A Look into the Crystal Ball: Post-MATS Utility Environmental Challenges

Transcription

1 A Look into the Crystal Ball: Post-MATS Utility Environmental Challenges Paper # 116 Presented at the Power Plant Pollutant Control MEGA Symposium August 19-21, 2014 Baltimore, MD Constance Senior 1, Sharon Sjostrom 1 ; 1 ADA-ES, Inc., 9135 S. Ridgeline Blvd., Suite 200, Highlands Ranch, CO ABSTRACT The years leading up to the final compliance date of the Mercury and Air Toxics Standards (MATS) have kept utilities busy testing, designing, and procuring new emission control systems to meet limitations on mercury, acid gases, and particulate matter. Compliance begins in the timeframe (as some utilities have received extensions from their state agencies). After MATS compliance, coal-fired electric utilities will face new regulatory challenges. In this paper, we look into the often-cloudy crystal ball for utility environmental compliance. In particular, data and results from a number of previous field demonstrations will be analyzed in the light of the needs for fuel flexibility and compliance with MATS as well as coming regulations on coal combustion residuals and effluent guidelines for water and wastewater discharges.. Multi-media emissions of trace metals and halogens, greenhouse gas requirements, and the ongoing challenge of maintaining fuel flexibility will be discussed. INTRODUCTION Electricity generating unit (EGU) boilers face a variety of regulatory challenges, some of which are certain, while others are unclear. Currently, EGU boilers are dealing with the certainty of the Mercury and Air Toxics Standard (MATS), as well as other regulations on air emissions. On the horizon, are new regulations on water discharges and ash disposition. On February 16, 2012, the final rule for National Emission Standards for Hazardous Air Pollutants from coal- and oil-fired electric utility steam generating units was published in the Federal Register (Vol. 37, No. 22). The rule is intended to regulate emissions of mercury and selected metals (Sb, As, Be, Cd, Cr, Co, Pb, Mn, Hg, Ni, and Se), gases, and organics like dioxins and furans. Numerical emission limits were set for mercury and the other metals. With the exception of mercury, sources can comply with the limits on metals by controlling particulate matter (PM) emissions as a surrogate. Similarly, compliance with acid gas emissions can be achieved by controlling emissions of HCl (on coal-fired utility boilers) as a surrogate. Boilers that have flue gas desulfurization (FGD) technology in place can monitor emissions of SO2 instead of HCl, using an alternate emissions limit. A work-practice standard, intended to 2014 ADA-ES, Inc. 1

2 optimize combustion efficiency, is established for reduction of organic emissions. This rule, known as the Mercury and Air Toxics Standards (MATS), will be effective April 15, 2015, although some states have granted one-year extensions to certain plants. In addition to the MATS rule, which addresses hazardous air pollutant (HAP) emissions, utilities may be subject to other air emission regulations related to EPA s charter to maintain ambient air quality. The Regional Haze program is designed to ensure that air emissions do not impair visibility in parks and wilderness areas. The pollutants that reduce visibility include fine particulate matter (PM2.5) and compounds that contribute to PM2.5 formation, such as nitrogen oxides (NOx) and sulfur dioxide (SO2). This rule is aimed at older facilities, those from 35 to 50 years old. Regional Haze requirements were established in 1999 and state implementation plans (SIPs) were due in States must determine Best Available Retrofit Technology (BART) and identify long-term strategies to ensure that reasonable progress is being made to meet the national regional haze goal. The Transport Rule has had various names, the latest being the Cross States Air Pollution Rule (CASPR), which replaced the Clean Air Interstate Rule (CAIR), covering 27 eastern states and the District of Columbia. While the name has changed, the intent remains to reduce emissions from power plants that may result in exceedances of the 1997 ozone and PM2.5 and 2006 PM2.5 National Ambient Air Quality Standards (NAAQS). The rule requires reductions in ozone season NOx emissions that cross state lines for states under the ozone requirements, and reductions in annual SO2 and NOx for states under the PM2.5 requirements. How the reductions are achieved in CAIR and the Transport Rule differs substantially. Under CAIR, all states were part of one region, while in the Transport Rule, states covered by NOx limitations are one region, while states covered by SO2 limitations are divided into two regions, Group 1 and Group 2. Group 1 and Group 2 allowances cannot be traded with each other, but can be traded within each group. On August 2012, the United States Court of Appeals for the D.C. Circuit vacated CSAPR and ordered the EPA to continue to administer CAIR while working on a replacement Transport Rule. In April 2014, the U.S. Supreme Court reversed the D.C. Circuit opinion vacating CSAPR. On June 26, 2014, the U.S. government filed a motion with the U.S. Court of Appeals for the D.C. Circuit to lift the stay of the CSAPR. During the period while the Court considers the motion, the EPA indicated that ( CAIR remains in place and no immediate action from States or affected sources is expected. EPA recently proposed the Clean Power Plan for reduction of CO2 emissions from existing EGUs. This rule is not due to be finalized until June, 2015, and legal challenges will almost certainly ensue. Thus, the final rule isn t clear; broadly speaking, the rule gives individual states a cap on the overall CO2 emission rate. States are to submit SIPs to EPA outlining how the rule will be implemented. Regional trading among states could be one option. The rule might result in closures of older, less efficient coal-fired EGUs and in more load-cycling of existing coalfired boilers ADA-ES, Inc. 2

