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### MEMORANDUM **TO:** Bob Kelly, U.S. Environmental Protection Agency **FROM:** Eastern Research Group, Inc. **DATE:** March 28 , 2012 **SUBJECT:** BART Control Cost and Emission Reduction Estimates for the Virgin Islands
**B ACKGROUND**  

### Section 169A of the Clean Air Act requires sources affecting areas designated as Class I areas to reduce emissions to eliminate all anthropogenic obscuration of visibility, with the goal of reaching natural background levels of visibility by 2064. The Virgin Islands National Park on the island of St. John is a designated Class I area. Therefore, a Regional Haze State Implementation Plan (SIP) is being developed by EPA to address the need to reduce emissions to provide reasonable progress toward reducing regional haze in the Virgin Islands National Park. As part of the analysis needed to develop the SIP, the costs of applying Best Available Retrofit Technology (BART) to BART
-eligible sources have been estimated using information provided by EPA and the VIDPNR. This analysis has been conducted to estimate control costs and emissions reduction potential for controlling NO x

### , SO 2 

### , and PM. The results of this effort are presented in this memo, including the estimated control costs, emissions reductions, and cost effectiveness of each evaluated control technology for each pollutant. This memo is organized as follows: I. Selected Controls and Control Efficiency Assumptions II. Emission Reductions III. Emission C ontrol Costs

A . Filling Data Gaps for Control Cost Inputs B . Cost Summary IV . Cost Effectiveness V. References **I. S**  **ELECTED** 

### C **ONTROLS AND**  

### C **ONTROL** 

### E **FFICIENCY** 

### A**SSUMPTIONS** 

### For SO 2 

### and PM control, a duct sorbent injection and fabric filter (DIFF) combination was prescribed. Duct sorbent injection is a control technique for SO 2 

### control where a sorbent such as lime is injected into the duct upstream from the particulate matter control device. The SO 2 

### is absorbed, neutralized and/or oxidized by the alkaline reagent into a sold compound, either calcium or sodium sulfate. The solid is then removed from the waste gas stream using the downstream particulate control equipment. DIFF is a semi
wet 

## flue gas desulfurization (FGD) process, with additional water added due to quench demand. The water is used to humidif

y and cool the gas stream to the desired reaction temperature. In this instance, we have assumed a fabric filter is the particulate matter control device that collects the sorbent medium (and any particulate formed directly from the combustion process)
.

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### According to the Clean Air Technology Center (CATC) Flue Gas Desulfurization fact sheet 1 

### , dry sorbent injection is 50% to 60% efficient for SO 2 

### removal when using calcium
-based sorbent. For our emission reduction estimates, we have assumed a 55% removal efficiency. For PM removal, fabric filter efficiencies typically range from 95% to 99.9%, with newer equipment ranging from 99% to 99.9% 2 

### . We have therefore assumed a 99% PM removal efficiency for installed fabric filters. For NOX 

### control, s elective non-c atalytic reduction (SNCR) and s elective c atalytic reduction (SCR) were considered. In an SNCR system, a nitrogen
-based reducing agent, or reagent, such as ammonia or urea, is injected into the post
-com bustion flue gas through nozzles mounted on the wall of the combustion unit. In an SCR system, the nitrogen
-based reagent is injected downstream of the combustion unit, then the gas enters a reactor containing a catalyst, through which the hot flue gas and reagent diffuse. In the presence of the catalyst, the reagent reacts selectively with NOX 

### . SNCR is used on a wide range of boiler configurations; for large gas turbines, however, SCR is most commonly used. In conjunction with combustion controls, SNCR NOX 

### removal efficiencies range from 65% to 75%. 3 

### For the purposes of estimating control costs and emission reductions, we have conservatively assumed a 65% removal rate in case combustion controls are not in place or are not feasible in some cases. SCR system removal efficiencies for NOX 

