Environmental solutions delivered uncommonly well

Anadarko Petroleum Corporation

BlackHornet PSD/Title V Permit Application 

Operations in the Eastern Gulf of Mexico

Prepared By:

TRINITY CONSULTANTS

301 Main Street, Suite 900

Baton Rouge, LA 70816

(225) 292-2661

August 2013

Project No. 131901.0020
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TABLE OF CONTENTS

1. INTRODUCTION 7

1.1. Location of the Proposed Project.................................................................................................................................................7

1.2. Air Permitting and Summary of Regulatory Requirements..............................................................................................8

1.3. Description of Emission Sources............................................................................................................................................... 11

1.3.1. Emission Sources....................................................................................................................................................................11

1.4. Contents of the Application Addendum ................................................................................................................................. 17

2. PROCESS DESCRIPTION 18

2.1. Exploratory Drilling Description............................................................................................................................................... 18

2.2. Well Completion............................................................................................................................................................................... 19

2.3. Production Description (Well Maintenance)....................................................................................................................... 20

3. EMISSIONS CALCULATIONS 21

3.1. ‘Equivalency’ Determination....................................................................................................................................................... 21

3.2. Operating Scenarios........................................................................................................................................................................ 21

3.3. Drillship................................................................................................................................................................................................ 22

3.3.1. Main Engines (DR-ME-01 through DR-ME-08)...........................................................................................................22

3.3.2. Emergency Generator (DR-GE-01)..................................................................................................................................24

3.3.3. Emergency Air Compressor (DR-AC-01)........................................................................................................................25

3.3.4. Life Boat Engines (DR-LB-01 through DR-LB-06).....................................................................................................26

3.3.5. Fast Rescue Craft (DR-FR-01)............................................................................................................................................27

3.3.6. Mud degassing Vent (DR-VG-01)......................................................................................................................................28

3.3.7. Dust Collectors (DR-DC-01 through DR-DC-03)..........................................................................................................29

3.3.8. Storage Vessels (DR-FT-01 through DR-FT-18)..........................................................................................................30

3.3.9. Drillship Fugitive Emissions (DR-FE-01).......................................................................................................................30

3.3.10. Painting Operations (DR-PO-01)...................................................................................................................................30

3.3.11. Welding Operations (DR-WO-01)..................................................................................................................................31

3.3.12. Third Party Engines (DR-TP-01 through DR-TP-21) .............................................................................................32

3.3.13. Flowback Boiler (DR-TP-22) ...........................................................................................................................................33

3.3.14. Boom Flare (DR-TP-23).....................................................................................................................................................34

3.3.15. Well Completion Condensate Tanks (DR-TP-24 through DR-TP-26)...............................................................35

3.4. Support Vessels................................................................................................................................................................................. 35

Supply Boats (HOS Coral) Combustion Sources......................................................................................................................36

3.4.1. Marine Propulsion Engines 1 and 2 (SB-ME-01 and SB-ME-02)..........................................................................36

3.4.2. Marine Thruster Engines (SB-TE-01 through SB-TE-03)........................................................................................37

3.4.3. Electrical Generator Engines (SB-GE-01 and SB-GE-02).........................................................................................38

3.4.4. Emergency Electrical Generator Engine (SB-GE-03)................................................................................................39

3.4.5. ROV Electrical Generator Engine (SB-GE-04)..............................................................................................................40

3.4.6. Well Evaluation Third Party Engine (SB-TP-01 and SB-TP-02)...........................................................................41

3.4.7. Well Evaluation Third Party Crane Motor Engine #1 (SB-TP-03)......................................................................42

3.4.8. Well Evaluation Third Party Crane Motor Engine #2 (SB-TP-04)......................................................................43

3.4.9. Third Party Well Evaluation Engines (SB-TP-05 through SB-TP-09)................................................................44

Anchor Handling Boat (Kirt Chouest) Combustion Sources..............................................................................................45

3.4.10. Marine Propulsion Engines (AB-ME-01 and AB-ME-02) ......................................................................................45

3.4.11. Thruster Engines (AB-TE-01 through AB-TE-03)....................................................................................................46

3.4.12. Service Generator Engines (AB-GE-01 through AB-GE-05).................................................................................47

3.4.13. Emergency Generator Engine (AB-GE-06).................................................................................................................47
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3.4.14. Winch Hydraulic Engines (AB-GE-07 and AB-GE-08)............................................................................................48

3.4.15. Supply Boat Storage Tanks..............................................................................................................................................49

Tug Boat Combustion Sources.......................................................................................................................................................49

3.4.16. Tug Boat Main Engines (TB-ME-01 to TB-ME-03) and Generator Engines (TB-GE-01 to TB-GE-02) 49

Barge Combustion Sources.............................................................................................................................................................51

3.4.17. Barge Electrical Generators (BG-LP-01thru BG-LP-03)........................................................................................51

Stimulation Vessel Combustion Sources....................................................................................................................................52

3.4.18. Stimulation Vessel Main Engines (SV-ME-01 and SV-ME-02).............................................................................52

3.4.19. Bow Thruster Engine (SV-BT-01)..................................................................................................................................54

3.4.20. Bow Drop-Down Engine (SV-DD-01)............................................................................................................................54

3.4.21. Stern Thruster Engines (SV-ST-01)...............................................................................................................................55

3.4.22. Representative Pump Engines (SV-PE-01 through SV-PE-08)............................................................................56

3.4.23. Stimulation Vessel Generators (SV-GE-01 and SV-GE-02)....................................................................................57

3.4.24. Stimulation Vessel Generators (SV-GE-03 and SV-GE-04)....................................................................................58

Well Evaluation Vessel Combustion Sources............................................................................................................................59

3.4.25. Well Evaluation Vessel Main Engines (WE-ME-01and WE-ME-02).................................................................59

3.4.26. Well Evaluation Vessel Auxiliary Engines (WE-AE-01 and WE-AE-02)..........................................................61

3.4.27. Well Evaluation Vessel Emergency Generator #1 (WE-GE-01).........................................................................61

3.4.28. Well Evaluation Vessel Emergency Generator #2 (WE-GE-02).........................................................................62

3.4.29. Well Evaluation Vessel Emergency Generator #3 (WE-GE-03).........................................................................63

4. REGULATORY APPLICABILITY ANALYSIS 65

4.1. Outer Continental Shelf Air Regulations (40 CFR 55)...................................................................................................... 65

4.2. Prevention of Significant Deterioration (PSD) Regulations........................................................................................... 67

4.3. New Source Performance Standards (NSPS)....................................................................................................................... 68

4.3.1. 40 CFR Subpart A – General Provisions..........................................................................................................................68

4.3.2. 40 CFR Subpart K- Standards of Performance for Storage Vessels for Petroleum Liquids........................68

4.3.3. 40 CFR 60 Subpart Ka – Standards of Performance for Storage Vessels for Petroleum Liquids..............69

4.3.4. 40 CFR 60 Subpart Kb- Standards of Performance for Volatile Liquid Storage Vessels..............................69

4.3.5. 40 CFR 60 Subpart IIII – Stationary Compression Ignition Internal Combustion .........................................71

4.3.5.1. Drillship Main Engines (DR-ME-01 through DR-ME-08).....................................................................................72

4.3.5.2. Drillship Emergency Generator (DR-GE-01).............................................................................................................73

4.3.5.3. Drillship Emergency Air Compressor (DR-AC-01)..................................................................................................74

4.3.5.4. Drillship Temporary Third Party Well Evaluation Engines (DR-TP-12 through DR-TP-16).................74

4.3.5.5. Stimulation Vessel Pumps (SV-PE-01 through SV-PE-08)...................................................................................74

4.3.6. 40 CFR 60 Subpart JJJJ – Stationary Spark Ignition Internal Combustion........................................................75

4.3.7. 40 CFR 60 Subpart Dc – Standards of Performance for Small Industrial – Commercial – Institutional 

Steam Generating Units...................................................................................................................................................................75

4.4. National Emission Standards For Hazardous Air Pollutants (NESHAP - 40 CFR Part 61)............................... 75

4.4.1. 40 CFR 61 Subpart A- General Provisions.....................................................................................................................76

4.5. National Emission Standards For Hazardous Air Pollutants (NESHAP – 40 CFR Part 63).............................. 76

4.5.1. 40 CFR 63 Subpart A – General Provisions...................................................................................................................76

4.5.2. 40 CFR 63 Subpart ZZZZ – Stationary Reciprocating Internal Combustion Engines...................................76

4.5.3. 40 CFR 63 Subpart HHHHHH – Paint Stripping and Miscellaneous Surface Coating Operations at Area 

Sources...................................................................................................................................................................................................77

4.6. Federal Operating Permits Program (40 CFR Part 71).................................................................................................... 77

4.7. Engangered Species Act ................................................................................................................................................................ 78

5. BACT ANALYSIS 79

5.1. NOX BACT Analysis .......................................................................................................................................................................... 81
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5.1.1. NOX BACT Analysis for the Drillship Main Engines (DR-ME-01 to DR-ME-08)...............................................81

5.1.2. NOX BACT Analysis for Emergency Generators (DR-GE-01)...................................................................................88

5.1.3. NOX BACT Analysis for Emergency Air Compressor Engine (DR-AC-01)...........................................................90

5.1.4. NOX BACT Analysis for Third Party Engines (DR-TP-01 through DR-TP-11 and DR-TP-17 though DRTP-21).....................................................................................................................................................................................................92

5.1.5. NOX BACT Analysis for Third Party Well Evaluation Engines (DR-TP-12 through DR-TP-16).................94

5.1.6. NOX BACT Analysis for Pumps on the Stimulation Vessel (SV-PE-01 through SV-PE-08)...........................97

5.1.7. NOX BACT Analysis for Flowback Boiler (DR-TP-22).............................................................................................100

5.1.8. NOX BACT Analysis for Boom Flare (DR-TP-23)......................................................................................................101

5.2. CO and VOC BACT Analysis........................................................................................................................................................103

5.2.1. CO and VOC BACT Analysis for Drillship Main Propulsion Electrical Generator Engines (DR-ME-01 

through DR-ME-08)........................................................................................................................................................................103

5.2.2. CO and VOC BACT Analysis for Drillship Emergency Generator (DR-GE-01)...............................................105

5.2.3. CO and VOC BACT Analysis for Air Compressor Engine (DR-AC-01)................................................................107

5.2.4. CO and VOC BACT Analysis for Drillship Third Party Engines (DR-TP-01 through DR-TP-11 and DR-TP17 though DR-TP-21).....................................................................................................................................................................108

5.2.5. CO and VOC BACT Analysis for Third Party Well Evaluation Engines (DR-TP-12 through DR-TP-16)

................................................................................................................................................................................................................110

5.2.6. CO and VOC BACT Analysis for Representative Stimulation Vessel Pumps (SV-PE-01 thru SV-PE-08)

................................................................................................................................................................................................................111

5.2.7. CO and VOC BACT Analysis for Flowback Boiler (DR-TP-22).............................................................................112

5.2.8. CO and VOC BACT Analysis for Boom Flare (DR-TP-23).......................................................................................113

5.3. PM/PM10/PM2.5 BACT Analysis ................................................................................................................................................115

5.3.1. PM/PM10/PM2.5 BACT Analysis for the Drillship Main Propulsion Electrical Generator Engines (DR-ME01 to DR-ME-08)..............................................................................................................................................................................115

5.3.2. PM/PM10/PM2.5 BACT Analysis for Drillship Emergency Generator (DR-GE-01)........................................118

5.3.3. PM/PM10/PM2.5 BACT Analysis for the Air Compressor Engine (DR-AC-01)................................................119

5.3.4. PM/PM10/PM2.5 BACT Analysis for Drillship Third Party Engines (DR-TP-01 through DR-TP-11 and DRTP-17 though DR-TP-21)..............................................................................................................................................................120

5.3.5. PM/PM10/PM2.5 BACT Analysis for Third Party Well Evaluation Engines (DR-TP-12 through DR-TP-16)

................................................................................................................................................................................................................121

5.3.6. PM/PM10/PM2.5 BACT Analysis for Representative Pump Engines on the Stimulation Vessel (SV-PE-01 

thru SV-PE-08).................................................................................................................................................................................123

5.3.7. PM/PM10/PM2.5 BACT Analysis for Flowback Boiler (DR-TP-22).....................................................................124

5.3.8. PM/PM10/PM2.5 BACT Analysis for Boom Flare (DR-TP-23)...............................................................................125

5.3.9. PM/PM10/PM2.5 BACT Analysis for Cement and Mud Mixing Operations (DR-DC-01 thru DR-DC-03)

................................................................................................................................................................................................................126

5.3.10. PM/PM10/PM2.5 BACT Analysis for Painting Operations (DR-PO-01)...........................................................126

5.3.11. PM/PM10/PM2.5 BACT Analysis for Welding Operations (DR-WO-01)..........................................................128

5.4. VOC BACT Analysis for Storage Tanks And Paints...........................................................................................................130

5.4.1. VOC BACT Analysis for Storage Tanks (DR-DT-01 thru DR-DT-09 and DR-FT-01 thru DR-FT-03).....130

5.4.2. VOC BACT Analysis for Mud Degassing Operations (DR-VG-01).......................................................................131

5.4.3. VOC BACT Analysis for Painting Operations (DR-PO-01).....................................................................................132

5.5. Greenhouse Gas (GHG) BACT Analysis .................................................................................................................................132

5.5.1. GHG BACT Analysis for the Diesel Fired Internal Combustion Engines ..........................................................133

5.5.2. GHG BACT Analysis for Mud Degassing Operations (DR-VG-01).......................................................................135

5.5.3. GHG BACT Analysis for Flowback Boiler (DR-TP-22)............................................................................................136

5.5.4. GHG BACT Analysis for Boom Flare (DR-TP-23)......................................................................................................136

6. PART 71 FORMS 139
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APPENDIX A – PLOT PLAN

APPENDIX B – EMISSION CALCULATIONS

APPENDIX C – LIST OF INSIGNIFICANT ACTIVITIES

APPENDIX D – AIR DISPERSION MODELING ANALYSIS

APPENDIX E – BACT ANALYSIS SUPPORTING DOCUMENTATION

APPENDIX F – ENVIRONMENTAL IMPACT ASSESSMENT

APPENDIX G -1 – SPECIFICATION SHEETS: DRILLSHIP

APPENDIX G-2 – SPECIFICATION SHEETS: THIRD PARTY EPA TIER II CERTIFIED ENGINES

APPENDIX G-3 – SPECIFICATION SHEETS: NON-EPA TIERED WELL EVALUATION ENGINES

APPENDIX G-4 – TANKS 4.09 OUTPUT FOR DRILLSHIP TANKS

APPENDIX G-5 – SPECIFICATION SHEETS: DUST COLLECTORS

APPENDIX G-6 – SPECIFICATION SHEETS: MSDS - PAINTS/BASE/THINNER

APPENDIX G-7 – TANKS 4.09 OUTPUT FOR SUPPLY BOAT TANKS

APPENDIX G-8 – DRILLSHIP MAIN ENGINE MANUFACTURER MAINTENANCE

APPENDIX G-9 – THIRD PARTY FLOWBACK BOILER

APPENDIX G-10 – SPECIFICATION SHEETS: SUPPLY BOAT

APPENDIX G-11 – ANCHOR HANDLING BOAT

APPENDIX G-12 – SPECIFICATION SHEETS: TUG

APPENDIX G-13 – SPECIFICATION SHEETS – BARGE

APPENDIX G-14 – TANKS 4.09 OUTPUT FOR CONDENSATE TANKS

APPENDIX G-15 – SPECIFICATION SHEETS – STIMULATION VESSEL

APPENDIX G-16 – SPECIFICATION SHEETS – WELL EVALUATION VESSEL

APPENDIX G-17 – TANKS 4.09 OUTPUT FOR ANCHOR BOAT TANKS

APPENDIX G-18 – MSDS OF ULTRA LOW SULFUR DIESEL
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LIST OF TABLES

Table 1-1. Location of Lease Blocks Relative to Nearest Class I Areas 7

Table 1-2. Project Potential-to-Emit (PTE) of Project 9

Table 1-3. Summary of Emission Units on the Drillship 11

Table 1-4. Summary of Temporary Third Party Emission Sources on the Drillship 13

Table 1-5. Summary of Emission Units on the Supply Boats 13

Table 1-6. Summary of Emission Units on the Anchor Handling Boats 15

Table 1-7. Summary of Emission Units on the Stimulation Vessel 16

Table 1-8. Summary of Emission Units on the Tug Boats and Barges 16

Table 1-9. Summary of Emission Units on the Well Evaluation Vessel 17

Table 4-1. NSPS Subpart Kb Applicability Determination for Fuel Storage Tanks 69

Table 4-2. Applicable Engines Subject to Subpart IIII 72

Table 4-3. Emergency Generator Offset Requirements 73

Table 4-4. Emergency Generator Residual Emissions 74

Table 5-1. Ranks of Technologies Feasible for Main Engines 87

Table 5-2. Ranks of Technologies Feasible for Emergency Generators 89

Table 5-3. Ranks of Technologies Feasible for Emergency Air Compressor Engine 92

Table 5-4. Ranks of Technologies Feasible for Diesel Fired Engines 97

Table 5-5. Ranks of Technologies Feasible for Pumps on Stimulation Vessel 99

Table 5-6. Proposed NOX BACT Emission Limits 102

Table 5-7. Ranks of Technologies Feasible for Main Diesel Engines 105

Table 5-8. Ranks of Technologies Feasible for Emergency Engine 106

Table 5-9. Ranks of Technologies Feasible for Emergency Air Compressor Engine 108

Table 5-10. Ranks of Technologies Feasible for the Third Party Engines 109

Table 5-11. Ranks of Technologies Feasible for Pumps on Stimulation Vessel 112
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Table 5-12. Proposed CO & VOC BACT Emission Limits 113

Table 5-13. Ranks of Technologies Feasible for Main Diesel Engines 117

Table 5-14. Ranks of Technologies Feasible for the Emergency Diesel Engine 118

Table 5-15. Ranks of Technologies Feasible for the Emergency Diesel Engine 120

Table 5-16. Ranks of Technologies Feasible for the Third Party Engines 121

Table 5-17. Ranks of Technologies Feasible for the Pumps on Stimulation Vessel 124

Table 5-18. Paint Application and Transfer Efficiencies 127

Table 5-19. Ranks of Technologies Feasible for the Welding Operations 128

Table 5-20. Proposed PM/PM10/PM2.5 BACT Emission Limits 129

Table 5-21. Proposed VOCBACT Emission Limits 132

Table 5-22. Proposed CO2e BACT Emission Limits 138
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1. INTRODUCTION

Anadarko is proposing to conduct exploratory drilling, completion, and associated maintenance 

activities (the proposed project) on the Outer Continental Shelf (OCS) of the Eastern Gulf of Mexico 

(EGOM). The proposed project activity will consist of three phases – (1) the drilling phase, (2) the 

well completion phase, and (3) production well maintenance (remedial well-work) phase. The 

proposed project will be conducted over a period of five years, with the proposed operation of 

approximately 200 days per year. As specified in the application, Anadarko requested operating 

limit in terms of fuel consumption in lieu of operating time restriction. With the submittal of 

application, Anadarko is applying for a pre-construction permit and a Title V operating permit.

1.1. LOCATION OF THE PROPOSED PROJECT

The proposed project is planned to be conducted within a set of lease blocks available for 

exploratory drilling using a dynamically positioned Diamond Offshore Drilling, Inc. (Diamond)

BlackHornet drillship and associated support vessels in the EGOM, east of the 87.5 degree longitude. 

The available lease blocks (i.e., the “wedge”) in the EGOM are identified by a boundary line within 

the map presented in Figure 1-1. Within the wedge, there are both active lease blocks (currently 

leased or available for lease) and lease blocks that could potentially be available for lease by the 

Bureau of Ocean Energy Management (BOEM) in the future. The area within the boundary line 

identified as the “wedge” as shown in Figure 1-1, is bounded by the following limits:

1. The 87.5 longitude line to the west (Environmental Protection Agency Jurisdiction);

2. The 86.88 longitude line to the east (Military Mission Line);

3. The limit of 100 miles to the shore in the BOEM Central Planning area; and

4. The limit of 125 miles to the shore in the BOEM Eastern Planning area

Anadarko has identified all lease blocks currently available for the proposed project in the EGOM 

within the “wedge” and has determined which of these lease blocks are closest to Class I areas in the 

vicinity of 300 kilometers (i.e., Breton National Wildlife Refuge [Breton NWR], St. Marks National 

Wildlife Refuge [St. Marks NWR], and Bradwell Bay Wilderness Area). Also, the distance between 

these blocks and the boundary separating inner OCS and outer OCS is provided in the Table 1-1 

below. Table 1-1 also presents the direction and approximate distance to the Class I area and the 

corresponding Federal Land Managers (FLM) for each Class I area. A map showing the location of 

worst-case lease blocks relative to the nearest Class I areas and surrounding onshore areas is 

provided in Figure 1-1. 

