of Pulse-Jet Fabric Filter Pilot Plants

Pulse-jet fabric filters (PJFFs) are widely used in U.S. industrial boiler applications and in utility and industrial boilers abroad. Their small size and reduced cost relative to more conventional reverse-gas baghouses makes the use of PJFFs appear to be an attractive particulate control option for utility boilers. This paper (Part 2 of a three-part series) summarizes the results of pilot PJFF studies sponsored by the Electric Power Research Institute at different utility sites in the United States. The purpose of these tests is to evaluate PJFF performance for U.S. fossil-fuel-fired applications. These data are also used to corroborate the results of a recent worldwide survey of PJFF user experience, as described in Part 1 of this series. Part 3 will provide a cost comparison of PJFFs to other particulate control options such as electrostatic precipitators and reverse-gas baghouses.     

Understanding the effectiveness of precursor reductions in lowering 8-hr ozone concentrations--Part II. The eastern United States

Analyses of ozone (O3) measurements in conjunction with photochemical modeling were used to assess the feasibility of attaining the federal 8-hr O3 standard in the eastern United States. Various combinations of volatile organic compound (VOC) and oxides of nitrogen (NOx) emission reductions were effective in lowering modeled peak 1-hr O3 concentrations. VOC emissions reductions alone had only a modest impact on modeled peak 8-hr O3 concentrations. Anthropogenic NOx emissions reductions of 46-86% of 1996 base case values were needed to reach the level of the 8-hr standard in some areas. As NOx emissions are reduced, O3 production efficiency increases, which accounts for the less than proportional response of calculated 8-hr O3 levels. Such increases in O3 production efficiency also were noted in previous modeling work for central California. O3 production in some urban core areas, such as New York City and Chicago, IL, was found to be VOC-limited. In these areas, moderate NOx emissions reductions may be accompanied by increases in peak 8-hr O3 levels. The findings help to explain differences in historical trends in 1- and 8-hr O3 levels and have serious implications for the feasibility of attaining the 8-hr O3 standard in several areas of the eastern United States.     

SCR performance on a hydrogen reformer furnace

In late 1993, Air Products and Chemicals, Inc. began operating a new steam-methane reformer at the Tosco Refining Co.'s Avon refinery in Martinez, CA, to provide hydrogen and steam to the refinery under a long-term supply agreement. The hydrogen plant--owned, operated, and maintained by Air Products--includes a selective catalytic reduction (SCR) unit on the reformer-furnace flue gas for environmental control. SCR is a commercially proven process capable of abating emissions of nitrogen oxides (NOx) to extremely low levels; however, documented experience in a refinery setting has been limited. This paper discusses performance of the SCR, primarily during its first two years of operation; it incorporates theory and prior research findings sufficient to understand the relationship between key system variables and SCR performance. Test results demonstrate that NOx, ammonia (NH3) slip, and carbon monoxide (CO) emissions are in compliance with permit limits. NOx removal efficiency is nearly linear with the inlet NH3:NOx molar ratio up to almost 90% NOx conversion, where ammonia slip begins to rise steeply. The stoichiometric reaction ratio of NH3 to NOx is close to the theoretical 1.0. Catalyst life is estimated at four years, in line with published figures for SCR catalysts in clean-gas service.     

Modeling analyses of the effects of changes in nitrogen oxides emissions from the electric power sector on ozone levels in the eastern United States

In this paper, we examine the changes in ambient ozone concentrations simulated by the Community Multiscale Air Quality (CMAQ) model for summer 2002 under three different nitrogen oxides (NOx) emission scenarios. Two emission scenarios represent best estimates of 2002 and 2004 emissions; they allow assessment of the impact of the NOx emissions reductions imposed on the utility sector by the NOx State Implementation Plan (SIP) Call. The third scenario represents a hypothetical rendering of what NOx emissions would have been in 2002 if no emission controls had been imposed on the utility sector. Examination of the modeled median and 95th percentile daily maximum 8-hr average ozone concentrations reveals that median ozone levels estimated for the 2004 emission scenario were less than those modeled for 2002 in the region most affected by the NOx SIP Call. Comparison of the "no-control" with the "2002" scenario revealed that ozone concentrations would have been much higher in much of the eastern United States if the utility sector had not implemented NOx emission controls; exceptions occurred in the immediate vicinity of major point sources where increased NO titration tends to lower ozone levels.     

1987 Joint EPRI/EPA Symposium on Stationary Combustion NOX Control

From March 23rd to 26th, 1987, the city of New Orleans hosted 350 attendees, including representatives from 15 foreign countries, at the 1987 Joint Symposium on Stationary Combustion NO_x Control. Cosponsored by the Electric Power Research Institute (EPRI) and the U.S. Environmental Protection Agency (EPA), the symposium provided attendees the opportunity to hear 49 papers in nine sessions covering technological and regulatory developments on NO_x control in the United States and abroad since the May 1985 symposium in Boston. Session topics included general environmental issues, low-NO_x combustion equipment (i.e., low-NO_x burners, reburning, etc.), flue gas treatment, fundamental combustion research, and special issues for cyclone coal-fueled boilers, oil- and gas-fired boilers, and industrial combustion applications.

