Best Available Retrofit Technology Analysis For

Sherburne County Generating Plant Units 1 and 2

Prepared by

Northern States Power Co.

d/b/a Xcel Energy

October 25, 2006

Table of Contents

1.0 Executive Summary ................................................................................ 1

2.0 Introduction ............................................................................................... 3

3.0 Baseline Conditions and Visibility Impacts for BART-eligible Units ............. 6

4.0 BART Analysis for BART-Eligible Emission Units............................. 7 4.A Sulfur Dioxide Emission Controls - Emission Unit EU001/EU002.........................7

4.A.1 Available Retrofit Control Technologies .....................................................7 4.A.2 Technically Infeasible Options..................................................................17 4.A.3 Control Effectiveness of Remaining Control Technologies ......................18 4.A.4 Impact Analysis ........................................................................................18 4.A.5 Energy Impacts ........................................................................................23 4.A.6 Non-Air Quality Environmental Impacts ...................................................23 4.A.7 Remaining Useful Life ..............................................................................23 4.A.8 Visibility Impacts.......................................................................................23 4.A.9 Proposed SO2 BART................................................................................27

4.B Nitrogen Oxides Emission Controls – Emission Units EU001/EU002.................28

4.B.1 Available Retrofit Control Technologies ...................................................28 4.B.2 Technically Infeasible Options..................................................................41 4.B.3 Control Effectiveness of Remaining Control Technologies ......................42 4.B.4 Impact Analysis ........................................................................................42 4.B.5 Energy Impacts ........................................................................................47 4.B.6 Non-Air Quality Environmental Impacts ...................................................47 4.B.7 Remaining Useful Life ..............................................................................47 4.B.8 Visibility Impacts.......................................................................................47 4.B.9 Proposed NOx BART................................................................................51

4.C Particulate Matter Emission Controls – Emission Units EU001/EU002...............52

4.C.1 Available Retrofit Control Technologies ...................................................52 4.C.2 Technically Infeasible Options..................................................................62 4.C.3 Control Effectiveness of Remaining Control Technologies ......................62 4.C.4 Impact Analysis ........................................................................................62 4.C.5 Energy Impacts ........................................................................................65 4.C.6 Non-air Quality Impacts............................................................................65 4.C.7 Visibility Impacts.......................................................................................65 4.C.8 Proposed PM10 BART ..............................................................................65

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4.D Multipollutant Controls – Emissions Units EU001/EU002 ...................................66 4.D.1 Available Retrofit Control Technologies ...................................................66 4.D.2 Technically Infeasible Options..................................................................70

5.0 Conclusions ............................................................................................ 71

Appendix A.......................................................................................................... 76

Appendix B........................................................................................................ 100

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List of Figures

Figure 1. Process Flow Diagram of a Spray Tower Wet FGD System ......................................8 Figure 2. Cutaway View of a Jet Bubbling Reactor Wet FGD System.......................................9 Figure 3. Spray Dryer System .................................................................................................11 Figure 4. SDA FGD System ....................................................................................................11 Figure 5. Circulating Dry Scrubber System (Lurgi Lentjes North America)..............................13 Figure 6. Least Cost Curve - Unit 1 SO2 .................................................................................21 Figure 7. Least Cost Curve - Unit 2 SO2 .................................................................................22 Figure 8. SO2 Visibility Impacts at BWCA ...............................................................................26 Figure 9. Staged Combustion of low NOx burners and overfire air system..............................31 Figure 10. Mobotec ROFA™ and ROTAMIX™ Simplified Process Flow Diagram..................32 Figure 11. ECOTUBE Installation in a Boiler...........................................................................34 Figure 12. Schematic Diagram of a Typical SCR reactor ........................................................35 Figure 13. Schematic of SNCR System with Multiple Injection Levels ....................................37 Figure 14. Schematic of Gas Reburn System .........................................................................41 Figure 15. Least Cost Curve - Unit 1 NOx ...............................................................................45 Figure 16. Least cost Curve - Unit 2 NOx ................................................................................46 Figure 17. NOx Visibility Impacts at BWCA .............................................................................50 Figure 18. Electrostatic Precipitator System (MHI)..................................................................53 Figure 19. Pulse Jet Fabric Filter Compartment......................................................................55 Figure 20. COHPAC Arrangement ..........................................................................................57 Figure 21. Max-9 Electrostatic Filter........................................................................................58 Figure 22. Multi-cyclone Particulate Collector .........................................................................59

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Figure 23. Multiclone ...............................................................................................................59 Figure 24. ECO™ Process Flow Diagram...............................................................................67 Figure 25. Pahlman Process™ Simplified Process Flow Diagram ..........................................68 Figure 26. Phenix Clean Coal Process Flow Diagram.............................................................69 Figure 27. SO2 Visibility Impacts at BWCA ...........................................................................100 Figure 28. NOx Visibility Impacts at BWCA ...........................................................................101 Figure 29. SO2 Visibility Impacts at BWCA ...........................................................................102 Figure 30. NOx Visibility Impacts at BWCA ...........................................................................103 Figure 31. SO2 Visibility Impacts at IR...................................................................................104 Figure 32. NOx Impacts at IR ................................................................................................105 Figure 33. SO2 Visibility Impacts at IR...................................................................................106 Figure 34. NOx Visibility Impacts at IR...................................................................................107 Figure 35. SO2 Visibility Impacts at VNP...............................................................................108 Figure 36. NOx Visibility Impacts at VNP...............................................................................109 Figure 37. SO2 Visibility Impacts at VNP ...............................................................................110 Figure 38. NOx Visibility Impacts at VNP...............................................................................111

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List of Tables

Table 1. Summary of Proposed BART ......................................................................................2 Table 2. Baseline Conditions Modeling Input Data....................................................................6 Table 3. Basis for 24 Hour Actual Emissions Data in Table 4 ...................................................6 Table 4. Baseline Visibility Modeling Results ............................................................................6 Table 5. Control Effectiveness for SO2 Reduction Technologies ............................................18 Table 6. Unit 1 SO2 Compliance Costs ...................................................................................20 Table 7. Unit 2 SO2 Compliance Costs ...................................................................................20 Table 8. SO2 Post-Control Emission Rates for Emission Unit EU001/EU002 .........................24 Table 9. SO2 Post-Control Stack Parameters for Emission Unit EU001/EU002......................24 Table 10. SO2 Controls - Visibility Modeling Results ...............................................................24 Table 11. Incremental Visibility Costs at BWCA for SO2 Control .............................................25 Table 12. Control Effectiveness for NOx Reduction Technologies ..........................................42 Table 13. Unit 1 NOx Compliance Costs ................................................................................44 Table 14. Unit 2 NOx Compliance Costs .................................................................................44 Table 15. NOx Post-Control Emission Rates for Emission Unit EU001/EU002 .......................48 Table 16. NOx Post-Control Stack Parameters for Emission Unit EU001/EU002....................48 Table 17. NOx Controls - Visibility Modeling Results ...............................................................48 Table 18. Incremental Visibility Costs for BWCA for NOx Control ...........................................49 Table 19. Control Effectiveness for PM10 ................................................................................62 Table 20. Unit 1 PM10 Compliance Costs................................................................................64 Table 21. Unit 2 PM10 Compliance Costs................................................................................64 Table 22. Emission Unit EU001/EU002: Summary of the Impacts Analysis for SO2, NOx, PM10

Control Scenarios.....................................................................................................73

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Table 23. Visibility Modeling: Baseline Model Results.............................................................74 Table 24. Visibility Modeling: Boundary Waters Results .........................................................74 Table 25. Visibility Modeling: Voyageur National Park Results ...............................................74 Table 26. Visibility Modeling: Isle Royale Results ...................................................................75

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Page 1 of 111

1.0 Executive Summary The Regional Haze Rule calls for state and federal agencies to work together to improve visibility in 156 national parks and wilderness areas. Each state must modify its State Implementation Plan (SIP) to incorporate measures necessary to make reasonable progress toward the national visibility goal, including requirements that certain existing stationary sources install, operate, and maintain Best Available Retrofit Technology (BART). For Units 1 and 2 at Xcel Energy’s Sherburne County Generating Plant (Sherco), the Minnesota Pollution Control Agency (MPCA) determined that Xcel Energy must evaluate what constitutes BART for nitrogen oxides (NOx), sulfur dioxide (SO2), and particulate matter less than 10 microns (PM10). The regulations also provide that a state participating in the Clean Air Interstate Rule (CAIR), which includes Minnesota, need not require BART-eligible electric generating units to install BART, because EPA’s analysis concluded that CAIR controls are “better than BART” for electric generating units in states subject to CAIR. The MPCA has stated that it will determine whether CAIR substitutes for BART after BART analyses have been submitted. Since EPA concluded that CAIR will provide more visibility improvement than BART, Xcel Energy believes Sherco Units 1 and 2 should not be given BART limits and instead CAIR should drive emission reductions. Nevertheless, a BART analysis has been performed as required for Sherco Units 1 and 2, and is presented in this report. MPCA guidance for the BART analysis lists a presumptive NOx limit of 0.15 lb/MMBTU for units such as Sherco Units 1 and 2. Sherco 1 currently utilizes an overfire air (OFA) system and burners that will not allow the unit to achieve the presumptive NOx limit for BART. Sherco 2 utilizes low NOx burners (LNB) and a separated/close coupled overfire air system to control NOx. In response to the CAIR program, Xcel Energy is committed to the installation of LNBs, a separated/close coupled overfire air system, and a combustion optimization (CC) system for Sherco Unit 1 for NOx control in 2007. All control options for Sherco 1 include the costs for these projects. Likewise, Xcel Energy is installing a computer based CC system for NOx control for Sherco 2 in 2006. All control options for Sherco Unit 2 include the cost for this project. These changes to the boilers will bring NOx emissions for Sherco Units 1 and 2 to 0.15 lb/MMBTU. Xcel Energy proposes to meet the presumptive limit of 0.15 lb/MMBTU at the stack, on a 30-day rolling average. The proposed changes will be complete by the end of 2007, and compliance demonstrated by the end of 2008. There are no presumptive limits for SO2 for boilers with existing controls that achieve at least 50% removal. SO2 is controlled by wet flue gas desulfurization (FGD) systems (scrubbers) for each unit, which currently achieve 75% removal. Xcel Energy proposes

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to retrofit the existing scrubbers with sparger tubes and lime injection. The applicable emission limit would be 0.12 lb/MMBTU at the stack, based on a 30-day rolling average. These changes would be in place by the end of 2012. PM10 is controlled by wet scrubbers and wet electrostatic precipitators (WESP). Xcel Energy notes that there are no controls at this time for condensable PM10. No technology would significantly improve the particulate control from current levels at Sherco Units 1 and 2. As the cost-effectiveness was so high for all options, no new technology is proposed for PM10. Because no new technology is proposed, no change to the permit limit is proposed. Emission modeling predicts that Sherco Units 1 and 2 have the greatest effect on visibility in the Boundary Waters Canoe Area (BWCA), as compared to Voyageur National Park (VNP) and Isle Royale (IR), regardless of whether the effect is measured by the number of days with visibility impairment (visibility impairment > 0.5 deciview), or by the change in impairment at the 98th percentile. The proposed controls and visibility improvements (for the BWCA) are summarized in Table 1 below. The proposed BART controls and emission limits will result in significant visibility improvement. This proposed control equipment also provides Xcel Energy flexibility in determining a compliance strategy for mercury control requirements under the Clean Air Mercury Rule (CAMR) and the Minnesota Mercury Reduction Act, as well as for CAIR Phase II.

Table 1. Summary of Proposed BART

Emission Unit Proposed BART

Control

Pollutant(s) Controlled

Proposed BART

Emission Limit

Visibility Improvement

on 98th percentile

Day1

Class I Area(s)

Impacted

EU001/EU002

Retrofit existing FGD System with sparger

tubes and lime injection for Sherco 1 & Sherco 2

SO2 0.12 lb/MMBTU 2.13 BWCA

EU001/EU002

LNB/SOFA – Sherco1;

Combustion Optimization –

Sherco 1 & Sherco 2

NOx 0.15 lb/MMBTU 2.11 BWCA

1 Baseline 98th percentile was 2.68 dv

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2.0 Introduction In 1999, the U. S. Environmental Protection Agency (EPA) announced the Regional Haze Rule, a major effort to improve visibility in 156 national parks and wilderness areas. The rule requires states, in coordination with the EPA, the National Park Service, U.S. Fish and Wildlife Service, the U.S. Forest Service, and other interested parties, to develop and implement air quality protection plans to reduce the pollutants that cause visibility impairment, nitrogen oxides (NOx), sulfur dioxide (SO2), and particulate matter less than 10 microns (PM10). Each state must modify its State Implementation Plan (SIP) to include emissions limits, schedules of compliance, and other measures necessary to make reasonable progress toward meeting the national visibility goal, including the implementation of Best Available Retrofit Technology (BART) for certain major stationary sources (BART-eligible sources). BART-eligible sources are identified as selected sources (e.g. coal-fired power plants with more than 250 MMBTU/hour heat input) that were not in operation prior to August 6, 1962, were in existence on August 7, 1977, and have the potential to emit 250 tons per year or more of any visibility impairing air pollutant. For Xcel Energy’s emission units in Minnesota, Sherburne County (Sherco) Units 1 and 2, Riverside Unit 8, and A.S. King Unit 1 were all potentially BART-eligible. As a result of the Metro Emissions Reduction Project (MERP), Riverside Unit 8 will be decommissioned prior to the time Xcel Energy would have been required to comply with BART regulations. Results of visibility modeling conducted by the Minnesota Pollution Control Agency (MPCA) using the post-MERP emission rates for A.S. King Unit 1 indicated that emissions will not cause a visibility impact greater than 0.5 deciview (dv). Therefore, both Riverside Unit 8 and A. S. King Unit 1 are exempt from BART analysis. The MPCA performed visibility modeling to determine that Sherco Units 1 and 2 are subject to BART. The regulations also provide that a state participating in the Clean Air Interstate Rule (CAIR), which includes Minnesota, need not require BART-eligible electric generating units to install BART, because EPA’s analysis concluded that CAIR controls are “better than BART” for electric generating units in states subject to CAIR. The MPCA has stated that it will determine whether CAIR substitutes for BART after BART analyses have been submitted. Since EPA concluded that CAIR will provide more visibility improvement than BART, Xcel Energy believes Sherco Units 1 and 2 should not be given BART limits and instead CAIR should drive emission reductions. Nevertheless, a BART analysis has been performed as required for Sherco Units 1 and 2, and is presented in this report.