Table 1-1. Location of Lease Blocks Relative to Nearest Class I Areas

Desoto 

Canyon 

Lease 

Block

Nearest 

Class I Area 

(State) Direction Distance (km)

Federal Land 

Manager

Distance 

From The 

OCS 

Boundary 

(km)

141 Breton NWR 

(LA)

NW 167 U.S. Fish & Wildlife 

Service (FWS)

95

149 St. Marks NWR 

(FL)

NE 285 U.S. Fish & Wildlife 

Service (FWS)

101

149

Bradwell Bay 

Wilderness 

(FL)

NE 281

U.S. Forest Service 

(FS) 101
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1.2. AIR PERMITTING AND SUMMARY OF REGULATORY REQUIREMENTS

The drillship used for the proposed project activities will qualify as an OCS source, as defined in 40 

CFR 55.2 as follows:

“OCS source means any equipment, activity, or facility which:

(1) Emits or has the potential to emit any air pollutant;

(2) Is regulated or authorized under Outer Continental Shelf Lands Act (“OCSLA”) (43 U.S.C. §1331 et 

seq.); and 

(3) Is located on the OCS or in or on waters above the OCS.

This definition shall include vessels only when they are:

(1) Permanently or temporarily attached to the seabed and erected thereon and used for the purpose of 

exploring, developing or producing resources therefrom, within the meaning of section 4(a)(1) of 

OCSLA (43 U.S.C. §1331 et seq. ); or

(2) Physically attached to an OCS facility, in which case only the stationary sources aspects of the 

vessels will be regulated.”

Therefore, when Anadarko will be conducting the proposed project, it will be considered an OCS 

source and will be subject to the requirements of 40 CFR 55. In addition, when a support vessel is 

attached to an OCS source, the stationary source aspects of that support vessel will also be regulated 

as an OCS source. 

Per 40 CFR 55.3(a), all OCS sources located in the EGOM are regulated by the OCS Air Regulations 

codified under 40 CFR 55. As the regulatory authority over the EGOM has not been delegated 

through the requirements of 40 CFR 55.11(j), the proposed OCS source falls under the regulatory 

jurisdiction of the United States Environmental Protection Agency (U.S. EPA) and U.S. EPA Region 4 

will issue the applicable permits and implement and enforce the requirements of 40 CFR 55. As the 

proposed project activities will be carried out beyond 25 miles of the nearest State’s seaward 

boundary, it will be outside of the corresponding state and local regulatory authority.

As an OCS source subject to the requirements of 40 CFR 55, the proposed source will need to comply 

with 40 CFR 55.13(d) which specifies that the PSD program (codified under 40 CFR 52.21), applies 

to OCS sources located beyond 25 miles of States’ seaward boundaries. The PSD program is a preconstruction permitting program that regulates emissions from “major” sources of regulated air 

pollutants. Further, as specified in 40 CFR 55.2, the emissions from vessels servicing or associated 

with an OCS source shall be considered direct emissions from such a source while at the source, and 

while en route to or from the source when within 25 miles of the source, and shall be included in the 

“potential to emit” (PTE) for an OCS source, when considered for complying with the requirements 

of 40 CFR 55.13. 

An OCS source is considered PSD major if PTE of any PSD-regulated pollutant exceed the major 

source threshold of 250 tons per year (tpy). The PSD program regulates the emissions of all criteria 

pollutants and several non-criteria pollutants such as total reduced sulfur compounds, sulfuric acid 

mist, and fluorides (not including hydrogen fluoride). 

The proposed potential to emit (PTE) of criteria pollutants and HAPs for the project are summarized 

in Table 1-2. The proposed project will be subject to requirements of the PSD program since it is

classified as a major source. As shown in Table 1-2, total particulate matter (PM), particulate matter 

with an aerodynamic diameter less than 10 microns (PM10), particulate matter with an aerodynamic 

diameter less than 2.5 microns (PM2.5), nitrogen oxides (NOX), carbon monoxide (CO), volatile 
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organic compounds (VOC), and greenhouse gases (GHG) exceed their respective Significant Emission 

Rates (SER). Hence, the Best Available Control Technology (BACT) review for all air emission 

sources with emissions of these pollutants has been conducted and is included in this permit 

application.

Table 1-2. Project Potential-to-Emit (PTE) of Project 

Pollutant

Project Potential 

to Emit 

Tons/year

Significant 

Emission Rate 

(SER) 

Tons/year

Exceeds

SER?

NOX 1,208 40 Yes

CO 529 100 Yes

PM 35 25 Yes

PM10 32 15 Yes

PM2.5 31 10 Yes

SO2 1 40 No

VOC 120 40 Yes

Pb 0.02 0.6 No

H2SO4 0.03 7 No

GHG 109,692 75,000 Yes

In accordance with 40 CFR 52.21(i)(3), the requirements under 40 CFR 52.21(k), (m), and (o) do not 

apply to a major stationary source or major modification with respect to a particular pollutant, if the 

allowable emissions of that pollutant from the source, or the net increase of that pollutant from the 

modification would not impact a Class I area, would not impact an area where an applicable 

increment is known to be violated, and when the source would be temporary (i.e., less than two (2) 

years of operation). 

The proposed project does not meet these criteria and does not qualify for an exemption from 40 

CFR 52.21(k), (m), and (o) as explained in Section 4.2 of this permit application report. Therefore, 

Class II area modeling analysis and additional impact analyses are included in this permit 

application.

Based on the locations of the proposed operations and analysis of project emissions, air quality 

modeling analyses of the impacts on federally protected Class I areas and Class II areas have been 

performed to demonstrate compliance with PSD Class I area and Class II area Increment standards 

and air quality related values (AQRV) thresholds.1 Accordingly, a Class I area and Class II area 

modeling analysis and report has been prepared and is included in Appendix D of this permit 

application report.

 

1 Anadarko’s EGOM Exploratory Project lease blocks are located within 300 kilometers of three federally protected Class I areas in the Southern United States.

 
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Figure 1-1. Anadarko’s EGOM Exploratory Project Lease Blocks in Eastern Gulf of Mexico
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1.3. DESCRIPTION OF EMISSION SOURCES

The proposed project will be conducted using the Diamond BlackHornet drillship and associated 

support vessels. The support vessels include a combination of supply boats (i.e., work boats and/or 

crew boats), an anchor handling boat, tug boats, barges, stimulation vessels, and well evaluation vessels. 

The anchor handling boat will not be used to set anchors while on site. Hence, it was treated as a Supply 

Boat in this application. Supply boats will be used to transport personnel and supplies to the drillship, 

as required for conducting the project activities. The tug boats, barges, stimulation vessels, and well 

evaluation vessels will be utilized under various operating scenario as described in Section 3 of this 

application.

The different support vessels will be used interchangeably depending on availability, and therefore it is 

not known which specific support vessel will be available during the proposed project operations. To 

accommodate this uncertainty, Anadarko selected the highest emitting vessels in each category of the 

support vessels to develop Potential to Emit (PTE) calculations. Similarly, Anadarko will utilize various 

third party equipment (e.g., internal combustion engines, flowback boiler, boom flare, and condensate 

storage tanks,) on the drillship and/or support vessels during various operating scenarios as described 

in Section 3 of this application. The exact specifications of third party equipment to be utilized over the 

duration of the proposed project are currently unknown to Anadarko. 

Air pollutant emissions generated from the project include the criteria pollutants of NOX, CO, PM, PM10,

PM2.5, SO2, VOC, and GHGs. These emissions are primarily released from the combustion of diesel fuel in 

the internal combustion engines and a boiler, storage tanks, and miscellaneous activities. 

1.3.1. Emission Sources

The emission sources on the BlackHornet drillship primarily consist of internal combustion engines, 

storage tanks, mud degasser, dust collectors, diesel fuel lines, welding, and painting. The emission 

sources on the support vessels primarily consist of internal combustion engines, storage tanks, and 

diesel fuel lines. Several third party temporary emission sources (e.g., internal combustion engines, 

flowback boiler, boom flare, and condensate storage tanks) will be utilized on the drillship and/or 

support vessels per project requirements. Tables 1-3 through 1-9 present a summary of the emission 

units proposed for this project. 

Table 1-3. Summary of Emission Units on the Drillship

EPN

Emission Unit 

Description

# of 

units Model Rating or Capacity

Fuel 

Type or 

Contents

DR-ME-01

to

DR-ME-06

Main Propulsion Electrical 

Generator Engines or Main 

Engines

(#1 to #6) 6

HYUNDAI-HiMSEN, 

9H32/40 6,035 HP

Ultra Low 

Sulfur 

Diesel 

(ULSD)

DR-ME-07

DR-ME-08

Main Propulsion Electrical 

Generator Engines or Main 

Engines 2

HYUNDAI-HiMSEN, 

18H32/40V 12,069 HP ULSD
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EPN

Emission Unit 

Description

# of 

units Model Rating or Capacity

Fuel 

Type or 

Contents

(#7 and #8)

DR-GE-01 Emergency Generator 1

Cummins 

QSK60DMGE 2,547 HP ULSD

DR-LB-01

to

DR-LB-06

Life Boat Engines

(#1 TO #6) 6 SIYANG 485-J 41 HP ULSD

DR-AC-01 Emergency Air Compressor 1 HATZ 2M41 39 HP ULSD

DR-FR-01 Fast Rescue Craft 1 SABB-L4 Turbo 55 HP ULSD

DR-FT-01

No. 1 Fuel Oil Storage Tank 

(Port) 1

-- 657

M3 ULSD

DR-FT-02

No. 1 Fuel Oil Storage Tank 

(Starboard) 1

--

657

M3

ULSD

DR-FT-03

No. 2 Fuel Oil Storage Tank 

(Port) 1

--

1485

M3

ULSD

DR-FT-04

No. 2 Fuel Oil Storage Tank 

(Starboard) 1

--

1485

M3

ULSD

DR-FT-05

No. 3 Fuel Oil Storage Tank 

(Port) 1

--

1439

M3

ULSD

DR-FT-06

No. 3 Fuel Oil Storage Tank 

(Starboard) 1

--

1439

M3

ULSD

DR-FT-07

No. 1 Fuel Oil Settling Tank 

(Starboard) 1

--

71

M3

ULSD

DR-FT-08

No. 2 Fuel Oil Settling Tank 

(Port) 1

--

71

M3

ULSD

DR-FT-09

No. 1 Fuel Oil Servicing 

Tank (#1 E/R) 1

--

31

M3

ULSD

DR-FT-10

No. 2 Fuel Oil Servicing 

Tank (#1 E/R) 1

--

31

M3

ULSD

DR-FT-11

No. 1 Fuel Oil Servicing 

Tank (#2 E/R) 1

--

31

M3

ULSD

DR-FT-12

No. 2 Fuel Oil Servicing 

Tank (#2 E/R) 1

--

31

M3

ULSD

DR-FT-13

No. 1 Fuel Oil Servicing 

Tank (#3 E/R) 1

--

35

M3

ULSD

DR-FT-14

No. 2 Fuel Oil Servicing 

Tank (#3 E/R) 1

--

35

M3

ULSD

DR-FT-15 Fuel Oil Over Tank 1 -- 46 M3 ULSD

DR-FT-16 Fuel Oil Leak Tank 1 -- 23 M3 ULSD

DR-FT-17

DR-FT-18 Helicopter Fuel Tanks 2

--

2,900 Liter Jet Fuel

DR-DC-01

DR-DC-02

DR-DC-03 Dust Collector 3

--

26

M3/

Min --
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EPN

Emission Unit 

Description

# of 

units Model Rating or Capacity

Fuel 

Type or 

Contents

DR-VG-01 Mud Degasser Vent 1 -- -- -- --

DR-FE-01 Drillship Fugitive Emissions -- -- -- -- --

DR-PO-01 Painting Operations -- various -- -- --

DR-WO-01 Welding Operations -- various -- -- --

Table 1-4. Summary of Temporary Third Party Emission Sources on the Drillship

EPN

Emission Unit 

Description

# of 

units Model Rating or Capacity

Fuel 

Type or 

Content

s

DR-TP-01 

and 

DR-TP-02 Third Party Engines 2

Various - EPA Tier 

II Certified ≤ 860 HP ULSD

DR-TP-03 to 

DR-TP-11 Third Party Engines 9

Various - EPA Tier 

II Certified ≤ 300 HP ULSD

DR-TP-12 to

DR- TP- 16

Third Party Well Evaluation 

Engines 5 Detroit Diesel ≤ 140 HP ULSD

DR-TP-17 to 

DR-TP-21 Third Party Engines 5

Various - EPA Tier 

II Certified ≤ 126 HP ULSD

DR-TP-22 Flowback Boiler 1 various 8

MMBTU

/Hr ULSD

DR-TP-23 Boom Flare 1 various 60

MMSCF/

Day

Natural 

gas

DR-TP-24

DR-TP-25

DR-TP-26

Well Completion 

Condensate Tanks

(#1 to #3) 3 -- 21,000 Gallons

Condens

ate

Table 1-5. Summary of Emission Units on the Supply Boats

EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel 

Type or 

Contents

SB-ME-01

SB-ME-02

Marine Propulsion Engines 

(#1 and #2) 2

Caterpillar 3516C 

DITA or equivalent 3,004 HP ULSD

SB-TE-01

SB-TE-02

SB-TE-03

Marine Thruster Engines

(#1 to #3) 3

Caterpillar 3508C 

DITA or equivalent 1,100 HP ULSD

SB-GE-01

SB-GE-02

Electrical Generator Engine 

(#1 and #2) 2

Caterpillar C32 DITA

or equivalent 1,047 HP ULSD

SB-GE-03

Emergency Electrical 

Generator #3 1

Caterpillar C9 DITA or 

equivalent 253 HP ULSD

SB-GE-04 ROV Electrical Generator 1 various 475 HP ULSD
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EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel 

Type or 

Contents

SB-DT-01

Vessel's Diesel Fuel Storage 

Tanks #1 Port 1 -- 38,020 Gallons ULSD

SB-DT-02

Vessel's Diesel Fuel Storage 

Tanks #1 Starboard 1 -- 38,020 Gallons ULSD

SB-DT-03

Vessel's Diesel Fuel Storage 

Tank #2 Port 1 -- 38,424 Gallons ULSD

SB-DT-04

Vessel's Diesel Fuel Storage 

Tank #2 Starboard 1 -- 38,424 Gallons ULSD

SB-DT-05

Vessel's Diesel Fuel Storage 

Tank #3 Port 1 -- 42,398 Gallons ULSD

SB-DT-06

Vessel's Diesel Fuel Storage 

Tank #3 Starboard 1 -- 42,398 Gallons ULSD

SB-DT-07

Vessel's Diesel Fuel Storage 

Tank #4 Port 1 -- 42,346 Gallons ULSD

SB-DT-08

Vessel's Diesel Fuel Storage 

Tank #4 Starboard 1 -- 42,346 Gallons ULSD

SB-DT-09

Vessel's Diesel Fuel Storage 

Tank #5 Port 1 -- 6,572 Gallons ULSD

SB-DT-10

Vessel's Diesel Fuel Storage 

Tank #5 Starboard 1 -- 7,340 Gallons ULSD

SB-DT-11

Vessel's Diesel Fuel Storage 

Day Tank #1 Port 1 -- 6,027 Gallons ULSD

SB-DT-12

Vessel's Diesel Fuel Storage 

Day Tank #1 Starboard 1 -- 9,149 Gallons ULSD

SB-DT-13

Vessel's Diesel Fuel Stern 

Thruster Day Tank 1 -- 1,496 Gallons ULSD

SB-DT-14

Vessel's Diesel Fuel 

Overflow Port Storage Tank 1 -- 4,401 Gallons ULSD

SB-DT-15

Vessel's Diesel Fuel 

Overflow Standby Storage 

Tank 1 -- 4,401 Gallons ULSD

SB-FE-01

Work Boat Fugitive 

Emissions -- -- -- --

--

SB-TP-01

SB-TP-02

Well Evaluation Third Party 

Engine (#6 and #7) 2

Caterpillar 3406C or 

equivalent 360 HP ULSD

SB-TP-03

Well Evaluation Third Party 

Crane Motor Engine #1 1

John Deere PE 4045D

or equivalent 62 HP ULSD

SB-TP-04

Well Evaluation Third Party 

Crane Motor Engine #2 1

Cummins B 5.9-C or 

equivalent 130 HP ULSD

SB-TP-05

to SB-TP09Third Party Well Evaluation 

Engines 5 Detroit Diesel ≤ 140 HP ULSD
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Table 1-6. Summary of Emission Units on the Anchor Handling Boats

EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel 

Type or 

Contents

AB-ME-01

AB-ME-02

Marine Propulsion Engine 

(#1 and #2) 2

Caterpillar Model 

3616 7,570 HP ULSD

AB-TE-01

AB-TE-02

AB-TE-03

Thruster Engines

(#1 to #3) 3

Caterpillar Model 

3512B-HD 1,674 HP ULSD

AB-GE-01

AB-GE-02

AB-GE-03

Service Generator Engines 

(#1 to #3) 3

Caterpillar Model 

3412C 716 HP ULSD

AB-GE-04

AB-GE-05

Service Generator Engines 

Crane Dedicated 

(# 4 and #5) 2

Caterpillar Model 

3508B 1,300 HP ULSD

AB-GE-06

Emergency Generator 

Engine 1

Caterpillar Model 

3406C 307 HP ULSD

AB-GE-07

AB-GE-08

Winch Hydraulic Engines 

(#7 and #8) 2 Caterpillar Model C32 1,300 HP ULSD

AB-DT-01

Port Side Double Bottom 

Diesel Fuel Tank #1 1 -- 12,842 Gallons ULSD

AB-DT-02

Starboard Side Double 

Bottom Diesel Fuel Tank #1 1 -- 12,852 Gallons ULSD

AB-DT-03

Center Double Bottom 

Diesel Fuel Tank #1 1 -- 15,706 Gallons ULSD

AB-DT-04

Port Side Double Bottom 

Diesel Fuel Tank #2 1 -- 31,483 Gallons ULSD

AB-DT-05

Starboard Side Double 

Bottom Diesel Fuel Tank #2 1 -- 31,483 Gallons ULSD

AB-DT-06

Port Wing Diesel Fuel Tank 

#1 1 -- 16,321 Gallons ULSD

AB-DT-07

Starboard Wing Diesel Fuel 

Tank #1 1 -- 16,321 Gallons ULSD

AB-DT-08

Port Side Double Bottom 

Diesel Fuel Tank #3 1 -- 27,788 Gallons ULSD

AB-DT-09

Starboard Side Double 

Bottom Diesel Fuel Tank #3 1 -- 27,788 Gallons ULSD

AB-DT-10

Port Wing Diesel Fuel Tank 

#2 1 -- 53,328 Gallons ULSD

AB-DT-11

Starboard Side Double 

Bottom Diesel Fuel Tank #4 1 -- 55,097 Gallons ULSD

AB-DT-12

Starboard Wing Diesel Fuel 

Tank #2 1 -- 38,974 Gallons ULSD

AB-DT-13

AB-DT-14

Port Side Double Bottom 

Diesel Fuel Tank #4 and #5 1 -- 28,138 Gallons ULSD

AB-DT-15 Port Service Diesel Tank 1 -- 13,497 Gallons ULSD
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EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel 

Type or 

Contents

AB-DT-16

Starboard Service Diesel 

Tank 1 -- 13,497 Gallons ULSD

AB-DT-17 Port Diesel Settling Tank 1 -- 13,724 Gallons ULSD

AB-DT-18

Starboard Diesel Settling 

Tank 1 -- 13,724 Gallons ULSD

AB-DT-19 Diesel Overflow Tank 1 -- 3,694 Gallons ULSD

AB-FE-01

Anchor Handling Boat 

Fugitive Emissions -- -- -- -- --

Table 1-7. Summary of Emission Units on the Stimulation Vessel

EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel 

Type or 

Contents

SV-ME-01

SV-ME-02

Stimulation Vessel Main 

Propulsion Engines

(#1 and #2) 2 various 3,634 HP ULSD

SV-BT-01 Bow Thruster Engine 1 various 1,675 HP ULSD

SV-DD-01 Bow Drop-Down Engine 1 various 1,200 HP ULSD

SV-ST-01 Stern Thruster Engine 1 various 1,675 HP ULSD

SV-PE-01 

through

SV-PE-08

Representative 

Pump Engines

(#1 to #8) 8 various 2,250 HP ULSD

SV-GE-01 

SV-GE-02 Generators (#1 and #2) 2 various 1,220 HP ULSD

SV-GE-03 

SV-GE-04 Generators (#3 and #4) 2 various 805 HP ULSD

Table 1-8. Summary of Emission Units on the Tug Boats and Barges

EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel Type 

or 

Contents

TB-ME-01

TB-ME-02

TB-ME-03

Tug Boat Main Engines (#1 

to #3) 3 various 2,200 HP ULSD

TB-GE-01

TB-GE-02

Tug Generator Engine 

(#1 and #2) 1 various 174 HP ULSD

BG-LP-01

BG-LP-02

BG-LP-03

Barge Electrical Generators

(#1 to #3) 3 various 456 HP ULSD
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Table 1-9. Summary of Emission Units on the Well Evaluation Vessel

EPN Emission Unit Description

# of 

units Model

Rating or 

Capacity

Fuel 

Type or 

Contents

WE-ME-01

WE-ME-02

Well Evaluation Vessel Main 

Engines (#1 and #2) 2 various 2,250 HP ULSD

WE-AE-01

WE-AE-02

Well Evaluation Vessel Axillary 

Engines (#1 and #2) 2 various 1,468 HP ULSD

WE-GE-01 Emergency Generator #1 1 various 272 HP ULSD

WE_GE-02 Emergency Generator #2 1 various 212 HP ULSD

WE-GE-03 Generator Engine #3 1 various 200 HP ULSD

1.4. CONTENTS OF THE APPLICATION ADDENDUM

This permit application is being submitted in accordance with 40 CFR 55.6(a)(1) and satisfies all 

applicable requirements of 40 CFR 52.21. This application includes the following:

Section 2 Process Description: contains a brief description of drilling and completion days; 

Section 3 Emission Calculations: contains the discussion of emission calculation methodology for all 

additional sources and operations in this application;

Section 4 Regulatory Applicability Analysis: contains the air regulatory applicability analysis for all 

emission sources related to the proposed drilling operations;

Section 5 BACT Analysis: contains the BACT review for all emission sources in this application;

Section 6 Part 71 forms: contains the Part 71 forms; and

Appendices
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2. PROCESS DESCRIPTION

This section describes the process involved in conducting the exploratory drilling, well completion, and 

production well maintenance operations, and associated source of air emissions as represented in this 

permit application. 

