Midwest Regional Planning Organization (RPO) Boiler Best Available Retrofit Technology (BART) Engineering Analysis

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1 Midwest Regional Planning Organization (RPO) Boiler Best Available Retrofit Technology (BART) Engineering Analysis Prepared for: The Lake Michigan Air Directors Consortium (LADCO) Prepared by: MACTEC Federal Programs / MACTEC Engineering and Consulting, Inc. (MACTEC) March 30, 2005

2 Table of Contents SECTION 1 OVERVIEW... 5 Introduction... 5 SECTION 2 AVAILABLE CONTROL TECHNOLOGIES... 6 Introduction... 6 NO x Emission Control Options Flue Gas Recirculation Low-NO x Burners Ultra-low NO x Burners Selective Non-Catalytic Reduction Selective Catalytic Reduction Site-specific Measures...13 SO 2 Emission Control Options Advanced Flue Gas Desulfurization Wet Scrubbing / Flue-Gas Desulfurization Dry Flue Gas Desulfurization (Spray Dryer Absorption) PM Emission Control Options Fabric Filter Dust Collector Dry Electrostatic Precipitator Wet Electrostatic Precipitator SECTION 3 BOILER BART ENGINEERING SCREENING ANALYSIS Application of BART Screening to Model Fossil-fuel Boilers of More Than 250 million BTUs per hour Heat Input Sources Information Sources General Control Technology Review Issues Emission Controls vs. Impact on Visibility Site-specific Factors that Affect Control Costs Model Source Parameters...21 Model Boiler NO x Control Technology Review BART Step 1: Identify All Available Retrofit Control Technologies BART Step 2: Eliminate Technically Infeasible Options BART Step 3: Rank Remaining Control Technologies BART Step 4: Evaluate Impacts and Document the Results Boiler SO 2 Control Technology Review BART Step 1: Identify Available Retrofit Control Technologies BART Step 2: Eliminate Technically Infeasible Options BART Step 3: Rank Remaining Control Technologies BART Step 4: Evaluate Impacts and Document the Results Boiler PM Control Technology Review BART Step 1: Identify Available Retrofit Control Technologies BART Step 2: Eliminate Technically Infeasible Options BART Step 3: Rank Remaining Control Technologies BART Step 4: Evaluate Impacts and Document the Results Boiler VOC Control Technology Review... 37

3 SECTION 4 SOURCE SPECIFIC DATA AND BART RECOMMENDATIONS Remaining Useful Life Existing Controls Fuel Issues... 38

4 Table of Contents (continued) List of Tables Table 2.1 Table 2.2 Table 3.1 Table 3.2 Table 3.3 Table 3.4 Table 3.5 Table 3.6 Table 3.7 Table 3.8 Table 3.9 Table 3.10 Table 3.11 Table 4.1 Table 4.2 LADCO BART Category 22 (boiler) Emission Units Three Control Technology Options Identified for Each Emission Unit Segment for NO x Summary of Model Boiler Operating Characteristics. Summary of Technical Feasibility for Boiler NO x Emissions Control Technology Rankings for Boiler NO x - Control Efficiency (typical configurations listed) Summary of Costs Estimates for Coal Fired Boiler NO x Controls Summary of Costs Estimates for Oil Fired Boiler NO x Controls Control Technology Rankings for Boiler SO 2 Control Summary of Costs Estimates for Coal Fired Boiler SO 2 Controls Summary of Costs Estimates for Oil Fired Boiler SO 2 Controls Control Technology Rankings for Boiler PM Control Summary of Costs Estimates for Coal Boiler PM Controls Summary of Costs Estimates for Oil Fired Boiler PM Controls LADCO BART Category 22 (boiler) Emission Units Existing Controls LADCO BART Category 22 (boiler) Emission Units Recommended BART Controls List of Figures Figure 2.1 Advanced Flue Gas Desulfurization Process Flow

5 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 5 Midwest Regional Planning Organization (RPO) Boiler Best Available Retrofit Technology (BART) Engineering Analysis SECTION 1 OVERVIEW Introduction An appropriate first step in evaluating BART for a group of sources is to categorize emission units within each general source category. For this work, the source categories included (BART numeric category in parentheses): Portland cement plants (4), Iron and steel mill plants (6), Primary aluminum ore reduction plants (7), Petroleum refineries (11), Primary lead smelters (17), Chemical process plants (21), and Fossil-fuel boilers of more than 250 million BTUs per hour heat input (22) In general, these types of emission units were found in several of the LADCO States. In order to effectively characterize the BART controls for these emission sources, MACTEC determined that using an initial model emission source for each category would be the most effective means of evaluating the types of emission units and the likely candidate BART controls for each. For each of these emission sources, MACTEC developed model sources to enable the development of representative control cost estimates. The physical characteristics of the model sources are summarized in each section specific to that source category. The model sources were selected to reflect typical emission units found at each emission source type.