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Sherco Units 1 and 2 are located in Becker, Minnesota. They are tangential, pulverized coal fired boilers burning sub-bituminous coal. Sherco Unit 1 has a heat input of 7,111 MMBTU/hr with a gross output of 697 MW and began operation in 1976. Sherco Unit 2 began operation in 1977 and has a heat input of 7,111 MMBTU/hr and a gross output of 682 MW. The units discharge through a common 650-foot tall stack. The closest affected national park or wilderness areas are the Boundary Waters Canoe Area (BWCA), Voyageurs National Park (VNP), and Isle Royale (IR). The remainder of this report is the BART analysis performed for Sherco Units 1 and 2 (EU001/EU002). The analysis followed the 5 steps shown below:

Step 1. Identify all available retrofit technologies Step 2. Eliminate technically infeasible options Step 3. Evaluate control effectiveness of remaining control technologies Step 4. Evaluate impacts and document the results Step 5. Evaluate visibility impacts

The MPCA’s BART guidance document requires the use of maximum historical emissions data from different time periods for cost-effectiveness calculations and visibility modeling.

• The cost-effectiveness data was based on the maximum emissions of each pollutant during a rolling 12-month period from January 2001 through December 2005:

- maximum SO2 emissions were between January 2005 and December 2005,

- maximum NOx emissions were between May 2001 and April 2002, and - maximum heat input, used to calculate maximum PM10 emissions,

occurred between March 2002 and February 2003.

• The visibility model data are based on the maximum daily values from the period between January 2002 and December 2004:

- maximum daily value for NOx occurred on February 24, 2003, - maximum daily value for SO2 occurred on February 12, 2004, and - maximum daily heat input, which was used to calculate the maximum daily

PM10 emissions, occurred on February 12, 2004. The different sets of data do not occur during the same time period, nor are they for the same time periods. Since the units may have been operating differently during these

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periods, there is no way to correlate the emissions used in cost-effectiveness calculations with those used in visibility modeling. The heat input numbers were determined from the Continuous Emission Monitoring System (CEMS). The methodology was discussed with and agreed to by the MPCA. There are no presumptive limits for SO2 for coal fired electric generating units with existing controls that achieve at least 50% removal. For units with less than 50% removal, the presumptive SO2 limit is 0.15 lb/MMBTU. SO2 from Sherco Units 1 and 2 is controlled by wet flue gas desulfurization (FGD) systems (scrubbers) that currently achieve 75% removal. MPCA guidance for the BART analysis lists a presumptive limit of 0.15 lb/MMBTU for NOx for tangential-fired boilers greater than 200 MW located at sites with a capacity greater than 750 MW operating without post-combustion controls and burning sub-bituminous coal. Sherco Units 1 and 2 fit this category. Sherco Unit 1 currently utilizes an overfire air (OFA) system and burners that will not allow the unit to achieve the presumptive NOx limit for BART. Sherco Unit 2 utilizes LNBs and a separated/close coupled OFA system to control NOx. In response to the CAIR program, Xcel Energy is committed to the installation of LNBs, a separated/close coupled OFA (SOFA) system, and a combustion optimization (CC) system for the OFA system for Sherco Unit 1 for NOx control in 2007. All control options for Sherco Unit 1 in this analysis include the costs for these projects. Likewise, Xcel Energy is installing a computer based CC system for the OFA system for Sherco Unit 2 in 2006. All control options for Sherco Unit 2 in this analysis include the cost for this project. These changes to the boilers will allow Sherco Units 1 and 2 to achieve the presumptive NOx limit of 0.15 lb/MMBTU. PM10 is controlled by wet scrubbers and wet electrostatic precipitators (WESP). Xcel Energy notes that there are no controls at this time for condensable PM10. No technology would significantly improve the particulate control from current levels at Sherco Units 1 and 2.

3.0 Baseline Conditions and Visibility Impacts for BART-eligible Units

Table 2. Baseline Conditions Modeling Input Data

Emission Unit ID

Emission Unit

Description

SO2 Max 24 Hour Actual

Emissions (lb/day)

NOX Max 24 Hour Actual

Emissions (lb/day)

PM2.5 Max 24

Hour Actual

Emissions (lb/day)

PM10 Max 24 Hour Actual

Emissions (lb/day)

Stack Number

Location Easting (utm)

Location Northing

(utm)

Height of

opening from

ground, ft

Base Elevation

of ground,

ft

Stack Diameter,

ft

Flow Rate at exit, acfm

Exit Gas Temperature,

°F

EU001/EU002 Boiler 1 / Boiler 2 122,469 102,563 N/A 12,962 SV001 429,842 5,025,449 650 969 32.5 5,200,000 171

Table 3. Basis for 24 Hour Actual Emissions Data in Table 4

Emission Unit ID Basis for SO2 24 Hour Actual

Emissions Basis for NOx 24 Hour Actual

Emissions Basis for PM2.5 24 Hour Actual

Emissions Basis for PM10 24 Hour Actual

Emissions

EU001/EU002 CEMS Data CEMS Data N/A Stack test, 6/2004; Heat input from CEMS

Table 4. Baseline Visibility Modeling Results

2002 2003 2004 2002-2004 Combined

Emission Unit ID

Class I Area with Greatest

Impact Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

Modeled 98th percentile

Value, deciview

No. of days exceeding

0.5 deciview

Modeled 98th percentile

Value, deciview

No. of days exceeding

0.5 deciview

Modeled 98th percentile

Value, deciview

No. of days exceeding

0.5 deciview

EU001/EU002 BWCA 2.60 85 2.93 87 2.77 91 2.68 263

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4.0 BART Analysis for BART-Eligible Emission Units

4.A Sulfur Dioxide Emission Controls - Emission Unit EU001/EU002

4.A.1 Available Retrofit Control Technologies Both units currently use wet FGD systems to control SO2, which achieve 75% removal. SO2 control technologies that were identified as available for retrofit for Sherco Units 1 and 2 are listed below, followed by a detailed description:

• Wet flue gas desulfurization (FGD) • Semi-dry FGD • Dry FGD • Furnace/Duct reagent injection • Increase liquid to gas ratio (L/G) to existing scrubber • DBA (or other organic acid additive) addition to existing scrubber • Lime injection into existing scrubber • Retrofit wet ESP with sparger tubes • Retrofit existing FGD (installation of liquid distribution ring, installation of

perforated trays, redesign spray header or nozzle configuration) Wet flue gas desulfurization Although wet lime and ammonia FGD systems are available, wet limestone FGD processes are the most frequently applied FGD technology in the U. S. when treating flue gas from combustion of medium and high sulfur coals (typically greater than 1.5% sulfur). Wet limestone FGD systems are also applicable for units burning low sulfur bituminous and sub-bituminous coals, but economics typically favor the semi-dry lime FGD systems. However, wet limestone FGD systems are capable of achieving higher SO2 removal than semi-dry lime FGD systems, which could make them suitable for low sulfur applications with high removal requirements. A typical wet limestone FGD system consists of a reagent storage and handling system, FGD spray tower absorber, and byproduct dewatering system as illustrated in Figure 1.

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Figure 1. Process Flow Diagram of a Spray Tower Wet FGD System

For most wet limestone FGD applications, the absorber module is located downstream of the ID fans (or booster ID fans, if required). If flue gas bypass or reheat is applied, the ID or ID booster fans could be located downstream of the FGD absorber module. For a wet FGD system, the flue gas enters the absorber and it contacts a slurry containing reagent and byproduct solids. The SO2 is absorbed into the slurry and reacts with the calcium to form CaSO3•½H2O and CaSO4•2H2O. There are several types of absorber modules, and each has characteristic advantages and disadvantages. FGD equipment vendors have specific designs for one or more types, and all compete on a capital/operating cost and guarantee basis. Depending on the process vendor, the absorber may be a co-current or countercurrent spray tower, with or without internal packing or trays (refer to Figure 1). Other vendors use a unique absorber where the flue gas is bubbled into a reaction tank as illustrated in Figure 2. Regardless of the type of absorber used, the flue gas leaving the absorber is saturated with water and the stack will have a visible, persistent moisture plume. Generally, wet FGD systems do not remove significant quantities of SO3 from the flue gas. Condensed SO3, in the form of sulfuric acid mist (H2SO4), can be removed from the flue gas if a wet ESP is used as a mist eliminator downstream of a wet FGD system. If a wet ESP is not used downstream of a wet FGD system, there will be significant increase in SO3 emitted from the stack.

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Figure 2. Cutaway View of a Jet Bubbling Reactor Wet FGD System

Because of the chlorides present in the mist carryover from the absorber and the pools of low pH condensate that can develop, the conditions downstream of the absorber are highly corrosive to most materials of construction. Highly corrosion-resistant materials are required for the downstream ductwork and for the stack flue. Careful design of the stack is needed to prevent “rainout” from condensation that occurs in the downstream ductwork and stack. The reaction byproducts are typically dewatered by a combination of hydro-cyclones and vacuum filters. For natural oxidation wet limestone FGD systems, the resulting filter cake is suitable for landfill disposal. In some instances, the FGD byproduct requires mixing with fly ash and/or lime (fixation) to produce a physically stable material. If air is bubbled through the reaction tank, practically all of the CaSO3• ½H2O can be converted to CaSO4•2H2O, which is commonly known as gypsum. This oxidation step is termed “forced oxidation.” Compared to calcium sulfite, gypsum has much superior dewatering and physical properties, and forced-oxidized systems exhibit few scaling problems in the absorber and mist eliminators. Dewatered gypsum can be disposed of in landfills without stabilization or fixation. Many wet FGD systems in the U. S. are using the forced-oxidation process to produce commercial grade gypsum that can be

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used in the production of Portland cement or wallboard. Marketing of the gypsum can eliminate or greatly reduce the need to dispose of FGD byproducts in landfills. However, the market for the commercial grade gypsum is often neither available nor stable. The wet FGD processes are characterized by high efficiency (typically between 92 to 98%) and high reagent utilization (95 to 97%). The absorber vessels are fabricated from corrosion-resistant materials such as epoxy/vinylester-lined carbon steel, rubber-lined carbon steel, stainless steel, or fiberglass. The absorbers handle large volumes of abrasive slurries. The reagent handling and byproduct dewatering equipment is also relatively complex and expensive. These factors result in relatively higher initial capital costs and lower annual operating costs compared to the semi-dry FGD alternatives. Semi-dry flue gas desulfurization The semi-dry FGD process is based on the spray drying of lime into flue gas. Spray drying has been used in many industrial process industries since the 1920's. Since its introduction in the utility industry in the 1970's, the semi-dry spray dryer absorber (SDA) FGD process has been one of the most widely applied FGD technologies. U.S. utilities have installed numerous SDA FGD systems on boilers using low-sulfur fuels. These installations, primarily located in the western U.S., use either lignite or sub-bituminous coals as boiler fuel and generally have spray dryer systems designed for a maximum fuel sulfur content of less than 2%. There are several variations of this process, but the most prevalent is the installation of one or more spray dryer vessels upstream of the particulate control device as shown in Figures 3 and 4. The SDA absorber vessel is located between the air heater and the particulate removal device, most commonly a pulse jet fabric filter (PJFF). Although either quicklime slurry (CaO) or a sodium carbonate (soda ash) solution may be used as the scrubbing reagent, the current generation of SDA FGD processes primarily use quicklime. The quicklime is first slaked with water to form a calcium hydroxide (Ca(OH)2) slurry. The lime slurry is combined with the recycled solids from the PJFF to form the reagent slurry. The reagent slurry is injected in the absorber using either a rotary or two-fluid atomizer, where the lime reacts with the SO2 in the flue gas. Sufficient water is added with the reagent slurry to lower the flue gas temperature to within 18 °C (32 °F) of the adiabatic saturation temperature. The SO2 is absorbed into the fine spray droplets and reacts with the lime slurry to form both calcium sulfite (~1/3) and calcium sulfate (~2/3). Before the droplet can reach the wall of the atomizer, the

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heat of the flue gas evaporates the droplet to a dry particle containing the byproduct solids and excess reagent. As the reagent slurry evaporates, a relatively dry powder remains.

Figure 3. Spray Dryer System

Figure 4. SDA FGD System

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The byproduct solids and fly ash are collected in the PJFF. Some additional SO2 removal occurs as the flue gas passes through the dust cake on the bags. The byproducts and fly ash are conveyed pneumatically to the fly ash silo in the conventional manner. These solids are unloaded, conditioned with water, and transported to a landfill. Because of the level of free lime in the byproduct solids, the byproduct/fly ash mixture attains a very high bearing strength and low permeability in the landfill. Unlike a wet limestone FGD system, there is currently no commercial use for the byproduct/fly ash. Dry flue gas desulfurization A circulating dry scrubber (CDS) is a form of Dry FGD for SO2 removal. This technology is capable of removing 95 to 98% of the SO2 in the flue gas. Hydrated lime (Ca(OH)2) is the reagent used and is introduced as a dry, free flowing powder into the scrubber vessel. Flue gas is then flowed through the lime reagent in a circulation pattern for adsorption of SO2 by the lime. A schematic of the process flow of a CDS process is shown in Figure 5. Generally, there are no constraints on the maximum fuel sulfur content, as the CDS can be adjusted to account for the higher SO2 loading by increasing the concentration of reagent. However, this flexibility is limited by the cost of the lime reagent. An evaluation on the overall reagent cost is important before selecting this technology. Lime utilization is improved by cooling the flue gas before it reacts with the lime. Flue gas coming into the scrubber vessel is cooled to about 30 oF above the adiabatic saturation temperature. As is the case with the SDA, a downstream particulate collection device is required, usually an ESP or fabric filter for the removal of particulate matter that is from the ash in the coal and the product of the reaction of lime with the SO2 in the flue gas. Because of the relatively high velocity of the flue gas through the scrubber vessel (approximately 19 ft/s), the treated flue gas carries entrained reagent and reaction products from the module to the downstream particulate control device. More than 90% of the collected solids in the ESP or fabric filter contain unreacted lime. Because of abrasion and impacts of the other particles in the flue gas as well as materials handling dynamics, the “shell” of reaction products on the reagent particles is broken up. This material is recycled into the scrubber vessel to further improve lime utilization. This solids recirculation also maintains the bed densities needed for contact

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and removal of SO2. Typically, reagent is circulated 35 to 50 times, providing a residence time of 30 minutes or more. Collected solids, which are not recirculated, will be disposed.

Figure 5. Circulating Dry Scrubber System (Lurgi Lentjes North America)

As illustrated in the Figure 5, the CDS is a small vessel with the associated ESP in an elevated location because flue gas travels upward in a CDS vessel. This results in a smaller footprint for applications with space constraints. However, depending on the site situation, the retrofit of such a system might be costly, especially if there are substantial construction and structural difficulties.

