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Impact of Carbon-in-Ash on Mercury Removal across Particulate Control Devices in Coal-Fired Power Plants Constance L. Senior* Reaction Engineering International, 77 W. 200 S., Suite 210, Salt Lake City, Utah 84103
Stephen A. Johnson Quinapoxet Solutions, 30 Hickory Lane, Windham, New Hampshire 03087 Received June 11, 2004. Revised Manuscript Received January 14, 2005
Emissions of mercury to the environment, in particular air emissions, are of increasing concern in the United States. The U.S. EPA has surveyed sources of mercury emissions, and coal-fired power plants were found to discharge the largest amount of mercury into the atmosphere as compared to other man-made sources. In December 2000, the U.S. EPA made a determination to regulate mercury emissions from coal-fired electric utility boilers. Compliance with the as-yetto-be-determined regulations may necessitate additional air-pollution control devices being installed at utility power plants.There is a considerable amount of data in the literature showing that high levels of mercury removal can occur in existing control devices. Particulate control devices such as electrostatic precipitators and fabric filters are capable of removing mercury, but the level of removal is highly variable, depending on coal type, boiler configuration, mercury speciation in flue gas, and operating conditions in the control device. The composition of the fly ash has been shown to be an important factor in mercury removal (and oxidation). However, the evidence has been, until recently, largely anecdotal. In this paper, we review recent literature on the effects of fly ash carbon content on mercury and present the results of current sampling campaigns on full-scale coal-fired power plants where mercury control processes are being demonstrated. Correlations of Hg removal with carbon content are developed for pulverizedcoal-fired units burning bituminous coals.
Introduction The 1990 Clean Air Act Amendments required the EPA to study the impacts on public health caused by emissions of mercury (and other hazardous air pollutants) from electric utilities. The EPA has estimated that during the period 1994-1995 annual emissions of mercury from human activities in the United States were 158 tons.1 Approximately 87% of these emissions were from combustion sources. Both elemental and oxidized mercury are emitted to the air from combustion point sources. Coal-fired utilities in the United States were estimated to emit 52 tons of mercury per year into the air during this period, or about one-third of anthropogenic emissions. A more recent study by the EPA2 estimated that power plants emitted 43 tons of mercury into the atmosphere in 1999. A similar study carried out by EPRI3 estimated 45 tons per year in 1999 with * Author to whom correspondence should be addressed. E-mail:
[email protected]. Tel: (801) 364-6925. Fax: (801) 364-6977. (1) Keating, M. H.; et al. Mercury Study Report to Congress, Volume I: Executive Summary; EPA-452/R-97-003, December 1997. (2) Kilgroe, J. D.; Srivastava, R. K. “EPA Studies on the Control of Toxic Air Pollutant Emissions from Electric Utility Boilers,” EM, A&WMA’s magazine for environmental managers, January 2001, 3036. (3) Chu, P.; Behrens, G.; Laudal, D. Estimating Total and Speciated Mercury Emissions from U.S. Coal-Fired Power Plants. In Proceedings of the Air & Waste Management Association Specialty Conference on Mercury Emissions: Fate, Effects, and Control; Air & Waste Management Association: Pittsburgh, 2001.
approximately 40% of the emissions consisting of gaseous oxidized mercury. In December of 2003, the U.S. EPA proposed regulations for the emission of mercury from coal-fired power plants. Compliance with the proposed regulation may in some cases necessitate additional controls for mercury. Since some mercury is removed by existing air pollution control devices (APCDs), it is vital to understand the behavior in existing equipment in order to cost-effectively control emissions. Coal-fired power plants already have APCDs such as fabric filters (FFs) and electrostatic precipitators (ESPs) for particulate control, scrubbers for SO2 control and low-NOx burners (LNBs), and selective catalytic reduction (SCR) or selective noncatalytic reduction (SNCR) for NOx control. If there is mercury in the particulate phase at the inlet to an ESP or fabric filter, these devices will remove it efficiently. There can be a substantial amount of mercury in the particulate phase at the inlet to particulate control devices (PCDs). Figure 1 shows the relative amount of gaseous elemental mercury at the inlet to cold-side devices (ESPs, baghouses, scrubbers). The figure is taken from ref 4 and is based on the EPA Information Collection Request (ICR) data. For the low-rank coals (sub-bitminous and lignite), increasing levels of chlorine in the coal appear correlated with decreasing fractions of
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Figure 1. Percentage of mercury in the elemental form at the inlet to the particulate control device (ref 4).