3 Additionally, impending rules for the disposition of ash and other combustion byproducts (the Coal Combustion Residue or CCR Rule) and for water discharges (the Effluent Limitation Guidelines or ELG) can affect the choices that EGUs make regarding their air pollution control strategies. Neither of these rules has been finalized, but in their final forms, utilities might have to convert wet ash-handling systems to dry-ash handling systems, use lined landfills with leachate monitoring for byproduct disposal, and be subject to limitations on the discharge of mercury, arsenic, and selenium from wet FGD scrubbers. This discussion attempts to illustrate the many different facets of compliance for coal-fired EGUs. Many plants have been focused recently on complying with the MATS rule, but beyond MATS lie more challenges. Each plant is unique and the appropriate solution for one plant that supports compliance with existing regulations and provides flexibility for future federal, state, and local regulations may not be appropriate when broadly applied. In this paper, three case studies will be presented to provide some perspectives associated with potential challenges plant may encounter over the next few years. CASE STUDIES Case 1: Bituminous coal-fired plant with SCR, ESP, and WFGD Based upon data from the Energy Information Administration (EIA) supplemented with updated information from plants, approximately 14% of plants operating in the United States are firing bituminous coal and are configured with selective catalytic reduction (SCR) technology for NOx control, an electrostatic precipitator (ESP) to control particulate emissions, and a wet flue gas desulfurization (WFGD) scrubber to control sulfur dioxide emissions. While developing the MATS rule and the associated costs and control options for achieving compliance, EPA relied heavily on available data from short-term testing programs. EPA developed emissions factors for nearly every configuration. For the Case 1 configuration, EPA assumed that the combination of a SCR and a WFGD installed on a bituminous coal would result in 90% control (i.e., 10% emission factor). For other configurations, the addition of the SCR did not improve mercury removal. Relative emissions factors developed by EPA are presented in Figure 1 for reference. 1 The possibility of reliably achieving 90% Hg removal with an SCR-FGD combination depends on several factors related to design and operation of air pollution control devices not intended for mercury control. Careful consideration of the operation of these devices is therefore warranted. The main function of the reactive sites on an SCR catalyst is to attract the NH3 to the catalyst surface, and oxidize NH3 to NH2 so that it can remove NO from the flue gas. SCRs can also promote the oxidation of halogens, which can then react with mercury. At SCR temperatures, chlorine contained in combusted coal is present primarily as HCl ADA-ES, Inc. 3