6 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 6 Introduction SECTION 2 AVAILABLE CONTROL TECHNOLOGIES This section describes each potentially available control technology evaluated for BART category 22, fossil-fuel boilers of more than 250 million BTUs (MMBtu) per hour heat input. The technologies are grouped by the pollutant that they control (i.e., NO x, SO 2, PM, or VOC). Determining technical feasibility of a control technology for a new source (e.g., determining best available control technology for a new boiler) will be different than determining technical feasibility for a retrofit at an existing source (e.g., determining best available retrofit technology for an existing boiler). In this section, MACTEC determines the technical feasibility of each of three control technologies for a fossil-fuel boiler emission unit as if that unit could be designed or re-designed to meet the control device physical and operating parameters. As part of the BART screening evaluation, a literature/internet/vendor review was conducted to identify potential control equipment options for the emission units identified (see below). The three control devices represent the top three options (based on control efficiency and costs) for these units. The top controls were identified in a spreadsheet provided to LADCO in December 2004 and updated in January 2005 to address comments received on the December spreadsheet. In the section that follows this, MACTEC further evaluates the technical feasibility of each control technology as a retrofit to the existing emission units identified in task 2 of this contract (and provided in a spreadsheet to LADCO participants in October 2004). The emission units identified in that spreadsheet were selected based on three criteria: 1) emission levels for SO 2 and NO x ; 2) commonality of sources (i.e., how many similar sources occurred across the LADCO region and; 3) the potential impact of emissions from these units at Class I areas (as determined by Q/D [emissions/distance] values for several Class I areas in or near the LADCO region). In addition, cost estimates have been modified to the extent possible to reflect actual emission unit operational conditions. Table 2.1 shows the boiler emission units identified for LADCO as meeting the three criteria listed above. These boiler emission units were evaluated for BART. In addition to the boilers identified as being part of category 22, we have also included boilers identified at chemical process plants (category 21). We have included these boilers because they were the only BART eligible sources found at chemical process plants. Boilers found at other BART category facilities were evaluated for those facilities since other types of emission sources were also found for the other categories. For boilers, control technology options for SO 2 include advanced flue gas desulfurization (AFGD), dry FGD, and wet FGD; control technology options for NO x include low and ultra-low- NO x burners (LNB and ULNB), selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR) and flue gas recirculation (FGR). Combinations of these technologies were also considered (e.g., ULNB+SCR, LNB+SNCR, and LNB+FGR). For this report, two types of low-no x burners were evaluated, staged fuel low-no x burners and ultra-low NO x burners. External flue gas recirculation is a common technique for controlling NO x emissions, so it is added to the list of NO x control technologies for review. For PM emissions, dust collectors (DC), fabric filters (FF), dry electrostatic precipitators (DESP) and wet electrostatic precipitators (WESP) were considered. In some cases more than one set of three controls was identified for a single unit. This was due to alternative fueling configurations for the boilers. For example some boilers in the identified group

7 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 7 fired more than one fuel (i.e., had more than one segment and thus more than one source classification code [SCC]) and thus slightly different control options were identified. Table 2.2 shows control options one through three for NO x for boilers from category 22 (chemical process plant boilers are not included in this table). For cases where the emission unit had more than one segment (i.e., fuel) MACTEC used the segment (SCC/fuel type) with the largest emissions of that pollutant to identify the control set to evaluate for BART.

8 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 8 STATE SOURCE NAME TABLE 2.1 LADCO BART CATEGORY 22 (BOILER) EMISSION UNITS EMIS UNIT ID EMIS UNIT DESCRIPTION MAX HEAT RATE BART CATEGORY SO 2 NO x PM PM 10 VOC NH 3 INDIANA AGC DIVISION-ALCOA POWER 003 BOILER NO GEENRATING INDIANA AGC DIVISION-ALCOA POWER 012 BOILER NO.2-NO. 1 STACK GEENRATING INDIANA AGC DIVISION-ALCOA POWER 022 BOILER NO.2-NO. 2 STACK GEENRATING MICHIGAN MICHIGAN STATE UNIVERSITY EU00529 Boiler unknown MICHIGAN MICHIGAN STATE UNIVERSITY EU00530 Boiler unknown MICHIGAN MICHIGAN STATE UNIVERSITY EU00531 Boiler unknown MICHIGAN STONE CONTAINER CORP EU0069 Riley Boiler OHIO Cinergy Solutions of St Bernard B022 Steam production OHIO Cognis Corp B027 Steam boiler fired with natural gas, landfill gas, coal, and fuel oil. OHIO Mead Paper Division B002 No. 7 Coal Boiler OHIO Mead Paper Division B003 Steam generation OHIO Sun Company, Inc. B046 H CO Boiler OHIO Sun Company, Inc. B047 H CO Boiler OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with pulzd. coal, N G, BFG and COG OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with N-G, BFG and COG WISCONSIN Fort James Operating Company B27 boiler WISCONSIN International Paper Kaukauna Facility B11 boiler WISCONSIN Procter & Gamble Paper Production B06 boiler Company Chemical Facility Boilers ILLINOIS Williams Ethanol Services Inc 0019 BOILER C - PULVERIZED WET BOTTOM, WALL FIRED unknown ILLINOIS Williams Ethanol Services Inc 0020 BOILER A unknown ILLINOIS Williams Ethanol Services Inc 0021 BOILER B unknown INDIANA GE PLASTICS MT. VERNON INC. 101 RILEY BOILER unknown INDIANA GE PLASTICS MT. VERNON INC. 107 LASKER BOILER unknown INDIANA GE PLASTICS MT. VERNON INC. 108 ERIE BOILER unknown INDIANA GE PLASTICS MT. VERNON INC. 117 B&W BOILER (09-001) unknown

