Post on 20-Jan-2018
description
Presented by:Eastern Research Group, Inc.
May 10, 2005
Status Report to the Stationary Sources Joint Forum:
Task 2: Control Technology Analysis
2
Objective: Provide costs and impacts for options used to control emissions of NOx, SO2, PM, VOC, and Ammonia
NOx from EGUs EGUs firing coal – Draft report has been issued. EGUs firing oil and gas – Database of sources has been
assembled. Working on identifying control options and costs and emission reductions of options.
Other NOx from non-EGU’s SO2
PM, VOC, and ammonia
Overview
3
Plan for NOx From Coal-fired EGUs
Assemble database of all EGUs in WRAP
Profile state of the art NOx combustion controls
Identify control optionsCalculate costs and impacts of
options
4
Database of All EGUs in WRAPData obtained from EPA databases
CAMDEIA 767EIA 423
Data from telephone contacts w/utilitiesCoal and combustor properties
Database is available on website
5
Bins for Coal-fired EGU’s in WRAP
EGU’s were grouped into bins based on similarities in combustor type, coal fired, and nitrogen content of coal.
Bins were further specified by the generation of existing combustion control.E.g., 1st generation LNB, 2nd generation LNB, State
of the Art LNBInsufficient information was available
on more specific combustor parameters (e.g., residence time, combustor volume, and heat release rate).
6
Bins for Coal-fired EGU’s in WRAP (cont.)
Bin ID Bin Description # EGU’s in Bin1a Tangentially-fired, high N
coal27
1b Tangentially-fired, low N coal
17
2 Wall-fired, high N coal 333 Wall-fired, low N coal 124 Cyclone burners 55 Cell burners 36 CFB units 27 Dry bottom vertically fired 4
7
Summary of Combustor Configurations
LNB = Low NOx burner, this includes an older low technology found on some tangentially-fired boilers and a technology used on tangential units.LNBO = Low NOx burner with over-fire airLNC1 = Low NOx burner with closed-coupled OFALNC2 = Low NOx burner with separated OFALNC3 = Low NOx burner with close-coupled and separated OFAOFA = Over-fired airSCR = Selective Catalytic Reduction
Combustor Type Coal Type
Baseline NOx Control
Wall-fired Tangential
Other (including unknown) Bituminous
Sub-bituminous Lignite Unknown
None Listed 4 9 14 3 13 6 5 LNB 22 3 2 8 15 4 LNBO 13 2 7 8 LNC1 12 4 7 1 LNC2 2 1 1 LNC3 7 3 2 2 OFA 5 8 2 1 14 SCR 1 1 Other 3 1 4 Total 45 44 21 30 61 14 5
8
Control ScenariosIdentified 5-7 control options for
bins (except for fluidized bed, cell, and cyclone burners).
Options 1-3 are existing combustion controls that are widely used.Most are variations of LNB and/or OFA
Options 4-7 are next generation burners or state of art combustion controls.E.g., ULNB, ULNB+OFA, ROFA
9
Control Options Applied to Bin 1A
Baseline Controls Number of
Units
NOx Control Applied at the
Option
Removal Efficiency from
Baseline Assumed (%)
Lowest Achievable Rate
(lb/MMBtu) Option 1
None 5 LNC2 47 0.24 OFA – 1st generation 7 LNC2 47 0.24 LNC1 3 None LNC1 - post 1997 4 None LNC3 2 None LNC3 - post 1997 3 None Other 3 LNC2 47 0.24
Option 2 None 5 LNC2 47 0.24 OFA – 1st generation 7 LNC2 47 0.24 LNC1 3 Upgrade to LNC3 20 0.24 LNC1 - post 1997 4 Upgrade to LNC3 20 0.24 LNC3 2 None LNC3 - post 1997 3 None Other 3 LNC2 47 0.24
Option 3 None 5 LNC3 62 0.24 OFA – 1st generation 7 LNC3 62 0.24 LNC1 3 LNC3 62 0.24 LNC1 - post 1997 4 LNC3 62 0.24 LNC3 2 LNC3 62 0.24 LNC3 - post 1997 3 LNC3 62 0.24 Other 3 LNC3 62 0.24
Option 4 None 5 ROFA 60 0.21 OFA – 1st generation 7 ROFA 60 0.21 LNC1 3 ROFA 59 0.21 LNC1 - post 1997 4 ROFA 59 0.21 LNC3 2 ROFA 59 0.21 LNC3 - post 1997 3 ROFA 59 0.21 Other 3 ROFA 60 0.21
10
Costs and Impacts of ScenariosCosts for LNB and OFA from CAMD
analysis were updated to 2004 $.Vendor information on LNB and OFA in
2004 $ were compared to updated CAMD costs. If significantly different, vendor data used to reflect decrease in costs.