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The disadvantages of this process include high dust loading at the particulate removal system and lack of U.S. utility operating experience. Higher fabric filter pressure drops are encountered because of the flue gas dust loading, thus, ESPs are preferred for particulate removal. The high particulate loadings make sizing of the ESP critical to ensure compliance with particulate emission requirements. However, this could limit future fuel flexibility. Furnace/duct reagent injection Two potential low-efficiency, low capital cost SO2 control options are furnace and duct injection systems. Each of these two control technologies requires either a wet or dry reagent such as: sodium bicarbonate, powdered lime, hydrated lime, lime slurry, limestone or magnesium hydroxide. This technology is typically capable of removing between 20 to 50% of the SO2 in the flue gas; removal efficiency is highly dependent on the application, primarily the configuration of the existing ductwork and the flue gas resident time in the ductwork. Typically, depending on the type of reaction, temperature, percentage reduction rate, and the corresponding retention time requirements, dry reagents such as powdered lime or hydrated lime are preferred for furnace injection applications. Wet reagents such as lime slurry, sodium bicarbonate, or magnesium hydroxide are typically preferred for duct injection applications based on the removal requirements and the flue gas properties. Generally, depending on the inlet concentration levels, it is expected that a combined injection system that includes both furnace and duct injection would be necessary. However, based on the total removal requirements in some applications, duct injection would be preferred over furnace injection. Therefore, wet reagent duct injection downstream of the boiler and near the ESP inlet may be necessary. The use of a wet reagent for duct injection is preferred over a dry reagent because of the elevated gas temperatures that exist during normal operating conditions. The use of a wet reagent upstream of an existing ESP will help reduce the gas temperature, improve ESP performance for opacity and particulate control, and eliminate the need for additional ID booster fans for additional draft control. Also, Computational Fluid Dynamics (CFD) and chemical kinetic modeling may be necessary to determine which reagent is preferred, the preferred location of reagent injection, the amount of SO2 emissions removed, and whether furnace injection, duct injection or both furnace/duct injection systems are required for the effective removal.

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Unit design and operational data are collected for the CFD computer model inputs. This data, combined with unit mapping information, enables the model to develop precise injection locations and reagent injection characteristics for each boiler. The major components of a typical reagent injection system include an air compressor, chemical storage tank, heat tracing, controls, injection system (i.e., flanges, lances, nozzles, hoses, hardware, etc.), injection platform, and slurry pump. Furnace injection can reduce or eliminate fireside slagging, fouling, corrosion and erosion problems in the furnace. Other benefits in terms of various efficiency improvements include: savings through greater heat transfer cleanliness, reduction of periodic air heater replacement, increase in overall unit reliability, boiler cleaning cost reduction, and ultimately extending unit runs to the point where only scheduled outages are taken. Increase liquid to gas ratio to existing scrubber This alternative assumes that the SO2 removal efficiency in the existing wet scrubber could be increased from the current level of 75% to a maximum value of 85% by the addition of another spray header in the scrubber. For the purpose of this analysis, it was assumed that this new spray level would provide a liquid-to-gas ratio (L/G) of 20 gallons per 1000 cubic feet of flue gas. One additional spray pump with a flow rate of 6,000 gpm would be required for each of the 12 existing scrubber modules (assuming 10 modules in service and 2 in standby). The location and orientation of the required new spray header in the absorber were not identified in this study. No additional reagent was assumed to be required in this alternative. As in the existing system, all of the reagent requirements are assumed to be provided by the alkaline fly ash removed in the scrubber. Pilot testing would be required to determine the optimum spray header location and L/G and to identify any effects on the performance of the scrubber and associated wet ESPs. DBA addition to existing scrubber This alternative assumes that the SO2 removal efficiency of the existing scrubber could be increased to 80% by the addition of dibasic acid (DBA) to the process slurry. DBA buffers the scrubbing slurry in the optimum range for SO2 removal. For this alternative, it was assumed that 10 pounds of DBA would be consumed for every ton of SO2 removed. DBA has a unit cost of approximately $0.42/lb. Pilot testing would be required to determine the effectiveness of DBA addition and the actual consumption

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rate. The only equipment required is a DBA storage and feed system consisting of a storage tank, feed pumps, and piping. Because DBA will solidify if its temperature drops below approximately 90 °F, the storage tank must be heated and insulated and all piping must be heat traced. DBA is corrosive, and all materials of construction are Type 316 stainless steel. Lime injection to existing scrubber This alternative assumes that the SO2 removal efficiency of the existing scrubber could be increased to 85% by raising the pH of the scrubber slurry through the addition of lime to the process slurry. Currently, all calcium reagent for the desulfurization process is provided by the alkaline fly ash removed in the scrubber. Typically, SO2 removal efficiency increases as the slurry pH increases. For this alternative, lime slurry would be added to the existing scrubber in an amount equal to 20% of the total reagent demand (e.g., a stoichiometric feed rate of 0.2). At design conditions, this would be approximately 16 tons per day of lime. Pilot testing would be required to determine the effectiveness of lime addition and the actual consumption rate. It was assumed that the existing limestone slurry storage and feed equipment could be reused to feed the lime to the scrubber modules. The use of lime slurry from the Unit 3 storage tank was assumed to be available and approved for use in the Unit 2 system by Xcel Energy and its SMMPA partner. It was also assumed that the relatively small increase in lime slaking demand could be accommodated by the existing slaking equipment by extending operating hours. Further analysis of the existing equipment would be necessary to determine if new equipment (or reconditioning of the existing equipment) would be required. Retrofit wet FGD with sparger tubes Xcel Energy could consider retrofitting the current venturi scrubber/wet ESP modules with sparger tubes. These sparger tubes would be installed within the existing modules so that the incoming flue gas would be channeled through the sparger tubes, forcing the flue gas to bubble through the slurry in the reaction tank. With this configuration, the higher the level of slurry relative to the bottom of the sparger tubes the greater the contact of the flue gas with the slurry, increasing SO2 removal. As such, it is similar to the option of increasing the L/G ratio. The volumetric flue gas flow and the pressure drop across the sparger modules would be kept the same as the current arrangement. Half of the existing venturi rods would

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be removed, reducing the maximum pressure drop across the rods from 22” wc to 3” wc. This would allow for as much as 18” wc of slurry above the bottom of the sparger tubes. The venturi spray flows and the crossover duct spray flows would remain unchanged, allowing the incoming flue gas to be wetted and for some particulate and SO2 removal prior to entering the sparger tubes. Retrofit wet FGD with sparger tubes with lime injection The retrofit of the wet FGD with sparger tubes would also allow the injection of lime into the scrubber to raise the pH of the slurry. The increased pH would contribute to higher SO2 removal as discussed with the option above.

4.A.2 Technically Infeasible Options It is impractical to install furnace/duct injection when more reagent could be added to the existing scrubber. In fact, Xcel Energy is not aware of any unit using furnace/duct injection with an existing FGD System. Furnace/Duct injection will not be considered further in this report. Retrofitting the existing FGD system (installation of liquid distribution ring, installation of perforated trays, redesign spray header or nozzle configuration) is considered infeasible due to a lack of physical space in the existing scrubbers.

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4.A.3 Control Effectiveness of Remaining Control Technologies

Table 5. Control Effectiveness for SO2 Reduction Technologies

(lb/MMBTU) (tons/yr) (tons/yr)

Emitted Emitted Removed

Unit 1 (Baseline 0.27 lb/MMBTU)

DBA Addition to Existing Scrubber 0.24 6,700 830

Lime Injection into Existing Scrubber 0.18 5,000 2,500

Increase L/G to Existing Scrubber 0.18 5,000 2,500

Retrofit Wet FGD with Sparger Tubes 0.14 3,900 3,600

Retrofit Wet FGD with Sparger Tubes with Lime Injection 0.12 3,300 4,200

New Semidry FGD 0.11 3,100 4,400

New Wet FGD 0.09 2,500 5,000

Unit 2 (Baseline 0.27 lb/MMBTU)

DBA Addition to Existing Scrubber 0.24 6,700 830

Lime Injection into Existing Scrubber 0.18 5,000 2,500

Increase L/G to Existing Scrubber 0.18 5,000 2,500

Retrofit Wet FGD with Sparger Tubes 0.14 3,900 3,600

Retrofit Wet FGD with Sparger Tubes with Lime Injection 0.12 3,300 4,200

New Semidry FGD 0.11 3,100 4,400

New Wet FGD 0.09 2,500 5,000

4.A.4 Impact Analysis Tables 6 and 7 show the costs of compliance for SO2 control for Sherco Units 1 and 2 respectively for the technologies considered applicable and available. Capital and operating costs were estimated with CUECOST and supplemented with data from Xcel Energy (see Appendix A). As these are order of magnitude estimates, they are accurate only to ±30%. The capital costs were annualized over a 20-year period and then added to the annual operating costs to obtain the total annualized costs for each technology. The data in the table are sorted from least expensive annualized cost to most expensive annualized cost. The incremental costs were calculated after constructing the least cost curves, shown in Figures 6 and 7 (based on 40 CFR Part 51,

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Appendix Y). From these curves, all options would be considered dominant, or potentially cost-effective, except new semi-dry FGD systems for each unit and lime injection to the existing scrubbers. The incremental costs compare the average cost-effectiveness of the dominant options by dividing the difference in annual costs from a higher cost-effectiveness option to the next less expensive option with the difference in tons of SO2 removed for the two options. The incremental cost-effectiveness compares the cost-effectiveness between Options 1 and 2 ($60/ton), Options 2 and 4 ($150/ton), Options 4 and 5 ($900/ton), and Options 5 and 7 (> $40,000/ton). As seen above, the incremental costs change significantly between Options 5 and 7. Based on these incremental costs, the most cost-effective option for optimal SO2 control is retrofitting the existing scrubbers with sparger tubes and lime injection (Option 5 in Tables 6 and 7).

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Table 6. Unit 1 SO2 Compliance Costs

Option Number Technology

Expected Reduction (tons/year)

Rate (lb/MMBTU)

Capital Costs

Annualized Capital Costs

Annual Operating

Costs

Total Annualized

Cost

Cost Effectiveness

($/ton)

Incremental Cost

Effectiveness ($/ton)

1 DBA addition to existing scrubber 800 0.24 $1,030,000 $97,000 $158,000 $260,000 310 2 Increase L/G ratio to existing scrubber 2,500 0.18 $2,300,000 $217,000 $135,000 $350,000 140 583 Lime injection in existing scrubber 2,500 0.18 $90,000 $8,000 $490,000 $500,000 2004 Retrofit existing scrubber with sparger tubes 3,600 0.14 $3,600,000 $340,000 $177,000 $520,000 140 1505 Retrofit scrubbers with sparger tubes + Lime injection in existing scrubber 4,200 0.12 $3,700,000 $349,000 $667,000 $1,000,000 240 900 6 New semi-dry FGD 4,400 0.11 $106,000,000 $10,017,000 $12,105,000 $22,000,000 5,000 7 New wet FGD 5,000 0.09 $222,000,000 $20,979,000 $16,286,000 $37,000,000 7,500 44,000

Table 7. Unit 2 SO2 Compliance Costs

Option Number Technology

ExpectedReduction(tons/year)

Rate (lb/MMBTU)

Capital Costs

Annualized Capital Costs

Annual Operating

Costs

Total Annualized

Cost

Cost Effectiveness

($/ton)

Incremental Cost

Effectiveness ($/ton)

1 DBA addition to existing scrubber 800 $1,000,0000.24 $100,000 $200,000 300$250,000 2 Increase L/G ratio to existing scrubber 2,500 0.18 $2,300,000 $200,000 $100,000 $350,000 140 603 Lime injection in existing scrubber 2,500 0.18 $90,000 $0 $470,000 190$480,0004 Retrofit existing scrubber with sparger tubes 3,600 0.14 $3,600,000 $300,000 $200,000 $510,000 140 1505 Retrofit scrubbers with sparger tubes + Lime injection in existing scrubber 4,200 0.12 $3,700,000 $300,000 $600,000 $990,000 240 860 6 New semi-dry FGD 4,400 0.11 $106,100,000 $10,000,000 $11,800,000 $22,000,000 4,900 7 New wet FGD 5,000 0.09 $222,200,000 $21,000,000 $15,800,000 $37,000,000 7,400 43,000

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Figure 6. Least Cost Curve - Unit 1 SO2

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0 1,000 2,000 3,000 4,000 5,000 6,000

Expected Reduction, tons/yr

Tota

l Ann

ualiz

ed C

ost,

$1,0

00/y

r

Sparger TubesSparger Tubes w/Lime Injection

new Wet FGD

Increase L/G RatioDBA Addition

Most Cost Effective Option

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Figure 7. Least Cost Curve - Unit 2 SO2

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

0 1,000 2,000 3,000 4,000 5,000 6,000

Expected Reduction, tons/yr

Tota

l Ann

ualiz

ed C

ost,

$1,0

00/y

r

Sparger TubesSparger Tubes w/Lime Injection

New Wet FGD

Increase L/G RatioDBA Addition

Most Cost Effective Option

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4.A.5 Energy Impacts New wet and semi-dry FGD systems would increase auxiliary power needed in the plant, and would reduce efficiency and energy available to consumers. This would increase the need for generation from some other source. A new wet FGD system will require an additional 13,900 kW of auxiliary power. A new semi-dry FGD system will require an additional 4,900 kW of auxiliary power. There are no other anticipated energy impacts from the other feasible technologies.

4.A.6 Non-Air Quality Environmental Impacts No non-air quality environmental impacts were identified.

4.A.7 Remaining Useful Life

Since the useful life of Sherco is longer than 20 years, there is no impact to the annualized capital costs because the useful lives of the units are longer than the feasible technologies.

4.A.8 Visibility Impacts

Computer modeling was performed to predict the number of days that visibility impairment would be greater than 0.5 dv. The model also predicts the change in the 98th percentile delta dv, where a larger change in the delta dv translates into an improvement in visibility. Based on the control costs discussed earlier, computer modeling was performed to predict the effect on visibility of either retrofitting the existing scrubbers with sparger tubes and lime injection (Control Scenario 3), or installing a new wet FGD system for each unit (Control Scenario 4). From Table 10 and Figure 8, it can be seen that, over the period from 2002 through 2004, the computer modeling predicts a 98th percentile delta dv of 2.13 for the sparger tube retrofit with lime injection to the existing scrubbers, and 2.00 for new wet FGD systems for both units. The model predicts that there will be 208 days above 0.5 dv with the sparger tube retrofit and lime injection, and 206 days above 0.5 dv for new wet FGD systems for both units, as opposed to the baseline of 263 days above 0.5 dv. Also note that for 2003, the model predicted that visibility would actually decrease with new wet FGDs. From a visibility standpoint, both options provide nearly the same improvement in visibility.

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Table 8. SO2 Post-Control Emission Rates for Emission Unit EU001/EU002

Control Scenario #

SO2 Control Technology

SO2 Max 24 Hour Actual Emissions,

lb/day % Reduction

NOx Max 24 Hour Actual Emissions,

lb/day % Reduction

(Increase)

PM2.5 Max 24 Hour Actual Emissions,

lb/day % Reduction

(Increase)

PM10 Max 24 Hour Actual Emissions,

lb/day % Reduction

(Increase)

3 Sparger

tube w/lime injection

54,431 56 102,563 0 N/A N/A 1966 0

4 New wet FGD system 40,823 67 102,563 0 N/A N/A 1966 0

Table 9. SO2 Post-Control Stack Parameters for Emission Unit EU001/EU002

Control Scenario #

SO2 Control Technology Stack No.