4 Figure 1. Mercury emission factors for SO 2 control devices cited in EPA s Integrated Planning Model (IPM) assessment for MATs (Source: Ref. 1) Emissions Factor Bit Bit-SCR Subbit Subbit-SCR Lignite Lig-SCR 0 None WFGD DFGD SO 2 Control The following global reactions have been identified as being of importance in coal-fired SCR reactors. 2 HCl + Hg 0 + 1/2 O2 HgCl2 + H2O (1) 2 NH3 + 3 HgCl2 N2 + 3 Hg HCl (2) 2 NO + 2 NH3 + ½ O2 2 N2 + 3 H2O (3) Reaction 1 is the oxidation of Hg 0 with HCl. Reaction 2 is the reduction of HgCl2 with NH3. Reaction 3 is the DeNOx reaction. The net rate of Hg oxidation is the sum of oxidation (Reaction 1) and reduction (Reaction 2). At SCR temperatures less than about 615 o F (325 o C), reduction of HgCl2 by NH3 can take place. Reaction 3 will affect the rate of Reaction R1 by consuming active sites on the catalyst, which can oxidize Hg 0. The effectiveness of an SCR for halogen oxidation is affected by several variables. Studies have shown that mercury oxidation varies with unit load. 3 This is likely a result of increased ammonia flow rate (and coverage of active sites), gas residence time and temperature, where the residence time is typically longer at lower load, and the temperature is lower. Honjo et al. studied the effect of flue gas temperature on mercury oxidation on a specific SCR catalyst. 4 These results 2014 ADA-ES, Inc. 4

5 are shown in Figure 2. Although each catalyst will have different characteristics and flue gas composition can vary widely, there is a general trend of reduced performance at higher temperatures. Figure 2. Impact of SCR temperature on mercury oxidation with 10 ppmv HCl in flue gas. (Source: Ref. 4) Hg Oxidation (%) Flue Gas Temp (F) The mercury oxidation activity of an SCR catalyst also decreases as the catalyst ages. 4 Increasingly, a catalyst management strategy involving measuring and planning for not only loss of denox activity, but also changes in mercury oxidation activity with time, is recommended. In recent years catalyst manufacturers have advanced the understanding of mercury oxidation across SCR catalysts in coal-fired boilers, leading to improvements in catalysts. One catalyst manufacturer claims that their optimized catalyst has a mercury oxidation that is 50% to 400% higher than their standard catalyst, depending on the flue gas composition. 5 Another catalyst manufacturer claims to have a catalyst that produces greater than 95% oxidation of mercury for flue gas from bituminous coals and greater than 85% oxidation of mercury for flue gas from subbituminous coals, while keeping the oxidation of SO2 to 0.15% to 0.25% per layer. 6 When sufficient oxidized mercury is present in the flue gas, WFGDs are considered an effective mercury control option because oxidized mercury is water soluble. However, if the mercury remains in the liquid-phase rather than associating with solids in the scrubber, there is a risk that the oxidized mercury will be reduced and re-emitted as elemental mercury, which is much less soluble than oxidized mercury. There are several factors that can contribute to the likelihood of 2014 ADA-ES, Inc. 5

6 re-emission including how oxidizing the scrubber solution is, as measured by the Oxidation Reduction Potential (ORP), the scrubber ph, and level of halogens in the scrubber. Many plants firing bituminous coals with SCRs and WFGDs are planning to rely on co-benefits from these systems for mercury control. While this system may be appropriate for most of the year, especially under a compliance scenario where the averaging period is 30- or 90-days, some evidence suggests that compliance throughout the year is not necessarily assured. During , Southern Company monitored mercury emissions from five of its plants firing exclusively Central Appalachian bituminous coals. 3 During this period, the coal mercury ranged from 0.02 to 0.19 ppmw and chlorine ranged from 84 to 2352 ppmw. The equivalent uncontrolled mercury emissions based on the coal mercury was calculated to be 1.51 to lb/tbtu. Although the EPA emissions factors predicted 90% control, analysis of the emissions from the five Southern Company plants indicated that 90% control was achieved only 47% of the operating time. The factors limiting greater controls were primarily attributed to reduced oxidation across the SCR and periods of mercury re-emissions from the WFGD. In the Case 1 scenario, a plant may be in compliance until the hot summer months when the load demand is high, or until an operator alters scrubber operation that result in an increase in mercury re-emissions are increased. In the summer scenario, the temperatures will consistently be elevated due to high ambient temperatures, ammonia flows will be high to maximize load, and corresponding velocities through the SCR will be high. All of these factors are expected to lower the fraction of oxidized mercury. Activated carbon is often considered for supplemental mercury control. Unfortunately, mercury control using activated carbon is also more challenging when gas temperatures are elevated, and on units firing bituminous coals where the coal sulfur results in higher levels of SO3. Thus, Case 1, rather than a low risk mercury control scenario, can represent a very challenging case for compliance during periods of the year when load demand may be the highest. Case 2: Subbituminous coal-fired plant with ESP and supplemental SO2 control Approximately 16% of plants operating in the United States are firing subbituminous coal and are configured with an ESP to control particulate matter, but do not have supplemental equipment to control SO2. Many of these plants are currently operating below existing SO2 emissions limits. However, some will require supplemental acid-gas controls either due to statespecific SO2 rules, as a result of the re-instatement of CSAPR, or because their HCl exceeds emissions limits for MATS, which is a concern for units firing a blend of bituminous and subbituminous coals. Review of the SO2 emissions from 2013 indicated that 9 states listed as Group 1 States for CSAPR exceeded their Phase 2 budget for SO2, and plants in those states may be required to implement additional controls to reduce state emissions. These states include Illinois, Indiana, Kentucky, Michigan, Ohio, Pennsylvania, Virginia, West Virginia, and Wisconsin. Of the Case 2 plants, more than 50% are operating in the above Group 1 states and may be considering options for additional control ADA-ES, Inc. 6