9 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 9 TABLE 2.2 THREE CONTROL TECHNOLOGY OPTIONS IDENTIFIED FOR EACH EMISSION UNIT SEGMENT FOR NO X STATE SOURCE_NAME EMISUNITID EMISUNITDESC SCC SCCDESC INDIANA AGC DIVISION-ALCOA POWER GEENRATING INDIANA AGC DIVISION-ALCOA POWER GEENRATING INDIANA AGC DIVISION-ALCOA POWER GEENRATING INDIANA AGC DIVISION-ALCOA POWER GEENRATING INDIANA AGC DIVISION-ALCOA POWER GEENRATING 003 BOILER NO External Combustion Boilers Electric Generation Bituminous/Subbituminous Coal Pulverized Coal: Dry Bottom (Bituminous Coal) 003 BOILER NO External Combustion Boilers Electric Generation Natural Gas Boilers > 100 Million Btu/hr except Tangential 012 BOILER NO.2-NO. 1 STACK 012 BOILER NO.2-NO. 1 STACK 022 BOILER NO.2-NO. 2 STACK INDIANA AGC DIVISION-ALCOA POWER GEENRATING 022 BOILER NO.2-NO. 2 STACK INDIANA AGC DIVISION-ALCOA 022 BOILER NO.2-NO. 2 POWER GEENRATING STACK OHIO OHIO Cinergy Solutions of St Bernard Cinergy Solutions of St Bernard External Combustion Boilers Electric Generation Bituminous/Subbituminous Coal Pulverized Coal: Dry Bottom (Bituminous Coal) External Combustion Boilers Electric Generation Natural Gas Boilers > 100 Million Btu/hr except Tangential External Combustion Boilers Electric Generation Bituminous/Subbituminous Coal Pulverized Coal: Dry Bottom (Bituminous Coal) External Combustion Boilers Electric Generation Distillate Oil Grades 1 and 2 Oil External Combustion Boilers Electric Generation Natural Gas Boilers > 100 Million Btu/hr except Tangential B022 Steam production External Combustion Boilers Industrial Bituminous/Subbituminous Coal Pulverized Coal: Wet Bottom B022 Steam production External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr OHIO Cognis Corp B027 Steam boiler fired with natural gas, landfill gas, coal, and fuel oil. OHIO Cognis Corp B027 Steam boiler fired with natural gas, landfill gas, coal, and fuel oil. OHIO Cognis Corp B027 Steam boiler fired with natural gas, landfill gas, coal, and fuel oil External Combustion Boilers Industrial Bituminous/Subbituminous Coal Pulverized Coal: Dry Bottom External Combustion Boilers Industrial Distillate Oil Grade 4 Oil External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr Technology 1 ULNB ULNB+SCR SCR ULNB ULNB+SCR SCR ULNB ULNB+SCR SCR ULNB+SCR SCR ULNB ULNB+SCR SCR ULNB ULNB+SCR SCR ULNB+SCR SCR Technology 2 Technology 3 LNB+SNCR LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+FGR

10 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 10 TABLE 2.2 THREE CONTROL TECHNOLOGY OPTIONS IDENTIFIED FOR EACH EMISSION UNIT SEGMENT FOR NO X (CONTINUED) STATE SOURCE_NAME EMISUNITID EMISUNITDESC SCC SCCDESC OHIO Cognis Corp B027 Steam boiler fired with natural gas, landfill gas, coal, and fuel oil. OHIO Cognis Corp B027 Steam boiler fired with natural gas, landfill gas, coal, and fuel oil. OHIO Mead Paper Division OHIO Mead Paper Division External Combustion Boilers Industrial Process Gas Other: Specify in Comments External Combustion Boilers Industrial Liquid Waste Specify Waste Material in Comments Technology 1 ULNB+SCR SCR ULNB+SCR SCR Technology 2 Technology 3 LNB+FGR LNB+FGR B002 No. 7 Coal Boiler External Combustion Boilers Industrial Bituminous/Subbituminous Coal Pulverized Coal: Wet Bottom ULNB LNB+SNCR LNB+FGR B003 Steam generation External Combustion Boilers Industrial ULNB LNB+SNCR LNB+FGR Bituminous/Subbituminous Coal Pulverized Coal: Wet Bottom B046 H CO Boiler External Combustion Boilers Industrial Residual Oil ULNB LNB+SNCR LNB+FGR Grade 5 Oil B046 H CO Boiler External Combustion Boilers Industrial Process Gas ULNB+SCR SCR LNB+FGR Petroleum Refinery Gas B047 H CO Boiler External Combustion Boilers Industrial Residual Oil ULNB LNB+SNCR LNB+FGR Grade 5 Oil B047 H CO Boiler External Combustion Boilers Industrial Process Gas ULNB+SCR SCR LNB+FGR Petroleum Refinery Gas OHIO Sun Company, Inc. OHIO Sun Company, Inc. OHIO Sun Company, Inc. OHIO Sun Company, Inc. OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with pulzd. coal, N-G, BFG and COG OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with pulzd. coal, N-G, BFG and COG OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with pulzd. coal, N-G, BFG and COG OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with pulzd. coal, N-G, BFG and COG OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with N- G, BFG and COG External Combustion Boilers Industrial Bituminous/Subbituminous Coal Pulverized Coal: Dry Bottom External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr External Combustion Boilers Industrial Process Gas Blast Furnace Gas External Combustion Boilers Industrial Process Gas Coke Oven Gas External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr ULNB ULNB+SCR SCR ULNB+SCR SCR ULNB+SCR SCR ULNB+SCR SCR LNB+SNCR LNB+FGR LNB+FGR LNB+FGR LNB+FGR LNB+FGR