Location Easting (utm)

Location Northing

(utm)

Height of opening from

ground, ft

Base elevation of ground, ft

Stack Diameter, ft

Flow rate at exit, acfm

Exit gas temperature,

°F

3 Sparger tube

w/lime injection

SV001 429,842 5,025,449 650 969 32.5 5,200,000 171

4 New wet FGD system SV001 429,842 5,025,449 650 969 32.5 4,720,000 129

Table 10. SO2 Controls - Visibility Modeling Results

2002 2003 2004 2002-2004 Combined

Control Scenario #

SO2 control

technology

Class I Area with Greatest Impact

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

3 Sparger

tube w/lime

injection

BWCA 2.01 64 2.36 72 2.28 72 2.13 208

4 New wet

FGD system

BWCA 1.92 64 2.51 69 2.09 73 2.00 206

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Table 11. Incremental Visibility Costs at BWCA for SO2 Control

Control Case Technology

Total Annualized

Cost

Incremental Total

Annualized Cost

98th Percentile Visibility

Impairment, dv

Impairment Improvement,

dv

Incremental Impairment

Improvement, $/dv

Base 2.68Case 1 Sparger tube retrofit $2,000,000 $2,000,000 2.13 0.55 4,000,000Case 2 New wet FGD $74,000,000 $72,000,000 2.00 0.13 550,000,000

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Figure 8. SO2 Visibility Impacts at BWCA

2.60

2.932.77

2.68

2.01

2.36 2.282.13

1.92

2.51

2.09 2.00

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile v

alue

, dv

Baseline Spargers Wet FGD

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4.A.9 Proposed SO2 BART Xcel Energy proposes to retrofit the existing wet scrubbers with sparger tubes and lime injection. The proposed emission rate is 0.12 lb/MMBTU at the stack, on a 30-day rolling average. This rate is lower than the presumptive limit for units that are not achieving 50% removal. Retrofitting existing scrubbers with sparger tubes and lime injection would be completed by the end of 2012. The retrofit would reduce SO2 emitted from Sherco Units 1 and 2 on the order of 8,300 tons per year and allow Xcel Energy flexibility in achieving required mercury reductions. The total annualized cost for retrofitting the existing scrubbers with sparger tubes and lime injection is $2,000,000 with a significant visibility improvement of 0.55 dv, or $4,000,000/dv (Table 11). Conversely, the total annualized cost to move to the next most effective control technology (new wet FGD) is approximately $72,000,000 with a visibility improvement of only 0.13 dv, or $550,000,000/dv. The incremental cost-effectiveness between the sparger/lime retrofit and new wet FGD is greater than $40,000/ton removed, which Xcel Energy asserts is excessive. New wet FGD systems would increase auxiliary power needed in the plant, reduce efficiency, and reduce energy available to consumers. This would increase the need for generation from some other source. Xcel Energy firmly believes the most cost-beneficial visibility improvements will be brought about by retrofitting the existing wet scrubbers with sparger tubes and lime injection.

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4.B Nitrogen Oxides Emission Controls – Emission Units EU001/EU002

4.B.1 Available Retrofit Control Technologies Sherco Unit 2 currently utilizes LNB, and a separated/close coupled OFA system. A combustion optimization system will be installed on this unit during an outage this fall (2006). Unit 1 is scheduled to receive LNB and separated/close coupled OFA system and a combustion optimization system next fall (2007). NOx control technologies that were identified as available for retrofit at Sherco Units 1 and 2 are listed below:

• Combustion optimization (CC) system • LNB with SOFA - Unit 1 only • Mobotec ROFA & ROTAMIX • NOxStar & NOxStar Plus • Ecotube • Induced flue gas recirculation (IFGR) • Selective catalytic reduction (SCR) • Selective non-catalytic reduction (SNCR) • SCR/SNCR Hybrid (Cascade System) • LoTOx • Natural gas reburn (includes fuel lean gas reburn (FLGR) and amine-enhanced

fuel lean gas reburn (AE-FLGR)) Combustion optimization system For optimum combustion, properly balanced amounts of coal and air should enter the furnace through the delivery of each burner and the OFA system, if present. This balanced delivery should produce the maximum amount of heat with the minimum amount of waste. However, without the ability to continuously monitor air and fuel flow entering each burner and the resulting burner performance, conditions typically exist where inadequate air is supplied for combustion, creating a fuel-rich or air-rich area. Both conditions reduce boiler efficiency and result in excess carbon monoxide (CO), fly ash loss-on-ignition (LOI) or NOx emissions. In an attempt to prevent or reduce these effects, plants often turn to the procedure known as “burner balancing.” This entails the monitoring and adjustment of burners so

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that the fuel/air ratio is equalized across the boiler. Historically, this has not been a simple procedure to perform or to maintain across the normal boiler load range. Initial attempts at monitoring LNB performance were directed toward measuring flue gas constituents leaving the boiler, which provided an indication of the total air-to-fuel ratio and average NOx and CO emissions. This information established the average performance of the complete firing system, but the performance status of each individual burner was not available. Recent advances in flow measurement and flame-scanning techniques have shown some limited success in monitoring both coal and primary airflow, and also secondary airflow to each burner, in addition to burner flame pattern. With this additional level of on-line performance data, the secondary airflow and pulverizer feeders can be biased to continuously maintain burner-to-burner balance. Additionally, recent advances in computer hardware and software technology have enabled power generation companies to improve their competitive position by implementing cost-effective optimization solutions that decrease emissions and maximize plant efficiency. These solutions, commonly referred to as boiler optimization or neural network systems, provide simultaneous improvements in both fuel efficiency and emissions. Neural network computing differs from traditional computing in that engineering, statistical, and first-law principles have been replaced by complex, time varying, nonlinear relationships. Neural network systems use real-time operational data extracted from a plant Distributed Control System (DCS), "learn" solutions from plant operational experience, and reduce emissions, while improving plant performance by continuously adapting to changes in plant operation. Neural network systems also supplement other NOx reduction strategies. Some of these include LNBs, OFA and post-combustion controls such as SCR and SNCR. These systems are also used to help boiler manufacturers tune boilers with poor combustion characteristics or after an LNB retrofit or adding OFA.

Low NOx burners NOx, primarily in the form of nitric oxide (NO) and NO2 are formed during combustion by two primary mechanisms: thermal NOx and fuel NOx. Thermal NOx results from the dissociation and oxidation of nitrogen in the combustion air. The rate and degree of thermal NOx formation is dependent upon oxygen availability during the combustion

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process and is exponentially dependent upon combustion temperature. Fuel NOx, on the other hand, results from the oxidation of nitrogen organically bound in the fuel. This is the dominant NOx producing mechanism in the combustion of pulverized coal. All LNB offered commercially for application to coal-fired boilers control the formation and emission of NOx through some form of staged combustion. The basic NOx reduction principles for low NOx burners are to control and balance the fuel and airflow to each burner, and to control the amount and position of secondary air in the burner zone so that fuel devolatization and high temperature zones are not oxygen rich. In this process, the mixing of the fuel and the air by the burner is controlled in such a way that ignition and initial combustion of the coal takes place under oxygen deficient conditions, while the mixing of a portion of the combustion air is delayed along the length of the flame. The objective of this process is to drive the fuel-bound nitrogen out of the coal as quickly as possible, under conditions where no oxygen is present, and where it will be forced to form molecular nitrogen, rather than be oxidized to NOx. Any nitrogen escaping the initial fuel-rich region has a greater opportunity to be converted to NOx as the combustion process is completed. The net result of staged combustion is usually longer and/or wider flames, due to this delayed mixing process. Low NOx burners and OFA system In addition to the LNB system, an incremental approach to NOx control is to install an OFA system to combine LNBs with OFA. OFA works by reducing the excess air in the burner zone, thereby enhancing the combustion staging effect and further reducing NOx emissions. Any residual unburned material, such as CO and unburned carbon, which inevitably escapes the main burner zone, is subsequently oxidized as the OFA is added. As with primary NOx control, the performance that can be expected from a given OFA system depends upon a number of factors. As the amount of OFA is increased, the stoichiometry in the burner zone decreases and a point is reached at which CO emissions reach high levels and become uncontrollable. The point at which this occurs can be boiler and coal type specific, particularly if a fuel is difficult to burn, and will also depend upon the extent to which it is possible to balance flows between the individual cyclones or burners. As the OFA amount approaches 10 to 15%, the probability for individual burners operating under overall fuel-rich conditions increases, such that pockets of very high CO emissions and unburned carbon will be formed. Similarly, fuel rich operation at burners close to the water walls can begin to lead to local slag

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formation and increased tube wastage rates, particularly if slagging is an ongoing problem and the coals have high sulfur content. A fairly high level of unburned material leaving the burner zone can be accommodated by proper over fire port design, where requirements call for rapid and complete mixing of the OFA with the boiler flue gases. A diagram illustrating the staged combustion of LNB and OFA is illustrated in Figure 9.

Overfire Air

Figure 9. Staged Combustion of low NOx burners and OFA system

Mobotec ROFA & ROTAMIX Mobotec provides a NOx reduction system that combines LNB, OFA, and SNCR technologies into an integrated system. The system uses a modified OFA system with improved mixing characteristics achieved through adding a rotation to the OFA. This system is called ROFATM – Rotating Opposed Firing Air. In addition ROTAMIXTM, which consists of adding urea or ammonia injection into the ROFATM air nozzles, can be added to the system. The extra mixing produced by combining the OFA nozzles with the reagent injection, results in improved mixing and a more homogeneous temperature profile in the boiler. A simplified process flow diagram of the ROFATM and ROTAMIXTM system is illustrated in Figure 10. The NOx reduction system has been commercially proven and has achieved up to 75% NOx reduction. Basically, the more heterogeneous temperature profile in the boiler will optimize combustion and, in turn, will promote higher carbon content in the fly ash than a typical combustion environment would.

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Figure 10. Mobotec ROFA™ and ROTAMIX™ Simplified Process Flow Diagram

NOxStar & NOxStar Plus NOxStarTM is the trademarked name for a NOx control technology that involves the injection of ammonia and a hydrocarbon (typically natural gas) into the flue gas path of a coal-fired boiler at approximately 1,600 – 1,800 °F for reduction of NOx. The ammonia reduces NOx through a selective non-catalytic reduction (SNCR) reaction, with the hydrocarbon minimizing the ammonia slip. This enables higher reagent injection rates for NOx reductions than achievable with a typical SNCR technology. A central premise of the technology is the ability to achieve NOx emissions of less than 0.20 lb/MMBTU without the use of a catalyst. Although initially targeting high NOx reductions, full-scale demonstrations to date have been limited to nominally 50% NOx reduction performance. NOxStar eliminates solid catalyst and the associated problems of chemical poisoning, physical plugging, and sintering due to temperature excursions, pressure drop requiring new ID fans and disposal of a hazardous solid waste. NOxStar opportunistically operates within the confines of the boiler’s convective pass, eliminating the necessity to build a huge catalyst reactor and the associated SCR capital costs, economizer modifications, and major outages. The other advantage of the NOxStar system is that the conversion of SO2 to SO3 is said to be negligible, thus eliminating one of the main drawbacks of the SCR technology. NOxStar has a lower NOx reduction efficiency as compared to SCR and also has a higher ammonia slippage rate than an SCR. SO3 in the presence of ammonia will form ammonia sulfate, ammonia bisulfate, and other salts in combination with iron and aluminum. The deposition temperature of these salts from the flue gas is dependent on the relative concentration of ammonia and SO3 in the flue gas. Ammonium bisulfate is a sticky substance, which can deposit on air heater baskets, and other downstream

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equipment surfaces. Resultant particle diameters at the stack are on the order of 1 to 3 microns and thereby could contribute to PM10 emissions. Ammonia salts depositing on air heater surfaces could increase the frequency of off-line washes in combination with forced outages. A significant quantity (up to 80%) of the ammonia slip that exits the NOxStar system will react with flue gas and fly ash constituents and be collected with the fly ash in the particulate removal equipment (ESP or fabric filter). The ammonia content of the fly ash can affect waste disposal practices, and the potential for waste product sales due to odorous emissions. The major consideration for the NOxStar technology is that it currently has only one major installation in the U. S. and may require the installation of a single layer of in-duct catalyst to achieve advertised levels of NOx reduction.

ECOTUBE The ECOTUBE system is a boiler combustion improvement and NOx reduction technology. Retractable lance tubes that penetrate the boiler above the primary burner zone inject high-velocity air as well as reagents. The lance tubes work to create turbulent airflow and to increase the residence time for the air/fuel mixture. ECOTUBE is an advanced, extremely cost-effective system for reducing NOx, CO, and volatile organic compounds (VOC) while improving thermal efficiency by optimizing the combustion process in boilers. The ECOTUBE system is a hybrid of two proven technologies: separated OFA (SOFA) and SNCR. By injecting air, ammonia, or urea through retractable lances in the upper furnace, the ECOTUBE takes SOFA and SNCR well beyond their independent individual capabilities. Creating turbulence at the best location in the gas flow, an improved fuel/air ratio is achieved through better mixing - along with a lower stoichiometric ratio of O2. An illustration of the ECOTUBE installation in a typical boiler is shown in Figure 11. The water-cooled ECOTUBEs are automatically retracted from the boiler on a regular basis and cleaned to remove layers of soot and other depositions. The lances are designed to simulate boiler tubing for years of useful life in the boiler. ECOTUBE’s self-cleaning capability and safety control system allow safe and continuous operation. Unlike many low cost SNCR systems, ECOTUBE’s furnace combustion improvements increase efficiency, and reduce fuel usage. At the same time, it reduces convection

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pass, APH, precipitator, bag-house, ductwork, and stack corrosion and erosion. From a capital investment perspective, ECOTUBE is one of the lowest cost-per-ton NOx reduction systems available that is capable of achieving 60-80% NOx reduction. It is less than one-half the cost of SCRs and involves minimal installation downtime and boiler modifications.

Figure 11. ECOTUBE Installation in a Boiler

Induced flue gas recirculation Recirculation of flue gas back to the combustion zone has been one of the most effective methods of reducing NOx emissions from gas- and oil-fired boilers since the early 1970's. Injection of flue gas into the combustion air is a proven method for controlling NOx production from gas-fired utility boilers. For units not equipped with gas recirculation fans, flue gas can be injected into the combustion air by a technique known as induced flue gas recirculation (IFGR). IFGR acts to reduce NOx formation by reducing peak flame temperatures. In conventional applications, the recirculated flue gas is typically extracted from the boiler outlet duct upstream of the air heater. The flue gas is then returned through a separate duct and hot gas fan to the combustion air duct that feeds the windbox. The recirculated flue gas is mixed with the combustion air via airfoils or other mixing devices in the duct. This technology is known as windbox FGR (WFGR). WFGR systems require installation of a separate hot gas FGR fan to move flue gas from the boiler exit to the air supply ducting at the windbox inlet, where mixing of the air and flue gas must be uniformly achieved by installation of appropriate mixing devices.