### typically range from 70% to 90% 4 

### , so we have assumed an efficiency of 80% for our calculations. **II. E**  **MISSION** 

### R**EDUCTIONS** 

### Table 1 shows the emiss ion reductions resulting from the installation of controls discussed above. Baseline emissions are based on potential to emit and design data as provided by EPA Region II
. Total reduction estimates, based on efficiencies described above, can be summarized as follows: Installing DIFF on all units would result in approximately 4, 6 00 tons per year of SO 2 

### removal and 780 tons per year of PM removed. Installing SNCR on all boilers would result in a NOX 

### reduction of approximately 4 , 0 00 tons per year. Installing SCR on all turbines would result in a NOX 

### reduction of approximately 7 ,400 tons per year. **I I** **I. E**  **MISSION** 

### C **ONTROL** 

### C **OSTS** 

### This section presents the costs that were estimated for DIFF, SNCR, and SCR. **A. Filling Data Gaps for Control Cost Inputs**  Costs were calculated using algorithms based on those presented in the OAQPS Control Cost Manual5 

### as well as algorithms previously developed for regulatory development. In order to use these algorithms, input values for heat input, flow rate, operational hours, and other parameters were required for each unit. Unit
- specific data were limited, so data gaps were filled based on the assumptions described below. Resulting input values are presented in Appendix A. Stack data including temperature, velocity, and diameter, were provided for all units except for those at the WAPA St. Thomas facility. For the WAPA St. Thomas boilers, we assumed the same values as those provided for the two boilers at the WAPA St. Croix facility. F or the WAPA St. Thomas turbines, we used data from Hovensa unit GT1(G
- 1101E) , since these appeared to be similar units.

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### Stack velocity, diameter, and temperature were then used to calculate actual flow rate (acfm) where no flow rate data were available. Average moisture and oxygen values were based on moisture and oxygen values assigned to specific fuel categories in the boiler databas e. 6,7 

### Data pulled from the boiler database is listed in Appendix B. Fuel categories were assigned to the Hovensa and WAPA units based on reported fuel types. Because several units reported multiple fuel types, an average of the corresponding moisture and/or oxygen values was calculated for each unit. Average pollutant concentrations at 7% O 2 

### were based on the emissions data and the oxygen value determined as discussed above. Average dry flow rates were calculated using the moisture values obtained as discussed above. For the Hovensa units, operational hours were based on data for the same units in the boiler database . For the WAPA units, averages from comparable units in the boiler database were used. **B. Emission Control Costs**  The capital and annual costs for the emission controls were estimated in dollars ($) on a 2008 basis , and annualized costs assumed an interest rate of 7 percent. Downtime costs for the retrofits were assumed to be negligible. Each unit is assumed to have adequate space to install an emission control system. Appendix A contains a summary of the parameters used for each unit (e.g., heat input rate, stack gas flow rate, incinerator operating hours, and concentrations). Capital and annual control costs for each unit are provided in Table 2. Total capital and annual control costs for all BART
-eligible units are summarized in Table 3
. The total capital cost to install DIFF for all boilers and turbines is estimated at approximately $ 750 million, and the total annual cost for DIFF is approximately $ 203 million per year. The cost for applying SNCR at all boilers is e stimated at $ 29.1 million in capital costs and $ 3.3 million annually. For SCR, the capital cost to install for all turbines is estimated at $ 83 .0 million, and the total annual cost is estimated at $ 13.0 million per year. Cost details are discussed below. 1. Adding duct sorbent injection/fabric filter (DIFF). Calculations were bas ed on an algorithm consistent with that used for the boiler NESHAP. 8 

### Calculations are presented in Appendix C . DIFF capital costs per unit range from approximately $ 4. 8 million to $ 5 5.4 million, and annual costs range from approximately $1. 1 million/yr to $15.3 million/yr. 2. Adding a selective non
-catalytic reduction (SNCR) system. The cost algorithm for installing an SNCR system is presented in Appendix D and is based on algorithms in the OAQPS Control Cost Manual
. 5 

### The SNCR capital costs range from approximately $ 2.1 million to $ 3.0 million, and annual costs range from approximately $ 23 4 ,000/yr to $3 30,000/yr. 3. Adding a selective catalytic reduction (SCR) system. The cost algorithm for installing an S CR system is presented in Appendix E and is based on algorithms in the OAQPS Control Cost Manual
. 5 

### The S CR capital costs range from approximately $ 7.0 million to $ 8.7 million, and annual costs range from approximately $ 1.1 million/yr to $ 1.4 million /yr.