Advances to the state-of-the-art presented at this symposium include: improved and/or newly applied combustion modifications for pulverized coal-fired boilers; further analyses of reburning, the leading combustion modification option for cyclone-equipped boilers; initial experiences with catalytic flue gas treatment in Europe; studies of NO_x control retrofit options for oil- and gas-fired utility systems; and new technology developments for coal, oil, and gas fueled utility and industrial combustors.

This paper summarizes those presentations that discussed significant changes since May 1985 in areas of potential interest to EPRI and its utility members. Where appropriate, they include our perspectives on the applicability of these newly disclosed findings to utility systems.     

Mercury emission trend influenced by stringent air pollutants regulation for coal-fired power plants in Korea

Regulatory control of mercury emission from anthropogenic sources has become a global concern in the recent past. Coal-fired power plants are one of the largest sources of anthropogenic mercury emission into the atmosphere. This paper summarizes the current reducing trend of mercury emission as co-beneficial effect by more stringent regulation changes to control primary air pollutants with introducing test results from the commercial coal-fired facilities and suggesting a guideline for future regulatory development in Korea. On average, mercury emission concentrations ranged 16.3–2.7 μg Sm^?3, 2.4–1.1 μg Sm^?3, 3.1–0.7 μg Sm^?3 from anthracite coal-fired power plants equipped with electrostatic precipitator (ESP), bituminous coal-fired power plants with ESP + flue gas desulphurization (FGD) and bituminous coal-fired power plants with selective catalytic reactor (SCR) + cold side (CS) ? ESP + wet FGD, respectively. Among the existing air pollution control devices, the best configuration for mercury removal in coal-fired power plants was SCR + CS ? ESP + wet FGD, which were installed due to the stringent regulation changes to control primary air pollutants emission such as SO₂, NOx and dust. It was estimated that uncontrolled and controlled mercury emission from coal-fired power plants as 10.3 ton yr^?1 and 3.2 ton yr^?1 respectively. After the installation of ESP, FGD and SCR system, following the enforcement of the stringent regulation, 7.1 ton yr^?1 of mercury emission has been reduced (nearly 69%) from coal-fired power plants as a co-benefit control. Based on the overall study, a sample guideline including emission limits were suggested which will be applied to develop a countermeasure for controlling mercury emission from coal-fired power plants.     

Simultaneous control of Hg0, SO2, and NOx by novel oxidized calcium-based sorbents

Efforts to develop multipollutant control strategies have demonstrated that adding certain oxidants to different classes of Ca-based sorbents leads to a significant improvement in elemental Hg vapor (Hg0), SO2, and NOx removal from simulated flue gases. In the study presented here, two classes of Ca-based sorbents (hydrated limes and silicate compounds) were investigated. A number of oxidizing additives at different concentrations were used in the Ca-based sorbent production process. The Hg0, SO2, and NOx capture capacities of these oxidant-enriched sorbents were evaluated and compared to those of a commercially available activated carbon in bench-scale, fixed-bed, and fluid-bed systems. Calcium-based sorbents prepared with two oxidants, designated C and M, exhibited Hg0 sorption capacities (approximately 100 microg/g) comparable to that of the activated carbon; they showed far superior SO2 and NOx sorption capacities. Preliminary cost estimates for the process utilizing these novel sorbents indicate potential for substantial lowering of control costs, as compared with other processes currently used or considered for control of Hg0, SO2, and NOx emissions from coal-fired boilers. The implications of these findings toward development of multipollutant control technologies and planned pilot and field evaluations of more promising multipollutant sorbents are summarily discussed.     

Effect of NOx Control Processes on Mercury Speciation in Utility Flue Gas

Abstract

The speciation of Hg in coal-fired flue gas can be important in determining the ultimate Hg emissions as well as potential control options for the utility. The effects of NO_x control processes, such as selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR), on Hg speciation are not well understood but may impact emissions of Hg. EPRI has investigated the reactions of Hg in flue gas at conditions expected for some NO_x control processes. This paper describes the methodology used to investigate these reactions in actual flue gas at several power plants. Results have indicated that some commercial SCR catalysts are capable of oxidizing elemental Hg in flue gas obtained from the inlets of SCR or air heater units. Results are affected by various flue gas and operating parameters. The effect of flue gas composition, including the presence of NH₃, has been evaluated. The influence of NH₃ on fly ash Hg reactions also is being investigated.