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Selective catalytic reduction Selective catalytic reduction (SCR) systems are the most widely used post-control technologies for achieving significant reductions in NOx emissions. In SCR systems, vaporized ammonia (NH3) injected into the flue gas stream acts as a reducing agent, achieving NOx emission reductions when passed over a catalyst. The NOx and ammonia reagent react to form nitrogen and water vapor. The reaction mechanisms are very efficient with a reagent stoichiometry of approximately 1.05 (on a NOx reduction basis) with very low ammonia slip (unreacted ammonia emissions). A simplified schematic diagram of a typical SCR reactor is illustrated in Figure 12.

IsolationDampers

To Air Heater

Temperature Grid

uture

orns

Tuning/MonitoringGrid

CatalySonic H

st

Catalyst

Catalyst

Space for FCatalyst

Sonic Horns

Sonic Horns

VaporizedAmmonia

BypassDamper

Economizer

Bypass, if needed

From Economizer

Figure 12. Schematic Diagram of a Typical SCR Reactor

The SCR reactor is the housing for the catalyst. The reactor is basically a widened section of ductwork modified by the addition of gas flow distribution devices, catalyst, catalyst support structures, access doors, and soot blowers. An ammonia injection grid is located upstream of the SCR reactor and the system can be designed with or without a flue gas bypass. The SCR reactor is typically elevated above and behind the air heater and downstream emissions control equipment (typically an ESP) and gas flow direction through the reactor is vertically downward for coal-fired applications. In a “high-dust” SCR arrangement, the reactor is located between the outlet of the economizer and the inlet of the air heater. The high-dust system is typically the most economical and preferred arrangement where physically possible.

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The SCR reaction occurs within the temperature range of 550 to 850 °F where the extremes are highly dependent on the fuel quality. The oxidation of SO2 to SO3 could also require moderate air heater modifications since the acid dew point temperature of the flue gas is directly related to SO3 concentration. As the SO3 concentration increases, the acid dew point of the flue gas increases, potentially increasing corrosion in downstream equipment or possibly requiring an increase in the air heater gas outlet temperature. The ammonia reagent for the SCR systems can be supplied by anhydrous ammonia, aqueous ammonia, or by conversion of urea to ammonia. Since the ammonia is vaporized prior to contact with the catalyst, the selection of ammonia type does not influence the catalyst performance. However, the selection of ammonia type does affect all other subsystem components, including reagent storage, vaporization, injection control, and balance-of-plant requirements. The vast majority of worldwide installations use anhydrous ammonia. SCR systems have a variety of interfacing system requirements to support operations. These impacts predominately relate to draft, auxiliary power, sootblowing steam, gas temperature, controls, ductwork, reactor footprint, and air heater. The SCR system will impact the boiler draft system. Dependent on arrangement and performance requirements, draft losses can range from 4 to 10 in. wg. This can be compensated with the addition of ID booster fans. If necessary, ductwork, and/or boiler box reinforcement need to be considered. In conjunction with the fan modification, the upgrade of the auxiliary power system might be necessary. Auxiliary power modifications may also be necessary for ammonia supply system requirements. The major impact of the SCR system can be seen at the air heater where there are two areas of concern. One is the formation and deposition of ammonium bisulfate on the air heater surface. This will cause an increase in the pressure drop of the air heater. The other potential danger for the air heater is high concentrations of SO3 in the flue gas. If the acid dew point has been increased to more than the exhaust temperature, a significant amount of acid gases will condense in the air heater and lead to plugging and corrosion. Several measures can be taken to avoid or correct this situation. Most important is the right composition of the catalyst to minimize the SO2 to SO3 conversion rate and the proper temperature control of the flue gas entering the reactor.

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Selective non-catalytic reduction Selective non-catalytic reduction (SNCR) systems reduce NOx emissions by injecting a reagent at multiple levels in the steam generator as illustrated in Figure 13. SNCR systems rely solely on reagent injection rather than a catalyst and an appropriate reagent injection temperature, good reagent/gas mixing, and adequate reaction time to achieve NOx reductions. SNCR systems can use either ammonia or urea as the reagent. Ammonia or urea is injected into areas of the steam generator where the flue gas temperature ranges from 1,500 to 2,200 °F. The furnace of a pulverized coal fired boiler operates at temperatures between 2,500 to 3,000 °F. SNCR systems are capable of achieving a NOx emission reduction as high as 50 to 60% in optimum conditions (adequate reaction time, temperature, and reagent/ flue gas mixing, high baseline NOx conditions, multiple levels of injectors) with ammonia slips of 10 to 50 ppmvd. Lower ammonia slip values can be achieved with lower NOx reduction capabilities. Typically, optimum conditions are difficult to achieve, resulting in emission reduction levels of 20 to 40%. Potential performance is very site-specific and varies with fuel type, steam generator size, allowable ammonia slip, furnace CO concentrations, and steam generator heat transfer characteristics.

Combustion Air

InjectionLevel 2

InjectionLevel 3

Burners

Steam GeneratorAir Heater

Injection Level 1

Flue Gas

Ammonia or Urea Storage Tank

Figure 13. Schematic of SNCR System with Multiple Injection Levels

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SNCR systems reduce NOx emissions using the same reduction mechanism as SCRs. Most of the undesirable chemical reactions occur when reagent is injected at temperatures above or below the optimum range. At best, these undesired reactions consume reagent with no reduction in NOx emissions while, at worst, the oxidation of ammonia can actually generate NOx. Accordingly, NOx reductions and overall reaction stoichiometry are very sensitive to the temperature of the flue gas at the reagent injection point. This complicates the application of SNCR for boilers larger than 100 MW. Reagent injection lances are usually located between the boiler soot blowers in the pendent superheat section. Optimum injector location is mainly a function of tempera-ture and residence time. To accommodate SNCR reaction temperature and boiler turndown requirements, several levels of injection lances are normally installed. Typically, four to five levels of multiple lance nozzles are installed if sufficient boiler height and resident time is available. A flue gas residence time of at least 0.3 second in the optimum temperature range is desired to assure adequate SNCR performance. Residence times in excess of 1 second yield high NOx reduction levels even under less than ideal mixing conditions. Computational Fluid Dynamics and Chemical Kinetic Modeling can be performed to establish the optimum ammonia injection locations and flow patterns. For an existing boiler, minor waterwall modifications are necessary to accommodate installation of SNCR injector lances. Steam piping modifications would probably be required to achieve optimum performance. SNCR/SCR hybrid The SNCR/SCR hybrid system uses components and operating characteristics of both SNCR and SCR systems. Hybrid systems were developed to combine the low capital cost and high ammonia slip associated with SNCR systems with the high reduction potential and low ammonia slip inherent to the catalyst of SCR systems. The result is a NOx reduction alternative that can meet initially low reduction requirements but be upgraded to meet higher reductions at a future date, if required. The SNCR component of the hybrid system is identical to the SNCR system described previously except that the hybrid system may have more levels of multiple lance nozzles for reagent injection. This will increase the capital cost of the SNCR component of the hybrid system. During operation, the SNCR system would be allowed to inject higher amounts of reagent into the flue gas. This increased reagent flow has a two-fold effect: NOx reduction within the boiler is increased while ammonia slip also increases. The

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ammonia that slips from the SNCR is then used as the reagent for the catalyst in the SCR. There are two design philosophies for using this excess ammonia slip. The most conservative hybrid systems will use the catalyst simply as an ammonia slip “scrubber” with some additional NOx reduction. As with in-duct systems, the flue gas velocity through the catalyst is an important factor in design. Operating in this mode allows maximum NOx reduction within the boiler by the SNCR while minimizing the catalyst volume requirement. While some NOx reduction is realized at the catalyst, the relatively small catalyst requirement of this design can potentially fit all the catalyst in a true in-duct arrangement, with no significant ductwork changes, arrangement interference, or structural modifications. The second philosophy uses adequate catalyst volume to obtain significant levels of additional NOx reduction. The additional reduction is a function of the quantity of ammonia slip, catalyst volume, and distribution of ammonia to NOx within the flue gas. Using ammonia slip produced by the SNCR system is not a highly efficient method of introducing reagent, due to the low reagent utilization discussed as a part of the SNCR. Therefore, even though the reaction at the catalyst requires 1 ppm of ammonia to remove 1 ppm of NOx, the SNCR must inject at least 3 ppm of ammonia to generate 1 ppm of ammonia at the catalyst. Catalyst volume is strongly influenced by the NOx reduction required and the ammonia distribution. The impact of catalyst volume on the design of a hybrid system is on the size of the reactor required to hold the catalyst. If multiple levels of catalyst operating at low flue gas velocity are required, some modifications will be required to the existing ductwork. If widening the ductwork cannot provide adequate catalyst volume, then a separate reactor is required. The addition of a reactor negates the capital cost advantage of a hybrid system. LoTOx The LoTOx technology is the low temperature gas-phase oxidation of NOx by ozone injection. In this method, ozone is injected into the flue gas upstream of a wet FGD system. The ozone reacts with the NO and NO2 to form nitrogen pentoxide (N2O5). The nitrogen pentoxide formed is soluble in water and can be removed from the flue gas using a wet FGD system. The LoTOx technology has been demonstrated on several industrial size plants and several refinery applications.

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The LoTOx technology offers high NOx removal efficiency with a reported potential of 15 to 25% savings in capital cost over a SCR. The major drawbacks of this system are the lack of experience on larger power generating units, high power consumption and the production of nitrates. The high power level resulting from the multiple ozone generators required to produce the ozone for the process is expected to be comparable to what is needed for a conventional FGD system and is significantly higher than the power consumption from an SCR. The nitrate produced from this process is captured in the FGD waste product. Most regulatory agencies are strict about nitrate release into water systems; a wastewater treatment plant might be required. Natural gas reburn The natural gas reburning process employs 3 separate combustion zones to reduce NOx emissions as illustrated in Figure 14. The first zone consists of the normal combustion zone in the lower furnace, which is formed by the existing wall burners. In this zone, 75 to 80% of the total fuel heat input is introduced. The first zone burners are operated with about 10% excess air (a 1:10 stoichiometric ratio). A second combustion zone (the reburn zone) is created above the lower furnace by operating a row of conventional natural gas burners at a stoichiometric ratio less than 1. This technology also has the potential for increased furnace corrosion (especially with higher sulfur fuels) because of the reducing atmosphere in the lower furnace. The sub-stoichiometric reburn zone causes NOx produced in the lower furnace units to be reduced to molecular nitrogen and oxygen, because the oxygen stripped from the NOx molecules is combined with the more active carbon monoxide molecules to form CO2 as combustion is completed in the upper furnace. Fuel burnout is completed in the third zone (the burnout zone) by the introduction of OFA. Sufficient OFA is introduced to complete combustion of the unburned materials in the upper furnace with an overall excess air rate for the boiler of 15 to 20%. Reburn technology has demonstrated NOx reduction of 40 to 65%. Sufficient residence time (adequate furnace height) in the reburn and OFA zones is a key factor in determining whether the reburning technology can be applied. Successful retrofit of this technology requires space within the boiler to allow adequate residence time for both the additional burning zone (0.4 to 0.6 second) and the associated OFA

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burnout zone (0.6 to 0.9 second). When this space is available, reburning can be highly effective, but a low residence time will limit system performance. In addition, the high cost of natural gas increases annual operating costs and makes these costs unpredictable because of the high volatility of natural gas prices.

Burnout Zone•Normal Excess Air

Reburning Zone•Slightly Fuel Rich•NOx Reduced to N2

Primary CombustionZone•Reduced Firing Rate•Low Excess Air•Lower NOx

Overfire Air

40 to 60% NOx Reduction

10 to 20 % GasFuel Rich

80 to 90% Coal10% Excess Air

Figure 14. Schematic of Gas Reburn System

4.B.2 Technically Infeasible Options The following systems were not considered further in this study for the following reasons:

• The Mobotec Rotamix system has not been demonstrated on units as large as Sherco.

• The Mobotec ROFA system is in the same category as OFA system. • NOxStar and NoxStar Plus technologies are not currently being marketed, nor

there is a natural gas line to the Sherco plant site. • ECOTUBE has no existing installations at units of the size and design of Sherco

Units 1 and 2. Xcel Energy has significant experience with injection methods similar to ECOTUBE, and believes that the equipment would be initially

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unreliable and possibly not capable of accepting modifications to make this method more reliable.

• IFGR is not applicable for coal-fired units. • LoTOx has no installations at units in the size range of Sherco Units 1 and 2. • There is no natural gas line to the Sherco site for natural gas reburn.

4.B.3 Control Effectiveness of Remaining Control Technologies

Table 12. Control Effectiveness for NOx Reduction Technologies

(lb/MMBTU) (tons/yr) (tons/yr)

Reduction Technologies Emitted Emitted Removed

Unit 1 (Baseline 0.34 lb/MMBTU)

Combustion Optimization System (CC) 0.28 7,600 1,600

New LNB, New OFA System and CC 0.15 4,100 5,200

New LNBs, OFA, CC, and SNCR 0.14 3,800 5,400

New LNBs, OFA, CC, and SNCR/SCR Hybrid (Cascade) 0.12 3,300 6,000

New LNBs, OFA, CC, and SCR 0.08 2,200 7,100

Unit 2 (Baseline 0.20 lb/MMBTU)

Combustion Optimization System (CC) 0.15 4,100 1,400

CC and SNCR 0.14 3,800 1,600

CC and SNCR/SCR Hybrid (Cascade) 0.12 3,300 2,200

CC and SCR 0.08 2,200 3,300

4.B.4 Impact Analysis Tables 13 and 14 show the costs of compliance for NOx control for Sherco Units 1 and 2 respectively for the technologies considered applicable and available. Capital and operating costs were estimated with CUECOST, and supplemented with data from Xcel Energy (Appendix A). As these are order of magnitude estimates, they are accurate only to ±30%. The capital costs were annualized over a 20-year period and then added to the annual operating costs to obtain the total annualized costs for each technology. The data in the table are sorted from least expensive total annualized cost to most expensive total annualized cost. The incremental costs were calculated after

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constructing the least cost curves, shown in Figures 15 and 16 (based on 40 CFR Part 51, Appendix Y). From these curves, all options would be considered dominant, or potentially cost-effective, except a new SNCR system and a new hybrid SNCR/SCR system. The incremental costs compare the average cost-effectiveness of the dominant options by dividing the difference in total annualized costs from a higher cost effectiveness option to the next less expensive option with the difference in tons of NOx removed for the two options. The incremental cost-effectiveness for Unit 1 compares the cost effectiveness between Options 1 and 2 ($470/ton), and Options 2 and 5 ($8,000/ton). The incremental cost-effectiveness for Unit 2 compares the cost effectiveness between Options 1 and 4 ($7,600/ton). As seen above, the incremental costs for Unit 1 change significantly between Options 2 and 5. Based on this incremental cost, the most cost-effective option for NOx control for Unit 1 is the installation of a combustion optimization system, and LNB and SOFA (Option 2 in Table 13). The incremental costs for Unit 2 change significantly between Options 1 and 4. Based on this incremental cost, the most cost-effective option for NOx control for Unit 2 is installation of a combustion optimization system (Option 1 from Table 14).