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### I**V .**  **C OST**  

### E **FFECTIVENESS** 

### Table 2 summarizes the pollution control cost effectiveness for each unit for each control type (DIFF for all units, SNCR for the boilers and SCR for the turbines). Appendix F contains details on how these data were derived. Table 3 summarizes the overall pollution control cost effectiveness. The cost effectiveness for each control was calculated based on the total annual control costs for all units for which the c ontrol was assigned and the estimated annual emission reductions resulting from the application of those controls. For NOX 

### control using SNCR for boilers, the overall cost effectiveness was estimated at $ 834 per ton of pollutant removed. For NOX 

### control using SCR for turbines, the overall cost effectiveness was estimated at $ 1,734 per ton of pollutant removed. For PM and SO 2 

### control using DIFF for all units, the overall cost effectiveness was estimated at $ 38,064 per ton of pollutant removed. The overall cost effectiveness of using these three controls to reduce NOx

### , PM, and SO 2 

### emissions from all units is $ 13,153 per ton of pollutant removed. **V. R** **EFERENCES** 

### 1. “Air Pollution Control Technology Fact Sheet: Flue Gas Desulfurization (FGD)
- Wet, Spray Dry, and Dry Scrubbers. ” http://www.epa.gov/ttn/catc/dir1/ffdg.pdf
. 2. “Air Pollution Control Technology Fact Sheet: Fabric Filter” http://www.epa.gov/ttn/catc/dir1/ff
shaker.pdf

, http://www.epa.gov/ttn/catc/dir1/ff
-pulse.pdf

, http://www.epa.gov/ttn/catc/dir1/ff
revar .pdf
. 3. “Air Pollution Control Technology Fact Sheet: Selective Non
-Catalytic Reduction (SNCR).” http://www.epa.gov/ttn/catc/dir1/fsncr.pdf
. 4. “Air Pollution Control Technology Fact Sheet: Selective Catalytic Reduction (SCR).” http://www.epa.gov/ttn/catc/dir1/fscr.pdf
. 5. U.S. Environmental Protection Agency. January 2002. OAQPS Control Cost Manual, Sixth Edition. Publication Number EPA/452/B
-02
-001. 6. Survey Database containing Results of the 2008 Questionnaire for Boilers, Process Heaters, & Other Combustion Units (ICR No. 2286.01) (Version 3) 7. Emissions Database for Boilers and Process Heaters Containing Stack Test, CEM, & Fuel Analysis Data Reported under ICR No. 2286.01 & ICR No. 2286.03 (Version 7). 8. 40 CFR 63, subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters
.