2.1. EXPLORATORY DRILLING DESCRIPTION

The Diamond BlackHornet drillship is a dynamically-positioned drillship that is designed for operation 

in the deep water (i.e., 10,000 feet of water or below.) As a dynamically-positioned drillship, the 

BlackHornet maintains its position over the desired location by using computer-controlled thruster 

propellers rather than anchors and is not required to be attached to the seabed in order to establish or 

maintain its position like a traditional moored semi-submersible drillship. 

The dynamically positioned drillship transits to a particular drilling location and performs a bottom 

survey with a remotely operated vehicle (ROV) to mark the spud-in location. The well is then spudded 

to initiate drilling operations at the site. To accomplish this, a short length of pipe called the jet pipe is 

run to the seabed floor using a smaller multi-purpose pipe called the drill pipe. The drill pipe is run 

through the jet pipe, terminating with a drill bit at the end. The drill bit is spaced so that it extends just 

outside the jet pipe a few inches. 

Seawater is pumped through the bit as the jet pipe is lowered into the seabed until approximately 12

feet of the end of the jet pipe remains above the seabed floor. The drill pipe is then released from the jet 

pipe so that the drill bit can be used to drill the exploration well. Seawater or drilling fluid (mud) is 

pumped down the drill pipe out the bit to clean the hole as the drill bit is rotated with weight put down 

on the formation. Once the drill bit has drilled to a designated depth, the drill bit is retrieved back to 

surface, leaving the jet pipe and a section of hole drilled below the jet pipe. Another pipe called the 

surface casing is then run through the jet pipe and into the open-hole section. Cement is then pumped 

around the outside of the casing to cement it in place. Once surface casing has been set, the blow out 

preventer (BOP) is run.

The BOP is run on pipe called the drilling riser which is connected to the wellbore at the seabed floor. 

This arrangement allows a closed loop system in which fluids pumped through the drill bit return to the 

drillship for reuse. The BOP also serves as a safety device protecting against a well blowout. The drill 

and casing process is then repeated to progress the well to the well objective depth. Casings are run at 

designed intervals according to the subsurface data used to design the well. Each time a casing is run, 

the next section's casing will be smaller in order to fit inside the casing that has just been cemented. 

Once the well objective depth in the potential reservoir is achieved, an evaluation program is carried 

out. This typically involves running a series of wire line tools to measure various properties of the 

formation. Depending upon the evaluation results, the well will either be sidetracked to another 

objective, abandoned, or a casing set. Once the exploratory work scope is completed, the well is plugged 

with cement and/or mechanical tools. The BOP is retrieved along with the riser and an ROV bottom 

survey is performed. This will complete the exploratory drilling activity for one location.
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During the exploratory drilling, several diesel fired internal combustion engines are used to provide 

power for several activities. The main engines on the drillship are utilized to maintain a position of the 

drillship as well as to supply power to the drilling activity. Some of these engines are fixed on the 

drillship (such as main engines, emergency generators, and air compressors etc.) and remaining engines 

are brought onboard as required (i.e., third party engines such as wire line engines, casing units and 

electric line engines etc.). These engines emit criteria pollutants, GHGs, as well as hazardous air 

pollutants (HAPs) due to combustion of diesel fuel. Several diesel fuel storage tanks are located on the 

drillship and these tanks emit VOCs due to variation in ambient temperature (also known as ‘breathing 

losses’) and during fuel loading activity (also known as ‘working losses’). These storage tanks are 

equipped with pumps, flanges, connectors, and/or other miscellaneous devices (also known as fugitive 

components of air emissions) for transferring the fuel from one location to other. The support vessels 

also operate several diesel fired internal combustion engines and fuel storage tanks contributing to air 

pollution. Other miscellaneous air pollution sources during the drilling activity include painting 

operations, mud degassing, and cement and mud mixing operations. Air emissions from these activities 

are described in details in Section 3 of this application. 

2.2. WELL COMPLETION

Once a well has been drilled and evaluated, a decision must be made whether to complete the well or 

plug it. If the well is to be completed, a well head which serves as the pressure-containing equipment 

will be installed subsea where casing strings are suspended and the BOP or subsea tree is connected. 

Production casing is run down the hole and cemented. Once the casing is in place, holes are perforated 

through the casing, cement, and into the reservoir. These holes are made to facilitate material transfer 

between the reservoir and the production casing. Tubing along with the packer is run into the casing. A 

plug is set above the perforations as a barrier between the production casing and the tubing. 

For a gas well, a gravel pack completion assembly is typically installed to reduce the inflow of sand from 

the formation. The formation is perforated through the well casing to allow the expected natural gas 

into the well and then to the surface. During the well completion phase, a sub-sea well head is installed 

on the sea floor and the production tubing, with down-hole control valve, and packer is lowered into the 

finished well (inside the final casing string). 

Thereafter, a production packer and a tubing are installed. Production packers are placed above the 

production zone. The packer isolates the annulus between the tubing and the inner casing and the foot 

of the well. It provides a seal to stop reservoir fluids from flowing up the full length of the casing and 

damaging it. Production tubing plays the role of the main conduit for transporting hydrocarbons from 

the reservoir to surface (or injection material the other way). It runs from the tubing hanger at the top 

of the wellhead down to a point generally just above the top of the production zone. Tubing hanger sits 

on top of the wellhead and serves as the main support for the production tubing. 

A surface-controlled sub-surface safety valve (SCSSV) is installed in the production tubing and is held in 

the open position by a high-pressure hydraulic line from surface contained in a control line that is 

attached to the down-hole control valve's hydraulic chamber and terminated at surface to a hydraulic 

actuator. The high pressure is needed to overcome the production pressure in the tubing upstream of 

the choke on the tree. The SCSSV acts as a safety device in the event of the wellhead/tree/tubing failure. 

During temporary unloading/flowback phase, through portable well testing equipment on a drillship, 
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the hydrocarbons flow up the tubing and are processed through surface well test equipment. The 

hydrocarbons are separated and the gas flared and the liquids are directed to the barge or to the tanks. 

After flowback is completed and the well is cleaned up, the well is secured until flow lines are installed 

to the production facility. 

During the well completion, several diesel fired internal combustion engines are used to provide power 

for different activities. The drillship main engines supply power along with various third party 

equipment to perform different activities. This phase could require use of supply boats, tug boats, 

barges, stimulation vessel, or well evaluation vessel to support the various activities. The different well 

completion scenario and associated sources of air emissions are described in the Section 3. 

2.3. PRODUCTION DESCRIPTION (WELL MAINTENANCE)

After completion activities, the well is brought on production, and the oil and gas is flowed back to the 

production facility for processing and then sent to shore via the sales pipeline. Downhole equipment 

failure or reservoir-related issues (i.e., remedial well-work/maintenance) may require drillship 

intervention to repair and restore production to the well.

The drillship, the support vessels, and/or the stimulation vessel will conduct remedial well-work if 

needed after the well is put in production. The air pollution sources during the well maintenance are 

similar to that of the drilling and the well completion phases. Emissions associated with well 

maintenance phase are lower compared to that of drilling and well completion phases and therefore, 

emissions associated with the well maintenance activities are not separately estimated in this 

application.
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3. EMISSIONS CALCULATIONS

This section presents a summary of the emissions calculation methodologies, emission factors, and 

operating parameter assumptions for estimating emissions from the sources of air pollution on the 

drillship, the supply boats, the stimulation vessel, the well evaluation vessel, and miscellaneous 

activities. The detailed emissions calculations are included in Appendix B of this application.

3.1. ‘EQUIVALENCY’ DETERMINATION

As mentioned previously, Anadarko will operate various emission units for which exact specifications 

are not available at this time due to scheduling and other contractual agreements that will be completed 

in the future. Therefore, Anadarko has proposed the worst case emission units for each category of air 

pollution sources to develop the PTE while maintaining sufficient operational flexibility to provide 

Anadarko the ability to utilize various, ‘equivalent’ operational equipment. Also, Anadarko proposes the 

demonstration of ‘equivalency’ based on the following factors:

Equal or lower mass emissions for each criteria, toxic, and other regulated air pollutants on a shortterm (e.g., lbs/day) and a long-term (e.g., ton/year) basis;

Compliance with applicable regulations (e.g., 40 CFR 60, 40 CFR 63); 

Compliance with applicable certifications (e.g., EPA Tier 2, IMO Tier 2); and

Compliance with applicable BACT requirements identified for representative equipment. 

A list of equipment for which Anadarko is requesting above-mentioned flexibility is provided below.

Third party engines (DR-TP-01 through DR-TP-21)

Supply boats and all associated air pollution sources (all EPNs starting with SB and AB)

Stimulation vessel and all associated air pollution sources (all EPNs starting with SV)

Well evaluation vessel and all associated air pollution sources (all EPNs starting with WE)

Tug boats, barges and all associated air pollution sources (all EPNs starting with TB and BG)

Other miscellaneous sources (such as painting, welding, etc.) as described in this application.

3.2. OPERATING SCENARIOS

Various operating scenarios can occur during the drilling, well completion, and maintenance phases. 

The proposed project can be broadly classified in to six operating scenario. The goal of this classification 

is to represent the worst-case hourly, 24-hour, and annual air emissions for calculating Potential to Emit 

(PTE). The following scenarios were derived for estimating the PTE. 

Worst-case gas well flowback scenario;

Worst-case oil well flowback scenario;

Worst-case stimulation vessel operations scenario;

Well completion third party equipment operations scenario; 

Well evaluation vessel operations scenario; and

Worst-case drilling scenario.
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The proposed emissions sources during each scenario and associated operating parameters are 

provided in Appendix B. The aforementioned operation scenarios will not happen concurrently. Only 

one out of these scenarios OR any ‘equivalent’ combination will be conducted and the resulting 

emissions from activities involved in the scenario will not exceed the worst-case emissions among the 

six scenarios. The drillship and supply boats will also be operating on an as required basis. The 

operation of the aforementioned scenarios will typically involve the following sources as listed below. 

The remainder of this section discusses the short term and long term emission calculation 

methodologies for each equipment, assumptions, proposed operating parameters, and the derivation of 

the fuel based emission factors, if applicable. Appendix B provides a summary of emissions for each 

operating scenario for each criteria pollutant, GHGs, H2SO4, and HAPs.

3.3. DRILLSHIP

The emission calculation methodologies for the air pollution sources on the BlackHornet drillship are 

discussed below.

3.3.1. Main Engines (DR-ME-01 through DR-ME-08)

The drillship consists of eight main engines. Six of the eight engines are identical HYUNDAI-HiMSEN, 

9H32/40 6,035 HP diesel-fired engines. The other two engines are HYUNDAI-HiMSEN, 18H32/40V 

12,069 HP diesel-fired engines. The specification sheets for these engines are provided in Appendix G-1.

Emission Factors – The sources of emission factors used to estimate emissions for each of the eight 

engines are summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines –CO, VOC, 

and HAP emissions estimates for the eight main engines are based on AP-42, Section 3.4 

emission factors (Table 3.4-1, Table 3.4-2, and Table 3.4-3). Non-methane VOC emission factor 

has been taken as 91% of the total organic compounds (TOC) emission factor. 

NSPS Subpart IIII- Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines – Particulate Matter and NOX Emission estimates for the eight main 

engines are based on the emission standards specified in 40 CFR 60.4204(c) for non-emergency 

stationary CI engines with a displacement of greater than or equal to 30 liters per cylinder and 

installed after January 1, 2012 and before January 1, 2016 where maximum engine speed is 

greater than 130 rpm but less than 2,000 rpm. Furthermore, based on AP-42 guidance, all of the 

particulate matter is assumed to be less than 1 μm. Therefore, it is assumed PM2.5 = PM10 = PM.

EPA Guidance Documents – Lead emission factor is obtained from EPA’s guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to unavailability of emission factors. 

EPA Regulations – CO2, CH4, and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 
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Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel 

fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the 

fuel is oxidized to sulfuric acid (H2SO4) mist based on Section 4.1.1 of Draft Regulatory Impact 

Analysis: Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. 

Emissions of Hydrogen sulfide (H2S), total reduced sulfur (TRS), and reduced sulfur compounds 

resulting from sulfur content in the fuel are negligible.

Fuel Based Emission Factor Derivation:

Since the main engines operate in a group, the PTE is calculated for the group of main engines based on 

the maximum power requirements for all operating scenario. Based on the specifications sheet 

provided, all of these engines have a break specific fuel consumption (BSFC) of 179 g/kW-hr. Since the 

main engines are the highest emitters of a pollutant on a lbs of pollutant/cubic meter of fuel consumed 

among the various engines on the drillship, the fuel limits established on the fuel based emission factors 

for the main engines represent the worst case emission scenario. Hence, Anadarko is proposing 

drillship-wide fuel limit derived using the main engine fuel based emission factors (i.e., lbs of pollutant 

per cubic meter of fuel.) These fuel based emission factor calculation is presented in Appendix B. 

Proposed Operating Limits:

Anadarko proposes a drillship-wide fuel cap of 123 cubic meters/day for all the diesel combustion 

sources located on the drillship. This fuel cap is the highest fuel usage of all the six scenarios. The daily 

fuel cap is derived based on the maximum daily power requirement of 576,000 KW.

Also, Anadarko proposes to use 18,438 cubic meters/year fuel for all the diesel combustion sources 

located on the drillship. The annual fuel limit is calculated based on approximately 200 days of 

operation and the power requirement of 86,400,000 KW. However, Anadarko proposes the annual fuel 

limit in lieu of annual operating time limit. In case Anadarko does not consume the proposed annual fuel 

in 200 days, Anadarko proposes to maintain the flexibility of operating more than 200 days as long as 

total fuel consumption is within the proposed limit. The maximum hourly, daily, and annual emissions 

from the main engines are calculated based on the derived fuel based emission factor as described 

below:

Maximum Hourly Emissions – The maximum hourly emissions for the main engines are calculated 

based on the fuel based emission factor and maximum fuel requirement of 5.1 cubic meter of fuel. 

Maximum Daily Emissions – The maximum daily emissions for the main engines are based on the fuel 

based emission factor and maximum fuel requirement of 123 cubic meter of fuel.

Annual Emissions – The annual emissions for the main engines are based on the fuel based emission 

factor and maximum fuel requirement of 18,438 cubic meter of fuel.
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3.3.2. Emergency Generator (DR-GE-01)

The drillship includes one 2,547 HP Cummins QSK60DMGE diesel-fired emergency generator. Air 

emissions are generated as a result of combustion of diesel fuel in the engine. 

Emissions Factors – The sources of emission factors used to estimate emissions for the engine are 

summarized below.

IMO Tier 2 NOX Emission Limits – The NOX, emissions factors are obtained from IMO Tier 2 

Emission Limits since this engine is IMO Tier 2 certified. 

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines –PM VOC, 

and HAP emissions estimates for the emergency generator is based on AP-42, Section 3.4 

emission factors (Table 3.4-1, Table 3.4-2, and Table 3.4-3). Non-methane VOC emission factor 

has been taken as 91% of the TOC emission factor. All of the particulate matter is assumed to be 

less than 1 μm. Therefore, it is assumed PM2.5 = PM10 = PM. 

Manufacturer Specification – The CO emissions factors are obtained from the manufacturer’s 

specification sheet. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R98-006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as 

a surrogate for distillate oil-fired engines due to lack of emission factors. 

EPA Regulations – CO2, CH4, and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel 

fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the 

fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control 

of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, 

TRS, and reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions from the emergency generator are calculated as 

described below:

Maximum Hourly Emissions – The maximum hourly emissions for the emergency generator are 

calculated based on one hour of operation. 

Maximum Daily Emissions – The maximum daily emissions for the emergency generator based on 2 

hrs/day operation.

Annual Emissions – The annual emissions for the emergency generator calculated based on annual 

operation of 100 hours. 
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Proposed Operating Limits:

Since this emission unit will be a part of drillship-wide fuel consumption limit, no separate fuel limit is 

required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.3.3. Emergency Air Compressor (DR-AC-01)

The drillship consists of one 39 HP HATZ 2M41 diesel-fired emergency air compressor, which is EPA 

Tier 2 certified. The specification sheet is provided in Appendix G-1. Emissions are generated as a 

result of combustion of diesel fuel in the engine. 

Emissions Factors – The sources of emission factors used to estimate emissions for each of the 

emergency air compressor engine is summarized below.

40 CFR 89 Control Of Emissions From New And In-Use Nonroad Compression-Ignition 

Engines –Particulate matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the 

third party engines are based on 40 CFR 89 Tier 2 exhaust emission standards. NOX emission 

factors are assumed to be equal to the NMHC + NOX emission factor. Based on footnote b of AP42 Chapter 3, Table 3.3-1, all PM is assumed to be < 1 μm. Therefore, it is assumed PM2.5 = PM10

= PM. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – VOC and HAP Emissions are 

based on AP-42 Section 3.3 emission factors (Table 3.3-2.) An average BSFC of 7,000 Btu/HP-hr 

has been used to convert emission factors from lb/MMBtu to lb/HP-hr.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R98-006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as 

a surrogate for distillate oil-fired engines due to lack of emission factors. 

EPA Regulations – CO2, CH4, and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel 

fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the 

fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control 

of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, 

TRS, and reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions from the emergency air compressor are calculated as 

described below:
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Maximum Hourly Emissions – The maximum hourly emissions for the air compressor are 

calculated based on 0.5 hours of operation. 

Maximum Daily Emissions – The maximum daily emissions for the air compressor calculated 

based on 0.5 hours of operation.

Annual Emissions – The annual emissions for the air compressor calculated based on 100 

hours of operation. 