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Table 13. Unit 1 NOx Compliance Costs

Option Number Technology

Expected Reduction (tons/year)

Rate (lb/MMBTU)

Capital Costs

Annualized Capital Costs

Annual Operating

Costs

Total Annualized

Cost

Cost Effectiveness

($/ton)

Incremental Cost

Effectiveness ($/ton)

1 Combustion Optimization (CC) 1,600 0.28 $4,200,000 $400,000 $89,000 $485,000 300 2 CC + new low NOx burners (LNB)/Separated overfire air (SOFA) 5,200 0.15 $19,000,000 $1,800,000 $400,000 $2,200,000 430 500 3 CC/LNB/SOFA + new Selective Non-Catalytic Reduction (SNCR) 5,400 0.14 $28,000,000 $2,600,000 $2,300,000 $5,300,000 980 4 CC/LNB/SOFA + new SNCR/SCR Hybrid 6,000 0.12 $66,000,000 $6,300,000 $3,500,000 $10,000,000 1,700 5 CC/LNB/SOFA + new Selective Catalytic Reduction (SCR) 7,100 0.08 $105,000,000 $9,900,000 $7,200,000 $18,000,000 2,500 8,000

Table 14. Unit 2 NOx Compliance Costs

Option Number Technology

ExpectedReduction(tons/year)

Rate (lb/MMBTU)

Capital Costs

Annualized Capital Costs

Annual Operating

Costs

Total Annualized

Cost

Cost Effectiveness

($/ton)

Incremental Cost

Effectiveness($/ton)

1 Combustion Optimization (CC) 1,400 0.15 $4,200,000 $400,000 $100,000 $490,000 360 2 CC + new Selective Non-Catalytic Reduction (SNCR) 1,600 0.14 $13,300,000 $1,300,000 $2,200,000 $3,500,000 2,100 3 CC + new SNCR/SCR Hybrid 2,200 0.12 $51,900,000 $4,900,000 $3,500,000 $8,400,000 3,9004 CC + new Selective Catalytic Reduction (SCR) 3,300 0.08 $90,100,000 $8,500,000 $6,400,000 $15,000,000 4,600 7,600

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Figure 15. Least Cost Curve - Unit 1 NOx

Most Cost Effective Option

CC/LNB/OFACC

CC/LNB/OFA/SCR

0 1,000

20,000

18,000

16,000

Tota

l Ann

ual C

ost,

$1,0

00/y

r 14,000

12,000

10,000

8,000

6,000

4,000

2,000

2,000 5,000 8,000 3,000 4,000 6,000 7,000Expected Reduction, tons/yr

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Figure 16. Least cost Curve - Unit 2 NOx

CC + SCR

CC

Most Cost Effective Option

0 1,000

16,000

14,000

12,000

Tota

l Ann

ualiz

ed C

ost,

$1,0

00/y

r

10,000

8,000

6,000

4,000

2,000

1,500 4,000 2,000 2,500 3,000 3,500Expected Reduction, tons/yr

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4.B.5 Energy Impacts There will be slight energy impacts from the available and applicable technologies.

4.B.6 Non-Air Quality Environmental Impacts No non-air quality environmental impacts were identified.

4.B.7 Remaining Useful Life Since the useful life of Sherco is longer than 20 years, there is no impact to the annualized capital costs because of a shorter useful life for the unit than the feasible technologies.

4.B.8 Visibility Impacts

Computer modeling was performed to predict the number of days that visibility impairment would be greater than 0.5 dv. The model also predicts the change in the 98th percentile delta dv, where a larger change in the delta dv translates into an improvement in visibility. Based on the control costs discussed earlier, computer modeling was performed to predict the effect on visibility of either installing a combustion optimization system for each unit, and low NOx burners and SOFA for Unit 1 (Control Scenario 1), or installation of a combustion optimization system and an SCR for both units, and low NOx burners and SOFA for Unit 1 (Control Scenario 2). From Table 17 and Figure 17, it can be seen that, over the period from 2002 through 2004, the computer model predicts a 98th percentile delta dv of 2.11 for Option 1 (Table 13), and 1.80 for Option 2 (Table 14). The model predicts that there would be 227 days above 0.5 dv with Control Scenario 1 and 206 days above 0.5 dv for Control Scenario 2, as opposed to the baseline of 263 days above 0.5 dv. It would cost approximately $1,300,000 per dv to decrease the 98th percentile delta dv from 2.68 to 2.11 for Control Scenario 1. It would cost approximately $18,000,000 per dv to decrease the 98th percentile delta dv from 2.68 to 1.80 for Control Scenario 2. The incremental cost to decrease the 98th percentile delta dv from 2.11 to 1.80 is almost $100,000,000.

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Table 15. NOx Post-Control Emission Rates for Emission Unit EU001/EU002

Control Scenario

# NOx Control Technology

SO2 Max 24 Hour Actual Emissions,

lb/day % Reduction

(Increase)

NOx Max 24 Hour Actual Emissions,

lb/day % Reduction

PM2.5 Max 24 Hour Actual

Emissions, lb/day

% Reduction (Increase)

PM10 Max 24 Hour Actual Emissions,

lb/day % Reduction

(Increase)

1 Sherco Unit 1 - LNB/SOFA/CC

Sherco Unit 2 – CC 122,469 0 56,979 44 N/A N/A 1,966 0

2 Sherco Unit 1 -

LNB/SOFA/CC/SCR Sherco Unit 2 –

CC/SCR 122,469 0 30,389 70 N/A N/A 1,966 0

Table 16. NOx Post-Control Stack Parameters for Emission Unit EU001/EU002

Control Scenario #

NOx Control Technology Stack No.

Location Easting (utm)

Location Northing

(utm)

Height of opening

from ground, ft

Base elevation of ground, ft

Stack Diameter, ft

Flow rate at exit, acfm

Exit gas temperature,

°F

1 Sherco Unit 1 - LNB/SOFA/CC

Sherco Unit 2 – CC SV001 429,842 5,025,449 650 969 32.5 5,200,000 171

2 Sherco Unit 1 -

LNB/SOFA/CC/SCR Sherco Unit 2 –

CC/SCR SV001 429,842 5,025,449 650 969 32.5 5,200,000 171

Table 17. NOx Controls - Visibility Modeling Results

2002 2003 2004 2002-2004 Combined

Control Scenario

#

NOx Control Technology

Class I Area with

Greatest Impact

Modeled 98th

percentile Value,

deciview

No. of days

exceeding 0.5

deciview

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

Modeled 98th

percentile Value,

deciview

No. of days exceeding

0.5 deciview

1 Sherco Unit 1 - LNB/SOFA/CC

Sherco Unit 2 – CC BWCA 2.02 73 2.33 77 2.22 77 2.11 227

2 Sherco Unit 1 -

LNB/SOFA/CC/SCR Sherco Unit 2 –

CC/SCR BWCA 1.74 63 1.95 74 1.94 69 1.80 206

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Table 18. Incremental Visibility Costs for BWCA for NOx Control

Control Case Technology

Total Annualized

Cost

Incremental Total

Annualized Cost

98th Percentile Visibility

Impairment, dv

Impairment Improvement,

dv

Incremental Impairment

Improvement, $/dv

Base 2.68

Case 1 LNB/SOFA/CC - Unit 1, CC - Unit 2 $2,700,000 $2,700,000 2.11 0.57 5,000,000

Case 2 LNB/SOFA/CC/SCR -

Unit 1, CC/SCR - Unit 2

$32,000,000 $29,300,000 1.80 0.31 95,000,000

LNB - Low NOx burners SOFA – Separated/close coupled OFA CC – Combustion optimization

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Figure 17. NOx Visibility Impacts at BWCA

2.60

2.932.77

2.68

2.02

2.332.22

2.11

1.741.95 1.94

1.80

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile v

alue

, dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

4.B.9 Proposed NOx BART Xcel Energy proposes to install new LNB, a separated/close coupled OFA system, and a combustion optimization system for Unit 1, and a combustion optimization system for Unit 2. The proposed emission rate is 0.15 lb/MMBTU at the stack, based on a 30-day rolling average. This rate meets the presumptive limit for tangentially fired boilers burning sub-bituminous coal. The controls will be installed on Unit 2 by the end of 2006 and on Unit 1 by the end of 2007. Compliance with the new limit will be demonstrated by the end of 2008. The proposed option will reduce NOx emitted from Sherco Units 1 and 2 on the order of 6,800 tons/year and allow Xcel Energy to meet CAIR Phase I requirements. The total annualized cost for the proposed option is $2,700,000, with a significant visibility improvement of 0.57 dv, or $5,000,000/dv (Table 18). Conversely, the total annualized cost to move to the next most effective control technology (new SCR) is approximately $29,300,000, and would further improve visibility by only 0.31 dv, or $95,000,000/dv. The incremental cost-effectiveness between the proposed option and new SCR systems for both boilers is on the order of $8,000/ton, which Xcel Energy asserts is excessive. Xcel Energy firmly believes the most cost-beneficial visibility improvements will be brought about by installing new LNB, a separated/close coupled OFA system, and a combustion optimization system for Unit 1, and a combustion optimization system for Unit 2.

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4.C Particulate Matter Emission Controls – Emission Units EU001/EU002

4.C.1 Available Retrofit Control Technologies Sherco Units 1 and 2 utilize wet electrostatic precipitators (WESP) for particulate control. A side benefit of the use of WESP is the control of SO3. PM10 control technologies that were identified as available for retrofit at Sherco are listed below:

• Electrostatic precipitator (ESP) • Pulse jet fabric filter (PJFF) baghouse • Compact Hybrid Particulate Collector (COHPAC) • GE MAX-9 Hybrid • Multi-cyclone • Wet ESP

Electrostatic precipitator Electrostatic precipitators (ESPs) are the most widely installed utility particulate removal technology. ESPs use transformer-rectifiers to energize discharge electrodes and produce a high voltage, direct current electrical field between the discharge electrodes and grounded collecting plates. Particulate matter entering the electrical field acquires a negative charge and migrates to the grounded collecting plates. This migration can be expressed in engineering terms as an empirically determined effective migration velocity, but it takes place in the turbulent flow regime, with the particulate entrained within the turbulent gas patterns. Thus, the charged particles are actually captured when the combined effect of electrical attraction and gas flow patterns moves the particulate matter close enough so that it can attach to the collecting surfaces. A layer of collected particles forms on the collecting plates and is removed periodically by mechanically rapping the plates. The collected particulate drops into hoppers below the precipitator and is removed by the ash handling system. Some particulate is also re-entrained and either collected in subsequent electrical fields or emitted from the ESP. A picture showing the sections of an ESP is shown in Figure 18.

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Figure 18. Electrostatic Precipitator System (MHI)

The required particulate removal efficiency, the expected electrical resistivity of the fly ash to be collected, and the expected electrical characteristics of the energization system determine the physical size of an ESP. Many parameters determine the ESPs capability for particulate collection including the following major items. The first parameter is the specific collection area (SCA). ESP size is often measured in terms of SCA, and is defined as the total collecting area (ft2) divided by the volumetric flue gas flow rate (1,000 acfm). Second, the treatment time that the flue gas is within the electric collection fields of the ESP is an important aspect of particulate collection. High-efficiency ESPs typically have treatment times between 7 and 20 seconds. Treatment time is becoming a major design parameter, since lower particulate emissions are being mandated.

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Flue gas velocity, which is the speed with which the flue gas moves through the ESP, is important in the design and sizing of the ESP. Design gas velocities ranging between 3 to 4 feet per second are common. The aspect ratio, defined as the treatment length to the collection plate height, is an important design parameter of ESPs. As the aspect ratio increases, the re-entrainment losses from the ESP are minimized. Many existing ESPs have aspect ratios of around 0.8 to 1.2. Newer ESPs, especially those meeting new particulate emission limits, have aspect ratios around 1.2 to 2.0. The gas distribution for optimum particulate removal requires uniform gas velocity throughout the entire ESP treatment volume with minimal gas bypass around the discharge electrodes or collecting plates. If flue gas distribution is uneven, the particulate removal efficiency will decrease and re-entrainment losses will increase in high velocity areas, reducing overall collection efficiency. Finally, fly ash resistivity is a measure of how easily the ash or particulate acquires an electric charge. Typical coal fly ash resistivity values range from 1 x 108 ohm-cm to 1 x 1014 ohm-cm. The ideal resistivity range for electrostatic precipitation of fly ash is 5 x 109 to 5 x 1010 ohm-cm. Operating resistivity varies with flue gas moisture, SO3 concentration, temperature, and ash chemical composition. As a result of fly ash resistivity being sensitive to these constituents, ESPs can be affected greatly by changes in fuel or operating conditions. Pulse jet fabric filter baghouse Fabric filters are media filters that the flue gas passes through to remove the particulate. Cloth filter media is typically sewn into cylindrical tubes called bags. Each fabric filter may have thousands of these filter bags. The filter unit is typically divided into compartments, which allows online maintenance or bag replacement. The quantity of compartments is determined by maximum economic compartment size, total gas volume rate, air-to-cloth (A/C) ratio, and cleaning system design. Extra compartments for maintenance or offline cleaning increase the reliability at the expense of capital cost and real estate utilization. Each compartment includes at least one hopper for temporary storage of the collected fly ash. A cut-away view of a pulse jet fabric filter (PJFF) compartment is illustrated in Figure 19.