7 In a February 2014 presentation, the Brattle Group 7 reported on the projected capital costs for various retrofit control equipment compared to unit size. This costing data for SO2 controls is shown in Table 1 for reference. The cost of dry sorbent injection (DSI) represents a significant cost savings over other options, and many plants are considering DSI for their control needs. Table 1. Capital Cost of Control Equipment in 2011 $/kw 7 Unit Size (MW) Equipment WFGD Dry Scrubber Dry Sorbent Injection DSI, especially sodium-based DSI such as trona and sodium bicarbonate (SBC), can be very effective at controlling SO2 and HCl. During a study conducted by DTE Energy in 2012, 8 both trona and SBC were evaluated for HCl control. At a normalized stoichiometric ratio of just below 1.2 (SO2 basis), up to 60% SO2 capture was achieved and HCl was controlled to well below the target emission limit for HCl. The HCl target emissions were achieved at an NSR in the range of 0.2 to 0.4. When trona or SBC are injected into the flue gas, a reaction occurs that produces NO2. 9 During the DTE study, the impact of NO2 on the effectiveness of activated carbon for mercury control was also evaluated. In Figure 3, data are presented for trona injected both upstream and downstream of the air heater (APH). The data demonstrates that trona was more effective for HCl control when injected upstream of the APH, and more NO2 was produced when trona was injected upstream of the APH. The impact of sodium-based DSI on mercury emissions is clearly shown in Figure 4. Without DSI, the plant was able to achieve MATS levels of mercury emissions. At an NSR of 0.7 to 0.8, sufficient for 25% SO2 control with 100% PRB fuel and 40% SO2 control with a 85% PRB/15% bituminous blended fuel, PAC was required to achieve the target mercury emissions. The study demonstrated that the PAC was reducing NO2 emissions and that the NO2 was interfering with mercury emissions. Although high levels of SO2 control were not the objective of the DTE tests, a linear relationship between NO2 production and SO2 control was observed. The production of NO2 from sodium sorbents will be affected by the injection temperature and available residence time; thus, it is difficult to identify a universal relationship for NO2 production. However, for plants targeting more than 30 to 40% SO2 trim using sodium-based DSI, significant impacts to mercury control should be expected as a result of NO2 formation. In addition, to challenges introduced for mercury control, DSI sorbents can have other unintended consequences. For example, sodium is very soluble and sodium-containing ash can mobilize heavy metals in ash. 10,11 Discharge limits for selenium are of particular concern and are 2014 ADA-ES, Inc. 7