elemental mercury. This trend is expected from consideration of the effect of gas-phase chlorine species on the oxidation of elemental mercury. For the bituminous coals, however, there is little correlation between elemental mercury at the inlet to the PCD and coal chlorine content, suggesting that other factors are important in determining mercury oxidation. High levels of particulate-phase mercury are found in cases where the chlorine content of the coal is greater than 200-300 µg/g (dry basis); these are almost entirely bituminous coals. Bituminous coals can also have more unburned carbon in the fly ash as compared to low-rank coals. Unburned carbon has been suspected of adsorbing mercury for both eastern and western bituminous and sub-bituminous coals. Often a consequence of low-NOx burners or low-NOx combustion systems, pulverized coal boilers can produce high levels of unburned carbon.5,6 Mercury has been found to concentrate in the carbonrich fraction of fly ash.7,8 However, it is not possible to generalize and conclude that high carbon in ash will always give high levels of particulate-bound mercury. Unfortunately, the largest database of mercury speciation and removal in existing coal-fired power plant APCDs (EPA’s ICR data) does not include any information on the carbon content of the ash. A recent attempt to estimate the carbon content from a subset of ICR data9 concluded that increased carbon in the fly ash was positively correlated with increased mercury removal (4) Afonso, R. F.; Senior, C. L. Assessment of Mercury Emissions from Full Scale Power Plants. In Proceedings of the EPRI-EPA-DOEAWMA Mega Symposium and Mercury Conference; Air & Waste Management Association: Pittsburgh, 2001. (5) DeVito, M. S.; Rosenhoover, W. A. Flue Gas Mercury and Speciation Studies at Coal-Fired Utilities Equipped with Wet Scrubbers. In Proceedings of 15th International Pittsburgh Coal Conference; University of Pittsburgh: Pittsburgh, 1998. (6) Gao, Y.-M.; Ku¨laots, I.; Chen, X.; Suuberg, E.; Hurt, R. H.; Veranth, J. M. The Effect of Solid Fuel Type and Combustion Conditions on Residual Carbon Properties and Fly Ash Quality. Twenty-Ninth Symposium (International) on Combustion; The Combustion Institute: Pittsburgh, 2002; pp 475-483. (7) Maroto-Valer, M. M.; Yaulbee, D. N.; Hower, J. C. Fuel 2001, 80, 795-800. (8) Hower, J. C.; Maroto-Valer, M. M.; Taulbee, D. N.; Sakulpitakphon, T. Energy Fuels 1999, 14, 224-226. (9) Sjostrom, S.; Bustard, C. J.; Durham, M.; Chang, R. Mercury Removal Trends in Full-Scale ESPs and Fabric Filters. In Proceedings of the EPRI-EPA-DOE-AWMA Mega Symposium and Mercury Conference; Air & Waste Management Association: Pittsburgh, 2001.