Proposed Operating Limits:

Since this emission unit will be a part of drillship-wide fuel consumption limit, no separate fuel limit is 

required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.3.4. Life Boat Engines (DR-LB-01 through DR-LB-06)

The drillship consists of six SIYANG 485-J 41 HP, diesel-fired life boat engines. The specification sheet is 

provided in Appendix G-1. The life boats will be operated during emergency situations, drills and 

periodically operated for maintenance checks. Emissions are generated as a result of combustion of 

diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for the engines are 

summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – Particulate matter (PM, PM10, 

and PM2.5), NOX, VOC, CO, and HAP emissions estimates for the diesel-fired life boat engines are 

based on AP-42, Section 3.3 emission factors. Based on AP-42 guidance, all of the particulate 

matter is assumed to be less than 1 μm. Therefore, it is assumed PM2.5 = PM10 = PM. All of the 

TOC is assumed to be VOC. TOC emission factor has been calculated as the sum of exhaust and 

crankcase emission factors. An average BSFC of 7,000 Btu/HP-hr has been used to convert 

emission factors from lb/MMBtu to lb/HP-hr.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R98-006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as 

a surrogate for distillate oil-fired engines due to lack of emission factors. 

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel 

fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the 

fuel is oxidized to sulfuric acid (H2SO4) mist based on Section 4.1.1 of Draft Regulatory Impact 
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Analysis: Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. 

Emissions of Hydrogen sulfide (H2S), total reduced sulfur (TRS), and reduced sulfur compounds 

resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions from the life boat engines are calculated as described 

below:

Maximum Hourly Emissions – The maximum hourly emissions for the life boats are calculated

based on 1 hour of operation per engine. 

Maximum Daily Emissions – The maximum daily emissions for the life boats are calculated 

based on 1 hour of operation per day per engine.

Annual Emissions – The annual emissions for the life boats are calculated based on 100 hours 

of annual operation per engine. 

Proposed Operating Limits:

Since these emission units will be a part of drillship-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits. 

3.3.5. Fast Rescue Craft (DR-FR-01)

The drillship consists of one EPA Marine Tier 2 fast rescue craft with 55 HP power rating and SABB-L4 

Turbo engine. The specification sheet for the representative engine is provided in Appendix G-1. 

Emissions are generated as a result of combustion of diesel fuel used in the engine. 

Emissions Factors – The sources of emission factors used to estimate emissions for the engine are 

summarized below.

40 CFR 89 Control Of Emissions From New And In-Use Nonroad Compression-Ignition Engines 

–Particulate matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the third party 

engines are based on 40 CFR 89 Tier 2 exhaust emission standards. NOX emission factors are 

assumed to be equal to the NMHC + NOX emission factor. Based on footnote b of AP-42 Chapter 3, 

Table 3.3-1, all PM is assumed to be < 1 μm. Therefore, it is assumed PM2.5 = PM10 = PM.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – VOC and HAP Emissions are based 

on AP-42 Section 3.3 emission factors (Table 3.3-2.) An average BSFC of 7,000 Btu/HP-hr has been 

used to convert emission factors from lb/MMBtu to lb/HP-hr.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-
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006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors. 

Mass Balance – Anadarko proposed the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

and assuming that 98 percent of sulfur in the fuel will be converted to SO2 and 2 percent of the 

sulfur in the fuel will be converted to H2SO4 based on U.S. EPA guidance document.

The maximum hourly, daily, and annual emissions from the main engines are calculated as described 

below:

Maximum Hourly Emissions – The maximum hourly emissions for the fast rescue craft are 

calculated based on one hour operation.

Maximum Daily Emissions – The maximum daily emissions for the fast rescue craft are calculated 

based on 1 hour/day operation.

Annual Emissions – The annual emissions for the fast rescue craft are calculated based on 100 

hours per year operation.

Proposed Operating Limits:

Since this emission unit will be a part of drillship-wide fuel consumption limit, no separate fuel limit is 

required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.3.6. Mud degassing Vent (DR-VG-01)

Drilling mud is used in the drilling process to cool and lubricate the drill bit. When the drilling mud 

returns to the surface, it may contain entrained hydrocarbons from the well. On reaching the surface, 

off-gassing occurs, leading to VOC emissions. Also during this process, Anadarko may emit trace 

amounts of H2S during non-routine conditions that could be encountered while drilling. At this juncture, 

Anadarko cannot reasonably quantify the H2S amount emitted or anticipate how much H2S, if any, will 

be encountered during this operation as this would only occur during non-routine, upset conditions. As 

such, H2S emitted during mud degassing operation would be considered an upset condition which is not 

required to be permitted under PSD (40 CFR 52.21) and Title V (40 CFR 71) regulations.

Emissions Factors - The emission factor sources used in the development of emissions estimates for the 

mud degassing operations are summarized below. 

MMS Guidance Document – Emission factors for total hydrocarbon (THC) emissions during 

degassing for synthetic-based muds, and the volume percent composition of the THC emissions 

were obtained based on a study commissioned by the formers Mineral Management Services 

(MMS) that is currently the Bureau of Ocean Energy Management (BOEM). Specifically, the 
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emission factors and volume % speciation were obtained from Year 2005 Gulfwide Emission 

Inventory Study, conducted by the Eastern Research Group, Inc.2

Operating Parameters - The maximum hourly, daily and average annual emissions from the 

mud degassing operations are calculated based on the following operating parameters.

Maximum Hourly/Daily Emissions – Based on the expected throughputs of synthetic-based 

muds for the proposed operations and based on the emission factors provided in the guidance 

document referenced above, a weighted average THC (lb/day) emission factor has been 

developed. Also, the volume % composition obtained from the MMS guidance document have 

been converted to weight % based on molecular weights of the components. 

As shown in Appendix B, maximum hourly speciated emissions are calculated based on the 

weighted average THC emission factor and weight % of the speciated components, using 24 

hours of operation per day. Maximum hourly VOC emissions are obtained as the sum of all 

speciated hourly emissions except methane and ethane. 

Annual Emissions – Annual emissions for the mud degassing operation have been estimated 

similar to the maximum hourly emissions. Annual emissions are calculated using pound per day 

emission factors and a worst-case 4,800 hours of operation per year.

3.3.7. Dust Collectors (DR-DC-01 through DR-DC-03)

Mud and cement mixing operations on the drillship are controlled by three National Oilwell Varco dust 

collectors. The specification sheet for these dust collectors is provided in Appendix G-1.

Emissions Factors - The emission factor sources used in the development of emissions estimates for the 

dust collectors are summarized below.

AP-42, Section 11.12. Concrete Batching – Particulate matter (PM, PM10, and PM2.5) emissions 

estimates for the cement mixing operations are based on the controlled emission factor provided in AP42, Section 11.12 Concrete Batching emission factors (Table 11.12-2). 

Operating Parameters – The maximum hourly, daily and annual emissions from the dust collectors are 

calculated based on the following operating parameters. 

Maximum Hourly Emissions – Maximum hourly emissions are estimated based on 150 tons/hr of 

maximum process rate.

Maximum Daily Emissions – Maximum daily emissions are estimated based on 150 tons/hr of 

maximum process rate and 24 hrs/day operation.

Annual Emissions – Maximum annual emissions are estimated based on 150 tons/hr of maximum 

process rate and 4,800 hrs/year operation.

 

2 Wilson, Darcy, Richard Billings, Regi Oomen, and Roger Change; Eastern Research Group, Inc.; Year 2005 Gulfwide Emission Inventory 

Study; US Department of Interior, Minerals Management Service; Gulf of Mexico OCS Region, New Orleans, December 2007.
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3.3.8. Storage Vessels (DR-FT-01 through DR-FT-18)

The drillship includes following fuel storage tanks:

Diesel fuel storage vessels (16) – various capacities

Helicopter fuel storage tanks (2) – 2,900 gallons each

Emissions from all storage vessels on the Drillship have been estimated using EPA’s TANKS 4.0.9d 

(TANKS) program. Default TANKS properties for distillate fuel oil No. 2 were used to model the contents 

of the diesel tanks. Default speciation profile and physical and chemical properties for Jet Naphtha (JP4) in TANKS 4.09d program are used to model the contents of the helicopter fuel storage tanks. Refer 

Appendix G-4 for Tanks program output.

The maximum diesel fuel usage for the Drillship is 123 cubic meters/day. To represent conservative 

scenario, a throughput equal to twice the fuel usage restriction. It was assumed that all fuel will be 

loaded into the largest tank DR-DT-04 to calculate the maximum total tank VOC emissions (tpy) on the 

drillship.

Maximum hourly emissions was calculated using EPA TANKS 4.09d program for the month of June, since 

June results in the highest daily emissions.

3.3.9. Drillship Fugitive Emissions (DR-FE-01)

The fugitive emissions on the drillship occur from the diesel fuel lines and associated components. 

Emissions from the lines are based on an estimated number of components and heavy oil emission 

factors from Table 2-4 of the EPA Protocol for Equipment Leak Emission Estimates. Since the exact 

component counts were not available, component count were conservatively estimated using 

engineering judgments and based on the component counts for the other drillship currently leased by 

Anadarko. 

Operating Parameters – The maximum hourly, daily and annual fugitive emissions are calculated 

based on the following operating parameters. 

Maximum Hourly Emissions – Maximum hourly emissions are estimated based on one hour 

operation.

Maximum Daily Emissions – Maximum daily emissions are estimated based on 24 hrs/day

operation.

Annual Emissions – Maximum annual emissions are estimated based on 4,800 hrs/year operation.

3.3.10. Painting Operations (DR-PO-01)

As part of maintenance activity, painting happens on the BlackHornet drillship. PM/PM10/PM2.5, VOC, 

and HAP emissions are calculated based on the average thinner usage, average primer usage, 30% air

assisted spray transfer efficiency and paint/primer usage of maximum 40 gal/day and thinner usage of 
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maximum 10 gal/day. Total emissions are estimated based on the sum of worst-case primer and 

thinner components. 

Anadarko proposes to maintain the flexibility of using the aforementioned air assisted or an airless 

spray gun with a 50% spray transfer efficiency (i.e., more efficient in transferring the material.) 

The PTE of PM/PM10/PM2.5, VOC, and HAP were estimated for air assisted spray gun operations to 

represent the worst case scenario. The specification sheet for the airless and air assisted spray guns

along with the MSDS sheets for the paints, primers and thinners are provided in Appendix G-6. Refer to 

Appendix B for assumptions, material usage limits, and detailed calculations.

Proposed Operating Limits:

Anadarko proposes annual limits of 5,200 gallons and 1,300 gallons for paints (i.e., any combination of 

paints, base, primer etc.) and thinner, respectively. Anadarko will maintain adequate records to comply 

with proposed daily and annual operation limits.

3.3.11. Welding Operations (DR-WO-01)

Anadarko proposes to carry out welding operations as part of the maintenance activities on the 

drillship. The proposed welding activity will use 80 lbs of welding rods per day, and 200 days per year.

Emissions Factors – Anadarko proposes to use several different types of welding rods. The welding 

rods resulting in maximum emissions are included in the emission calculations in Appendix B. 

Anadarko proposes to maintain a flexibility to utilize any other welding rod as long as the resulting 

emissions are less than the proposed maximum emissions.

AP-42, Section 12.19 Electric Arc Welding – PM10 and HAPs emissions estimates for the proposed 

welding activity are based on AP-42, Section 12.19 emission factors (Table 12.19-1). PM and PM2.5

emissions are assumed to be same as PM10.

Operating Parameters – The project emissions from the welding operations are calculated based on the 

following operating parameters. 

Maximum Hourly Emissions – Maximum hourly emissions for the welding operations are 

calculated based on 3.33 lbs of welding rod usage per hour.

Maximum Daily Emissions – Maximum daily emissions for the welding operations are calculated 

based on 80 lbs of welding rod usage per day.

Annual Emissions – Maximum annual emissions for the welding operations are calculated based on 

16,000 lbs of welding rod usage per year.

Proposed Operating Limits:

Anadarko proposes annual welding rod usage limit of 16,000 lbs. Anadarko will maintain adequate 

records to comply with proposed daily and annual operation limits.
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3.3.12. Third Party Engines (DR-TP-01 through DR-TP-21)

Various third party engines are required during the drilling and well completion operations. These 

engines are EPA Tier 2 certified engines (except DR-TP-12 and DR-TP-16) and can be grouped in the 

following categories:

Third Party Engines ≤ 860 HP (DR-TP-01 and DR-TP-02)

Third Party Engines ≤ 300 HP (DR-TP-03 through DR-TP-11)

Third Party Engines ≤ 140 HP (DR-TP-12 through DR-TP-16)

Third Party Engines ≤ 126 HP (DR-TP-17 through DR-TP-21)

Note that the third party engines shown in this application are for representation purposes only, and 

Anadarko may replace these engines with equivalent engines as specified in Section 3.1 with equal or 

lesser emissions. The specification sheets for the equivalent engines are provided in Appendix G-2 and 

Appendix G-3. Emissions from third party engines will be a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for each of these engines 

are summarized below. 

40 CFR 89 Control Of Emissions From New And In-Use Nonroad Compression-Ignition Engines 

– Except for engines DR-TP-12 through DR-TP-16, Particulate matter (PM, PM10, and PM2.5), NOX, 

and CO emissions estimates for the third party engines are based on 40 CFR 89 Tier 2 exhaust 

emission standards. NOX emission factors are assumed to be equal to the NMHC + NOX emission 

factor. Based on footnote b of AP-42 Chapter 3, Table 3.3-1, all PM is assumed to be < 1 μm. 

Therefore, it is assumed PM2.5 = PM10 = PM. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – VOC and HAP emissions are based 

on emission factors from AP-42 Chapter 3.3, Table 3.3-2: Speciated Organic Compound Emission 

Factors for Uncontrolled Diesel Engines. An average BFSC of 7,000 Btu/HP-hr was used to convert 

from lb/MMBtu to lb/HP-hr to calculate emissions. Particulate matter (PM, PM10, and PM2.5), NOX, 

and CO emissions estimates for the third party engines DR-TP-12 through DR-TP-16 are based on 

AP-42, Chapter 3, Table 3.3.1, Emission Factors for Uncontrolled Gasoline and Diesel Industrial 

Engines. 

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to sulfuric acid (H2SO4) mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: 

Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of 
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Hydrogen sulfide (H2S), total reduced sulfur (TRS), and reduced sulfur compounds resulting from 

sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions from the third party engines are calculated based on 

the derived fuel based emission factor as described below:

Maximum Hourly Emissions – The maximum hourly emissions are calculated based on 1 hour 

operation per engine.

Maximum Daily Emissions – The maximum daily emissions are calculated based on 24 hours/day 

operation per engine.

Maximum Daily Emissions – The maximum annual emissions are calculated based on 4,800 

hours/year operation per engine.

Proposed Operating Limits:

Since this emission unit will be a part of drillship-wide fuel consumption limit, no separate fuel limit is 

required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.3.13. Flowback Boiler (DR-TP-22)

A "SIGMA FIRED" SF-200SE, 8 MMBtu/hr flowback boiler or equivalent will be used for certain well 

completion operations. A copy of the specification sheet is provided in Appendix G-9.

Emissions Factors – The sources of emission factors used to estimate emissions for this boiler are 

summarized below. 

AP-42, Section 1.3 Fuel Oil Combustion - The sources of emission factors used to estimate 

emissions for this boiler are cited from AP-42, Section 1.3. Fuel Oil Combustion and emission 

Factors for No.2 fuel oil was used. PM, SO2, NOX, and CO emissions are based on emission factors 

from AP-42 Chapter 1.3, Table 1.3-1 Criteria Pollutant Emissions Factors for Fuel Oil Combustion 

and 1.3-2, Condensable Particulate Matter Emission Factors for Oil Combustion. Total particulate 

emissions are the sum of filterable and total condensable particulate emissions. All PM is 

assumed to be < 1 um, therefore, it is assumed PM2.5 = PM10 = PM. VOC emission factors are 

obtained from AP-42 Section 1.3, Table 1.3-3 Emission Factors for Total Organic compounds from 

Uncontrolled Fuel Oil Combustion. All non-methane TOC is assumed to convert to VOC. HAP 

Emission Factors are obtained from AP-42 Section 1.3, Table 1.3-9 Emission Factors for Speciated 

Organic Compounds from Fuel Oil Combustion, and Table 1.3-10 Emission Factors for Trace 

Elements from Distillate Fuel oil Combustion Sources.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 
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Operating Parameters – The maximum hourly, daily and annual emissions from the boiler are calculated 

based on the following operating parameters.

Maximum Hourly Emissions – Maximum hourly emissions for the boiler are calculated based on 

related emission factors and 8 MMBtu/hr of rated heat input. 

Maximum Daily Emissions – Maximum daily emissions for this boiler are calculated based on 192 

MMBtu/day. 

Annual Emissions – The annual emissions from the boiler are calculated based on 1152 

MMBtu/year.

Proposed Operating Limits:

Anadarko proposes annual heat input limit of 1152 MMBtu. Anadarko will maintain adequate 

records to comply with proposed daily and annual operation limits.

3.3.14. Boom Flare (DR-TP-23)

A gas fired Boom Flare capable of processing 60 MMScf/day could be used during the well completion 

operation. Since the exact equipment specifications are not known, a typical VOC reduction efficiency of 

98% is assumed. Emissions are generated as a result of combustion process.

Emissions Factors – The sources of emission factors used to estimate emissions for the representative 

flare are summarized below.

AP-42, Section 13.5 Industrial Flares - NOX, CO, and VOC emission factors are based on AP 42 

Section 13.5, Table 13.5-1 Emission Factors for Flare Operations. Total hydrocarbon are

assumed to be VOC. 

AP-42, Section 1.4, Natural Gas Combustion - SO2 and Particulate Matter (PM, PM10, and 

PM2.5) emission factors are obtained from AP-42 Section 1.4, Table 1.4-2 Emission Factors For 

Criteria Pollutants And Greenhouse Gases From Natural Gas Combustion. Total particulate 

emission is the sum of filterable and total condensable particulate emissions. All PM is assumed 

to be < 1 um, therefore, it is assumed PM2.5 = PM10 = PM. Each individual HAP emission factor 

(except total POM emission factor) is based on AP-42 Section 1.4, Table 1.4-4 Emission Factors 

for Metals from Natural Gas Combustion. Per footnote b and c of AP-42 Section 1.4, Table 1.4-3 

Emission Factors for Speciated Organic Compounds from Natural Gas Combustion, all individual 

species of POM have been conservatively added and represented as HAP. The emission factor 

for POM is calculated as the sum of the emission factors for all the individual species of POM.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 
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Operating Parameters – The maximum hourly, daily and annual emissions from the representative flare 

are calculated based on the following operating parameters.

Maximum Hourly Emissions – Maximum hourly emissions for the representative flare are 

calculated based on a process rate of 2.5 MMscf/hr. 

Maximum Daily Emissions – Maximum daily emissions for this representative flare are calculated 

based on a gas process rate of 60 MMscf/day. 

Annual Emissions – The annual emissions from the representative flare are calculated based on a 

gas process rate of 360 MMscf/year.

Proposed Operating Limit –Anadarko proposes to demonstrate compliance with a maximum firing 

rate of 60 MMScf/day or 360 MMScf/year. Anadarko proposes to maintain the flexibility of flaring at 

a higher flow rate as long as they stay at or below the mass emission limits as established in 

Appendix B.

Proposed Operating Limits:

Anadarko proposes an annual gas process limit of 360 MMScf. 

3.3.15. Well Completion Condensate Tanks (DR-TP-24 through DR-TP-26)

There are three condensate tanks in the well completion operation

Emissions from three condensate tanks in the well completion have been estimated using EPA’s TANKS 

4.0.9d (TANKS) program. Default TANKS properties for Gasoline RVP 13 were used to model the 

contents of the condensate tanks. To represent conservative scenario, a throughput equal to twice the 

fuel usage was used. The TANKS output files are presented in Appendix B. 

The maximum hourly emissions were calculated using EPA TANKS 4.09d program for the month of June, 

since June results in the highest daily emissions. They could be used during every completion so I don’t 

think I’d say this. I’d double the capacity as throughput to be safe.

3.4. SUPPORT VESSELS

As discussed under Section 2 of the application, the associated support vessels proposed for this project 

will include a combination of supply boats (work boat and crew boat), well evaluation vessels, well 

stimulation vessels, tug boats and barges, and an anchor handling boat. These vessels will be used for 

transport of fuel and equipment as well as performing various operations. Except for barges, Anadarko 

is proposing fuel consumption limit for each category of support vessel as described below.