8 identified in the proposed Effluent Limitation Guidelines (ELG). Prior to implementation of the ELG, sodium-containing ash entering an ash pond may mobilize metals otherwise stable in the pond. Sodium-containing ash may also require special ash handling procedures to limit sodium leaching, which can affect surrounding plant life. If large amounts of sodium are contained the ash, landfill subsidence may be a concern if significant mass leaches out, leaving vacancies in the landfill and affecting its overall stability. Figure 3. Impact of trona injection on HCl removal and NO2 production at St. Clair Unit 3, firing 85/15% Coal Blend (Ref. 8) HCl Pre APH NO2 Pre APH HCl Post APH NO2 Post APH HCl (lb/mmbtu) NO 2 (ppm) Trona Injection Rate Figure 4. Impact of Sodium DSI on Mercury Emissions at St. Clair units firing 85/15% Coal Blend (Source: Ref. 8) ADA-ES, Inc. 8

9 2.5 2 Unit 3 - Trona (0.8 NSR) Unit 3 - SBC (0.7 NSR) Unit 7 - Trona (0.45 NSR) Hg (lb/tbtu) Unit 7 - Trona (0.95 NSR) Hg Target PAC Injection Concentration (lb/mmacf) Although choosing DSI for SO2 or HCl trim may appear to be the appropriate economic choice for many unscrubbed plants, challenges associated with inadvertent impacts on mercury control due to NO2, and impacts to ash and landfill management may result in additional unplanned costs. Case 2 is another example of the complexity associated with managing emissions in a coal fired power plant. Case 3: Halogen addition for mercury oxidation control Addition of halogen compounds, either to the fuel or to the flue gas, has been demonstrated as an effective way to increase the amount of oxidized mercury in the flue gas, which can improve mercury emissions control. Configurations in which adding halogens to the fuel or flue gas is advantageous for mercury emissions control include the following. A low-halogen fuel and the use of a non-brominated PAC (in the hope that this combination would be cheaper than brominated PAC by itself); A low-halogen fuel on a unit with a wet or dry FGD with the intent of using the scrubber as the primary mercury removal device; Refined Fuel use which modification of the fuel by adding halogens results in sufficient demonstrated mercury reduction to qualify for tax credits under IRS Section 45. Generally the addition of 150 μg/g bromine (fuel equivalent basis) is sufficient to produce greater than 80% oxidized mercury at the outlet of the particulate control device (as illustrated in Figure 5 for low-halogen coal plants with cold-side ESPs). 12,13,14,15 The presence of an SCR has been shown to reduce the amount of bromine needed for high levels of oxidation. Catalytic surface, that is, an SCR catalyst, can oxidize mercury in the presence of halogens (previously discussed in Case 1) ADA-ES, Inc. 9

10 %Hg 2+ at ESP Outlet 100% 80% 60% 40% 20% 0% Equivalent coal bromine, μg/g dry Low rank coals, no SCR PRB, with SCR (Miller) PRB, with SCR (EMO) Figure 5. Fraction of oxidized mercury at ESP outlet as a function of bromine addition. 12,13,14,15 Balance of plant issues must be considered, when anything new is added to a boiler and its APCDs. An ongoing study by EPRI 16,17,18 on the balance of plant effects of bromine addition (including direct bromine addition and injection of brominated PAC) has, to date, identified corrosion as the major observed impact. The most commonly reported corrosion locations in the EPRI study associated with bromine addition were the cold-end baskets of air heaters. This corrosion was only observed on plants firing subbituminous coals or subbituminous-bituminous blends. Furthermore, most of the corrosion identified in plants in which bromine was added to the fuel took place in plants at which bromine addition rates were greater than 100 μg/g Br (coal equivalent basis). Certain types of brominated PACs have been associated with severe air heater corrosion, when the PACs are injected upstream of the air heater. 19 In particular, PAC that was brominated with ammonium bromide was in use. The speculation was that ammonium bromide could decompose at pre-air heater temperatures, and release gas-phase bromine compounds, which could condense or in some way react with the cold-end basket surface in the air preheater. Adding bromine to the flue gas has been demonstrated to increase the concentration of bromide ion in the liquid phase in a wet FGD scrubber. 12 If halogens in the scrubber liquor are increased and the materials of construction weren t designed for those increased halogen levels, corrosion could result. 16 In particular, scrubbers designed to operate on boilers firing Powder River Basin subbituminous coals, which typically have 25 μg/g chlorine or less, might not be constructed of the right materials for long-term operation with addition of greater than 100 μg/g bromine. In at least one case, an increase in brominated organic compounds in the wet FGD scrubber discharge has been observed with bromine addition to the fuel, although not at high enough concentrations to be of concern. 16 Increase of halogens (chloride, bromide, etc.) in wet scrubber liquid discharge could potentially be a problem, if the waters are discharged to a body of water with a drinking water treatment plant downstream. In public drinking water systems, the US EPA sets a limit of 80 parts per billion (μg/l) on the total concentration of four trihalomethanes (THMs): chloroform, bromoform, bromochloromethane, and dibromochloromethane. 20 In the chlorine disinfection process in the treatment plant, THMs containing bromine can be formed; there is a concern about the toxicity of brominated THMs ADA-ES, Inc. 10