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### Table 1. Emission Reductions for Selected Controls **Facility Location**  **Unit Ty** **pe Unit No.**  **Baseline Emissions (TPY) Reductions**  ***** **(TPY) Resulting Emissions (TPY)**  **PM 10**  **SO 2**  **NO X**  **PM 10**  **SO 2**  **NO X**  **PM 10**  **SO 2**  **NO X**  Hovensa St Croix Boiler 1 (B - 1151) 40.6 330.1 450.6 40.2 181.5 292.9 0.41 148.5 157.7 Hovensa St Croix Boiler 3 (B - 1153) 40.6 330.1 450.6 40.2 181.5 292.9 0.41 148.5 157.7 Hovensa St Croix Boiler 4 (B - 1154) 39.7 322.5 443.5 39.3 177.4 288.3 0.40 145.1 155.2 Hovensa St Croix Boiler 5 (B - 1155) 60.7 484.9 676.9 60.1 266.7 440.0 0.61 218.2 236.9 Hovensa St Croix Boiler 6 (B - 3301) 40.6 330.8 435.3 40.2 182.0 282.9 0.41 148.9 152.3 Hovensa St Croix Boiler 7 (B - 3302) 4 0.6 330.8 435.3 40.2 182.0 282.9 0.41 148.9 152.3 Hovensa St Croix Boiler 8 (B - 3303) 78.6 640.1 559.8 77.8 352.1 363.9 0.79 288.0 195.9 Hovensa St Croix Boiler 9 (B - 3304) 78.6 640.1 559.8 77.8 352.1 363.9 0.79 288.0 195.9 Hovensa St Croix Turbine GT1 (G - 1101E) 12.2 135.5 805.7 12.0 74.5 644.6 0.12 61.0 161.1 Hovensa St Croix Turbine GT2 (G - 1101F) 12.2 135.5 805.7 12.0 74.5 644.6 0.12 61.0 161.1 Hovensa St Croix Turbine GT3 (G - 1101G) 12.2 135.5 805.7 12.0 74.5 644.6 0.12 61.0 161.1 Hovensa St Croix Turbine GT4 (G - 3404) 12.9 161.0 809.5 12.8 88.5 647.6 0.13 72.4 161.9 Hovensa St Croix Turbine GT5 (G - 340 5) 12.9 161.0 766.5 12.8 88.5 613.2 0.13 72.4 153.3 Hovensa St Croix Turbine GT6 (G - 3406) 12.9 161.0 766.5 12.8 88.5 613.2 0.13 72.4 153.3 Hovensa St Croix Turbine GT7 (G - 3407) 12.9 161.0 766.5 12.8 88.5 613.2 0.13 72.4 153.3 Hovensa St Croix Turbine GT8 (G - 3408) 15.1 167.6 1002.1 14.9 92.2 801.7 0.15 75.4 200.4 Hovensa St Croix Turbine GT9 (G - 3409) 14.0 52.2 150.2 13.9 28.7 120.2 0.14 23.5 30.0 VI WAPA St Thomas Boiler 11 60 .0 646.0 371.0 59.4 355.3 241.2 0.60 290.7 129.9 VI WAPA St Thomas Boiler 13 28.0 1116.0 670.0 27.7 613.8 435.5 0.28 502.2 234.5 VI WAPA St Thomas Turbine 12 15.0 381.0 1288.0 14.9 209.6 1030.4 0.15 171.5 257.6 VI WAPA St Thomas Turbine 14 16.0 392.0 1326.0 15.8 215.6 1060.8 0.16 176.4 265.2 VI WAPA St Croix Boiler 10 45.0 396.0 359.0 44.6 217.8 233.4 0.45 178.2 125.7 VI WAPA St Croix Boiler 11 81.0 712.0 646.0 80.2 391.6 419.9 0.81 320.4 226.1 **Total** 782.2 8322.6 15350.1 774.4 4577.4 11371.4 7.8 3745.2 3978.7 

### * Control Efficiencies are based on typical efficiencies listed in EPA Clean Air Technology Center fact sheets for dry sorbent injection, fabric filters, selective non- catalytic reduction, and selective catalytic reduction. See Section I of this memorandum for details.

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### Table **2 .**  **Cost Effectiveness for Selected Controls**  **Facility Location**  **Unit Ty** **pe Unit No.**  **Reductions** ***** **(TPY) Annual Control Cost ($/y** **r) Cost Effectiveness ($/ton**  **reduced) PM**  **10 SO**  **2 NO** **X** 