Emissions from support vessels while the support vessels are at the drillship, and while enroute to or 

from the drillship when within 25 miles of the drillship. For purposes of the air permit application, 

representative emissions from the support vessels potentially available to support operations of the 

BlackHornet drillship have been quantified. Based on review of all available supply boats, the HOS Coral

supply boat was found to be the worst case supply boat for emission estimations. If anchor handling 
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boat is utilized as a supply boat then it will be subject to same short term and long term emission limits 

established for the HOS Coral. Anadarko proposes to maintain the flexibility of utilizing any supply boat 

as long as it meets the criteria of equivalency specified in Section 2.1. While complying with mass 

emissions to demonstrate equivalency, Anadarko proposes to use equal or lower emission for the entire 

supply boat and not on equipment by equipment basis. 

Supply Boats (HOS Coral) Combustion Sources

3.4.1. Marine Propulsion Engines 1 and 2 (SB-ME-01 and SB-ME-02)

HOS Coral supply boat consists of two 3,004 HP (2,240kW) Caterpillar 3516C DITA diesel-fired marine 

propulsion engines. Emissions are generated as a result of combustion of diesel fuel from the engines. 

The specification sheets for these engines are provided in Appendix G-10.

Emissions Factors – The sources of emission factors used to estimate emissions for these engines are 

summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – VOC and 

HAP emissions estimates for the engines are based on AP-42, Section 3.4 emission factors. Non 

methane VOC emission factor has been taken as 91% of TOC emission factor. A calculated heat rate 

of 19.16 MMBtu/hr was used to convert from lb/MMBtu to lb/hr to calculate emissions.

40 CFR 94 Control of Emissions From Marine Compression-Ignition - Particulate matter (PM, 

PM10, and PM2.5), NOX, and CO emissions estimates for the main propulsion engines are based on 40 

CFR 94 Marine Tier 2 exhaust emission standards. NOX emission factors are assumed to be equal to 

the NMHC + NOX emission factor. Emission factor of PM2.5 and PM10 are calculated based on ratio of 

PM/PM2.5 and PM/PM10 which are obtained from AP-42 Chapter 3, Table 3.4-2. Total particulate 

emission factor used in the ratio has been taken as the sum of filterable and condensable particulate 

emissions. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.
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Fuel Based Emission Factor Derivation:

Based on the specifications sheets for each engine, the BSFC was used to convert the above mentioned 

emission factors to lbs of pollutant/bbl of fuel consumed for all permanent diesel combustion sources on 

the supply boat as shown in Appendix B. Hence, Anadarko is proposing supply boat-wide fuel limit,

derived using the fuel based emission factors, to establish operating limits and PTE calculations for 

supply boats. 

Proposed Operating Limits:

Anadarko proposes a supply boat-wide fuel limit of 200 bbl/day and 40,000 bbl/year based on the 

historical fuel consumption records for comparable supply boats. Note that certain operating situation

require more than one supply boats simultaneously within 25 nautical miles from the drillship. In that 

case, the proposed fuel limit will serve as a combined fuel limit for all supply boats. For example, if two 

supply boats provide support to the drillship operations during the same day simultaneously then total 

fuel consumption on both the supply boats will not exceed 200 bbl/day and both the supply boats will 

meet “equivalency” criteria specified above. 

The maximum hourly, daily, and annual emissions from the main engines are calculated based on the 

derived fuel based emission factor as described below:

Maximum Hourly Emissions – The maximum hourly emissions for the main engines are calculated 

based on the fuel based emission factor and maximum fuel requirement of 8 bbl of fuel. 

Maximum Daily Emissions – The maximum daily emissions for the main engines are based on the fuel 

based emission factor and maximum fuel requirement of 200 bbl/day of fuel.

Annual Emissions – The annual emissions for the main engines are based on the fuel based emission 

factor and maximum fuel requirement of 40,000 bbl/year of fuel.

3.4.2. Marine Thruster Engines (SB-TE-01 through SB-TE-03)

HOS Coral supply boat includes three 1,100 HP (820 kW) Caterpillar 3508C DITA diesel-fired marine 

thruster engines. Emissions are generated as a result of combustion of diesel fuel from the engine. 

Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below. 

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – VOC and 

HAP emissions estimates for the engines are based on AP-42, Section 3.4 emission factors. Non 

methane VOC emission factor has been taken as 91% of TOC emission factor. A calculated heat rate 

of 7.01 MMBtu/hr was used to convert from lb/MMBtu to lb/hr to calculate emissions.

40 CFR 94 Control of Emissions From Marine Compression-Ignition Engines - Particulate 

matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for thruster engines are based on 40 

CFR 94 Marine Tier 2 exhaust emission standards. NOX emission factors are assumed to be equal to 

the THC + NOX emission factor. Emission factor of PM2.5 and PM10 are calculated based on ratio of 

PM/PM2.5 and PM/PM10 which are obtained from AP-42 Chapter 3, Table 3.4-2. 
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EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions from the supply boat main propulsion engines were 

calculated based on one hour, 24 hours, and 4,800 hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.3. Electrical Generator Engines (SB-GE-01 and SB-GE-02)

HOS Coral supply boat consists of two 1,047 HP (781 kW) Caterpillar C32 DITA diesel-fired electrical 

generator engines. Emissions are generated as a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below. 

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – VOC and 

HAP emissions estimates for the engines are based on AP-42, Section 3.4 emission factors. Non 

methane VOC emission factor has been taken as 91% of TOC emission factor. A calculated heat rate 

of 6.56 MMBtu/hr was used to convert from lb/MMBtu to lb/hr to calculate emissions.

40 CFR 94 Control of Emissions From Marine Compression-Ignition Engines - Particulate 

matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for electric generator engines are 

based on 40 CFR 94 Marine Tier 2 exhaust emission standards. NOX emission factors are assumed to 

be equal to the THC + NOX emission factor. Emission factor of PM2.5 and PM10 are calculated based 

on ratio of PM/PM2.5 and PM/PM10 which are obtained from AP-42 Chapter 3, Table 3.4-2. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-
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006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions from the supply boat main propulsion engines were 

calculated based on one hour, 24 hours, and 4,800 hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits. 

3.4.4. Emergency Electrical Generator Engine (SB-GE-03)

HOS Coral supply boat consists of one 253 HP (189 kW) Caterpillar C9 DITA diesel-fired, emergency 

electrical generator engine. Emissions from the emergency generator engine will be a result of 

combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for the engine are 

summarized below.

40 CFR 94 Control Of Emissions From Marine Compression-Ignition Engines - Particulate 

matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the two representative Main 

Engines (SV-ME-01 and SV-ME-02) are based on 40 CFR 94 Marine Tier 2 exhaust emission 

standards. NOX emission factors are assumed to be equal to the NMHC + NOX emission factor. PM10

and PM2.5 emission factors are obtained by applying the ratio of PM/PM10 and PM/PM2.5 from AP-42 

Chapter 3, Table 3.4-1 and Table 3.4-2 on EPA Tier 2 PM emission factor.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – VOC and HAP Emissions are based 

on AP-42 Section 3.3 emission factors (Table 3.3-2.) An average BSFC of 7,000 Btu/HP-hr has been 

used to convert emission factors from lb/MMBtu to lb/HP-hr.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 
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(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors. 

Mass Balance – Anadarko proposed the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

and assuming that 98 percent of sulfur in the fuel will be converted to SO2 and 2 percent of the 

sulfur in the fuel will be converted to H2SO4 based on U.S. EPA guidance document.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 2 hours, and 100 

hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.5. ROV Electrical Generator Engine (SB-GE-04)

HOS Coral supply boat includes one 475 HP (354 kW) diesel-fired, ROV electrical generator engine. 

Emissions from the ROV electric generator engine will be a result of combustion of diesel fuel in the 

engine. 

Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –VOC and HAP emissions estimates 

for the ROV electric generator engine are based on AP-42, Section 3.3 emission factors. An average 

BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to calculate emissions.

40 CFR 89 Control Of Emissions From New And In-Use Nonroad Compression-Ignition Engines 

- Particulate matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the electric 

generator engine are based on 40 CFR 89 Tier 2 exhaust emission standards. NOX emission factors 

are assumed to be equal to the NMHC + NOX emission factor. Based on footnote b of AP-42 Chapter 

3, Table 3.3-1, all PM is assumed to be < 1 μm. Therefore, it is assumed PM2.5 = PM10 = PM.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.
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EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.6. Well Evaluation Third Party Engine (SB-TP-01 and SB-TP-02)

Two temporary third party Well Evaluation Electrical Generator Engines, Caterpillar 3406C or 

equivalent - 360 HP, could be brought on the support vessels for well evaluation activities. These 

engines will be temporarily brought onboard and operated on the supply boat as required. Emissions 

from the electric generator engines will be a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the electric generator engines are based on AP-42, Section 3.3 emission 

factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to 

calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 
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Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.7. Well Evaluation Third Party Crane Motor Engine #1 (SB-TP-03)

One Well Evaluation Crane motor Engine #1, John Deere PE 4045D or equivalent - 62 HP, could be 

brought on the support vessels for well evaluation activities. Emissions from the crane motor engine #1

will be a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the Crane motor engine are based on AP-42, Section 3.3 emission factors. 

An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to calculate 

emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.
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The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.8. Well Evaluation Third Party Crane Motor Engine #2 (SB-TP-04)

One Well Evaluation Crane motor Engine #2, Cummins B 5.9-C or equivalent - 130 HP, could be brought 

on the support vessels for well evaluation activities. Emissions from the crane motor engine #2 will be a 

result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the crane motor engine #2 are based on AP-42, Section 3.3 emission factors. 

An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to calculate 

emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation, respectively.

Proposed Operating Limits:
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Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.9. Third Party Well Evaluation Engines (SB-TP-05 through SB-TP-09)

Five well evaluation third party engines are required for well evaluation activities. 

Note that the third party engines shown in this application are for representation purposes only, and 

Anadarko may replace these engines with equivalent engines as specified in Section 3.1 with equal or 

lesser emissions. The specification sheets for the equivalent engines are provided in Appendix G-10. 

Emissions from third party engines will be a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for each of these engines 

are summarized below. 

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – VOC and HAP emissions are based 

on emission factors from AP-42 Chapter 3.3, Table 3.3-2: Speciated Organic Compound Emission 

Factors for Uncontrolled Diesel Engines. An average BFSC of 7,000 Btu/HP-hr was used to convert 

from lb/MMBtu to lb/HP-hr to calculate emissions. Particulate matter (PM, PM10, and PM2.5), NOX, 

and CO emissions are based on AP-42, Chapter 3, Table 3.3.1, Emission Factors for Uncontrolled 

Gasoline and Diesel Industrial Engines. . Based on footnote b of AP-42 Chapter 3, Table 3.3-1, all PM 

is assumed to be < 1 μm. Therefore, it is assumed PM2.5 = PM10 = PM.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1 (Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to sulfuric acid (H2SO4) mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: 

Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of 

Hydrogen sulfide (H2S), total reduced sulfur (TRS), and reduced sulfur compounds resulting from 

sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation, respectively.

Proposed Operating Limits:
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Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

Anchor Handling Boat (Kirt Chouest) Combustion Sources

The Kirt Chouest is the worst case anchor handling boat which will be used as a supply boat when 

required to perform specific operations. The fuel consumption and emissions from this boat will be 

counted against the supply boat fuel limits. The emission estimation procedures for several diesel 

engines on the anchor handling boat are described below.

3.4.10. Marine Propulsion Engines (AB-ME-01 and AB-ME-02)

The Kirt Chouest includes two 7,570 HP (5,650 kW) Caterpillar 3616 diesel-fired marine propulsion

engines. Emissions are generated as a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for these engines are 

summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines –Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC, and HAP emissions estimates for the engines are based 

on AP-42, Section 3.4 emission factors. Non methane VOC emission factor has been taken as 91% of 

TOC emission factor. Total particulate emissions have been taken as the sum of filterable and 

condensable particulate emissions. An average BSFC of 7,000 Btu/HP-hr has been used to convert 

emission factors from lb/MMBtu to lb/HP-hr.

EPA Guidance Documents – Lead emission factor has been obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 15 ppm in 

diesel fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in 

the fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control 

of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation respectively.

Proposed Operating Limits:
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Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.11. Thruster Engines (AB-TE-01 through AB-TE-03)

The Kirt Chouest includes three 1,674 HP (1,249 kW) Caterpillar 3512B-HD diesel-fired thruster 

engines. Emissions are generated as a result of combustion of diesel. 

Emissions Factors – The sources of emission factors used to estimate emissions for these engines are 

summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines –Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC, and HAP emissions estimates for the engines are based 

on AP-42, Section 3.4 emission factors. Non methane VOC emission factor has been taken as 91% of 

TOC emission factor. Total particulate emissions have been taken as the sum of filterable and 

condensable particulate emissions. An average BSFC of 7,000 Btu/HP-hr has been used to convert 

emission factors from lb/MMBtu to lb/HP-hr.

EPA Guidance Documents – Lead emission factor has been obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 15 ppm in 

diesel fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in 

the fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control 

of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.
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3.4.12. Service Generator Engines (AB-GE-01 through AB-GE-05)

The Kirt Chouest includes of three 716 HP (534 kW) Caterpillar 3412C diesel-fired service generator 

engines and two 1,300 HP (968 kW) Caterpillar 3508B crane dedicated diesel-fired service generator 

engines. Emissions are generated as a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for these engines are 

summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines –Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC, and HAP emissions estimates for the generator engines

are based on AP-42, Section 3.4 emission factors. Non methane VOC emission factor has been taken 

as 91% of TOC emission factor. Total particulate emissions have been taken as the sum of filterable 

and condensable particulate emissions. An average BSFC of 7,000 Btu/HP-hr has been used to 

convert emission factors from lb/MMBtu to lb/HP-hr. 

EPA Guidance Documents – Lead emission factor has been obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 15 ppm in 

diesel fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in 

the fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control 

of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 

4,800 hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply 

with proposed daily and annual operation limits.

3.4.13. Emergency Generator Engine (AB-GE-06)

The Kirt Chouest includes one 307 HP (229 kW) Caterpillar 3406C diesel-fired, emergency generator 

engine. The emergency generator engine will be operated during emergencies, and periodically 

operated for maintenance checks. Emissions from the emergency generator engine will be a result of 

combustion of diesel fuel. 
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Emissions Factors – The sources of emission factors used to estimate emissions for this engine are 

summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – Particulate (PM, PM10, PM2.5), 

VOC, CO, NOX, and HAP emissions estimates for the emergency generator engine are based on 

AP-42, Section 3.3 emission factors. Based on AP-42 guidance, all of the particulate matter is 

assumed to be less than 1 μm. All of the TOC is assumed to be VOC. TOC emission factor has 

been calculated as the sum of exhaust and crankcase emission factors. 

EPA Guidance Documents – Lead emission factor has been obtained from EPA guidance 

document: Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 

454/R-98-006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was 

used as a surrogate for distillate oil fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 15 ppm in 

diesel fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of 

sulfur in the fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact 

Analysis: Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. 

Emissions of H2S, TRS, and reduced sulfur compounds resulting from sulfur content in the fuel 

are negligible.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

The maximum hourly, daily, and annual emissions were calculated based on one hour, one hour, and 

100 hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.14. Winch Hydraulic Engines (AB-GE-07 and AB-GE-08)

The Kirt Chouest includes two 1,300 HP (969 kW) Caterpillar C32 diesel-fired hydraulic engines. 

Emissions are generated as a result of combustion of diesel. 

Emissions Factors – The sources of emission factors used to estimate emissions for these engines are 

summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines –

Particulate matter (PM, PM10, and PM2.5), NOX, CO, VOC, and HAP emissions estimates for the 

engines are based on AP-42, Section 3.4 emission factors. Non methane VOC emission factor has 

been taken as 91% of TOC emission factor. Total particulate emissions have been taken as the 

sum of filterable and condensable particulate emissions. An average BSFC of 7,000 Btu/HP-hr 
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has been used to convert emission factors from lb/MMBtu to lb/HP-hr. 

EPA Guidance Documents – Lead emission factor has been obtained from EPA guidance 

document: Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 

454/R-98-006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was 

used as a surrogate for distillate oil fired engines due to lack of emission factors. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 15 ppm in 

diesel fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of 

sulfur in the fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact 

Analysis: Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. 

Emissions of H2S, TRS, and reduced sulfur compounds resulting from sulfur content in the fuel 

are negligible.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A.

The maximum hourly, daily, and annual emissions from the anchor handling boat winch hydraulic 

engines were calculated based on one hour, 24 hours, and 4,800 hours of operation respectively.

Proposed Operating Limits:

Since this emission unit will be a part of supply boat-wide fuel consumption limit, no separate fuel limit 

is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.15. Supply Boat Storage Tanks

The supply boat (HOS Coral) includes 15 diesel fuel storage vessels and the anchor handling boat (Kirt 

Chouest) includes 19 diesel fuel storage vessels. Emissions from all storage vessels on the support 

vessels have been estimated using EPA’s TANKS 4.0.9d program. Default TANKS properties for distillate 

fuel oil No. 2 were used to model the contents of the diesel tanks. The tank emissions calculations 

(including the EPA TANKS 4.09d runs) are included in Appendix G-7 of this application.

Tug Boat Combustion Sources

3.4.16. Tug Boat Main Engines (TB-ME-01 to TB-ME-03) and Generator Engines (TBGE-01 to TB-GE-02)

The Tug Boat includes Main Engines (TB-ME-01 through TB-ME-03) and Generator Engines (TB-GE-01 

and TB-GE-02) or equivalent engines for this operation. The Main Engines and Generator Engines as 

presented in this application have 2,200 HP (1,641 KW) rating and 174 HP (130 KW) rating,

respectively. Emissions are generated as a result of combustion of diesel fuel.
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Emissions Factors – The sources of emission factors used to estimate emissions Main Engines (TB-ME01 through TB-ME-03) and Generators (TB-GE-01 and TB-GE-02) are summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines – Particulate matter (PM, PM10, and 

PM2.5), NOX, CO, VOC and HAPs estimates for the representative Generators (TB-GE-01 and TB-GE02) are based on AP-42, Section 3.3 emission factors. Based on AP-42 guidance, all of the particulate 

matter is assumed to be less than 1 μm. All of the TOC is assumed to be VOC. TOC emission factor 

has been calculated as the sum of exhaust and crankcase emission factors. An average BFSC of 7,000 

Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to calculate emissions.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – Particulate 

matter (PM, PM10, and PM2.5), CO, VOC and HAPs emissions estimates for the representative Main 

Engines (TB-ME-01 through TB-ME-03) are based on AP-42, Section 3.4 emission factors (Table 3.4-

1, Table 3.4-2 and table 3.4-3). Non methane VOC emission factor has been taken as 91% of the 

total organic compounds (TOC) emission factor. Emission factor of PM2.5 and PM10 are calculated 

based on ratio of PM/PM2.5 and PM/PM10 which are obtained from AP-42 Chapter 3, Table 3.4-2. 

Total particulate emission factor used in the ratio has been taken as the sum of filterable and 

condensable particulate emissions. PM < 3um are taken as PM2.5. An average brake-specific fuel 

consumption (BSFC) of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr. 

IMO Tier 2 – NOX emissions estimates for the representative Main Engines (TB-ME-01 through TBME-03) are based on IMO Tier 2 emission factors for an engine speed of 1,800 rpm. 

EPA Guidance Documents – Lead emission factor for Main Engines (TB-ME-01 through TB-ME-03) 

and Generators (TB-GE-01 and TB-GE-02) is obtained from EPA guidance document: Locating and 

Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-006, May 1998, 

Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a surrogate for 

distillate oil-fired engines due to lack of emission factors. 

EPA Regulations – CO2, CH4 and N2O emission factors for Main Engines (TB-ME-01 through TB-ME03) and Generators (TB-GE-01 and TB-GE-02) are obtained from 40 CFR 98 Subpart C, Table C1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to sulfuric acid (H2SO4) mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: 

Control of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of 

Hydrogen sulfide (H2S), total reduced sulfur (TRS), and reduced sulfur compounds resulting from 

sulfur content in the fuel are negligible.

Fuel Based Emission Factor Derivation:

Based on the specifications sheets for each engine, the BSFC was used to convert the above mentioned 

emission factors to lbs of pollutant/bbl of fuel consumed as shown in the Appendix B. Hence, Anadarko 
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is proposing tug boat-wide fuel limit, based on the fuel based emission factors, to establish operating 

limits and PTE calculations for tug boats. 