O & M costs were based on CAMD dataVendor information used for new state of
the art combustion controls.Costs and emission reductions based on few data
points
11
Costs and Impacts MethodologyIncorporated the generation of the
control category to determine the baseline level of control
Baseline NOx emissions were based on CEM information from CAMD
Emission reductions were calculated using the percent reduction the control option can achieve, but bounded by the emission limit that can be achieved
12
ResultsCosts and emission reductions for control
options were compared to costs and emission reductions of applying SCR to only BART sources to meet the BART level of control (0.2 lb NOx/MMBtu).
BART sources comprise 64 of 110 EGU’s. Additional 21 EGU’s are likely BART sources.
To match the emissions reduction achieved by applying SCR, EGU’s would need to apply more advanced state of the art controls.
13
Results (cont.)
Option
Average Capital Costs
$millions
Average Total Annualized Costs $millions (CRF + Fixed
+Variable) Total Emission
Reductions Average $/ton
Removed % Emission Reductiona
Bin 1a Option 1 86.56 13.38 30,255 442 17% Option 2 102.30 16.20 40,373 402 23% Option 3 145.5 21.92 49,261 445 28% Option 4 250.6 32.84 69,623 472 40% Option 5 360.9 45.49 81,820 556 47% SCR on Bart Yes Units 936.3 159.7 50,190 3,182 29%
SCR on Bart Yes and Maybe Units 1,168 199.1 63,129 3,153 36%
Bin 1b Option 1 16.07 2.43 9,304 261 11% Option 2 30.41 4.96 15,055 330 18% Option 3 84.11 12.70 43,843 290 52% Option 4 113.9 15.25 44,563 342 53% Option 5 160.1 20.50 46,204 446 55%
SCR on Bart Yes Units 428.62 75.97 26,820 2,833 32% SCR on Bart Yes and Maybe Units 536.26 95.85 30,979 3,094 37%
14
Results (cont.)
Option
Average Capital Costs
$millions
Average Total Annualized Costs $millions (CRF + Fixed
+Variable) Total Emission
Reductions Average $/ton
Removed % Emission Reductiona
Bin 2 Option 1 27.40 4.47 12,093 370 7% Option 2 51.56 8.38 18,883 444 11% Option 3 44.93 6.59 17,578 375 10% Option 4 83.60 11.72 27,513 426 16% Option 5 122.30 21.99 41,573 529 24% Option 6 134.32 24.09 44,770 538 26% Option 7 205.36 27.21 71,610 380 42%
SCR on Bart Yes Units 550.55 95.47 46,212 2,066 27% SCR on Bart Yes and Maybe Units 850.68 148.06 69,819 2,121 41%
Bin 3 Option 1 12.60 2.07 3,426 603 8% Option 2 27.48 4.61 6,327 728 15% Option 3 26.51 3.88 8,348 465 19% Option 4 34.92 4.94 13,716 360 32% Option 5 51.54 9.48 15,923 596 37%
Option 6 65.83 8.82 18,649 472 43%
SCR on Bart Yes Units 318.34 57.98 9,784 5,926 23% SCR on Bart Yes and Maybe Units 349.99 63.42 12,211 5,194 28%
15
Results (cont.)
Option
Average Capital Costs
$millions
Average Total Annualized Costs $millions (CRF + Fixed
+Variable) Total Emission
Reductions Average $/ton
Removed % Emission Reductiona
Bin 4 Option 1 115.35 19.20 27,439 700 44% Option 2 120.51 20.11 32,279 623 51%
SCR on Bart Yes Units 146.21 26.90 36,824 731 59% SCR on Bart Yes and Maybe Units 189.33 34.59 46,375 746 74%
Bin 5 Option 1 24.57 4.32 8,153 530 24% Option 2 17.70 2.74 7,716 355 23%
SCR on Bart Yes Units (no maybe units) 211.72 35.46 20,697 1,714 62%
Bin 6
SCR on Bart Yes Units (no maybe units) 11.66 1.97 299 6,590 13%
Bin 7
Option 1 CAMD- LNB 6.24 0.92 2,601 352 36% No BART units
16
Example Scenarios
17
Example Scenarios (cont.)