11 The addition of bromine compounds to the flue gas has been observed to increase the concentration of selenium in the flue gas downstream of the air heater 21 and in a wet scrubber slurry. 22 It appears that the presence of bromine compounds in the flue gas can result in a shift of selenium from the fly ash to the flue gas leaving the particulate control device; the capture efficiency of wet FGD scrubbers for selenium is in the range of 60% to 90%. 23 Increasing the concentration of selenium in the scrubber slurry might result in an increase in selenium in the FGD discharge stream. Selenium, particularly the most oxidized form (Se[VI]) cannot be removed efficiently by conventional wastewater treatment units. The proposed ELG rule sets limits on selenium in wastewater discharge from coal-fired boilers, which, if enacted, might result in more costly water treatment processes required. Addition of halogens for increasing mercury oxidation in coal combustion flue gas can be a part of a plants mercury control strategy. However, the balance of plant effects of addition of bromine (the halogen most studied to date) must be considered in order to make an informed compliance decision. SUMMARY Three cases have been presented in this paper as examples of the challenges that plant operators face to manage compliance with existing and pending regulations. Choosing the appropriate controls to meet existing rules must take into consideration several factors to assure reliable operation at a reasonable cost. Coal combustion and the associated downstream equipment present complex non-equilibrium chemistry in the gas-phase and on surfaces across a range of temperatures. For example, catalytic effects from SCRs that change with temperature and age make evaluations more complex. Carbon, both unburned and introduced activated carbon, is an adsorbent that is affected by gas temperature and other flue gas constituents. Carbon can also act as a catalyst to promote mercury oxidation. Changes to combustion conditions or coal composition can impact the amount and characteristics of unburned carbon, which can have multiple downstream impacts on mercury control. Predicting the specific requirements and associated impact of future regulations on current choices places an additional uncertainty into the decision making process. Successful emissions management may often seem like it requires staring into the crystal ball to predict the impact of new hardware or introduced additives or sorbents. This uncertainty can be reduced by carefully considering the range of impacts and weighing the available choices. In general, there is rarely a perfect solution that will eliminate risks entirely. However, through a careful assessment, risks to plant operations and non-compliance events can typically be managed without relying too heavily on the crystal ball. REFERENCES 1. US EPA. Chapter 5: Emission Control Technologies in Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model, EPA 430-R-10010, August Madsen, K.; Jensen, A.D.; Frandsen, F.J.; Thørgersen, J.R. A Mechanistic Study of the Inhibition of the DeNOx Reaction on the Mercury Oxidation over SCR Catalysts. Air Quality VIII, Arlington, VA, October 23-27, ADA-ES, Inc. 11