Proposed Operating Limits:

Anadarko proposes a tug boat-wide fuel cap of 125 bbl/day and 25,000 bbl/year based on the historical 

fuel consumption records for comparable tug boats.

The maximum hourly, daily, and annual emissions from the main engines are calculated based on the 

derived fuel based emission factor as described below:

Maximum Hourly Emissions – The maximum hourly emissions for the main engines are calculated 

based on the fuel based emission factor and maximum fuel requirement of 5.1 bbl of fuel. 

Maximum Daily Emissions – The maximum daily emissions for the main engines are based on the fuel 

based emission factor and maximum fuel requirement of 125 bbl/day of fuel.

Annual Emissions – The annual emissions for the main engines are based on the fuel based emission 

factor and maximum fuel requirement of 25,000 bbl/year of fuel.

Barge Combustion Sources

3.4.17. Barge Electrical Generators (BG-LP-01thru BG-LP-03)

The Barge electrical generator engines represented in this application include three 456 HP electrical 

generator engines. Emissions are generated as a result of combustion of diesel fuel in the engines.

Emissions Factors – The sources of emission factors used to estimate emissions for representative 

engines are summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the electrical generator engines are based on AP-42, Section 3.3 emission 

factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to 

calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 
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assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible. 

Proposed Operating Limits:

The maximum hourly, daily, and annual emissions from the barge electrical generator engines are 

calculated based on the hours of operation as described below:

Maximum Hourly Emissions – The maximum hourly emissions for the barge electrical generator 

engines operations are calculated based on one hour operation per engine.

Maximum Daily Emissions – The maximum daily emissions for the barge electrical generator 

engines operations are calculated based on 24 hours operation per engine.

Annual Emissions – The maximum annual emissions for the barge electrical generator engines

operations are calculated based on 4800 hours of operation per engine.

Stimulation Vessel Combustion Sources

The representative Stimulation Vessel Engines includes Main Propulsion Engines (SV-ME-01 and SV-ME02), representative Thrusters (SV-BT-01 through SV-ST-01), representative Drop-down Engines (SVDD-01) representative Pump Engines (SV-PE-01 through SV-PE-08), and representative Generator 

Engines (SV-GE-01 through SV-GE-04) as presented in this application. Emissions are generated as a 

result of combustion of diesel fuel. 

3.4.18. Stimulation Vessel Main Engines (SV-ME-01 and SV-ME-02)

The Stimulation Vessel includes two 3,634 HP (2,710 kW) Caterpillar C280-8 main engines. Emissions 

are generated as a result of combustion of diesel fuel in the engines.

Emissions Factors – The sources of emission factors used to estimate emissions for representative 

stimulation vessel main engines are summarized below.

40 CFR 94 Control Of Emissions From Marine Compression-Ignition Engines - Particulate 

matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the two representative Main 

Engines (SV-ME-01 and SV-ME-02) are based on 40 CFR 94 Marine Tier 2 exhaust emission 

standards. NOX emission factors are assumed to be equal to the NMHC + NOX emission factor. PM10

and PM2.5 emission factors are obtained by applying the ratio of PM/PM10 and PM/PM2.5 from AP-42 

Chapter 3, Table 3.4-1 and Table 3.4-2 on EPA Tier 2 PM emission factor.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – VOC and 

HAP emissions estimates for the two main engines are based on AP-42, Section 3.4 Table 3.4-1 and 

Table 3.4-3. All of the TOC is assumed to be VOC. TOC emission factor has been calculated as the 

sum of exhaust and crankcase emission factors. Per footnote f of AP-42 Chapter 3, Table 3.4-1, non-
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methane VOC emission factor has been taken as 91% of TOC emission factor. An average BSFC of 

7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

Fuel Based Emission Factor Derivation:

Based on the specifications sheets for each engine, the BSFC was used to convert the above mentioned 

emission factors to lbs of pollutant/bbl of fuel consumed as shown in the Appendix B. Hence, Anadarko 

is proposing stimulation vessel-wide fuel limit, based on the fuel based emission factors, to establish 

operating limits and PTE calculations for stimulation vessel. 

Proposed Operating Limits:

Anadarko proposes a stimulation vessel-wide fuel cap of 225 bbl/day and 4725 bbl/year based on the 

historical fuel consumption records for comparable vessel and expected operating time for this vessel.

The maximum hourly, daily, and annual emissions from the stimulation vessel are calculated based on 

the derived fuel based emission factor as described below:

Maximum Hourly Emissions – The maximum hourly emissions for the main engines are calculated 

based on the fuel based emission factor and maximum fuel requirement of 9.37 bbl of fuel. 

Maximum Daily Emissions – The maximum daily emissions for the main engines are based on the fuel 

based emission factor and maximum fuel requirement of 225 bbl/day of fuel.

Annual Emissions – The annual emissions for the main engines are based on the fuel based emission 

factor and maximum fuel requirement of 4,725 bbl/year of fuel.
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3.4.19. Bow Thruster Engine (SV-BT-01)

The Stimulation Vessel includes one 1,675 HP (1,249 kW) bow thruster engine. Emissions are generated 

as a result of combustion of diesel fuel in the engines.

Emissions Factors – The sources of emission factors used to estimate emissions for representative 

Stimulation Vessel Bow Thruster Engine are summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC and HAP emissions estimates for thruster engine are 

based on AP-42, Section 3.4 Table 3.4-1 through Table 3.4-4. PM < 3um is taken as PM2.5. Total 

particulate emission is the sum of filterable and condensable particulate emissions. Per footnote f of 

AP-42 Chapter 3, Table 3.4-1, non-methane VOC emission factor has been taken as 91% of TOC 

emission factor. An average BSFC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HPhr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 504

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of stimulation vessel-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.20. Bow Drop-Down Engine (SV-DD-01)

The Stimulation Vessel has one 1,200 HP (895 kW) bow drop down engine. Emissions are generated as 

a result of combustion of diesel fuel in the engines.
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Emissions Factors – The sources of emission factors used to estimate emissions for representative 

Stimulation Vessel Bow Drop-Down Engine are summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC and HAP emissions estimates for the bow drop-down 

engine are based on AP-42, Section 3.4 Table 3.4-1 through Table 3.4-4. PM < 3um is taken as PM2.5. 

Total particulate emission is the sum of filterable and condensable particulate emissions. Per 

footnote f of AP-42 Chapter 3, Table 3.4-1, non-methane VOC emission factor has been taken as 91% 

of TOC emission factor. An average BSFC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to 

lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 504

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of stimulation vessel-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.21. Stern Thruster Engines (SV-ST-01)

The Stimulation Vessel includes one 1,675 HP (1,249 kW) Stern thruster engine. Emissions are 

generated as a result of combustion of diesel fuel.

Emissions Factors – The sources of emission factors used to estimate emissions for representative 

Stimulation Vessel Stern Thruster Engine are summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC and HAP emissions estimates for thruster engine are 
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based on AP-42, Section 3.4 Table 3.4-1 through Table 3.4-4. PM < 3um is taken as PM2.5. Total 

particulate emission is the sum of filterable and condensable particulate emissions. Per footnote f of 

AP-42 Chapter 3, Table 3.4-1, non-methane VOC emission factor has been taken as 91% of TOC 

emission factor. An average BSFC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HPhr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 504

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of stimulation vessel-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.22. Representative Pump Engines (SV-PE-01 through SV-PE-08)

The Stimulation Vessel includes eight 2,250 HP (1,678 kW) pump engines. Emissions are generated as a 

result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for these pumps are 

summarized below.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – Particulate 

matter (PM, PM10, and PM2.5), NOX, CO, VOC and HAP emissions estimates for the pump engines are 

based on AP-42, Section 3.4 Table 3.4-1 through Table 3.4-4. PM < 3um is taken as PM2.5. Total 

particulate emission is the sum of filterable and condensable particulate emissions. Per footnote f of 

AP-42 Chapter 3, Table 3.4-1, non-methane VOC emission factor has been taken as 91% of TOC 

emission factor. An average BSFC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HPhr to calculate emissions.
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EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 10 hours, and 210

hours of operation, respectively. Anadarko proposes to maintain flexibility of operating fewer pumps 

for longer duration than specified above as long as total daily and annual operations are within the 

proposed daily and annual operating limits, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of stimulation vessel-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.23. Stimulation Vessel Generators (SV-GE-01 and SV-GE-02)

The Stimulation Vessel includes two 1,220 HP (910 kW) generator engines. Emissions are generated as 

a result of combustion of diesel fuel. 

Emissions Factors – The sources of emission factors used to estimate emissions for the generator engines

are summarized below.

40 CFR 89 Control Of Emissions From New And In-Use Nonroad Compression-Ignition Engines 

- Particulate matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the Generators are 

based on 40 CFR 89 Tier 2 exhaust emission standards. NOX emission factors are assumed to be 

equal to the NMHC + NOX emission factor. PM10 and PM2.5 emission factors are obtained by applying 

the ratio of PM/PM10 and PM/PM2.5 from AP-42 Chapter 3, Table 3.4-1 and Table 3.4-2 on EPA Tier 2

PM emission factor.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – VOC and 

HAP emissions estimates for the generator engines are based on AP-42, Section 3.4 Table 3.4-1 and 

Table 3.4-3. All of the TOC is assumed to be VOC. TOC emission factor has been calculated as the 
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sum of exhaust and crankcase emission factors. Per footnote f of AP-42 Chapter 3, Table 3.4-1, nonmethane VOC emission factor has been taken as 91% of TOC emission factor. An average BSFC of 

7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 504

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of stimulation vessel-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

3.4.24. Stimulation Vessel Generators (SV-GE-03 and SV-GE-04)

The Stimulation Vessel includes two 805 HP (600 kW) Caterpillar C18 ATAAC engines. Emissions are 

generated as a result of combustion of diesel fuel.

Emissions Factors – The sources of emission factors used to estimate emissions for the generator engines

are summarized below.

40 CFR 89 Control Of Emissions From New And In-Use Nonroad Compression-Ignition 

Engines - Particulate matter (PM, PM10, and PM2.5), NOX, and CO emissions estimates for the 

generator engines are based on 40 CFR 89 Tier 2 exhaust emission standards. NOX emission 

factors are assumed to be equal to the NMHC + NOX emission factor. PM10 and PM2.5 emission 

factors are obtained by applying the ratio of PM/PM10 and PM/PM2.5 from AP-42 Chapter 3, 

Table 3.4-1 and Table 3.4-2 on EPA Tier 2 PM emission factor.

AP-42, Section 3.4. Large Stationary Diesel and All Stationary Dual-fuel Engines – VOC and 

HAP emissions estimates for the Generators Baker Hughes engines are based on AP-42, Section 
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3.4 Table 3.4-1 and Table 3.4-3. All of the TOC is assumed to be VOC. TOC emission factor has 

been calculated as the sum of exhaust and crankcase emission factors. Per footnote f of AP-42 

Chapter 3, Table 3.4-1, non-methane VOC emission factor has been taken as 91% of TOC 

emission factor. An average BSFC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to 

lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R98-006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as 

a surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, 

Table C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and 

Table C-2 (Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for 

CO2e has been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel 

fuel assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the 

fuel is oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control 

of Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, 

TRS, and reduced sulfur compounds resulting from sulfur content in the fuel are negligible.

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 504

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of stimulation vessel-wide fuel consumption limit, no separate fuel 

limit is required to demonstrate compliance. Anadarko will maintain adequate records to comply with 

proposed daily and annual operation limits.

Well Evaluation Vessel Combustion Sources

The Well Evaluation Vessel will consist of Main Engines (WE-ME-01 and WE-ME-02), Auxiliary Engines

(WE-AE-01 and WE-AE-02), and Emergency Generators (WE-GE-01, WE-GE-02, and WE-GE-03). 

Emissions from each air pollution source are estimated using the methodology as shown below. 

3.4.25. Well Evaluation Vessel Main Engines (WE-ME-01and WE-ME-02)

The Well Evaluation Vessel Main Engines represented in this application consist of two 2,250 HP 

engines. Emissions are generated as a result of combustion of diesel fuel in the engines.

Emissions Factors – The sources of emission factors used to estimate emissions for representative well 

evaluation vessel main engines are summarized below.
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AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the well evaluation main engines are based on AP-42, Section 3.3 emission 

factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to lb/HP-hr to 

calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible. 

Fuel Based Emission Factor Derivation:

Based on the specifications sheets for each engine, the BSFC was used to convert the above mentioned 

emission factors to lbs of pollutant/bbl of fuel consumed as shown in Appendix B. The fuel consumption 

resulting in highest emissions for the presented well evaluation vessel engines is 194 g/kW-hr as shown 

in Appendix B. Based on a conservative estimate, Anadarko proposes well evaluation vessel-wide fuel 

limit of 144 bbls/day. 

Proposed Operating Limits:

Anadarko proposes a well evaluation vessel-wide fuel cap of 144 bbl/day and 28,000 bbl/year based on 

the engineering estimates and expected operating time for this vessel.

The maximum hourly, daily, and annual emissions from the stimulation vessel are calculated based on 

the derived fuel based emission factor as described below:

Maximum Hourly Emissions – The maximum hourly emissions for the main engines are calculated 

based on the fuel based emission factor and maximum fuel requirement of 6 bbl of fuel. 

Maximum Daily Emissions – The maximum daily emissions for the main engines are based on the fuel 

based emission factor and maximum fuel requirement of 144 bbl/day of fuel.

Annual Emissions – The annual emissions for the main engines are based on the fuel based emission 

factor and maximum fuel requirement of 750 bbl/year of fuel.
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3.4.26. Well Evaluation Vessel Auxiliary Engines (WE-AE-01 and WE-AE-02)

The Well Evaluation Vessel Auxiliary Engines represented in this application consist of two 1,468 HP 

engines. Emissions are generated as a result of combustion of diesel fuel in the engines.

Emissions Factors – The sources of emission factors used to estimate emissions for representative well 

evaluation vessel auxiliary engines are summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the well evaluation auxiliary engines are based on AP-42, Section 3.3 

emission factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to 

lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible. 

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 125 

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of the well evaluation vessel-wide fuel consumption limit, no 

separate fuel limit is required to demonstrate compliance. Anadarko will maintain adequate records to 

comply with proposed daily and annual operation limits.

3.4.27. Well Evaluation Vessel Emergency Generator #1 (WE-GE-01)

The Well Evaluation Vessel Emergency Generator represented in this application consist of one 272 HP 

engine. Emissions are generated as a result of combustion of diesel fuel in the engine.

Emissions Factors – The sources of emission factors used to estimate emissions for representative well 

evaluation emergency generator are summarized below.
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AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the well evaluation emergency generator #1 are based on AP-42, Section 3.4

emission factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to 

lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible. 

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 125 

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of the well evaluation vessel-wide fuel consumption limit, no 

separate fuel limit is required to demonstrate compliance. Anadarko will maintain adequate records to 

comply with proposed daily and annual operation limits.

3.4.28. Well Evaluation Vessel Emergency Generator #2 (WE-GE-02)

The Well Evaluation Vessel Emergency Generator #2 represented in this application consist of one 212 

HP engine. Emissions are generated as a result of combustion of diesel fuel in the engine.

Emissions Factors – The sources of emission factors used to estimate emissions for representative well 

evaluation emergency generator #2 are summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the well evaluation emergency generator #2 are based on AP-42, Section 3.4

emission factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to 

lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.
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EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 

assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible. 

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 125 

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of the well evaluation vessel-wide fuel consumption limit, no 

separate fuel limit is required to demonstrate compliance. Anadarko will maintain adequate records to 

comply with proposed daily and annual operation limits.

3.4.29. Well Evaluation Vessel Emergency Generator #3 (WE-GE-03)

The Well Evaluation Vessel Emergency Generator #3 represented in this application consist of one 200 

HP engine. Emissions are generated as a result of combustion of diesel fuel.

Emissions Factors – The sources of emission factors used to estimate emissions for representative well 

evaluation emergency generator #3 are summarized below.

AP-42, Section 3.3. Gasoline and Diesel Industrial Engines –PM, NOX, CO, VOC and HAP 

emissions estimates for the well evaluation emergency generator #3 are based on AP-42, Section 3.4

emission factors. An average BFSC of 7,000 Btu/HP-hr was used to convert from lb/MMBtu to 

lb/HP-hr to calculate emissions.

EPA Guidance Documents – Lead emission factor is obtained from EPA guidance document: 

Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA 454/R-98-

006, May 1998, Section 5.2.2. Emission factor for distillate oil-fired gas turbines was used as a 

surrogate for distillate oil-fired engines due to lack of emission factors.

EPA Regulations – CO2, CH4 and N2O emission factors are obtained from 40 CFR 98 Subpart C, Table 

C-1(Default CO2 Emission Factors and High Heat Values for Various Types of Fuel) and Table C-2 

(Default CH4 and N2O Emission Factors for Various Types of Fuel). Emission factor for CO2e has 

been calculated using the GWPs obtained from 40 CFR 98 Subpart A. 

Mass Balance – Anadarko is proposing the use of ULSD fuel for all diesel combustion sources. 

Therefore, SO2 emissions are calculated based on a maximum sulfur content of 15 ppm in diesel fuel 
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assuming that 98 percent of sulfur in the fuel is oxidized to SO2 and 2 percent of sulfur in the fuel is 

oxidized to H2SO4 mist based on Section 4.1.1 of Draft Regulatory Impact Analysis: Control of 

Emissions from Nonroad Diesel Engines, EPA420-R-03-008, April 2003. Emissions of H2S, TRS, and 

reduced sulfur compounds resulting from sulfur content in the fuel are negligible. 

The maximum hourly, daily, and annual emissions were calculated based on one hour, 24 hours, and 125 

hours of operation, respectively.

Proposed Operating Limits:

Since this emission unit will be a part of the well evaluation vessel-wide fuel consumption limit, no 

separate fuel limit is required to demonstrate compliance. Anadarko will maintain adequate records 

to comply with proposed daily and annual operation limits. 
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4. REGULATORY APPLICABILITY ANALYSIS

To assist U.S. EPA Region 4 in drafting the pre-construction permit for the proposed project, this section 

of the application provides a review of pertinent federal air quality regulations that potentially apply to 

the emission sources associated with the proposed project. As the proposed project will be carried out 

beyond 25 miles of the nearest States’ seaward boundary, it will be outside of the corresponding state 

and local regulatory jurisdictions and will not be subject to any state or local regulations.

4.1. OUTER CONTINENTAL SHELF AIR REGULATIONS (40 CFR 55)

The BlackHornet drillship used for the proposed exploratory drilling operations will qualify as an OCS 

source, as defined in 40 CFR Part 55.2. An OCS source is defined in 40 CFR 55.2 as follows: 

“OCS source means any equipment, activity, or facility which:

(1) Emits or has the potential to emit any air pollutant;

(2) Is regulated or authorized under Outer Continental Shelf Lands Act (“OCSLA”) (43 U.S.C. §1331 et seq.); 

and 

(3) Is located on the OCS or in or on waters above the OCS.

This definition shall include vessels only when they are:

(1) Permanently or temporarily attached to the seabed and erected thereon and used for the purpose of 

exploring, developing or producing resources therefrom, within the meaning of section 4(a)(1) of OCSLA 

(43 U.S.C. §1331 et seq. ); or

(2) Physically attached to an OCS facility, in which case only the stationary sources aspects of the vessels 

will be regulated.”

Therefore, when the BlackHornet drillship is conducting the proposed project, it will be considered an 

OCS source and shall be subject to the requirements of 40 CFR 55. In addition, when an associated 

vessel is physically attached to an OCS source, the stationary source aspects of the vessel will also be 

regulated as an OCS source. 

The main engines on the support vessels are solely used for propulsion purposes and/or for maintaining 

the position of the respective vessel. The generators on the support vessels and the barge are not used 

for OCS activity; rather, they are used only for non-process ancillary activities such as operating HVAC 

System, maintaining the GPS position and other such similar functions. The ROV electric generator diesel 

engine on the Supply Boat is not operated while physically connected to the drillship. Therefore, these 

engines do not meet the definition of stationary aspects of these vessels. 