18
Example Scenario by State
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Plan for Other Pollutants/SourcesFor EGU’s, identify unique units
by ORIS codes.Identify highest emitting sources
and SCC’s using latest inventory work.
Use previous study (plus additional controls) to identify potential controls that may be used per source category.
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SO2 Emissions by SICTOP 95% SIC's FOR THE NINE STATES
SIC Primary Description SO2 Emissions (TPY)4911 Electric Services 376,147.82911 Petroleum Refining 47,006.7(blank) 16,374.22819 Industrial Inorganic Chemicals, NEC 15,241.54925 Mixed, Manufactured, or Liquefied Petroleum Gas Production and/or Distribution 6,267.13241 Cement, Hydraulic 6,202.88221 Colleges, Universities, and Professional Schools 5,814.74491 Marine Cargo Handling 5,353.35171 Petroleum Bulk Stations and Terminals 4,000.12611 Pulp Mills 3,470.92063 Beet Sugar 2,917.23334 Primary Production of Aluminum 2,730.04961 Steam and Air-Conditioning Supply 2,402.3
TOTAL THESE SIC's 493,928.6TOTAL NINE STATES 518,841.2
TOTAL ALL WRAP STATES 963,360.8
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SO2 Emissions by StateState Emission Summary (for units emitting >100TPY)
State SO2 Emissions (TPY) PercentageND 159,731.3 35.0CO 95,163.7 20.9NV 49,650.0 10.9WA 40,703.1 8.9CA 36,892.6 8.1MT 34,400.1 7.5ID 21,837.5 4.8SD 13,666.2 3.0AK 3,905.3 0.9
TOTAL 455,949.8 100.0
22
SO2 Emissions by Process Group
SO2 Emissions by Groups (for units emitting >100TPY)
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
1 Coal External Combustion Boilers 345,357.3 75.7 86 4,015.8 48 7,194.92 Petroleum Industry 42,218.6 9.3 53 796.6 25 1,688.73 Other External Combustion Boilers 18,855.4 4.1 28 673.4 18 1,047.54 Phosphate Processes 18,586.5 4.1 8 2,323.3 3 6,195.56 Kiln Processes 8,647.6 1.9 21 411.8 16 540.511 Sulfur Production 6,749.0 1.5 7 964.1 7 964.17 Furnaces 4,760.9 1.0 10 476.1 9 529.09 Primary Metal Production 3,181.2 0.7 22 144.6 6 530.28 Internal Combustion Engines 2,945.7 0.6 5 589.1 4 736.45 Sulfuric Acid Production 1,774.7 0.4 7 253.5 7 253.510 Industrial Processes In-Process Fuel 1,688.0 0.4 3 562.7 3 562.712 Miscellaneous 1,184.9 0.3 5 237.0 4 296.2
TOTAL 455,949.8 100.0 255 137**There are only 137 unique sources that are located in the nine non-Annex states and have at least one unit that emits >100 TPY.
