presented by: eastern research group, inc

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


$millions





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%


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%


15

Results (cont.)

Option


$millions





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

19

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.

20

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

21

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.

23

Group 1 ProcessesGROUP 1 - Coal External Combustion Boilers Breakdown

SO2 Emissions (TPY) Percentage# Units per


# 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

24

Group 2 ProcessesGROUP 2 - Petroleum Industry



# 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



# 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



# 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



# 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

28

Group 11 ProcessGROUP 11 - Sulfur Production



# 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

29

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



# 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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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



# Sources per Group

Avg Size per Source


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.

presented by: eastern research group, inc

Documents

low nox burner

emissions of nox

emission reductions

control category

bart level of control

generation lnb

updated camd costs

rofacontrol options