As specified in Section 1 of this application, per 40 CFR 55.3(a), all OCS sources located in the EGOM are 

regulated by the OCS Air Regulations codified under 40 CFR 55. As the regulatory authority over the 

EGOM has not been delegated through the requirements of 40 CFR 55.11(j), the proposed OCS source 

falls under the regulatory jurisdiction of the U.S. EPA and U.S. EPA Region 4 will issue the applicable 

permits and implement and enforce the requirements of 40 CFR 55.
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As specified at 40 CFR 55.13, OCS sources subject to the requirements of 40 CFR 55 must comply with 

the following federal requirements, as applicable:

40 CFR 52.21 - Prevention of Significant Deterioration (PSD);

40 CFR Part 60 - New Source Performance Standards (NSPS);

40 CFR Part 61 - National Emission Standards for Hazardous Air Pollutants (NESHAP), which 

represent pollutant-specific standards established pursuant to Section 112 of the Clean Air Act 

(CAA) for those pollutants for which a standard is prescribed under 40 CFR 61;

40 CFR Part 63 - Maximum Achievable Control Technology (MACT), which represent standards 

established pursuant to Section 112 of the CAA to regulate specific categories of stationary sources 

that emit (or have the potential to emit) one or more HAPs; and

40 CFR Part 71 - Federal Operating Permits Program.

Based on the definition of the OCS source, support vessels are subject to applicable regulatory 

requirements when they are physically attached to the OCS source, in which case only the stationary 

source aspects of the vessels will be regulated. 

Therefore, detailed regulatory applicability determinations in this section are only needed for the 

following emission units on the BlackHornet drillship:

Eight Main Engines (DR-ME-01 to DR-ME-08)

One Emergency Generator (DR-GE-01)

One Emergency Air Compressor (DR-AC-01)

Three Well Completion Condensate Tanks (DR-TP-24 to DR-TP-26)

Five Third Party Well Evaluation Engines (DR-TP-12 to DR-TP-16)

One Flowback Boiler (DR-TP-22)

One Boom Flare (DR-TP-23)

Fuel Storage tanks (several EPNs)

Painting (DR-PO-01)

Welding (DR-WO-01)

Under certain operating scenarios, the following sources of air pollution will constitute stationary 

source aspects of the vessels when the support vessels are physically attached to the OCS source:

Fuel Storage Tanks on the supply boats and the anchor handling boat (several EPNs)

Eight pumps on the stimulation vessel (SV-PE-01 through SV-PE-08)

The Life Boats (DR-LB-01 and DR-LB-06) and the Fast Rescue Craft (DR-FR-01) are included in the PTE 

calculations and air dispersion modeling as specified in 40 CFR part 55 and these sources are subject to 

operating limits, monitoring, recordkeeping and reporting requirements to ensure they will not exceed 

the potential emissions assumed in the application and impact review. Per 40 CFR 55.2, the support 

vessels operating within 25 miles of the OCS source are not subject to BACT requirements unless they 

are attached to the OCS. If attached, only the stationary source aspects of the vessel are regulated. 

These units do not have any stationary source aspects with respect to air pollutant emissions, as they 

are used for man overboard and emergency escape scenarios only. Hence, these units are not subject to 

NSPS and MACT regulations.
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Additionally, details (e.g., model year, exact power rating etc.) of the Temporary Third Party Emission 

Sources (DR-TP-01 through DR-TP-11 and DR-TP-17 through DR-TP-21) were not available at the time 

of this application since these engines are brought onboard as required. Therefore, regulatory 

determinations for these engines will be made before selecting the engines. A detailed overview of the 

applicability of each federal air quality regulation is provided in the following sections. 

4.2. PREVENTION OF SIGNIFICANT DETERIORATION (PSD) REGULATIONS

As an OCS source subject to the requirements of 40 CFR 55, the proposed project will need to comply 

with 40 CFR 55.13(d) which specifies that the PSD program (codified under 40 CFR 52.21), applies to 

OCS sources located beyond 25 miles of State’s seaward boundaries. The requirements of the PSD 

program apply to the construction of any new major stationary source or any project at an existing 

major stationary source in an area designated as attainment or unclassifiable under Sections 

107(d)(1)(A)(ii) or (iii) of the CAA. The pollutants regulated by the PSD program include all criteria 

pollutants and several non-criteria pollutants such as total reduced sulfur compounds, sulfuric acid mist, 

and fluorides (not including hydrogen fluoride).

An OCS source is considered a PSD major source if the potential emission of any PSD-regulated pollutant 

exceeds the major source threshold of 250 tons per year (tpy). For a PSD regulated pollutant emitted 

from a new PSD major source whose source-wide potential emissions exceed the respective Significant 

Emission Rates (SERs) defined in 40 CFR 52.21(b)(23)(i), PSD review is required.

On May 13, 2010, the U.S. EPA issued the final “Prevention of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule” specifying that as of January 2, 2011, all new industrial sources that are 

major sources for any new source review (NSR) regulated pollutants other than GHGs, and will emit or 

have the potential to emit 75,000 tons per year or more of total GHGs, on a CO2e basis will need to 

determine the Best Available Control Technology for their GHG emissions.3 

To determine the applicability of PSD permitting requirements and the pollutants to which these 

requirements would apply, the emissions estimates from the proposed EGOM Exploratory Project were 

compared to the respective PSD major source threshold and SER. As required by 40 CFR 55.13, the 

source-wide potential emissions were calculated by including the emissions from sources associated 

with the proposed exploratory drilling operations along with the associated support vessels while at the 

source, and while enroute to or from the source when within 25 miles of the source. Table 1-2 lists the 

source-wide potential emission rates of each regulated air pollutant for the EGOM Exploratory Prospect 

against the respective PSD SER.

As shown in Table 1-2, the proposed OCS source qualifies as a major source under the PSD program 

because potential annual emissions of NOX and CO are each greater than the 250 tpy major source 

threshold. Additionally, PSD review is required for PM, PM10, PM2.5, NOX, GHGs, and VOCs since 

emissions of these pollutants exceed their respective PSD SERs.

40 CFR 52.21(k) requires that Anadarko demonstrate that for all regulated air pollutants that would be 

emitted at or in excess of the SER would not cause or contribute to a violation of any NAAQS or cause or 

contribute to a violation of any applicable PSD increments. Therefore, for pollutants subject to PSD 

 

3 CO2 equivalent encompasses a list of six greenhouse gases, including carbon dioxide, methane, nitrous oxide, 

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 
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review, the following requirements of the PSD regulations applicable to the EGOM Exploratory Project 

are addressed in this application: 

A determination of BACT for each applicable emission unit as detailed in Section 5 of this report.

Air dispersion modeling analysis as detailed in Appendix D of this report

The air dispersion modeling analysis is performed for Class I and Class II areas to address following 

requirements in this regulation:

An analysis of the source’s impact on total air quality to ensure compliance with the NAAQS and 

the applicable maximum allowable increase over the baseline concentration in any area, per 40 

CFR 52.21(k);

Ambient air quality analysis per 40 CFR 52.21(m); and 

An analysis of source related growth impacts as well as an analysis of the impairment to soils, 

vegetation, and visibility per 40 CFR 52.21(o).

4.3. NEW SOURCE PERFORMANCE STANDARDS (NSPS)

NSPS require new, modified, or reconstructed sources in applicable source categories to control 

emissions to the level achievable by the best demonstrated technology as specified in the applicable 

provisions. A regulatory applicability determination and a summary of potentially applicable NSPS 

subparts for the equipment associated with the proposed EGOM Exploratory Project operations are 

provided in the following subsections.

4.3.1. 40 CFR Subpart A – General Provisions

All affected sources subject to an NSPS are also subject to the general provisions of NSPS Subpart A unless 

specifically excluded by the source-specific NSPS. NSPS Subpart A requires the following of facilities 

subject to a source-specific NSPS:

Initial construction/reconstruction notification

Initial startup notification

Performance tests

Performance test date initial notification

General monitoring requirements

General recordkeeping requirements

Semiannual monitoring system and/or excess emission reports

General control device and work practice requirements

Source-specific NSPS provisions can supersede NSPS Subpart A as noted in the relevant NSPS Subpart.

4.3.2. 40 CFR Subpart K- Standards of Performance for Storage Vessels for 

Petroleum Liquids

NSPS Subpart K, Standards of Performance of Storage Vessels for Petroleum Liquids for which 

Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 
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1978, provides standards of performance for storage vessels for petroleum liquids with a storage 

capacity greater than or equal to 40,000 gallons but less than 65,000 gallons for which the construction 

or modification is commenced after March 8, 1974 and prior to May 19, 1978. Requirements of this 

Subpart also apply to storage vessels with a capacity greater than 65,000 gallons for which construction 

or modification commenced after June 11, 1973 and prior to May 19, 1978.

All storage tanks represented in this application are exempt from NSPS subpart K since all of them were 

constructed after 1978.

4.3.3. 40 CFR 60 Subpart Ka – Standards of Performance for Storage Vessels for 

Petroleum Liquids 

NSPS Subpart Ka, Standards of Performance of Storage Vessels for Petroleum Liquids for which 

Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 

1984, provides standards of performance for storage vessels for petroleum liquids with a storage 

capacity greater than or equal to 40,000 gallons for which construction is commenced after May 18, 

1978 and prior to July 23, 1984.4

All storage tanks represented in this application are exempt from NSPS subpart Ka since all of them 

were constructed after 1984.

4.3.4. 40 CFR 60 Subpart Kb- Standards of Performance for Volatile Liquid 

Storage Vessels

NSPS Subpart Kb, Standards of Performance of Volatile Organic Liquid Storage Vessels (Including 

Petroleum Liquid Storage Vessels) for which Construction, Reconstruction, or Modification Commenced 

After July 23, 1984, provides standards of performance for storage vessels storing petroleum liquids with 

a capacity of greater than or equal to 75 m3 (19,812 gallons) for which construction, reconstruction, or 

modification is commenced after July 23, 1984.5

All bulk fuel storage tanks in this project were constructed after 1984 and hence are potentially subject 

to NSPS Subpart Kb. However, per 40 CFR 60.110(b) these tanks are exempt from the requirements of 

NSPS Subpart Kb. Table 4-1 lists all tanks in this project that were constructed after 1984 and includes 

the non-applicability determination for each tank with NSPS Subpart Kb.

Table 4-1. NSPS Subpart Kb Applicability Determination for Fuel Storage Tanks

 

4 40 CFR 60.110a(a)

5 40 CFR 60.110b(a)
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Tank ID Description

Capacity 

of the 

Tank (m3)

NSPS Subpart Kb 

Non-applicability 

Determination

DR-FT-01 No. 1 Fuel Oil Storage Tank (Port) 657

Per 40 CFR 60.110b(b), 

NSPS Subpart Kb does not 

apply to storage tanks with 

a capacity greater than or 

equal to 151 m3 storing a 

liquid with a maximum 

true vapor pressure less 

than 3.5 kPa (0.5 psia). 

These tanks store diesel 

fuel which has a vapor 

pressure lesser than or 

equal to 0.012 psi at 78  ̊F 

based on Tank 4.0.9d 

program.

DR-FT-02 No. 1 Fuel Oil Storage Tank (Starboard) 657

DR-FT-03 No. 2 Fuel Oil Storage Tank (Port) 1485

DR-FT-04 No. 2 Fuel Oil Storage Tank (Starboard) 1485

DR-FT-05 No. 3 Fuel Oil Storage Tank (Port) 1439

DR-FT-06 No. 3 Fuel Oil Storage Tank (Starboard) 1439

SB-DT-05 Vessel's Diesel Fuel Storage Tank #3 Port 161

SB-DT-06 Vessel's Diesel Fuel Storage Tank #3 Starboard 161

SB-DT-07 Vessel's Diesel Fuel Storage Tank #4 Port 160

SB-DT-08 Vessel's Diesel Fuel Storage Tank #4 Starboard 160

AB-DT-12 Starboard Wing Diesel Fuel Tank #2 148

AB-DT-13 Port Side Double Bottom Diesel Fuel Tank #4 107

AB-DT-14 Starboard Side Double Bottom Diesel Fuel Tank #5 107

AB-DT-10 Port Wing Diesel Fuel Tank #2 202

AB-DT-11 Starboard Side Double Bottom Diesel Fuel Tank #4 209

DR-FT-09 No. 1 Fuel Oil Servicing Tank (#1 E/R) 31

Per 40 CFR 60.110b (a), 

NSPS Subpart Kb does not 

apply to storage tanks with 

capacity less than 75 m3.

DR-FT-10 No. 2 Fuel Oil Servicing Tank (#1 E/R) 31

DR-FT-11 No. 1 Fuel Oil Servicing Tank (#2 E/R) 31

DR-FT-12 No. 2 Fuel Oil Servicing Tank (#2 E/R) 31

DR-FT-13 No. 1 Fuel Oil Servicing Tank (#3 E/R) 35

DR-FT-14 No. 2 Fuel Oil Servicing Tank (#3 E/R) 35

DR-FT-15 Fuel Oil Over Tank 46

DR-FT-16 Fuel Oil Leak Tank 23

DR-FT-17 Helicopter Fuel Tank 1 2.9

DR-FT-18 Helicopter Fuel Tank 2 2.9

Per 40 CFR 60.110b(a), 

NSPS Subpart Kb does not 

apply to storage tanks with 

capacity less than 75 m3.

SB-DT-09 Vessel's Diesel Fuel Storage Tank #5 Port 24.88

SB-DT-10 Vessel's Diesel Fuel Storage Tank #5 Starboard 27.79

SB-DT-11 Vessel's Diesel Fuel Storage Day Tank #1 Port 22.81

SB-DT-12 Vessel's Diesel Fuel Storage Day Tank #1 Starboard 34.63

SB-DT-13 Vessel's Diesel Fuel Stern Thruster Day Tank 5.66

SB-DT-14 Vessel's Diesel Fuel Overflow Port Storage Tank 16.66

SB-DT-15 Vessel's Diesel Fuel Overflow Standby Storage Tank 16.66

AB-DT-01 Port Side Double Bottom Diesel Fuel Tank #1 48.63

AB-DT-02 Starboard Side Double Bottom Diesel Fuel Tank #1 48.66

AB-DT-03 Center Double Bottom Diesel Fuel Tank #1 59.45

AB-DT-06 Port Wing Diesel Fuel Tank #1 61.78

AB-DT-07 Starboard Wing Diesel Fuel Tank #1 61.78

AB-DT-15 Port Service Diesel Tank 51.09

AB-DT-16 Starboard Service Diesel Tank 51.09

AB-DT-17 Port Diesel Settling Tank 51.95
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AB-DT-18 Starboard Diesel Settling Tank 51.95

AB-DT-19 Diesel Fuel Overflow Tank 13.98

DR-FT-07 No. 1 Fuel Oil Settling Tank (Starboard) 71 Per 40 CFR 60.110b(b), 

NSPS Subpart Kb does not 

apply to storage tanks with 

a capacity greater than or 

equal to 75 m3 but less 

than 151 m3 storing a 

liquid with a maximum 

true vapor pressure of less 

than 15 kPa (2.2 psia). 

These tanks store diesel 

fuel which has a vapor 

pressure lesser than or 

equal to 0.012 psi at

78  ̊F based on Tank 4.0.9d 

program.

DR-FT-08 No. 2 Fuel Oil Settling Tank (Port) 71

SB-DT-01 Vessel's Diesel Fuel Storage Tank #1 Port 143.92

SB-DT-02 Vessel's Diesel Fuel Storage Tank #1 Starboard 143.92

SB-DT-03 Vessel's Diesel Fuel Storage Tank #2 Port 145.46

SB-DT-04 Vessel's Diesel Fuel Storage Tank #2 Starboard 145.46

AB-DT-04 Port Side Double Bottom Diesel Fuel Tank #2 119.18

AB-DT-05 Starboard Side Double Bottom Diesel Fuel Tank #2 119.18

AB-DT-08 Port Side Double Bottom Diesel Fuel Tank #3 105.19

AB-DT-09 Starboard Side Double Bottom Diesel Fuel Tank #3

105.19

Well Completion Tanks 

DR-TP-24 Well Completion Condensate Tank 1 80

Per 40 CFR 60.110(d)(4), 

condensate tanks are 

exempt from the 

requirements of NSPS 

Subpart Kb since the tank 

volume is less than 

1,589.87m3, and 

condensate is stored prior 

to custody transfer.

DR-TP-25 Well Completion Condensate Tank 2 80

DR-TP-26 Well Completion Condensate Tank 3 80

4.3.5. 40 CFR 60 Subpart IIII – Stationary Compression Ignition Internal Combustion

NSPS Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion 

Engines, provides standards for manufacturers, owners, and operators of stationary compression 

ignition (CI) internal combustion engines (ICE). This subpart provides standards for owners and 

operators of stationary CI ICE that commence construction after July 11, 2005 where the stationary IC 

engines are:

Manufactured after April 1, 2006 and are not fire pump engines [40 CFR 60.4200(a)(2)(i)]; or 

Manufactured as a certified National Fire Protection Association (NFPA) fire pump engine after 

July 1, 2006 [40 CFR 60.4200(a)(2)(ii)].
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Table 4-2. Applicable Engines Subject to Subpart IIII 

EPN Description Manufacturing Year

Engine Rating 

(HP)

Displacement Per 

Cylinder

Drillship

Main Engines

DR-ME-01 Main Propulsion Electrical 

Generator Engine #1 2012

6,035 32.2

DR-ME-02 Main Propulsion Electrical 

Generator Engine #2 2012

6,035 32.2

DR-ME-03 Main Propulsion Electrical 

Generator Engine #3 2012

6,035 32.2

DR-ME-04 Main Propulsion Electrical 

Generator Engine #4 2012

6,035 32.2

DR-ME-05 Main Propulsion Electrical 

Generator Engine #5 2012

6,035 32.2

DR-ME-06 Main Propulsion Electrical 

Generator Engine #6 2012

6,035 32.2

DR-ME-07 Main Propulsion Electrical 

Generator Engine #7 2012

12,069 64.3

DR-ME-08 Main Propulsion Electrical 

Generator Engine #8 2012

12,069 64.3

Emergency Engines 

DR-GE-01 Emergency Generator April 2012 2,547 3.8

DR-AC-01 Emergency Air Compressor September 2011 38.5 0.9

4.3.5.1. Drillship Main Engines (DR-ME-01 through DR-ME-08)

Per 40 CFR 60.4200(a)(2)(i), the eight main engines on the drillship are subject to this regulation 

because they were manufactured after April 1, 2006. These engines are required to comply with the 

following requirements:

NOX and PM emission standards for owners and operators as outlined in 40 CFR 60.4204(c) 

Use of fuels that meet a maximum per-gallon sulfur content of 1,000 ppm [40 CFR 60.4207(d)].

Operation and maintenance requirements as specified in 40 CFR 60.4211(a). 

Initial and annual performance tests for NOX and PM, as well as continuous operating parameter 

monitoring per 40 CFR 60.4211(d), and 40 CFR 60.4213. 

Notification and recordkeeping requirements as specified in 40 CFR 60.4214.

Anadarko will comply with the NOX emission standard of 9.69 g/kw-hr and will comply with the PM 

emission standard of 0.15 g/kw-hr. Anadarko will demonstrate compliance with these standards during 

the initial performance test as required and will comply with notification and recordkeeping 

requirements. Furthermore, Anadarko will comply with the fuel sulfur content requirement by using 

ULSD, which has a maximum of 15 ppm sulfur content. Anadarko is proposing to install an emission 

monitoring system to comply with the requirements of 40 CFR 60.4211(d), and 40 CFR 60.4213. The 

details of the emission monitoring system will be submitted as they become available.
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4.3.5.2. Drillship Emergency Generator (DR-GE-01)

The drillship emergency generator is a 2011 model year with a displacement of less than 10 liters per 

cylinder CI engine. Per requirements of NSPS IIII for this category of engine, this engine must comply 

with emission limitations for new nonroad CI engines as specified in 40 CFR 89.112 and 40 CFR 89.113, 

for all pollutants. 

Currently, this engine is not certified as per requirements specified in the 40 CFR 89.112. However, this 

engine is compliant with IMO Tier II standard, which is more commonly applicable standards for a non 

U.S. flagged vessels such as the BlackHornet. Since certification is an engine manufacturer process, it is 

not possible for these engines to obtain an EPA Tier certificate. The IMO Tier II standard only limits 

emissions of NOX and the NOX emission standard for this engine is less conservative than the EPA Tier 2 

standard for this engine. Hence this engine currently does not comply with the EPA Tier 2 standards. 

Since an EPA Tier 2 certified engine is the only compliance option available to meet the requirements of 

40 CFR 60 Subpart IIII for this category of engines, a new engine would have to be purchased and 

installed by the operator to replace the existing engine to comply with NSPS IIII.