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Figure 19. Pulse Jet Fabric Filter Compartment

Fabric bags vary in composition, length, and cross-section (diameter or shape). Bag selection characteristics vary with cleaning technology, emissions limits, flue gas and ash characteristics, desired bag life, capital cost, A/C ratio, and pressure differential. Fabric bags are typically guaranteed for 3 years but frequently last 5 years or more. In pulse jet fabric filters the flue gas typically enters the compartment hopper and passes from the outside of the bag to the inside, depositing particulate on the outside of the bag. To prevent the collapse of the bag, a metal cage is installed on the inside of

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the bag. The flue gas passes up through the center of the bag into the outlet plenum. The bags and cages are suspended from a tube sheet. Cleaning is performed by initiating a downward pulse of air into the top of the bag. The pulse causes a ripple effect along the length of the bag. This releases the dust cake from the bag surface. The dust then falls into the hopper. This cleaning may occur with the compartment online or offline. Care must be taken during design to ensure that the upward velocity between the bags is minimized so that particulate is not re-entrained during the cleaning process. The PJFF cleans bags in sequential, usually staggered, rows. During online cleaning, part of the dust cake from the row being cleaned may be captured by the adjacent rows. Despite this apparent shortcoming, PJFF have successfully implemented online cleaning on many large units. The PJFF bags are typically made of felted materials that do not rely as heavily on the dust cake’s filtering capability as woven fiberglass bags. This allows the PJFF bags to be cleaned more vigorously. The felted materials also allow the PJFF to operate at a much higher cloth velocity, which significantly reduces the size of the unit and the space required for installation. Compact Hybrid Particulate Collector Another control technology used for particulate control is a high A/C ratio fabric filter installed after an existing particulate control device (typically a cold side ESP). Commonly referred to as a Compact Hybrid Particulate Collector (COHPACTM), this technology was developed and trademarked by the Electric Power Research Institute (EPRI). A cut-away view of a COHPAC is shown in Figure 20. If activated carbon is injected upstream of a COHPACTM filter, this configuration is referred to as TOXECON I and is also trademarked by EPRI. The COHPACTM filter typically operates at A/C ratios ranging from 6 to 8 ft/min. compared to a conventional fabric filter that typically operate at A/C ratios of about 4 ft/min. For a COHPACTM or TOXECON I system, the majority of the particulate is collected in the upstream particulate control device. Therefore, the performance requirements of a high A/C ratio fabric filter is reduced, allowing installation of this technology in a smaller footprint area, with less steel and filtration media to substantially lower both capital and operating costs compared to conventional fabric filters .

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Figure 20. COHPAC Arrangement

GE MAX-9 hybrid The Max-9 electrostatic filter is essentially a high-efficiency PJFF that combines fabric filter and ESP technologies. The Max-9 can be visualized as an ESP using fabric filter bags instead of collecting plates. A front and side elevation view of the Max-9 particulate filter is illustrated in Figure 21. When the dust particles are charged, they are attracted to the grounded metal cage inside the filter element, just as they would be attracted to the collecting plates in an ordinary ESP. Since the particles are charged positively, they repel each other on the surface of the filter, making the collected dust cake very porous. This results in a reduction of filter drag at a pressure drop about 25% of a normal fabric filter. Consequently, the Max-9 can operate at an A/C ratio higher than a conventional fabric filter and can treat a significant gas volume with a smaller footprint. Process gas enters the Max-9 from a hopper inlet duct. The gas then flows upward through the filters and out through the top of the filters. The area above the tube sheet is a clean gas plenum. Compressed air pulses are used to clean the filters. Compressed air pulses are used to clean the filters. A brief, intense blast of air is fired through the purge air manifold; holes in the blowpipes located above the filters direct the cleaning air pulse down through the filters. The cleaning sequence is controlled by timers, which trigger solenoids. The high voltage system operates at very low current densities and at a steady state. There is no danger of fire caused by sparking, and the transformer/rectifier requires no voltage control.

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The Max-9 can be supplied as shop-assembled modules that can be erected on site, although the units are usually custom engineered for each plant site and application to make the best use of available space.

Figure 21. Max-9 Electrostatic Filter

Multi-cyclone Multiple-cyclone separators, also known as multiclones, consist of a number of small diameter cyclones, operating in parallel and having a common gas inlet and outlet, as shown in Figure 22. Multiclones operate on the same principle as cyclones, creating a

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main downward vortex and an ascending inner vortex. Multiclones are more efficient than single cyclones because they are longer and smaller in diameter. The longer length provides longer residence time while the smaller diameter creates greater centrifugal force. These two factors result in better separation of dust particulates. The pressure drop of multiclone collectors is higher than that of single-cyclone separators.

Cyclone collectors are centrifugal collectors that rely on the particle density and velocity to separate the fly ash from the flue gas. The particulate-laden flue gas enters the top or the side of the cyclone. An illustration of the components and working principles of a multi-cyclone is shown in Figures 22 and 23. Vanes impart a rotational velocity to the flue gas, driving the fly ash to the edge of the cylinder. The flue gas then exits the center of the cyclone out the top, leaving the fly ash to fall out the bottom. At pressures near one atmosphere and 2 to 5 in. wg pressure differential, this technology can effectively remove particles larger than 20 microns in size; particles less than 10 microns are usually unaffected and not removed.

Figure 22. Multi-cyclone Particulate Collector

Figure 23. Multiclone

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Wet ESP Currently, both Sherco Units 1 and 2 have wet ESPs (WESP) that have been retrofitted into the venturi scrubber modules. If an SO2 control strategy is selected that involves the bypass or demolition of the venturi scrubbers, it may be applicable to consider the installation of new WESPs at Sherco. A WESP collects particles based on the same theory as a dry ESP: negatively charged particles are collected on positively charged surfaces. However, a WESP operates quite differently from a dry ESP. The collecting surfaces are wet instead of dry and are flushed with water to remove the particulate. Typically, a WESP is installed downstream of an existing wet FGD system where the flue gas is already saturated, so the amount of added water is minimized. The particulate collection efficiency is enhanced by preventing re-entrainment after contact with the wet walls (as contrasted with re-entrainment due to rapping on a dry electrostatic precipitator). Therefore, the WESP is well suited for fine particulate or acid mist applications by reducing opacity, sulfuric acid mist (H2SO4) and other aerosols. The use of WESP for acid mist collection is one of the earliest applications for electrostatic precipitators. Although there are few applications in the utility industry, this is a mature technology with hundreds of industrial installations. The particulate characteristics, temperature and humidity in WESPs provide excellent fuel flexibility regarding particulate removal. Water chemistry, scaling and corrosion potential need to be carefully investigated. The WESP collecting fields impart a negative charge to the particles and collect them on positively charged collecting electrodes. Each collection field is equipped with independent electrical bus sections, each having a dedicated high voltage transformer/rectifier (TR) and controller. The controllers for each TR are located in an environmentally controlled enclosure. Each electrical field has a separate discharge electrode support frame suspended by alumina insulators. A heater-blower system dedicated to each module supplies warm purge air for each of the insulator compartments. The discharge electrode support frames are constructed from 304 stainless steel. The discharge electrodes are suspended from the upper guide frame and held in the tube centerline. The discharge electrode is a rigid electrode constructed from 304 stainless steel and contains split corona-generating elements, which are welded to the electrode in an opposed orientation.

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A WESP can be installed in either horizontal or vertical gas flow orientation. In a horizontal gas flow orientation the WESP is very similar to a common dry ESP. The collection plates are arranged in parallel horizontal paths with discharge electrodes hanging between them. Vertical gas flow WESPs are usually of the tubular collection plate type. The collection plates are arranged in an array of vertical pipes or channel with a discharge electrode hanging down the center of the pipe or channel. Channel shapes such as squares or hexagons have more efficient packing densities than circular pipes (with a small loss in the maximum voltage that can be applied before sparking) and are the more common. Where multiple electrical stages are used (analogous to the electrical fields in a horizontal gas flow ESP), the stages are stacked one above the other. Two to three fields are common. Several major hurdles exist with the use of a WESP. First, the flue gas must be saturated with moisture prior to entering the ESP to allow the WESP to work correctly. This requires that a quenching system be installed to add water to the flue gas to reduce the flue gas temperature to the saturation point or the WESP needs to be installed downstream of an existing wet FGD system. Without the presence of a wet FGD system, the WESP adds additional cost, increases water demand on the plant, and generates a visible moisture plume at the stack outlet. The removed particulate would also be contained in a wastewater stream that is generated by the WESP. In addition to this issue, the capital cost of a WESP is high as compared to other technologies because of the higher cost of the alloy materials required. A higher grade of material is required to withstand the highly corrosive conditions presented by the wet and acidic flue gas stream. Each WESP module is cleaned by spraying flush water over the WESP components. Flush water is sprayed in the WESP at different spray levels. Normally, each WESP module is flushed once per day. Individual electrical sections of each field may be flushed on line while the power is turned off to the electrical section being cleaned. The WESP system may require continuous injection of dispersant into the system to help eliminate scale formation within the module. The dispersant can be stored in a small tank and fed into the flush water surge tank allowing dispersant to enter the modules through the spray levels.

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Additionally, the WESP may periodically require out-of-service cleaning of a more intense nature. Physical cleaning using high pressure water jets (“hydro lasers”) or chemical flushing using an acid based solvent to dissolve the scale build-up are two options.

4.C.2 Technically Infeasible Options The COHPAC system was not considered feasible because of blinding problems encountered when a slipstream system was tested at Sherco. The Max-9 Hybrid has not been demonstrated at units in the size range of Sherco and was not considered further in this study. Venturi scrubbers and multi-cyclones are not effective at removing fine particulate. The addition of multiclones is not expected to provide additional reduction with the existing venturi scrubbers and are not considered further in this study.

4.C.3 Control Effectiveness of Remaining Control Technologies

Table 19. Control Effectiveness for PM10

(lb/MMBTU) (tons/yr) (tons/yr)

Emitted Emitted Removed

Unit 1 (Baseline 0.018 lb/MMBTU)

ESPs Upstream of Current AQC Equipment 0.013 360 140

PJFF Upstream of Current AQC Equipment 0.013 360 140

Wet ESP Replacement 0.013 360 140

Unit 2 (Baseline 0.018 lb/MMBTU)

ESPs Upstream of Current AQC Equipment 0.013 360 140

PJFF Upstream of Current AQC Equipment 0.013 360 140

Wet ESP Replacement 0.013 360 140

4.C.4 Impact Analysis Tables 20 and 21 show the costs of compliance for PM10 control for Sherco Units 1 and 2 respectively for the technologies considered applicable and available. Capital and operating costs were estimated with CUECOST, and supplemented with data from Xcel

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Energy (Appendix A). As these are order of magnitude estimates, they are accurate only to ±30%. The capital costs were annualized over a 20-year period and then added to the annual operating costs to obtain the total annualized costs for each technology. The data in the table are sorted from least expensive total annualized cost to most expensive total annualized cost. As the average cost-effectiveness for all options considered was greater than $70,000/ton, no incremental cost-effectiveness calculations were performed.

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Table 20. Unit 1 PM10 Compliance Costs

Option Number Technology

Expected Reduction (tons/year)

Rate (lb/MMBTU)

Capital Costs

Annualized Capital Costs

Annual Operating

Costs

Total Annualized

Cost

Cost Effectiveness

($/ton)

Incremental Cost

Effectiveness ($/ton)

1 New ESP upstream of existing AQC equip. 140 0.013 $65,000,000 $6,000,000 $4,000,000 $10,000,000 75,000 2 Wet ESP replacement 140 0.013 $76,000,000 $7,000,000 $3,000,000 $10,000,000 76,000 3 Pulse jet fabric filter w/wet FGD 140 0.013 $55,000,000 $5,000,000 $6,000,000 $11,000,000 82,000

Table 21. Unit 2 PM10 Compliance Costs

Option Number Technology

Expected Reduction tons/year

Rate lb/MMBTU

Capital Costs

Annualized Capital Costs

Annual Operating

Costs

Total Annualized

Cost

Cost Effectiveness

$/ton

Incremental Cost

Effectiveness$/ton

1 New ESP upstream of existing AQC equip. 140 0.013 $65,000,000 $6,000,000 $4,000,000 $10,000,000 75,000 2 Wet ESP replacement 140 0.013 $76,000,000 $7,000,000 $3,000,000 $10,000,000 75,000 3 Pulse jet fabric filter w/wet FGD 140 0.013 $55,000,000 $5,000,000 $6,000,000 $11,000,000 82,000

4.C.5 Energy Impacts There are no major energy impacts from the control technologies considered.

4.C.6 Non-air Quality Impacts No non-air quality environmental impacts were identified.

4.C.7 Visibility Impacts As the cost-effectiveness was so high for all options, no CALPUFF modeling was performed for PM10.

4.C.8 Proposed PM10 BART No technology would significantly improve the particulate control from current levels at Sherco Units 1 and 2. As the cost-effectiveness was so high for all options (> $70,000/ton) no new technology is proposed for PM10. Because no new technology is proposed, no change to the permit limit is proposed.

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4.D Multipollutant Controls – Emissions Units EU001/EU002

4.D.1 Available Retrofit Control Technologies Research is ongoing to develop new and improved technologies for multi-pollutant control. The investigation focuses on adding new sorbents to more effectively adsorb mercury and on using new technologies to oxidize and remove mercury. Electrically induced oxidation of mercury is a new technology that is also being investigated. The list of emerging technologies is numerous and the technologies with the most promise include the PowerSpan ECOTM, EnviroscrubTM and Mobotec ROFA/ROTAMIXTM systems. Several other promising emerging technologies such as the AirborneTM and BOC LoTOxTM systems are also in the early stages of development but are not as far along in pilot testing as the others. Since many of these technologies are still at the pilot (slipstream) stage of development, they should be viewed with caution until more is known and performance guarantees become available. PowerSpan There are several emerging multi-pollutant technologies that use high electron beams or other proprietary processes. One of the more promising technologies that has only limited experience and has not been fully tested on full-scale systems is the PowerSpan ECOTM system. The ECOTM system is located downstream of an existing particulate control device and the process consists of three stages. In the first stage, the flue gas passes through a barrier discharge reactor where it is exposed to a high voltage discharge, generating high energy electrons. The electrons initiate a chemical reaction forming oxygen and hydroxyl radicals, which then oxidize NOx, SO2, and mercury. A process flow diagram of the ECOTM system is illustrated in Figure 24. This results in the formation of nitric acid, sulfuric acid and mercuric oxides. Stage 2 is the collection of these acids and oxides in a downstream ammonia scrubber. The final stage is the collection of acid aerosols, fine particulate matter and oxidized mercury in the downstream wet ESP. Scrubber effluents contain dissolved ammonium sulfate nitrate (ASN) salts along with solids and mercury. The ASN solution is sent to a recovery process where the mercury is removed via a sulfur impregnated activated carbon structure. Once the carbon activated bed becomes saturated with mercury, then it is disposed as a hazardous waste. The cleaned stream of ASN is converted to a saleable fertilizer.

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Figure 24. ECO™ Process Flow Diagram

PowerSpan also offers a mercury only control technology that uses a photochemical oxidation (PCO) process. In this process, mercury is oxidized via an ultraviolet (UV) light. The UV lights are placed in the ductwork upstream of a particulate control device. The PCO technology is in its infancy; because PowerSpan’s PCO process has not moved beyond bench-scale testing and has not been pilot tested at a facility burning a low sulfur coal, the technology will not be evaluated further. Enviroscrub Enviroscrub is a multi-pollution control technology that is capable of removing significant amounts of elemental and oxidized mercury, NOx, PM2.5, and SO2. This technology is based on the Pahlman Process.TM A sorbent made up of oxides of manganese called PahlmaniteTM sorbent (PS) is injected upstream of the SDA where the flue gas mixes with the PS. This is where the oxidation and adsorption of mercury takes place. Other pollutants such as SO2 and NOx are also adsorbed by the PS at this stage. Then the SDA byproducts are separated from the flue gas in the PJFF. The fly ash and waste byproduct collected in the PJFF hopper is eventually transported to a slurry tank for subsequent PS regeneration in a reactor. A process flow diagram of the PahlmanTM process is illustrated in Figure 25. The configuration for this technology is as follows: particulate removal (existing ESP), SDA, PJFF, sorbent regeneration and byproduct separation. Although significant

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progress has been made on the sorbent regeneration part of its technology, EnviroScrub is not considered a proven, viable technology. Since EnviroScrub’s process has not moved beyond pilot-scale testing, the technology will not be evaluated further.