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across cold-side ESPs for both bituminous and subbituminous coal. Unburned carbon (UBC) in fly ash can both adsorb and oxidize mercury for both eastern and western bituminous and sub-bituminous coals.10 Mercury adsorption on carbon is a complex phenomenon that depends on temperature, secondary flue gas components (including SOx, HCl, NOx), carbon particle size, surface area, type of coal, and surface chemistry. Recent studies suggest that oxide groups on carbon surfaces enhance the uptake of mercury from inert carrier gas streams11,12 but may suppress uptake in real or simulated flue gases.13 Other studies suggest that this difference is related to the dual function of carbon surfaces in mercury adsorption14sthey serve as oxidation catalysts and also as binding sites for the oxidized species. The amounts and properties of native unburned carbon depend in turn on fuel selection (coal type) and combustion conditions. Because of these sensitivities, there is great opportunity to enhance mercury capture on the native UBC by modifying the combustion process. Previous pilot-scale work15,16 has shown that modifying the combustion process to increase carbon in ash has led to increases in the amount of oxidized mercury at the inlet to an ESP or fabric filter and increases in the amount of mercury removed across the particulate control device for bituminous and sub-bituminous coals. However, pilot-scale combustion systems are not always completely representative of full-scale combustion systems, nor do they always completely represent the time-temperature history in a full-scale boiler that is important to the transformations of mercury. Therefore, it is important to see confirmation in full-scale data. In this paper, data from full-scale power plants are reviewed with the intent of assessing the impact of fly ash carbon on mercury removal across ESPs. New data are combined with existing data from the literature. All of the field data used in this paper include measurements of mercury speciation and removal across the ESPs and measurements of the carbon content of the ESP hopper as loss on ignition or LOI. Data Collection While the ICR database does not contain measurements of LOI, Sjostrom et al.9 estimated the LOI of the fly ash from plants that were included in the ICR database having ESPs (10) Dunham, G. E.; DeWall, R. A.; Senior, C. L. Fuel Process. Technol. 2003, 82, 197-213. (11) Ghorishi S. B.; Gullett, B. K. Waste Manage. Res. 1998, 16, 582593. (12) Ghorishi S. B.; Keeney R. M.; Serre S. D.; Gullett B. K. Environ. Sci. Technol. 2002, 36, 4454-4459. (13) Chen, X.; Mehta, A.; Paradis, J.; Hurt, R. H. Developing ashutilization-friendly sorbents for gas-phase mercury removal in coal combustion flue gas. In Proceedings of the 29th International Technical Conference on Coal Utilization and Fuel Systems; Coal Technology Association: Gaithersburg, MD, 2004. (14) Pavlish, J. H.; Sondreal, E. A.; Mann, M. D.; Olson, E. S.; Galbreath, K. C.; Laudal, D. L.; Benson, S. A. Fuel Process. Technol. 2003, 82, 89-165. (15) Lanier, W. S.; Booth, C. M., Lissianski, V. M.; Zamansky, V. M.; Maly, P. M.; Seeker, W. R. Method to decrease emissions of nitrogen oxide and mercury, U.S. Patent 6,726,888, 2004. (16) Gale, T.; et al. Mercury Speciation as a Function of Flue Gas Chlorine Content and Composition in a 1 MW Semi-industrial Scale Coal-Fired Facility. In Proceedings of the DOE-EPRI-U.S. EPA -A&WMA Combined Power Plant Air Pollutant Control Symposium The Mega Symposium; Air & Waste Management Association: Pittsburgh, 2003.
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Table 1. Coal Properties (Dry Basis) and Boiler Description
plant 1 plant 2 plant 3 plant 4 plant 5 plant 6 plant B-2 plant B-3 plant B-4 plant B-5 plant B-7 plant C plant D plant E
ash
SO2, lb/MBtu
HHV, Btu/lb
Cl, µg/g
firing system
PCD
LOI in ESP hopper ash, wt%
Hg removal, %
ref
13.9% 10.9% 18.5% 10.1% 10.0% 13.6% 7.8% 9.6% 13.0% 7.0% 10.7% 4.3% 9.1% 14.2%
5.36 5.94 6.04 6.61 6.41 5.6 0.51 0.53 1.37 0.79 0.42 0.8 1.12 1.81
13 130 12 737 11 729 12 731 12 753 12 332 13 744 12 818 10 920 12 610 11 547 14 056 13 787 13 177