11 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 11 TABLE 2.2 THREE CONTROL TECHNOLOGY OPTIONS IDENTIFIED FOR EACH EMISSION UNIT SEGMENT FOR NO X (CONTINUED) STATE SOURCE_NAME EMISUNITID EMISUNITDESC SCC SCCDESC OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with N-G, BFG and COG OHIO WCI Steel, Inc. B MMBtu/Hr B&W fired with N-G, BFG and COG WISCONSIN Fort James Operating Company WISCONSIN Fort James Operating Company WISCONSIN Fort James Operating Company WISCONSIN International Paper Kaukauna Facility WISCONSIN International Paper Kaukauna Facility WISCONSIN International Paper Kaukauna Facility WISCONSIN International Paper Kaukauna Facility WISCONSIN International Paper Kaukauna Facility WISCONSIN Procter & Gamble Paper Production Company WISCONSIN Procter & Gamble Paper Production Company WISCONSIN Procter & Gamble Paper Production Company External Combustion Boilers Industrial Process Gas Blast Furnace Gas External Combustion Boilers Industrial Process Gas Coke Oven Gas B27 boiler External Combustion Boilers Industrial Bituminous/Subbituminous Coal Cyclone Furnace B27 boiler External Combustion Boilers Industrial Distillate Oil Grades 1 and 2 Oil B27 boiler External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr B11 boiler External Combustion Boilers Industrial Bituminous/Subbituminous Coal Cyclone Furnace B11 boiler External Combustion Boilers Industrial Residual Oil Grade 6 Oil B11 boiler External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr B11 boiler External Combustion Boilers Industrial Petroleum Coke All Boiler Sizes B11 boiler External Combustion Boilers Industrial Wood/Bark Waste Wood-fired Boiler - Wet Wood (>=20% moisture) B06 boiler External Combustion Boilers Industrial Bituminous/Subbituminous Coal Pulverized Coal: Dry Bottom B06 boiler External Combustion Boilers Industrial Distillate Oil Grades 1 and 2 Oil B06 boiler External Combustion Boilers Industrial Natural Gas > 100 Million Btu/hr Technology 1 ULNB+SCR SCR ULNB+SCR SCR ULNB ULNB+SCR SCR ULNB+SCR SCR ULNB ULNB ULNB+SCR SCR ULNB+SCR SCR ULNB+SCR SCR ULNB ULNB+SCR SCR ULNB+SCR SCR Technology 2 Technology 3 LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+FGR LNB+FGR LNB+SNCR LNB+FGR LNB+FGR LNB+FGR

12 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 12 NO x Emission Control Options Five different control technologies were evaluated for NO x emissions from boilers. These technologies are: external flue gas recirculation, low NO x burners, ultra-low NO x burners, selective non-catalytic reduction, and selective catalytic reduction. Background information on each of these technologies is provided below. Flue Gas Recirculation Flue gas recirculation (FGR) uses flue gas as an inert material to reduce flame temperatures. In a typical flue gas recirculation system, flue gas is collected from the heater or stack and returned to the burner via a duct and blower. The flue gas for the FGR system is usually taken from the main flue gas flow downstream of the economizer. A fan (blower) is needed to withdraw the required amount of flue gas. This system is usually called Flue Gas Recirculation (FGR). In some cases, this type system is referred to as External Flue Gas Recirculation (EFGR) or Forced Flue Gas Recirculation. This differentiation is made because sometimes the flue gas for FGR is taken from the flue gas flow upstream of the stack using the forced draft (FD) fan instead of a separate FGR fan. This system is called Induced Flue Gas Recirculation (IFGR). In either system, the flue gas is mixed with the combustion air and this mixture is introduced into the burner. The addition of flue gas reduces the oxygen content of the combustion air (air + flue gas) in the burner. The lower oxygen level in the combustion zone reduces flame temperatures; which in turn reduces NO x emissions. When operated without additional controls, the normal NO x control efficiency range for FGR is 30 percent to 50 percent. When coupled with low-no x burners (LNB) the control efficiency increases to percent. Low-NO x Burners Low-NO x burner (LNB) technology utilizes advanced burner design to reduce NO x formation through the restriction of oxygen, flame temperature, and/or residence time. A LNB is a staged combustion process that is designed to split fuel combustion into two zones, primary combustion and secondary combustion. Two general types of low NO x burners exist, staged fuel and staged air. MACTEC utilized the staged fuel design in the cost analysis because lower emission rates can be achieved with a staged fuel burner than with a staged air burner. Staged fuel LNBs separate the combustion zone into two regions. The first region is a lean primary combustion region where the total quantity of combustion air is supplied with a fraction of the fuel. Combustion in the primary region (first stage) takes place in the presence of a large excess of oxygen at substantially lower temperatures than a standard burner. In the second region, the remaining fuel is injected and combusted with any oxygen left over from the primary region. The remaining fuel is introduced in the second stage outside of the primary combustion zone so that the fuel/oxygen are mixed diffusively (rather than turbulently) which maximizes the reducing conditions. This technique inhibits the formation of thermal NO x, but has little effect on fuel NO x. Thus staged fuel LNBs are particularly well suited for coal and natural gas boilers which are higher in thermal NO x than for fuel oils which are higher in fuel NO x. For fuel oil boilers the staged air LNBs are generally preferred. By increasing residence times staged air LNBs provide reducing conditions which has a greater impact on fuel NO x than staged fuel burners. The estimated NO x control efficiency for LNBs in high temperature applications is 25 percent. However when coupled with FGR or selective non-catalytic reduction (SNCR) these efficiencies increase to and percent, respectively.