Figure 25. Pahlman Process™ Simplified Process Flow Diagram

Phenix Clean Coal The Clean Combustion SystemTM (CCS) is an advanced hybrid coal gasification / combustion process that reduces the formation of NOx and SO2 emissions when burning coal. The only reagent required for pollution control is limestone. The CCS concept is that of an entrained-flow coal gasifier followed by stages of combustion air. The CCS burner is uniquely designed to provide the necessary time, temperature, and stoichiometry required for all the chemicals in coal to complete their combustion reactions (to reach equilibrium conditions). The coal, with limestone added as a source of calcium for sulfur capture, is pulverized and introduced to the burner along with a limited amount of hot combustion air. The initial high temperature combustion gasifies and/or releases all the constituents of coal, carbon, sulfur, nitrogen and ash compounds, into the gas. At these high temperatures

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and with limited available oxygen, the carbon aggressively commands oxygen to form CO from all sources, including such compounds as water (H2O). Nitrogen compounds that may form, such as NOx, HCN's and NH4, are simply forced to the molecular form (N2) by the aggressive action of carbon for oxygen. In the presence of calcium, the sulfur reacts to form calcium sulfide (CaS, a solid 'non-gaseous' particle). The hydrogen cannot compete with the other elements and remains H2. The high combustion temperatures melt together the coal ash (largely silica and alumna) and calcium sulfide solids to form an inert slag that drains from the bottom of the boiler. The very hot gases, high in CO and H2, and nearly free of NOx and sulfur, then exit into the boiler furnace. As the gases cool and generate steam, additional OFA air is added in stages to the furnace to complete the combustion of CO to CO2 and H2 to water. These steps prevent formation of any new (thermal) NOx and complete the combustion with excess air. The clean hot gases then enter the boiler superheat section as was before the retrofit. A schematic of the process is shown in Figure 26.

Figure 26. Phenix Clean Coal Process Flow Diagram

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The CCS retrofit modification requires replacing the existing pulverized coal burners with new down-fired CCS burners, adding separated OFA to the boiler furnace, and powdered limestone to the coal fuel. This is a complex retrofit that involves the modification of the boiler pressure parts. Most of the new, off-the-shelf equipment fits within the existing boiler space. A CCS repowered boiler has the potential to show improved efficiency from more complete coal combustion, very low NOx, and control of SO2 emissions with either Western or Midwest coals. Since the CCS process has not moved beyond the demonstration stage, the technology will not be evaluated further.

4.D.2 Technically Infeasible Options Since none of the options for multi-pollutant control have moved beyond the demonstration phase, these options will not be considered further in this report.

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5.0 Conclusions The Regional Haze Rule provides that a state participating in the Clean Air Interstate Rule (CAIR), which includes Minnesota, need not require BART-eligible electric generating units to install BART, because EPA’s analysis concluded that CAIR controls are ‘”better than BART” for electric generating units in states subject to CAIR. The MPCA stated that it would determine whether CAIR substitutes for BART after BART analyses have been submitted. Since EPA concluded that CAIR will provide more visibility improvement than BART, Xcel Energy believes Sherco Units 1 and 2 should not be given BART limits and instead CAIR should drive emission reductions. Nevertheless, Xcel Energy performed a BART analysis for Sherco 1 and 2 following the guidance provided by the MPCA and EPA. The analysis summary table (Table 22) follows this section. Based on the BART analysis for SO2, Xcel Energy proposes to retrofit the existing wet scrubbers with sparger tubes and lime injection. The proposed emission rate is 0.12 lb/MMBTU at the stack, on a 30-day rolling average, to be met by the end of 2012. This rate is lower than the presumptive limit for similar units that are not achieving 50% removal. The proposed option would reduce SO2 emitted from Sherco Units 1 and 2 on the order of 8,300 tons per year, and allows Xcel Energy flexibility in achieving required mercury reductions. Xcel Energy has an obligation to its ratepayers to evaluate all expenditures to ensure they are prudent. New wet FGDs would increase auxiliary power needed in the plant, and would reduce energy available to consumers, requiring the need for generation from some other source. The total annualized cost for retrofitting the existing scrubbers with sparger tubes and lime injection is $2,000,000, with a significant visibility improvement of 0.55 dv, or $4,000,000/dv. Conversely, the total annualized cost to move to the next most effective control technology is approximately $72,000,000, and this would further improve visibility by only 0.13 dv, or $550,000,000/dv. Xcel Energy firmly believes that retrofitting the existing wet scrubbers with sparger tubes and lime injection will bring about the most economical visibility improvements. Xcel Energy proposes a BART NOx limit of 0.15 lb/MMBTU at the stack, on a 30-day rolling average, to be achieved by installing combustion optimization systems for both Sherco Units 1 and 2, and low NOx burners and separated/close coupled overfire air for Sherco Unit 1. This is the presumptive limit for the category of electric generating units

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into which Sherco Units 1 and 2 fit. The proposed controls would be installed by the end of 2007, and compliance with the proposed limit would be demonstrated by the end of 2008. The total annualized cost for installation of combustion optimization systems for both units and installation of new low NOx burners and a separated/close coupled overfire air system for Sherco Unit 1 is $2,700,000, with a significant visibility improvement of 0.57 dv, or $5,000,000/dv. Conversely, the total annualized cost to move to the next most effective control technology is approximately $29,000,000; that technology would further improve visibility by 0.31 dv, or $95,000,000/dv. Xcel Energy firmly believes that the most economical visibility improvements will be brought about by the installation of new combustion optimization systems for Sherco Units 1 and 2 and the installation of new low NOx burners and a separated/close coupled overfire air system for Sherco Unit 1. No particulate matter control technology would significantly improve the control from current levels at Sherco Units 1 and 2. The cost-effectiveness values are unreasonably high for all PM10 options (>$70,000/ton). No new limit is proposed for PM10.

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Table 22. Emission Unit EU001/EU002: Summary of the Impacts Analysis for SO2, NOx, PM10 Control Scenarios

Control Scenario

#

Control Technology Evaluated

Emissions Performance

Level (percent pollutant removed)

Baseline Emission Rate, tons/year

Expected Emissions Reductions, tons/year

Current Emission Rate, lb/MMBTU

Expected Emission Rate,

lb/MMBTU

Total Annualized

Control Cost, $

Average Cost Effectiveness,

$/ton pollutant removed

Incremental Cost

Effectiveness, $/ton

pollutant removed

Energy Impacts

Collateral Increase in

Other Pollutants?

Non-Air Quality

Environmental Impacts

Greatest Change

in modeled visibility on 98th

Percentile day from baseline,

dv

SO2

NO

x

PM10

SO2

NO

x

PM10

SO2

NO

x

PM10

SO2

NO

x

PM10

SO2

NO

x

PM10

SO2

NO

x

PM10

1 X 44% 14,652 6,500 0.34/0.20 0.15 2,700,000 400 No No No 2.11

2 X 70% 14,652 10,300 0.34/0.20 0.08 32,000,000 3,100 7,800 Yes No No 1.80

3 X 56% 14,975 8,300 0.27 0.12 2,000,000 200 No No No 2.13

4 X 67% 14,975 10,000 0.27 0.09 74,000,000 7,400 43,000 Yes No No 2.00

Control Scenario 1: Combustion optimization/low NOx burners/separated OFA – Sherco Unit 1, Combustion optimization – Sherco Unit 2 Control Scenario 2: Combustion optimization/low NOx burners/separated OFA /selective catalytic reduction – Sherco Unit 1,

Combustion optimization/selective catalytic reduction – Sherco Unit 2 Control Scenario 3: Retrofit existing scrubbers with sparger tubes and lime injection – Sherco Units 1 and 2 Control Scenario 4: Install new wet FGD systems – Sherco Units 1 and 2

The total annualized costs for each control scenario were obtained by adding the total annualized costs for each unit together for proposed options. For example, the total annualized cost for a new wet FGD system for Sherco Unit 1 was added to the total annualized cost for a new wet FGD system for Sherco Unit 2, and reported in the Total Annualized Control Cost column in the table above. The expected emissions reductions were calculated the same way, however all reported numbers are rounded.

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Table 23. Visibility Modeling: Baseline Model Results

2002 2003 2004 2002-2004 Control Scenario Class I Area 98%

dv # days >0.5 dv

98% dv

# days >0.5 dv

98% dv

# days >0.5 dv

98% dv

# days >0.5 dv

Baseline BWCA VNP IR

2.60 1.98 1.69

85 54 50

2.932.512.04

87 55 52

2.77 2.39 1.95

91 56 57

2.682.341.79

263 165 159

Table 24. Visibility Modeling: Boundary Waters Results

2002 2003 2004 2002 through 2004

Control

Scenario 98th % ∆dv

# of days > 0.5 dv

98th % ∆dv

# of days > 0.5 dv

98th % ∆dv

# of days > 0.5 dv

98th % ∆dv

# of days > 0.5 dv

Baseline 2.60 85 2.93 87 2.77 91 2.68 263 Case 1 2.02 73 2.33 77 2.22 77 2.11 227 Case 2 1.74 63 1.95 74 1.94 69 1.80 206 Case 3 2.01 64 2.36 72 2.28 72 2.13 208 Case 4 1.92 64 2.51 69 2.09 73 2.00 206

Table 25. Visibility Modeling: Voyageur National Park Results

2002 2003 2004 2002 through 2004

Control

Scenario 98th % ∆dv

# of days > 0.5 ∆dv

98th % ∆dv

# of days > 0.5 ∆dv

98th % ∆dv

# of days > 0.5 ∆dv

98th % ∆dv

# of days > 0.5 ∆dv

Baseline 1.98 54 2.51 55 2.39 56 2.34 165 Case 1 1.66 46 1.92 51 1.76 50 1.82 147 Case 2 1.48 41 1.74 50 1.59 45 1.59 136 Case 3 1.46 39 1.86 45 1.87 39 1.75 123 Case 4 1.54 45 1.89 44 1.78 39 1.65 128

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Table 26. Visibility Modeling: Isle Royale Results

2002 2003 2004 2002 through 2005

Control

Scenario 98th % ∆dv

# of days > 0.5 ∆dv

98th % ∆dv

# of days > 0.5 ∆dv

98th % ∆dv

# of days > 0.5 ∆dv

98th % ∆dv

# of days > 0.5 ∆dv

Baseline 1.69 50 2.04 52 1.95 57 1.79 159 Case 1 1.35 41 1.59 44 1.47 46 1.44 131 Case 2 1.20 39 1.40 36 1.30 42 1.30 117 Case 3 1.16 38 1.38 40 1.47 43 1.34 121 Case 4 1.22 38 1.37 35 1.73 45 1.37 118 1 & 3 0.90 30 1.11 23 1.07 34 0.98 87 2 & 3 0.71 24 0.91 19 0.84 26 0.82 69

Appendix A

CUECOST Input

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Appendix B

Visibility Impact In Class I Areas

Figure 27. SO2 Visibility Impacts at BWCA

2.60

2.932.77

2.68

2.01

2.36 2.282.13

1.92

2.51

2.09 2.00

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile v

alue

, dv

Baseline Spargers Wet FGD

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Figure 28. NOx Visibility Impacts at BWCA

2.60

2.932.77

2.68

2.02

2.332.22

2.11

1.741.95 1.94

1.80

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile v

alue

, dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

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Figure 29. SO2 Visibility Impacts at BWCA

85 87 91

263

6472 72

208

64 69 73

206

0

50

100

150

200

250

300

2002 2003 2004 2002-2004 combined

Year

# D

ays

> 0.

5 dv

Baseline Spargers Wet FGD

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Figure 30. NOx Visibility Impacts at BWCA

85 87 91

263

73 77 77

227

6374 69

206

0

50

100

150

200

250

300

2002 2003 2004 2002-2004 combined

Year

# D

ays

> 0.

5 dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

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Figure 31. SO2 Visibility Impacts at IR

1.98

2.512.39 2.34

1.46

1.86 1.871.75

1.54

1.891.78

1.65

0.00

0.50

1.00

1.50

2.00

2.50

3.00

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile v

alue

, dv

Baseline Spargers Wet FGD

Page 104 of 111

Figure 32. NOx Impacts at IR

0.00

0.50

1.00

1.50

2.00

2.50

3.00

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile V

alue

, dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

Page 105 of 111

Figure 33. SO2 Visibility Impacts at IR

54 55 56

165

3945

39

123

45 4439

128

0

20

40

60

80

100

120

140

160

180

2002 2003 2004 2002-2004 combined

Year

# D

ays

>0.5

dv

Baseline Spargers Wet FGD

Page 106 of 111

Figure 34. NOx Visibility Impacts at IR

54 55 56

165

4651 50

147

4150

45

136

0

20

40

60

80

100

120

140

160

180

2002 2003 2004 2002-2004 combined

Year

# D

ays

>0.5

dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

Page 107 of 111

Figure 35. SO2 Visibility Impacts at VNP

1.69

2.041.95

1.79

1.16

1.381.47

1.341.22

1.37

1.73

1.37

0.00

0.50

1.00

1.50

2.00

2.50

2002 2003 2004 2002-2004 combined

Year

98th

per

cent

ile V

alue

, dv

Baseline Spargers Wet FGD

Page 108 of 111

Figure 36. NOx Visibility Impacts at VNP

1.69

2.041.95

1.79

1.35

1.591.47 1.44

1.20

1.401.30 1.30

0.00

0.50

1.00

1.50

2.00

2.50

2002 2003 2004 2002-2004 combined

Year

98th

Per

cent

ile v

alue

, dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

Page 109 of 111

Figure 37. SO2 Visibility Impacts at VNP

50 5257

159

38 40 43

121

38 35

45

118

0

20

40

60

80

100

120

140

160

180

2002 2003 2004 2002-2004 combined

Year

# D

ays

> 0.

5 dv

Baseline Spargers Wet FGD

Page 110 of 111

Figure 38. NOx Visibility Impacts at VNP

50 5257

159

41 44 46

131

39 3642

117

0

20

40

60

80

100

120

140

160

180

2002 2003 2004 2002-2004 combined

Year

# D

ays

>0.5

dv

Baseline Sherco 1 - LNB/OFA/CC, Sherco 2 - CC Sherco 1 - LNB/SOFA/CC/SCR, Sherco 2 - CC/SCR

Page 111 of 111