1100 1600 1100 2300 1400 1300 575 966 2100 800 333 206 1449 112
PC PC cyclone stoker PC PC PC PC PC PC PC PC PC PC
ESP ESP ESP ESP ESP ESP ESP ESP ESP ESP ESP ESP ESP HESP
4.0% 1.0% 35.0% 43.5% 3.5% 0.1% 5-10% 3-7% 5-10% 5-10% 3-6% 21-30% 4-9% 10-13%
24.0% 7.0% 13.0% 35.0% 9.0% 8.0% 26.0% 23.0% 24.0% 30.0% 46.0% 87.0% 64-92% 10.0%
5 5 5 5 5 5 9 9 9 9 9 17 17 17
or fabric filters. DeVito and co-workers5 measured mercury speciation at the inlet and outlet of electrostatic precipitators at six coal-fired power plants burning Northern Appalachian or Illinois Basin bituminous coals. Mercury speciation was measured by the Ontario Hydro method. The mercury content and LOI of the ESP hopper ash was also measured. This allowed the calculation of mercury mass balances across the APCDs in the plants in question. Mercury mass balance closures were very good, in the range of 92-116%. New data have been obtained under an ongoing cooperative agreement between DOE/NETL and ADA Environmental Solutions (ADA-ES). In this program17 ADA-ES carried out full-scale demonstrations of activated carbon sorbent injection at coal-fired utility boilers. ADA worked in partnership with PG&E National Energy Group; WE Energies; Alabama Power Company, a subsidiary of Southern Company; and EPRI on this program. Organizations participating in the program as team members included Apogee Scientific, Energy & Environmental Strategies, Hamon Research Cottrell, Microbeam Technologies, Norit Americas, Quinapoxet Solutions, Reaction Engineering International, and URS Corporation. As part of this program, detailed characterization of the baseline operating conditions was carried out at the plants chosen for sorbent injection. Gaseous mercury speciation measurements were made upstream and downstream of the PCDs using Apogee Scientific’s continuous mercury monitor. Coal and ash hopper samples were taken and analyzed for mercury. LOI was also measured on hopper samples. The properties of the coals burned in the plants described here are given in Table 1. Plants designated 1 through 6 are those characterized by DeVito, while plants designated B-2 through B-7 are taken from Sjostrom et al.9 Plants C, D, and E comprise the new data obtained in the ADA-ES program.17 All plants burned bituminous coals with similar heating values. The sulfur contents varied from 0.5 to 6.6 lb/106Btu (0.22-2.84 g/MJ). The chlorine contents ranged from 100 µg/g up to more than 2300 µg/g. All of the units had ESPs (Table 2). Plant B was the only unit with a hot-side ESP (HESP); all the other plants had coldside ESPs. All the plants except Plants 3 and 4 burned pulverized coal. Plants 3 and 4 were cyclone and stoker units, respectively.
Results and Discussion The bituminous ash data under cold-side ESP conditions exhibited a consistent trend of increasing mercury removal with LOI (Figure 2), although the chlorine contents varied by an order of magnitude among the coals. A second-order polynomial fit of the pulverizedcoal-fired data (from cold-side ESPs) yielded a value of (17) Bustard, J.; Durham, M.; Starns, T.; Lindsey, C.; Martin, C.; Schlager, R.; Baldrey, K. Fuel Process. Technol. 2004, 85, 549-562.
Table 2. LOI (or Carbon Content) and Surface Area of Ash Samples from Bituminous Coal (Full-Scale Power Plants) plant
coal
firing system
LOI, wt%
SA, m2/g
SA, m2/g C
plant 1 plant 2 plant 3 plant 4 plant 6 plant C plant C plant C plant C plant E plant E plant E plant E UK1A UK1B UK1C UK1D NEP1 NEP2 MTU1
IL bit. IL bit. IL bit. IL bit. Ohio bit S. Amer. bit. S. Amer. bit. S. Amer. bit. S. Amer. bit. S. App. bit. S. App. bit. S. App. bit. S. App. bit. E. bit. E. bit. E. bit. E. bit. S. Amer. bit E. bit. E. bit.
PC PC cyclone stoker PC PC PC PC PC PC PC PC PC PC PC PC PC PC PC PC
6.2a 1.5a 37.1a 44.4a 0.7a 21.0 26.8 30.0 12.6 13.1 11.9 13.6 13.7 30.0b 52.2b 67.1b 73.0b 19.8b 24.3b 38.6b
6.2 1.0 4.4 3.9 0.7 10.6 22.5 16.3 5.7 5.3 7.1 12.5 8.3 18.8 27.4 36.0 36.8 13.6 12.0 28.7
97.7 57.4 11.7 8.8 91.1 49.8 83.6 54.0 44.5 39.9 59.4 90.9 60.0 62.7 52.5 53.7 50.4 68.7 49.4 74.4
a
Reference 10. b Reference 19, reported as % carbon.