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Group 1 ProcessesGROUP 1 - Coal External Combustion Boilers Breakdown
SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
Electric Generation 333,280.4 96.5 65.0 5,127.4 34 9,802.4Industrial 6,998.7 2.0 15.0 466.6 10 699.9Commercial/Institutional 4,914.4 1.4 5.0 982.9 3 1,638.1(blank) 163.8 0.0 1.0 163.8 1 163.8
TOTAL 345,357.3 100.0 86 48
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Group 2 ProcessesGROUP 2 - Petroleum Industry
SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
Catalytic Cracking Units 9,600.5 22.7 13 738.5 13 738.5Petroleum Coke Calcining 7,756.5 18.4 3 2,585.5 3 2,585.5Process Heaters 6,515.1 15.4 12 542.9 6 1,085.8Fluid Coking Units 6,215.7 14.7 3 2,071.9 3 2,071.9Flares 5,461.3 12.9 14 390.1 8 682.7Catalytic Cracking Units, and Incinerators, and CO Boiler 5,035.0 11.9 1 5,035.0 1 5,035.0Blowdown Systems 1,233.2 2.9 5 246.6 5 246.6Fugitive Emissions 272.4 0.6 1 272.4 1 272.4(blank) 129.0 0.3 1 129.0 1 129.0
TOTAL 42,218.6 100 53 41
25
Group 3 ProcessesGROUP 3 - Other External Combustion Boilers
SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
Commercial/InstitutionalResidual Oil 108.5 0.6 1 108.5 1.0 108.5
TOTAL 108.5Electric Generation
Residual Oil 1,766.7 9.4 5 353.3 1 1,766.7Petroleum Coke 1,546.0 8.2 1 1,546.0 1 1,546.0
TOTAL 3,312.7Industrial
Natural Gas 6,055.3 32.1 2 3,027.6 2 3,027.6Process Gas 5,317.0 28.2 5 1,063.4 3 1,772.3Residual Oil and Process Gas 1,267.0 6.7 2 633.5 1 1,267.0Residual Oil 1,167.6 6.2 6 194.6 5 233.5Wood/Bark Waste 1,035.0 5.5 3 345.0 3 345.0CO Boiler 592.3 3.1 3 197.4 1 592.3
TOTAL 15,434.2GRAND TOTAL 18,855.4 100.0 28.0 18.0
26
Group 4 ProcessesGROUP 4 - Phosphate Processes
SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
Elemental Phosphorous 11,984.0 64.5 2 5,992.0 1 11,984.0Phosphate Rock 4,994.0 26.9 4 1,248.5 1 4,994.0Other Not Classified 1,608.5 8.7 2 804.3 1 1,608.5
TOTAL 18,586.5 100.0 8 3
27
Group 6 ProcessesGROUP 6 - Kiln Processes
SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
Cement Manufacturing (Dry Process) Kilns 2,364.6 27.3 5 472.9 5 472.9Cement Manufacturing (Wet Process) Kilns 1,855.8 21.5 5 371.2 4 464.0Calcining General 1,765.8 20.4 2 882.9 1 1,765.8Diatomaceous Earth Handling 1,023.8 11.8 3 341.3 1 1,023.8Bituminous Coal and Coke Cement Kiln/Dryer (Bituminous Coal) and General: Coke 555.4 6.4 1 555.4 1 555.4Cement Manufacturing (Dry Process) Preheater/Precalciner Kiln 377.6 4.4 1 377.6 1 377.6Cement Manufacturing (Dry Process) Cement Silos 311.2 3.6 1 311.2 1 311.2Concrete Batching Mixer Loading of Cement/Sand/Aggregate 169.0 2.0 1 169.0 1 169.0Cement Manufacturing (Dry Process) Pulverized Coal Kiln Feed Units 115.7 1.3 1 115.7 1 115.7Lime Manufacture Calcining: Rotary Kiln ** (See SCC Codes 3-05-016-18,-19,-20,-21) 108.7 1.3 1 108.7 1 108.7
TOTAL 8,647.6 100.0 21.0 17.0
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Group 11 ProcessGROUP 11 - Sulfur Production
SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
Elemental Sulfur Production Mod. Claus: 3 Stage w/o Control (95-96% Removal) 2,507.9 37.2 2 1,254.0 2 1253.950001Natural Gas Production Gas Sweetening: Amine Process (Tail Gas Incinerator and Flare) 1,563.9 23.2 1 1,563.9 1 1563.9Elemental Sulfur Production Other Not Classified 1,453.0 21.5 1 1,453.0 1 1453Elemental Sulfur Production Mod. Claus: 2 Stage w/o Control (92-95% Removal) 739.3 11.0 1 739.3 1 739.2999878Elemental Sulfur Production Mod. Claus: 4 Stage w/o Control (96-97% Removal) 283.0 4.2 1 283.0 1 283Sour Gas Treating Unit General 201.9 3.0 1 201.9 1 201.9361966