### DIFF **SNCR SCR**  **DIFF SNCR**  **SCR** Hovensa St Croix Boiler 1 (B - 1151) 40.2 181.5 292.9 $8,591,292 $235,848 $38,749 $805 Hovensa St Croix Boiler 3 (B - 1153) 40.2 181.5 292.9 $8,591,292 $235,848 $38,749 $805 Hovensa St Croix Boiler 4 (B - 1154 ) 39.3 177.4 288.3 $8,588,093 $234,532 $39,640 $814 Hovensa St Croix Boiler 5 (B - 1155) 60.1 266.7 440.0 $6,253,161 $313,100 $19,136 $712 Hovensa St Croix Boiler 6 (B - 3301) 40.2 182.0 282.9 $5,819,344 $234,477 $26,197 $829 Hovensa St Croix Boiler 7 (B - 3302) 40.2 182.0 282.9 $5,819,344 $234,477 $26,197 $829 Hovensa St Croix Boiler 8 (B - 3303) 77.8 352.1 363.9 $11,589,590 $312,326 $26,959 $858 Hovensa St Croix Boiler 9 (B - 3304) 77.8 352.1 363.9 $11,589,590 $312,326 $26,959 $858 Hovensa St Croix Turbine GT1 (G - 1101E) 12.0 74.5 644.6 $12,389,903 $1,172,745 $143,149 $1,819 Hovensa St Croix Turbine GT2 (G - 1101F) 12.0 74.5 644.6 $12,389,903 $1,172,745 $143,149 $1,819 Hovensa St Croix Turbine GT3 (G - 1101G) 12.0 74.5 644.6 $12,389,903 $1,172,745 $143,149 $1,819 Hovensa St Croix Turbine GT4 (G - 3404) 12.8 88.5 647.6 $12,395,811 $1,173,950 $122,333 $1,813 Hovensa St Croix Turbine GT5 (G - 3405) 12.8 88.5 613.2 $12,395,811 $1,160,377 $122,333 $1,892 Hovensa St Croix Turbine GT6 (G - 3406) 12.8 88.5 613.2 $12,395,811 $1,160,377 $122,333 $1,892 Hovensa St Croix Turbine GT7 (G - 3407) 12.8 88.5 613.2 $12,395,811 $1,160,377 $122,333 $1,892 Hovensa St Croix Turbine GT8 (G - 3408) 14.9 92.2 801.7 $15,316,917 $1,402,611 $142,990 $1,750 Hovensa St Croix Turbine GT9 (G - 3409) 13.9 28.7 120.2 $15,295,348 $1,135,171 $359,186 $9,447 VI WAPA St Thomas Boiler 11 59.4 355.3 241.2 $1,168,675 $256,705 $2,818 $1,065 VI WAPA St Thomas Boiler 13 27.7 613.8 435.5 $2,416,194 $330,397 $3,766 $759 VI WAPA St Thomas Turbine 12 14.9 209.6 1030.4 $6,217,806 $1,117,227 $27,709 $1,084 VI WAPA St Thomas Turbine 14 15.8 215.6 1060.8 $6,219,588 $1,132,200 $26,873 $1,067 VI WAPA St Croix Boiler 10 44.6 217.8 233.4 $1,128,352 $254,743 $4,301 $1,092 VI WAPA St Croix Boiler 11 80.2 391.6 419.9 $2,353,506 $327,269 $4,988 $779 **Total** 774.4 4577.4 11371.4 $203,711,047 $3,282,047 $12,960,525 $38,064 $834 $1,743 

### * Reductions are based on typical efficiencies listed in EPA Clean Air Technology Center fact sheets for dry sorbent injection, fabric filters, selective non
catalytic reduction, and selective catalytic reduction. See Section I of this memorandum for details.

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### Table **3 .**  **Total Control Costs and Cost Effectiveness Control**  **Total Capital Cost**

**($) Total Annual** 

**Cost ($/y r)**  **Total Emission**

**Reductions (tpy )**  **Cost Effectiveness**

**($/tpy pollutant reduced)**  DIFF $750,566,946 $203,711,047 5,352 $38,064 SNCR $29,146,033 $3,282,047 3,937 $834 SCR $82,692,433 $12,960,525 7,434 $1,743 **Overall $862,405,412**  **$219,953,619 16,723**  **$13,153**