13 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 13 Ultra-low NO x Burners These burners may incorporate a variety of techniques including induced flue gas recirculation, steam injection, or a combination of techniques. These burners combine the benefits of flue gas recirculation and low-no x burner control technologies. Rather than a system of fans and blowers (like FGR), the burner is designed to recirculate hot, oxygen depleted flue gas from the flame or firebox back into the combustion zone. This leads to a reduction in the average oxygen concentration in the flame without reducing the flame temperature below temperatures necessary for optimal combustion efficiency. Reduced oxygen concentrations in the flame have a strong impact on fuel NO x so ULNBs are an effective NO x control for boilers firing fuel oil. The estimated NO x control efficiency for ULNBs in high temperature applications is 50 percent. Newer designs have yielded efficiencies of between percent. When coupled with selective catalytic reduction, efficiencies in the range of percent can be obtained. Selective Non-Catalytic Reduction In the selective non-catalytic reduction (SNCR) process, urea or ammonia-based chemicals are injected into the flue gas stream to convert NO to N 2 and water. Without the participation of a catalyst, the reaction requires a high temperature range to obtain activation energy. The relevant reactions is: 2NO + CO(NH 2 ) 2 + 1/2 O 2 2N 2 + CO H 2 O The optimum operating temperature for SNCR is 1,600 F to 2,100 F. Under these temperature conditions a significant reduction in NO x occurs. At temperatures above 2,000 F an alternative reaction occurs and NO x control efficiency decreases rapidly. The normal NO x control efficiency range for SNCR is 50 percent to 70 percent. Selective Catalytic Reduction Selective catalytic reduction (SCR) is a post-combustion NO x control technology in which ammonia (NH 3 ) is injected into the flue gas stream in the presence of a catalyst. A catalyst bed containing metals in the platinum family is used to lower the activation energy required for NO x decomposition. NO x is removed through the following chemical reaction: 4 NO + 4 NH 3 + O 2 4 N H 2 O The reaction of NH 3 and NO x is favored by the presence of excess oxygen. However, the primary variable affecting NO x reduction is temperature. Optimum NO x reduction occurs at catalyst bed temperatures of F for conventional (vanadium or titanium based catalysts) and F for platinum catalysts. A high temperature zeolite catalyst is also available; it can operate in the 600 F 1000 F temperature range. However, these catalysts are very expensive. A given catalyst provides optimal performance within + 50 F of its design temperature for applications in which flue gas oxygen concentrations are greater than 1 percent. Below this optimum range, the catalyst activity is greatly reduced allowing unreacted NH 3 to slip through (ammonia slip). At temperatures above 850 F ammonia begins to oxidize to form additional NO x. The NH 3 oxidation to NO x increases with increasing temperature. The normal NO x control efficiency range for SCR is 70 percent to 90 percent. Site-specific Measures Site-specific measures may also be employed to reduce NO x emissions. Under this option, facility operators would evaluate the impact of fuels on NO x emission rates. Fuel switching may be a

14 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 14 method of reducing emissions of NO x, however changing from natural gas to coal may exacerbate an existing SO 2 emissions problem. For this analysis we have not directly considered fuel switching as an alternative to add on controls. However there may be specific sites that could see potential cost savings by fuel switching resulting in a single type of control rather than controls for several visibility impairing pollutants. If this option is employed, increases in SO 2 and PM emissions should be compared to the NO x reductions (or vice versa) to identify the best net reduction in visibility impairing pollutants. SO 2 Emission Control Options The three control technologies evaluated for SO 2 emissions from fossil fuel-fired boilers were: 1) advanced flue gas desulfurization (AFGD), 2) wet flue gas desulfurization, and 3) dry flue gas desulfurization (spray dryer absorption). A brief description of each of these technologies is provided below. Advanced Flue Gas Desulfurization The AFGD process accomplishes SO 2 removal in a single absorber which performs three functions: prequenching the flue gas, absorption of SO 2, and oxidation of the resulting calcium sulfite to wallboard-grade gypsum. Figure 2.1 shows the process flow for an AFGD system. FIGURE 2.1. ADVANCED FLUE GAS DESULFURIZATION PROCESS FLOW Incoming flue gas is cooled and humidified with process water sprays before passing to the absorber. In the absorber, two tiers of fountain-like sprays distribute reagent slurry over polymer grid packing that provides a large surface area for gas/liquid contact. The gas then enters a large