Figure 2. Mercury removal across full-scale ESPs as a function of LOI in ESP hopper ash.
r2 of 0.56. This suggests that a relationship exists between ash LOI and mercury removal for plants burning bituminous coals in pulverized-coal-fired boilers with cold-side ESPs. More data are needed to confirm if this relationship holds for a wider range of coals. The outliers in Figure 2 merit discussion. The data from the plant with a hot-side ESP (Plant E) show uniformly lower mercury removal for a given percentage of LOI as compared to the data for the other pulverizedcoal fired plants. Hot-side ESPs operate upstream of the air preheater at temperatures of 300-400 °C (570-750 °F), while cold-side ESPs operate downstream of the air
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preheater at temperatures of 135-175 °C (375-350 °F). Adsorption of mercury by fly ash or activated carbon has been observed to decrease as temperature increases.10,18 The higher temperatures of the hot-side ESP favor lower adsorption of mercury upstream of the ESP (and thus less capture of particulate-bound mercury in the ESP). Furthermore, the flue gas path between the air preheater inlet and the inlet of a coldside ESP provides additional residence time for mercury sorption, which may contribute to the higher removal of mercury observed across cold-side ESPs. The values of mercury removal for the cyclone and stoker units shown in Figure 2 are considerably lower than those for pulverized-coal-fired units with similar values of LOI. To determine if these points are outliers, the surface areas of selected fly ash samples were examined. Dunham et al.10 characterized five of De Vito’s ash samples for surface area and mercury adsorption and capture. As part of the ADA-ES program, the surface was measured on a subset of ash samples. Baltrus et al.19 measured surface area and other properties of ash samples from bituminous coals. For bituminous coals, the LOI can be used to estimate the carbon content of the fly ash. Table 2 gives the measured total surface areas of the fly ash and the LOI (or carbon content). The surface area of the carbon, in m2/g C, is estimated from the reported properties. For the bituminous coal fly ash samples from pulverized coal-fired boilers, the carbon surface area lies between 40 and 100 m2/g C. These values agree with others reported by Hurt et al. for Class F (bituminous) fly ash samples.6 The cyclone and stoker ash samples have lower carbon surface areas (8-11 m2/g C), which may explain the lower amount of mercury removal across ESPs in those boilers. For comparison, the activated carbon produced by Norit Americas for removal of mercury from flue gas in coal-fired power plants has a surface area of 600 m2/g.17 Fixed-bed studies can provide some insight into the mechanisms for mercury adsorption on carbon and will be discussed here briefly in order to provide insight into the results, particularly with respect to the leap from adsorption on fly ash carbon to adsorption on activated carbon. Both elemental mercury and HgCl2 are adsorbed by activated carbon and, in some cases, by fly ash at temperatures characteristic of the PCD. Saturated activated carbon capacities at equilibrium are much less than monolayer coverage,18 which suggests that only certain sites on the surface are active for mercury adsorption. The equilibrium capacity is a function of the concentration of mercury in the gas18,20 and has an inverse dependence on temperature.18 The adsorption of HgCl2 on activated carbon is not greatly affected by flue gas composition.20 The adsorption of Hg0, however, is highly dependent on gas composition and involves interaction with the acid gases (NOx, SOx, HCl) by paths that are not known. SO2 has (18) Karatza, D.; Lancia, A.; Musmarra, D.; Pepe, F. Adsorption of Metallic Mercury on Activated Carbon. Twenty-Sixth Symposium (International) on Combustion; The Combustion Institute: Pittsburgh, 1996; pp. 2439-2445. (19) Baltrus, J. P.; Wells, A. W.; Fauth, D. J.; Diehl, R.; White, C. M. Energy Fuels 2001, 15, 455-462. (20) Carey, T. R.; Hargrove, Jr.; O. W., Richardson; C. F., Chang; R., Meserole; F. B. J. Air Waste Manage. Assoc. 1998, 48, 1166-1174.
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Figure 3. Carbon surface area for fly ash samples from bituminous coal burned in pulverized-coal boilers, unless otherwise noted.