TOTAL 6,749.0 100.0 7 7
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SO2 Emissions by Group with BART-eligibility
SO2 Emissions (TPY) Per Group For Possible BART-Eligible Sources in the Nine Non-Annex States
Group Group Name
Total SO2 Emissions
(TPY)Total #
SourcesTotal # Units
Possibly BART-Eligible SO2 Emissions
# Possibly BART-Eligible
Sources1 Coal External Combustion Boilers 345,357.3 48 86 320,150.0** 32***2 Petroleum Industry 42,218.6 25 53 37,866.7 233 Other External Combustion Boilers 18,855.4 18 28 10,397.9 124 Phosphate Processes 18,586.5 3 8 1,608.5 16 Kiln Processes 8,647.6 16 21 4,869.0 1211 Sulfur Production 6,749.0 7 7 4,902.1 57 Furnaces 4,760.9 9 10 3,236.0 39 Primary Metal Production 3,181.2 6 22 2,747.3 38 Internal Combustion Engines 2,945.7 4 5 551.0 15 Sulfuric Acid Production 1,774.7 7 7 1,563.3 610 Industrial Processes In-Process Fuel 1,688.0 3 3 1,536.7 212 Miscellaneous 1,184.9 4 5 0.0 0
TOTAL 455,949.8 137* 255 389,428.5 100Percent Emissions 85.4
*There are only 137 unique sources that are located in the nine non-Annex states and have at least one unit that emits >100 TPY.** This value includes 6 non-EGU sources with coal-fired boilers that could be BART-Eligible.*** For EGUs, these sources consist of a total of 48 units.
30
Proposed BART Level of SO2 Control for EGUs In establishing BART emission limits, States as a
general matter, must apply EPA’s specified “Default Control Level” for each individual EGU greater than 250 MW.
The “Default Control Level” for SO2 is either: SO2 emissions from the EGU must be 95% controlled, OR The EGU’s control(s) must achieve in the range of 0.1 to 0.15 lbs
SO2/MMBtu. States may establish a different level of control if the
State can demonstrate that an alternative determination is justified based on a consideration of evidence before it.
EPA says that it will be extremely difficult to justify a BART determination less than the “default control level” for a plant greater than 750 MW, less difficult for a plant 750 MW or smaller.
31
Rough Estimate of SO2 Reductions due to BART for EGUs
Specific EGU Analysis (Coal Fired Electric Generation Units from Group 1)
Description Total # Units
SO2 Emissions
(TPY)Possibly BART-Eligible EGUs 48 311,079.6Possibly BART-Eligible EGUs that have emission reduction plans 29 107681.8*Possibly BART-Eligible EGUs that no emission reduction plans are known 19 203,397.8* It is assumed that any recent or planned reductions are not incorporated in this total 2002 actual emissions value.
10,169.9
Assuming 95% Emission Reduction Per BART
Guidelines
193,227.9
102,297.7
295,525.6
TOTAL EMISSION REDUCTION
15,554.0
5,384.1
32
North Dakota SO2 EmissionsNORTH DAKOTA
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
1 Coal External Combustion Boilers 146,555.2 91.8 20 7,327.8 13 11,273.5 10*3 Other External Combustion Boilers 5,653.6 3.5 1 5,653.6 1 5,653.6 02 Petroleum Industry 4,591.7 2.9 1 4,591.7 1 4,591.7 1
11 Sulfur Production 1,846.9 1.2 2 923.5 2 923.5 012 Miscellaneous 1,083.9 0.7 4 271.0 3 361.3 0
TOTAL 159,731.3 100.0 28 20 11* This value includes 3 non-EGU sources with coal-fired boilers that could be BART-Eligible.