15 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 15 gas/liquid disengagement zone above the slurry reservoir in the bottom of the absorber and exits through a horizontal mist eliminator. As the flue gas contacts the slurry, the sulfur dioxide is absorbed, neutralized, and partially oxidized to calcium sulfite and calcium sulfate. The overall reactions are shown in the following equations: CaCO 3 + SO 2 CaSO 3 1/2 H 2 O + CO 2 CaSO 3 1/2 H 2 O + 3H 2 O + O 2 2 CaSO 4 2 H 2 O After contacting the flue gas, slurry falls into the slurry reservoir where any unreacted acids are neutralized by limestone injected in dry powder form into the reservoir. The primary reaction product, calcium sulfite, is oxidized to gypsum by the air rotary spargers, which both mix the slurry in the reservoir and inject air into it. Fixed air spargers assist in completing the oxidation. Slurry from the reservoir is circulated to the absorber grid. A slurry stream is drawn from the tank, dewatered, and washed to remove chlorides and produce wallboard quality gypsum. The resultant gypsum cake contains less than 10 percent water and 20 ppm chlorides. The clarified liquid is returned to the reservoir, with a slipstream being withdrawn and sent to the wastewater evaporation system for injection into the hot flue gas ahead of the electrostatic precipitator. Water evaporates and dissolved solids are collected along with the flyash for disposal or sale. Wet Scrubbing / Flue-Gas Desulfurization Wet scrubbing techniques are used to control both particulate and SO 2 emissions. Wet scrubbing processes used to control SO 2 are generally termed flue-gas desulfurization (FGD) processes. FGD utilizes gas absorption technology, the selective transfer of materials from a gas to a contacting liquid, to remove SO 2 in the waste gas. Caustic, crushed limestone, or lime are used as scrubbing agents. Our BART screening evaluation assumes that lime is the scrubbing agent. The SO 2 removal reactions for lime are as follows: Ca(OH) 2 +SO 2 CaSO 3 1/2 H 2 O + 1/2 H 2 O Ca(OH) 2 + SO 2 + 1/2 O 2 + H 2 O CaSO 4 2 H 2 O The reactions when caustic are used are as follows: Na + + OH - + SO 2 NaHSO 3 2Na + + 2OH - + SO 2 + Na 2 SO 3 + H 2 O The reactions for limestone were presented in the AFGR section. Caustic scrubbing produces a liquid waste, and minimal equipment is needed. When lime or limestone is used as the reagent for SO 2 removal, additional equipment is needed for preparing the lime/limestone slurry and collecting and concentrating the resultant sludge. Calcium sulfite sludge is watery and it is typically stabilized with fly ash for land filling. The calcium sulfate sludge is stable and easy to dewater. To produce calcium sulfate, an air injection blower is needed to supply the oxygen for the second reaction to occur. There are several different versions of wet FGD systems. The choice of which version of wet FGD system to use may be influenced by the sulfur content of the fuel. For example, in the

16 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 16 proposed CAIR rule, January 30, 2004, FR, page 4162, it says, lime stone forced oxidation (LSFO) is generally used for installations, firing high-sulfur (2 percent and higher) fuels, with lime spray dryers (see dry FGD section below) used for low-sulfur coals (less than 2 percent) and magnesium enhanced lime (MEL) for low and high sulfur coals depending on the overall economics of each application. LSFO is generally an add-on to wet FGD in cases where there is high sulfur coal. The forced oxidation helps supply oxygen used to produce gypsum. MEL is also a wet FGD system. These systems would be included in our generalized costs for wet FGD. Together LSFO and MEL (with forced oxidation) and dry lime spray dryers account for approximately 85 percent of the installed FGD capacity in the United States. The normal SO 2 control efficiency range for SO 2 scrubbers is 80 percent to 90 percent for low efficiency scrubbers and 90 percent to 99 percent for high efficiency scrubbers. Dry Flue Gas Desulfurization (Spray Dryer Absorption) Spray dryer absorption (SDA) systems spray lime slurry into an absorption tower where SO 2 is absorbed by the slurry, forming CaSO 3 /CaSO 4. The liquid-to-gas ratio is such that the water evaporates before the droplets reach the bottom of the tower. The dry solids are carried out with the gas and collected with a fabric filter. When used to specifically control SO 2, the term dry fluegas desulfurization (dry FGD) may also be used. As with other types of dry scrubbing systems (such as lime/limestone injection) exhaust gases that exit at or near the adiabatic saturation temperature can create problems with this control technology by causing the baghouse filter cake to become saturated with moisture and plug both the filters and the dust removal system. In addition, the lime slurry would not dry properly and it would plug up the dust collection system. However there is some argument in the control community that indicates that some of the SO 2 removal actually occurs on the filter cake. Therefore, dry FGD (spray dryer absorption) may not be technically feasible if boiler exit gas temperatures are not substantially above the adiabatic saturation temperature. PM Emission Control Options Four control technologies are evaluated for PM emissions from boilers: fabric filter (baghouse), dust collector (cartridge), wet electrostatic precipitator and dry electrostatic precipitator. All of these control technologies are deemed technically feasible for a boiler retrofit. Fabric Filter A fabric filter, or baghouse, is a potential control method for particulate emissions from a fossilfuel fired boiler. The only potential drawback to a fabric filter would be when used in conjunction with a high moisture flue gas stream. If moisture levels in the flue gas stream are too high then filter caking can occur. A fabric filter, or baghouse, consists of a number of fabric bags placed in parallel inside of an enclosure. Particulate matter is collected on the surface of the bags as the gas stream passes through them. The particulate is periodically removed from the bags and collected in hoppers located beneath the bags. A number of methods are employed to facilitate the removal of particulate from the bags, including shaking, reverse air flow, and pulse air flow. The normal PM control efficiency range for a fabric filter is 95 percent to 99+ percent. Dust Collector Dust collectors are similar to fabric filters in that the air stream is cleaned by passing the stream through a material that acts as a filter. In the case of dust collectors, the filter material is typically a pleated fabric or filter type material. As with fabric filters, the dust is periodically removed, typically by pulsed air jets. The removed particulate is collected in hoppers located beneath the