Figure 4. Equilibrium capacity for elemental mercury (at a gas-phase mercury concentration of 50 µg/m3) for Wyodak fly ash and FGD carbon in simulated flue gas normalized to surface area (source: refs 10, 20).
been shown to displace adsorbed mercury,21 which suggests that the acid gases are adsorbed on specific sites where they interact with adsorbed mercury. The result of adsorption of Hg0 on carbon is an oxidized species (and not elemental mercury) on the surface of the carbon based on X-ray absorption fine structure spectroscopy (XAFS) analysis22 and based on the desorption of oxidized species.20,21 The mercury capacities of fly ash carbon (expressed per gram of carbon or per square meter of surface area) are considerably lower than those for commercial activated carbon. Figure 3 compares the equilibrium capacity for elemental mercury of Norit Americans FGD carbon20 with that of Wyodak fly ash generated in a pilot scale combustor.10 Note that the Wyodak fly ash was unusual in that it had about 4% carbon and a high surface area for fly ash (∼13 m2/g). SEM photos of this ash suggested that soot, unburned char, and ash were present. Since the mercury adsorption data were obtained in a fixed-bed apparatus in which mass transfer should not limit sorption, we conclude that the number and type of active sites is at least 10 times higher for commercial activated carbon than for this fly ash carbon. With respect to full-scale systems, the temperature, the nature of the surface sites, and the acid gases present in the flue gas will all affect adsorption of Hg0 (21) Miller, S. J.; Dunham, E. A.; Olson, E. S.; Brown, T. D. Fuel Process. Technol. 2000, 65-66, 343-363. (22) Huggins, F. E.; Yap, N.; Huffman, G. P. Jpn. J. Appl. Phys. 1999, 38, 588-591.
Mercury Removal in Coal-Fired Power Plants
and HgCl2 and oxidation of Hg0. Fly ash carbon and activated carbon have very different sorption capacities for mercury. When attempting to compare full-scale data on mercury removal by ash or oxidation (either by activated carbon or fly ash carbon), it is important to take note of the temperature, gas composition, and type of carbon, as well as the native mercury speciation in the flue gas. Conclusions Activated carbons currently being evaluated as Hg sorbents are derived from coal. This concept should not be surprising since treatment of power plant flue gases require huge tonnages and coal is the cheapest, most abundant source of carbon in the United States. The coal is partially oxidized in a kiln to provide the carbon and then further treated (usually with steam) to open up the appropriate pore structure and size distribution for Hg capture. Activated carbon is typically about 80% carbon and 20% ash, with trace amounts of sulfur, nitrogen, and oxide groups that also influence reactivity. Activated carbon is milled after activation to produce the desired particle size (external surface area) for higher reactivity. Fly ash that is 5-30% carbon represents coal that is 98-99.7% oxidized. Pore structures depend on coal type and combustion environment, but low-NOx combustion tends to produce smaller and more porous structures in oxygen-deficient regions of the flames. Activated carbon size distribution (due to grinding after activation) is usually slightly smaller than LOI carbon. LOI carbon from most coals can react with Hg, but capacity is usually quite limited, as shown above. The limited data collected from full-scale systems to date show that mercury removal across ESPs in pulverized-coal-fired boilers burning bituminous coals appears to be related to the LOI or unburned carbon in the fly ash. The surface area of the carbon in the fly ash was remarkably consistent among the samples from pulver-
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ized-coal-fired units; combustion systems that produced fly ash with lower carbon surface area showed lower mercury removal across the ESP. These conclusions cannot be extended to fly ash from sub-bituminous coals and lignites, however. There is evidence in the literature6 that the surface area of carbon from Class C (subbituminous) fly ash samples is considerably higher than that of Class F fly ash samples on a per gram of carbon basis. The important news is that huge amounts of LOI may be available; especially as low-NOx combustion systems strive to meet stricter compliance regulations during the latter half of this decade. LOI carbon could displace a small amount of activated carbon to reduce the operating costs of an integrated NOx-Hg-particulate control system. Another reason that we need to better understand the removal efficiency of LOI carbon for Hg capture is to better take advantage of LOI in the design and operation of Hg-control systems. Quinapoxet is working with suppliers of emerging ash beneficiation technologies that separate LOI carbon from salable mineral ash. The high-carbon stream has already removed some Hg but is far from saturated. We are investigating ways to reinject the high-carbon stream into the boiler system to minimize disposal costs. One concept is to use the highcarbon stream to replace some of the activated carbon in a dedicated fabric filter system (EPRI TOXECON) where temperature conditions permit further Hg capture. Here, the tradeoff is the extra capital cost of a larger fabric filter to handle the additional particle loading against the reduced cost of reagent. Another scheme is to monitor and control the combustion process for LOI production to affect both NOx and Hg control. Such opportunities will be highly site-specific but could offer significant compliance cost savings for the boiler owner. EF049861+