33
Colorado SO2 EmissionsCOLORADO
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
1 Coal External Combustion Boilers 91,483.4 96.1 29 3,154.6 14 6,534.5 92 Petroleum Industry 1,640.9 1.7 4 410.2 2 820.4 2
11 Sulfur Production 851.2 0.9 2 425.6 2 425.6 26 Kiln Processes 617.6 0.6 2 308.8 2 308.8 17 Furnaces 312.4 0.3 1 312.4 1 312.4 09 Primary Metal Production 258.3 0.3 2 129.1 1 258.3 1
TOTAL 95,163.7 100.0 40 22 15
34
Nevada SO2 EmissionsNEVADA
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
1 Coal External Combustion Boilers 49,197.1 99.1 8 6,149.6 3 16,399.0 39 Primary Metal Production 284.0 0.6 2 142.0 2 142.0 06 Kiln Processes 169.0 0.3 1 169.0 1 169.0 1
TOTAL 49,650.0 100.0 11 6 4
35
Washington SO2 EmissionsWASHINGTON
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
1 Coal External Combustion Boilers 19,404.9 47.7 3 6,468.3 2 9,702.5 13 Other External Combustion Boilers 8,916.6 21.9 17 524.5 9 990.7 72 Petroleum Industry 5,124.0 12.6 13 394.2 4 1,281.0 47 Furnaces 3,236.0 8.0 4 809.0 3 1,078.7 39 Primary Metal Production 2,217.0 5.4 14 158.4 2 1,108.5 16 Kiln Processes 1,051.5 2.6 3 350.5 3 350.5 38 Internal Combustion Engines 551.0 1.4 1 551.0 1 551.0 15 Sulfuric Acid Production 101.0 0.2 1 101.0 1 101.0 1
12 Miscellaneous 101.0 0.2 1 101.0 1 101.0 0TOTAL 40,703.1 100.0 57 26 21
36
Montana SO2 EmissionsMONTANA
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
1 Coal External Combustion Boilers 21,139.1 61.5 7 3,019.9 4 5,284.8 32 Petroleum Industry 6,720.0 19.5 9 746.7 4 1,680.0 4
11 Sulfur Production 3,849.0 11.2 2 1,924.5 2 1,924.5 23 Other External Combustion Boilers 1,755.0 5.1 2 877.5 2 877.5 19 Primary Metal Production 422.0 1.2 4 105.5 1 422.0 1
10 Industrial Processes In-Process Fuel 282.0 0.8 1 282.0 1 282.0 16 Kiln Processes 233.0 0.7 1 233.0 1 233.0 1
TOTAL 34,400.1 100.0 26 15 13
37
California SO2 EmissionsCALIFORNIA
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
2 Petroleum Industry 24,142.0 65.4 26 928.5 14 1,724.4 126 Kiln Processes 5,965.1 16.2 12 497.1 8 745.6 63 Other External Combustion Boilers 2,128.5 5.8 7 304.1 5 425.7 4
10 Industrial Processes In-Process Fuel 1,406.0 3.8 2 703.0 2 703.0 15 Sulfuric Acid Production 1,309.7 3.6 5 261.9 5 261.9 47 Furnaces 1,212.5 3.3 5 242.5 5 242.5 01 Coal External Combustion Boilers 341.9 0.9 2 170.9 2 170.9 0
11 Sulfur Production 201.9 0.5 1 201.9 1 201.9 18 Internal Combustion Engines 185.0 0.5 1 185.0 1 185.0 0
TOTAL 36,892.6 100.0 61 43 28
38
Idaho SO2 EmissionsIDAHO
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
4 Phosphate Processes 18,586.5 85.1 8 2,323.3 3 6,195.5 11 Coal External Combustion Boilers 2,887.0 13.2 6 481.2 4 721.8 3*5 Sulfuric Acid Production 364.0 1.7 1 364.0 1 364.0 1
TOTAL 21,837.5 100.0 15 8 5* This value includes 3 non-EGU sources with coal-fired boilers that could be BART-Eligible.
39
South Dakota SO2 EmissionsSOUTH DAKOTA
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
1 Coal External Combustion Boilers 12,653.2 92.6 3 4,217.7 3 4,217.7 16 Kiln Processes 611.4 4.5 2 305.7 1 611.4 03 Other External Combustion Boilers 401.7 2.9 1 401.7 1 401.7 0
TOTAL 13,666.2 100.0 6 5 1
40
Alaska SO2 EmissionsALASKA
Group Group Name SO2 Emissions (TPY) Percentage# Units per
GroupAvg Size per Unit
# Sources per Group
Avg Size per Source
# Possibly BART-Eligible Sources
8 Internal Combustion Engines 2,209.7 56.6 3 736.6 2 1,104.8 01 Coal External Combustion Boilers 1,695.6 43.4 8 212.0 4 423.9 2
TOTAL 3,905.3 100.0 11 6 2
41
Next StepsAddress comments on draft
report. Obtain input on control scenarios
for NOx from non-coal EGU’s, NOx from non-EGUs, SO2 for non-Annex States, and PM, VOC, and ammonia from all sources.