17 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 17 collector. Several factors determine cartridge filter collection efficiency including gas filtration velocity, particle characteristics, filter media characteristics, and cleaning mechanism. The normal PM control efficiency range for a dust collector is in the 99+ percent range. Cartridge dust collectors do have some limitations however. For example, cartridges are limited in temperature range due to filter media and sealant to approximately 200 ºF. Synthetic nonwoven media can be used to a temperature of approximately 400 ºF. Higher temperature streams must be cooled to temperatures below these levels using spray coolers or dilution air in order not to damage the cartridges. Minimum temperatures must be kept above the adiabatic saturation temperature in order not to condense materials out. Corrosive streams can also cause problems for the cartridges. Cartridge filtration systems are generally limited to low flow rate applications. The cartridges also need to operate with a medium pressure drop typically in the range of mm of water. Cartridge filtration does have two significant advantages. First the space requirements are significantly lower than those for a baghouse. Second for particles that have low resistivity that would not be handled well by an ESP, cartridges may be an ideal solution. Dry Electrostatic Precipitator An electrostatic precipitator (ESP) is a potential control method for particulates in boiler flue gas streams. An electrostatic precipitator applies electrical forces to separate suspended particles from the flue gas stream. The suspended particles are given an electrical charge by passing through a high voltage DC corona region in which gaseous ions flow. There are two general types of ESP: wire/plate and wire/pipe types. Further, ESPs come in both wet (see below) and dry configurations. The charged particles are attracted to and collected on oppositely charged collector surfaces. In a dry electrostatic precipitator (DESP) particles on the collector surfaces are released by rapping and fall into hoppers for collection and removal. The normal PM control efficiency range for an ESP is between 90 and 99+ percent with typical values reaching the 98 percent to 99+ percent range. One of the major advantages of an ESP is that it operates with essentially little pressure drop in the gas stream. As a consequence, energy and operational costs tend to be low (other than electricity to operate the ESP itself). They are also capable of handling high temperature conditions. The major disadvantages of ESPs are their high capital costs and the fact that wire discharge electrodes are a high maintenance item. They are also not well suited for operations that are highly variable due to their sensitivity to gas flow, temperature and particle/gas composition. They also do not handle sticky particles well or those that have high resistivities. There may also be the danger of explosion if the gas stream composition is flammable (unlikely for boilers). Relatively sophisticated maintenance personnel are required. Finally, ESPs can take up substantial space in order to achieve the low gas velocities required for efficient particle removal. This may be of concern for retrofit options where space is at a premium. Wet Electrostatic Precipitator A wet electrostatic precipitator (WESP) is a potential control method for particulates in boiler flue gas. A WESP operates on the same collection principles as a DESP, and uses a water spray to remove particulate matter from the collection plates. The normal PM control efficiency range for a WESP is 98 percent to 99+ percent. The same advantages and disadvantages that apply to a DESP apply to a WESP with the exception that WESPs can effectively be used to collect sticky particles and highly resistive dust. In addition, the wash used in WESPs can also have some

18 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 18 control effect on other pollutant gases via absorption and can help condense other emissions due to the cooling of the stream by the wash.

19 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 19 SECTION 3 BOILER BART ENGINEERING SCREENING ANALYSIS Application of BART Screening to Model Fossil-fuel Boilers of More Than 250 million BTUs per hour Heat Input Sources The first four of the five BART evaluation steps are completed in this section on a model boiler screening level. The fifth step, selecting BART for the boilers identified above, takes into account as much source-specific data as possible with respect to control options, costs and any non-air environmental impacts identified for those sources. The analysis of potential BART control technologies must take into account: The available retrofit control options, Any pollution control equipment in use at the source, The costs of compliance with control options, The remaining useful life of the facility, and The energy and non-air quality environmental impacts of control options. The BART screening study uses a model boiler approach, which attempts to represent average operational conditions for boilers across the various sources identified in the list of emission units for LADCO. Each boiler is different, and site-specific issues must be considered in the BART analysis. Site-specific conditions are discussed at the end of this section. Information Sources The screening BART analysis used the following primary information sources. Cost information was developed from the following sources: Emission control costs are estimated using the capital costs identified in the MACTEC spreadsheet identifying the top three control technologies for each pollutant. A list of references/sources reviewed to develop that list was provided with the spreadsheet. Operating costs were based on the EPA Air Pollution Control Cost Manual. Control equipment costs were also obtained from readily available vendor information. All control costs were adjusted for inflation using the Consumer Price Index to provide constant dollar estimates. Information gaps were addressed by collecting additional cost data from control equipment manufacturers or trade organization (e.g. ICAC). Gas and electric costs are based on the United States Department of Energy's data for industrial sources ( Wastewater treatment costs are obtained from the EPA Air Pollution Control Cost Manual. General Control Technology Review Issues This section outlines important issues that must be taken into account when performing a case-bycase BART evaluation.