12 3. Tyree, C.A.; Allen, J.O. Determining AQCS Mercury Removal Co-Benefits. Power, July Honjo, S.; Iwakura, K.; Welliver, B.; Sugita, S.; Ikeda, T.; Ukai, N.; Nochi, K.; Nagayasu; T.; Kiyosawa, M.; Okino, S.; Tyree, C.A. MHI Mercury Removal System with NH4Cl Injection. Presented at Power Plant Air Pollution Mega Symposium, Baltimore, MD, August 20-23, Pritchard, S. SCR Effects on Hg Control in Coal-Fired Boilers. Presented at Reinhold NOx Conference, Salt Lake City, UT, February 18-19, ( Accessed ) 6. Favale, A. SCR Effects on Hg Control in Coal-Fired Boilers. Presented at Reinhold NOx Conference, Salt Lake City, UT, February 18-19, ( Accessed ) 7. Celebi, M. Coal Plant Retirements and Market Impacts. Presented at Wartsila Flexible Power Symposium, Vail, CO, February 4, ( ements_and_market_impacts.pdf? Accessed ) 8. Rogers, W.; Stewart, R.; Banks, M.; Bertelson, A.; Copenhafer, J.; Sonobe, N.; Lynch, T. Is There a Place for DSI at Detroit Edison? Presented at 16th Annual EUEC, Phoenix, Arizona, January 28-30, US DOE. Integrated Dry NOx/SO2 Emissions Control System A DOE Assessment. DOE/NETL-2002/1160, October, Su, T; Shi, H.; Wang, J. Impact of Trona-Based SO2 Control on the Elemental Leaching Behavior of Fly Ash. Energy Fuels 2011, 25, Dan, Y.; Zimmerman, C.; Liu, K.; Shi, H.; Wang, J. Increased Leaching of As, Se, Mo, and V from High Calcium Coal Ash Containing Trona Reaction Products. Energy Fuels, 2013, 27 (3), pp Benson, S.A.; Holmes, M.J.; McCollar, D.P.; Mackenzie, J.M.; Crocker, C.R.; Kong, L.; Galbreath, K., Dombrowski, K.; Richardson, C. Large-Scale Mercury Control Testing for Lignite-Fired Utilities-Oxidation Systems for Wet FGD. Final Report, DOE NETL DE- FC26-03NT Grand Forks, ND: Energy & Environmental Research Center, March Richardson, C.F.; Dombrowski, K.; Chang, R. Mercury Control Evaluation of Halogen Injection into Coal-fired Furnaces. Presented at Electric Utilities Environmental Conference, Tucson, AZ, January 23-25, Berry, M.; Dombrowski, K.; Richardson, C.; Chang, R.; Borders, E.; Vosteen, B. Mercury Control Evaluation of Calcium Bromide Injection into a PRB-fired Furnace with an SCR. Presented at Air Quality VI, Arlington, VA, September 24-27, Shaw, B.I.T. EMO TM. Presented at Electric Utilities Environmental Conference, Phoenix, AZ, January 30-February 1, Dombrowski, K.; Aramasick, K.; Chang, R.; Tyree, C. Balance of Plant Effects of Bromide Addition for Mercury Control. Presented at Power Plant Air Pollution Mega Symposium, Baltimore, MD, August 20-23, Dombrowski, K.; Aramasick, K.; Srinivasan, N. Balance of Plant Impacts of Bromine for Mercury Control. Presented at Air Quality IX Conference, Arlington, VA, October ADA-ES, Inc. 12

13 18. Dombrowski, K.; Srinivasan, N. Bromine Balance of Plant Study. Presented at Reinhold NOx Conference, Salt Lake City, UT, February 18-19, ( Accessed ) 19. Guffre, J. Mercury Oxidation across the Air Heater. Presented at Worldwide Pollution Control Association Mercury Seminar, Birmingham, AL, October 30-31, ( Accessed ) 20. State of New Hampshire, Department of Environmental Services. Trihalomethanes: Health Information Summary. ARD-EHP-13, ( 13.pdf. Accessed ) 21. Gadgil, M.; Brown, S.R.; Bielawski, G.T. Selenium Control Using Combustion Additive. Presented at Power-Gen International, Orlando, FL, November 12-14, Blythe, G.; Bissell, J.S.; Labatt L.S. Optimization of Mercury Control on a new 800 MW PRB Fired Coal Plant. Presented at Power Plant Air Pollution Mega Symposium, Baltimore, MD, August 20-23, Senior, C.; Blythe, G.; Chu, P. Multi-Media Emissions of Selenium from Coal-Fired Electric Utility Boilers. Presented at Air Quality VIII, Arlington, VA, October 23-27, KEYWORDS Air emissions, mercury, compliance, balance of plant 2014 ADA-ES, Inc. 13