20 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 20 Emission Controls vs. Impact on Visibility In accordance with 40 CFR (e)(1)(ii)(A) and (B), a BART determination must be based on the following two analyses: (A) An analysis of the best system of continuous emission control technology available and associated emission reductions achievable for each BARTeligible source ; and (B) An analysis of the degree of visibility improvement that would be achieved in each mandatory Class I Federal area as a result of the emission reductions achievable from all sources subject to BART located within the region that contributes to visibility impairment in the Class I area, based on the analysis conducted under paragraph (e)(1)(ii)(a) of this section. This work is focused strictly on item A, the best system of continuous emission control technology and the associated emission reductions (i.e., the BART engineering analysis). For this analysis, a series of spreadsheets were developed to calculate the costs associated with the various control options evaluated for each model source. The spreadsheets were made flexible enough to handle some source-specific input, enabling the user to recalculate costs using these more sourcespecific inputs. For this analysis, the emission control costs reported in this section for the model sources include estimates of capital costs, operating costs and cost effectiveness (in units of dollars per ton of pollutant removed). It is important to remember that each pollutant has a different impact on visibility. All of the boilers identified for BART analysis had the highest pollutant levels associated with SO 2, with NO x also being a substantial contributor. Only one of the boilers identified would have been classified as a BART source based solely on PM emissions (AGC Division- Alcoa Power Generating Boiler 003). Site-specific Factors that Affect Control Costs Although the model sources have been developed to provide a general indication of the technical and economic feasibility of each control technology, a unit-specific BART evaluation must still be performed. A case-by-case evaluation should consider these steps. Determine the technical feasibility of listed control equipment for each source subject to BART. Check the technical feasibility analysis to see if analysis is consistent with site-specific conditions. Eliminate all technologies that are infeasible. Conduct a control cost analysis on the remaining technologies per the listed control technology rankings. At some point it is likely that site-specific vendor quotes will be required to get accurate cost analysis results. However, one of the reasons we decided to use the model source approach was that if there are a significant number of similar sources, selection of a typical-sized source helps minimize the amount of work needed to perform the cost analysis. Use of the appropriate model source cost analysis in this report as guidance for the cost analysis should provide a relatively good approximation of the potential costs. In addition, most of the cost analyses tools that are available (such as the EPA Control Cost Manual) are generally only good to within about 30 percent. While we have tried to include some specific items that are site-specific, a further review of the list of factors that affect site-specific retrofit costs is advised. From that review, one should identify those factors for which costs will affect control equipment installation at the specific site and include them in the

21 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 21 cost analysis. For example, the utility costs used in the spreadsheets should be checked and any appropriate adjustments in the cost calculations made. Compare the calculated control costs to the results of the economic affordability analysis to determine which controls are economically feasible and select the appropriate controls as BART. Conduct a site-specific economic analysis of control cost affordability. Site-specific factors can significantly impact the installed costs of pollution control equipment. This is especially true at retrofits of existing equipment, which is the case with BART-eligible sources. Site-specific factors that can impact control costs include: o Site preparation work due to removal of existing equipment or modification of existing buildings and structures. o Site access for equipment delivery and erection. Existing buildings and structures may limit access to the construction site by cranes and other construction equipment. o Additional engineering costs to address piping and duct work tie-ins to existing equipment and structural issues caused by installing new equipment that was not planned for in the original equipment design. Process Safety Management Hazardous Operation (Haz-Op) review requirements and resultant safety system designs could also add to engineering costs. o Additional piping and insulation costs to fit new piping and ductwork within existing pipe racks and equipment support structures. o Auxiliary equipment that may be needed to accommodate the new control system e.g. blowers, heat exchangers, duct burners, or bypass stacks. o Lost production due to process equipment down time while the new equipment is being installed. This generally occurs when piping and duct work are tied in to existing equipment. If the facility is located in a relatively remote location, freight costs may be higher than standard estimating factors. For larger facilities, installation of control equipment will likely require on-site fabrication, which can increase construction costs. Site-specific wastewater treatment costs should be carefully evaluated. The raw materials used in production affect the type of constituents that may be found in wastewater streams. When certain materials are captured by wet scrubbing systems, they will likely affect wastewater quality, and the impact of scrubber blowdown on wastewater management systems should be considered. Compliance with water quality standards also needs to be considered. Model Source Parameters The BART screening evaluation uses a model boiler source to develop cost estimates for pollution control equipment. The model boiler parameters are listed in Table 3.1. The model source parameters were selected by surveying data on a variety of industrial boilers to determine average operational conditions for boilers greater than 250 MMBtu/hr. Two boiler fuel types were considered, coal and oil. As indicated previously, MACTEC s approach to determining BART was based on the fuel type that caused the largest emissions. With the exception of two boilers at one facility (Sun Company boilers B046 and B047 in Ohio), the majority of emissions of SO 2 and NO x were from coal fired boilers. The Sun Company primary fuel is residual oil.

22 Midwest RPO Boiler BART Engineering Analysis 3/28/2005 Page 22 TABLE 3.1 SUMMARY OF MODEL BOILER OPERATING CHARACTERISTICS. Normal Flow (dscfm) Stack Exit Gas Temperature ( F) Sulfur content (%) SO 2 Emissions (tpy) NO x Emissions (tpy) PM Emissions (tpy) Boiler fuel Moisture (%) Coal 250, Oil 136, Model Boiler NO x Control Technology Review Most of the NO x formed from combustion of natural gas is attributable to thermal NO x. For high grade fuel oil (e.g., distillate oil or naphtha), the amount of thermal NO x relative to fuel NO x depends upon the firing temperature. NO x formed from coal combustion is primarily derived from fuel NO x. The five steps used to determine BART for the model boilers are listed below. 1. Identify Available Retrofit Control Technologies 2. Eliminate Technically Infeasible Options 3. Rank Remaining Control Technologies 4. Evaluate Impacts and Document the Results 5. Recommend BART for model source BART Step 1: Identify All Available Retrofit Control Technologies The control technologies identified for NO x are as follows: Flue Gas Recirculation (FGR) Low-NO x Burners Ultra-low NO x burners (ULNB) Selective Non-Catalytic Reduction (SNCR) Selective Catalytic Reduction (SCR) The previous section provided background information on these control technologies. BART Step 2: Eliminate Technically Infeasible Options A summary of the technical feasibility analysis is listed in Table 3.2. Details of the analysis for each control technology follow the summary table.

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