Pursuant to 40 CFR § 55.7, the EPA may grant an exemption from a part 55 requirement, if the 

Administrator or the delegated agency finds that compliance is technically infeasible or will cause an 

unreasonable threat to health and safety. Since the existing emergency generator was sized to meet the 

drillship’s stringent space and weight distribution requirements in the vessel’s design phase, any 

replacement engine would have to meet similar physical characteristics and restrictions dictated by the 

vessel’s design. It is very difficult, if not impossible, to find a replacement EPA Tier 2 certified engine 

meeting the constraints discussed above. Moreover, such a replacement will require significant 

redesign and recertification of the drillship.

As shown in Table 4-3 and Table 4-4 below, the emergency engine’s emission levels for NOX and PM are 

higher than that of the EPA Tier 2 emissions standards. Given the minimal operations of this equipment 

resulting in low emissions, Anadarko believes that replacement of the existing emergency engine with 

an EPA Tier 2 certified engine is cost prohibitive and therefore, requests an exemption from the 

requirements of 40 CFR Subpart IIII for the emergency generator engine.

Table 4-3. Emergency Generator Offset Requirements

Pollutant

PTE Emissions 

(g/KW-hr)

EPA Tier 2 Standard 

(g-KW-hr)

Emission 

Offsets 

Required

NOX + NMHC 10.1 6.4 Yes

CO 0.38 3.5 No

PM 0.43 0.2 Yes

Notes: 

1) Vendor supplied CO emissions data are less than Tier 2 emission standards for CO.

2) Vendor data unavailable for PM emissions, therefore Anadarko proposed PTE 

calculations for PM are based on AP-42 factor.
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Table 4-4. Emergency Generator Residual Emissions

Pollutant PTE Emissions (tpy) EPA Tier 2 (tpy)

Residual 

Emissions 

(tpy)

NOx + NMHC 1.51 0.96 +0.55

CO 0.57 0.57 --

PM 0.004 0.001 +0.003

4.3.5.3. Drillship Emergency Air Compressor (DR-AC-01)

Since the emergency air compressor engine is a post 2007 non-fire pump emergency CI engine less than 

50 HP with a displacement of less than 10 L per cylinder, this engine must comply with emission 

limitations for new nonroad CI engines as specified in 40 CFR 89.112 and 40 CFR 89.113. Table 1 of 40 

CFR 89.112(a) requires the engine to comply with the following EPA Tier 2 exhaust emission standards: 

NOX – 7.5 g/kw-hr

CO – 5.5 g/kw-hr

PM – 0.6 g/kw-hr

Additionally, the emergency air compressor must comply with the following exhaust opacity limits 

specified in 40 CFR 89.113(a):

20% during acceleration mode

15% during the lugging mode

50% during the peaks in acceleration or lugging modes

Since the emergency air compressor is an EPA Tier 2 certified engine compliance with the above 

mentioned emission standard is demonstrated. In addition, the emergency air compressor must comply 

with the diesel fuel requirements for nonroad diesel under 40 CFR 80.510(b) for 15 ppm sulfur content, 

a minimum cetane index of 40 or a maximum aromatic content of 35 volume percent. Anadarko will 

comply with the specified fuel requirements by using ULSD for all diesel combustion sources. 

4.3.5.4. Drillship Temporary Third Party Well Evaluation Engines (DR-TP-12 

through DR-TP-16)

Per 40 CFR 60.4200(a)(2)(i), above mentioned CI engines are not subject to this regulation because the 

engines were not manufactured after April 1, 2006. Also, these engines were not constructed, modified, 

or reconstructed after July 11, 2005. 

4.3.5.5. Stimulation Vessel Pumps (SV-PE-01 through SV-PE-08)

The only sources utilized for the well completion activity which are potentially subject to NSPS subpart 

IIII are eight pumps (SV-PE-01 thru SV-PE-08) on the Stimulation Vessel
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Per 40 CFR 60.4200(a)(2)(i), all the engines above are not subject to this regulation because the engines 

were not manufactured after April 1, 2006. Also, these engines were not constructed, modified, or 

reconstructed after July 11, 2005. 

With regard to the pumps on the stimulation vessel, they are “representative” pumps only (i.e., available 

at the time of this report preparation), and Anadarko may replace these engines with substitute engines 

with equal or lesser emissions. Therefore, in cases where the substitute engines are subject to 40 CFR

60 Subpart IIII, Anadarko will comply with all applicable requirements.

4.3.6. 40 CFR 60 Subpart JJJJ – Stationary Spark Ignition Internal Combustion

NSPS Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion Engines, 

provides standards for manufacturers, owners, and operators of stationary spark ignition (SI) ICE. For 

emergency engines with a maximum power greater than 25 HP, this subpart provides standards for 

owners and operators of stationary SI ICE that commence construction after June 12, 2006, where the 

stationary SI ICE are manufactured on or after July 1, 2009 [40 CFR 60.4230(a)(4)(iv)]. This subpart is 

also applicable to owners and operators of stationary SI ICE that modify or reconstruct their stationary 

SI ICE after June 12, 2006 [40 CFR 60.4230(a)(5)].

There are no stationary SI engines proposed for this project. Therefore, NSPS Subpart JJJJ does not apply 

to any source included in this permit application.

4.3.7. 40 CFR 60 Subpart Dc – Standards of Performance for Small Industrial –

Commercial – Institutional Steam Generating Units

A typical flowback boiler ("SIGMA FIRED" SF-200SE or equivalent) will be used for the well completion 

activity. Based on the firing capacity, it could be potentially subject to 40 CFR 60 Subpart Dc. 

Per 40 CFR 60.40c(a), owners and operators of each steam generating unit for which construction, 

modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat 

input capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)) or less, 

but greater than or equal to 2.9 MW (10 MMBtu/hr) should comply to standards in the subpart. 

The maximum design heat input capacity of the proposed flowback boiler is 8 MMBtu/hr which is less 

than 10 MMBtu/hr. Therefore, NSPS Subpart Dc does not apply to this equipment. 

4.4. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

(NESHAP - 40 CFR PART 61)

Per 40 CFR 55.13(e), 40 CFR Part 61 together with any other provisions promulgated pursuant to 

section 112 of the Clean Air Act shall apply to OCS sources if rationally related to the attainment and 

maintenance of federal or state ambient air quality standards or the requirements of part C of title I of 

the Clean Air Act (PSD).
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4.4.1. 40 CFR 61 Subpart A- General Provisions 

40 CFR 61 Subpart A provides the general provisions to which each source subject to another Part 61 

subpart must comply unless specifically excluded by the applicable subpart. These provisions include 

initial notification and performance testing, recordkeeping, and monitoring requirements for all other 

subparts as applicable. Part 61 applies to owners or operators of any stationary source for which a 

pollutant-specific standard is prescribed under this part. There are no subparts under the 40 CFR Part 

61 that applies to the exploratory drilling operations proposed in this application.

4.5. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS

(NESHAP – 40 CFR PART 63)

NESHAP apply to major sources of HAP or specifically designated area sources of HAP. A HAP major 

source is defined as having potential emissions in excess of 10 tons per year for any individual HAP 

and/or 25 tons per year for total HAPs. The proposed project results in an area source of HAP, because 

potential HAP emissions are less than the major source thresholds. Potentially applicable NESHAP 

subparts are discussed below.

4.5.1. 40 CFR 63 Subpart A – General Provisions 

All affected sources are subject to the general provisions of Part 63 NESHAP Subpart A unless 

specifically excluded by the source-specific NESHAP. These provisions include initial notification and 

performance testing, recordkeeping, reporting, monitoring, and control device and work practice 

standards for all other subparts as applicable. 

4.5.2. 40 CFR 63 Subpart ZZZZ – Stationary Reciprocating Internal Combustion 

Engines

NESHAPs Subpart ZZZZ, National Emission Standards for Hazardous Air Pollutants for Stationary 

Reciprocating Internal Combustion Engines, provides national emission limitations and operating 

limitations for HAPs emitted from stationary reciprocating internal combustion engines (RICE) 

located at major sources and area sources of HAP emissions. Anadarko's proposed exploratory 

drilling operations will be an area source for HAPs and therefore this Subpart would be potentially 

applicable.

Per CFR 63.6590(a)(1)(iii), stationary RICE located at an area source of HAP emissions would be 

defined as an existing source under the requirements of this Subpart if the construction or 

reconstruction of the stationary RICE is commenced before June 12, 2006. The third party well

evaluation engines (DR-TP-12 through DR-TP-16) qualify as existing non-emergency stationary RICE 

under 40 CFR 63, Subpart ZZZZ. These engines will be subject to the following requirements:

Operate and maintain the stationary RICE and after-treatment control device (if any) 

according to the manufacturer's emission-related written instructions or develop own 

maintenance plan which provides to the extent practicable for the maintenance and 

operation of the engine in a manner consistent with good air pollution control practice 

for minimizing emissions [40 CFR 63.6625(e)].

Minimize the engine's time spent at idle during startup and minimize the engine's 
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startup time to a period needed for appropriate and safe loading of the engine, not to 

exceed 30 minutes, after which time the non-startup emission standards apply [40 

CFR 63.6625(h)].

Comply with the recordkeeping requirements of 40 CFR 63.6655(e).

Comply with the management practices applicable requirements in Table 2d of this 

Subpart:

 change oil and filter every 1,000 hours of operation or annually, whichever 

comes first;

 inspect air cleaner every 1,000 hours of operation or annually, whichever 

comes first, and replace as needed; and

 inspect all flexible hoses and belts every 500 hours of operation or annually, 

whichever comes first, and replace as needed.

Per 40 CFR 63.6660, records of management practices discussed above need to be kept 

in readily accessible hard or electronic form for at least 5 years following the date of 

each maintenance activity. At a minimum, the most recent 2 years of data shall be 

retained on site and the remaining 3 years of data may be retained off site.

The following engines on the Drillship qualify as new stationary RICE under this regulation because the 

engines were constructed after June 12, 2006.

Drillship Main engines (DR-ME-01 through DR-GE-08)

Drillship Emergency Generator (DR-GE-01)

Drillship Emergency Air Compressor (DR-AC-01)

Pursuant to § 63.6590(c)(1) of this subpart, a new CI RICE located at an area source must comply with 

40 CFR part 60, subpart IIII, and no further requirements apply for such engines under 40 CFR part 63. 

Therefore, the engines will comply with 40 CFR part 60, subpart IIII, and will not be subject to any 

further requirements under this subpart.

4.5.3. 40 CFR 63 Subpart HHHHHH – Paint Stripping and Miscellaneous Surface 

Coating Operations at Area Sources

NESHAPs Subpart HHHHHH provides national emission limitations and operating limitations for HAPs 

emitted from paint stripping and miscellaneous surface coating operations performed at area sources of 

HAP emissions. 

Anadarko's proposed exploratory drilling operations will be an area source for HAPs and therefore this 

Subpart would be potentially applicable. The spray painting operation performed on the drillship is part 

of the routine maintenance to protect the vessel from the harsh environment so that the drillship 

functions in its intended capacity. Therefore, this activity meets the definition of “facility maintenance” 

provided in 40 CFR 63.11180. Pursuant to 40 CFR 63.11170(a)(3), spray painting operations on the 

drillship are not subject to the requirements of this regulation.

4.6. FEDERAL OPERATING PERMITS PROGRAM (40 CFR PART 71)

The Federal Operating Permits Program (40 CFR 71) sets forth the comprehensive Federal air quality 

operating permits permitting program consistent with the requirements of Title V of the Clean Air Act 
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and defines the requirements and the corresponding standards and procedures by which the 

Administrator will issue operating permits.6 Using the procedures of 40 CFR 71, the Administrator will 

issue permits to any source which is an OCS source that is located beyond 25 miles of States' seaward 

boundaries, as defined under 40 CFR 55.2.7 

A major source is defined under 40 CFR 71 as, “A major stationary source of air pollutants or any group 

of stationary sources as defined in section 302 of the CAA, that directly emits, or has the potential to 

emit, 100 tpy or more of any air pollutant.”8 Per this definition, the proposed project is a major source 

under 40 CFR 71 and shall obtain a Title V Operating Permit. 

All major sources under this subpart shall be subject to the general monitoring, recordkeeping, and 

reporting requirements as provided under 40 CFR 71, unless otherwise specified. In addition, each Part 

71 source is required to submit an annual report containing the actual emissions for the preceding 

calendar year, a fee calculations work sheet, and a full payment of the annual fee as required under 40 

CFR 71.9(h). Anadarko will comply with the requirement to submit annual emission report and pay 

such annual fees as required. 

4.7. ENDANGERED SPECIES ACT

Under Section 7 of the Endangered Species Act (ESA), 16 U.S.C. § 1536, EPA has a responsibility to 

ensure that any action authorized or permitted by EPA is not likely to jeopardize the continued 

existence of any federally-listed endangered or threatened species or result in the destruction or 

adverse modification of such species’ designated critical habitat. If EPA’s action (i.e., permit issuance) 

may affect a federally-listed species or critical habitat, Section 7 of the ESA sets up a procedure for 

consultation between EPA and U.S. Fish and Wildlife Service (USFWS) and/or the National Oceanic and 

Atmospheric Administration’s National Marine Fisheries Service (NMFS). 

BOEM issued an environmental assessment (EA) for the Central and Western Planning Areas in 2012 

(Post Macondo Oil Spill). Currently, BOEM is preparing a draft for the Eastern Planning Area which is 

expected to be completed by the end of 2013. Per a discussion between Trinity and the National Oceanic 

and Atmospheric Administration (NOAA) 9, no new protected species have been listed in the Gulf of 

Mexico since the 2007 biological opinion; hence, no further action is required from Anadarko to 

demonstrate compliance

 

6 40 CFR 71.1(a)

7 40 CFR 71.4(d)(1)

8 40 CFR 71.2

9 Per phone email communication with Mr. Rahul Pendse and Mr. Adam Brame on 08/06/2013 
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5. BACT ANALYSIS

As required by 40 CFR §52, Best Available Control Technology (BACT) must be applied to reduce or 

eliminate air emissions from a new or modified facility. PSD BACT is defined 40 CFR §52.21(b)(12) as:

“An emissions limitation (including a visible emission standard) based on the maximum degree of reduction 

for each pollutant subject to regulation under Act which would be emitted from any proposed major 

stationary source or major modification which the Administrator, on a case-by-case basis, taking into 

account energy, environmental, and economic impacts and other costs, determines is achievable for such

source or modification through application of production processes or available methods, systems, and 

techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of 

such pollutant. In no event shall application of best available control technology result in emissions of any 

pollutant, which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 

and 61. If the Administrator determines that technological or economic limitations on the application of 

measurement methodology to a particular emissions unit would make the imposition of an emissions 

standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may 

be prescribed instead to satisfy the requirement for the application of best available control technology. 

Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation 

of such design, equipment, work practice or operation, and shall provide for compliance by means which 

achieve equivalent results.”

EPA has developed a “top-down” process that can be used to ensure that a BACT analysis satisfies the 

applicable legal criteria. Presented below are the five basic steps of a top-down BACT review as 

identified by the EPA.10

STEP 1 – IDENTIFY ALL CONTROL TECHNOLOGIES

Step 1 of the top-down approach requires that all available control options that are potentially 

applicable to the proposed source are identified. It is the applicant’s responsibility to identify available 

control options by consulting the EPA’s Reasonably Available Control Technology (RACT)/BACT/Least 

Achievable Emission Rate (LAER) clearinghouse (RBLC), along with other reliable sources. Viable 

control options are those technologies that have a practical potential for application to the emissions 

unit and the regulated pollutant under evaluation.

STEP 2 – ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

Step 2 of the top-down approach allows for the elimination of control options that are technically 

infeasible. Also, each technology should be “demonstrated” (previously installed and operated 

successfully on a similar facility); or if undemonstrated, then the applicant must determine whether the 

technology is both “available” and “applicable.” Technologies identified in Step 1 that are neither 

demonstrated nor found to be both available and applicable are eliminated under Step 2.

STEP 3 – RANK REMAINING CONTROL TECHNOLOGIES

Step 3 of the top-down approach requires ranking of the remaining control technologies based on 

control effectiveness. If there is only one remaining option or if all of the remaining technologies could 

achieve equivalent control efficiencies, ranking based on control efficiency is not required.

 

10 U.S. EPA. Draft New Source Review Workshop Manual, Chapter B. Research Triangle Park, North Carolina, October 1990.
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STEP 4 – EVALUATE MOST EFFECTIVE CONTROLS

Step 4 of the top-down approach allows for the elimination of control options based on collateral 

impacts. In descending order, the applicant should evaluate and compare the collateral impacts of each 

control option. The permitting authority (EPA) has discretion on weighting each area of collateral 

impact. This step validates the suitability of the top control option identified or provides a clear 

justification as to why the top option should not be selected as BACT. Costs of installing and operating 

control technologies are estimated and annualized following the methodologies outlined in the U.S. 

EPA’s OAQPS Control Cost Manual (CCM).11

STEP 5 – SELECT BACT

Step 5 of the top-down approach requires selection of BACT for the emissions unit and the regulated 

pollutant under evaluation. The most effective control alternative not eliminated in Step 4 is selected as 

BACT with a corresponding emission limit established. The selection of BACT in the fifth step involves 

an evaluation of emission rates achievable with the selected control technology. BACT is an emissions 

limit unless technological or economic limitations of the measurement methodology would make the 

imposition of an emissions standard infeasible, in which case a work practice or operating standard can 

be imposed. Selected BACT can be no less stringent than an applicable NSPS, MACT, or RACT.

The emissions of NOX, CO, PM, PM10, PM2.5, VOC, and GHG exceed the applicable SERs. Therefore PSD 

BACT must be determined for each emission unit at the facility that emits NOX, CO, PM, PM10, PM2.5, VOC 

or GHG when conducting the proposed operations.

The emission sources on the drillship subject to BACT analysis are as listed below:

Eight main engines (DR-ME-01 to DR-ME-08)

One emergency generator (DR-GE-01)

One emergency air compressor engine (DR-AC-01)

Third party engines: 

Third party EPA Tier II certified engines ≤860 HP (DR-TP-01 and Dr-TP-02)

Third party EPA Tier II certified engines ≤300 HP (DR-TP-03 to DR-TP-11)

Third party well evaluation engines ≤140 HP (DR-TP-12 to DR-TP-16 and 

SB-TP-05 to SB-TP-09)

Third party EPA Tier II certified engines ≤126 HP (DR-TP-17 to DR-TP-21)

One flowback boiler (DR-TP-22)

One boom flare (DR-TP-23)

Fuel storage tanks (several EPNs)

Painting (DR-PO-01)

Welding (DR-WO-01)

Under certain operating scenarios, the following sources of air pollution will constitute stationary 

source aspects of the vessels when the support vessels are physically attached to the OCS source; hence, 

BACT analysis is performed for these sources.

Fuel Storage Tanks on the supply boats and the anchor handling boat (several EPNs)

 

11 Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, Sixth Edition, EPA 452-02-001 

(http://www.epa.gov/ttn/catc/products.html#cccinfo), Daniel C. Mussatti & William M. Vatavuk, January 2002.
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Eight pump engines on the Stimulation Vessel (SV-PE-01 thru SV-PE-08)

The life boats (DR-LB-01 and DR-LB-06) and the fast rescue boat (DR-FR-01) are included in the PTE 

calculations and air dispersion modeling as specified in 40 CFR part 55 and these sources are subject to 

operating limits, monitoring, recordkeeping and reporting requirements to ensure they will not exceed 

the potential emissions assumed in the application and impact review. Per 40 CFR § 55.2, the support 

vessels operating within 25 miles of the OCS source are not subject to BACT requirements unless they 

are attached to the OCS. If attached, only the stationary source aspects of the vessel are regulated. 

These units do not have any stationary source aspects with respect to BACT subject pollutant emissions, 

as they are used for man overboard and emergency escape scenarios only.

5.1. NOX BACT ANALYSIS 

The emission sources of NOX on the drillship subject to BACT analysis are as listed below:

Eight main engines (DR-ME-01 to DR-ME-08)

One emergency generator (DR-GE-01)

One emergency air compressor engine (DR-AC-01)

Third party engines: 

 Third party EPA Tier II certified engines ≤860 HP (DR-TP-01 and DR-TP-02)

 Third party EPA Tier II certified engines ≤300 HP (DR-TP-03 to DR-TP-11)

 Third party well evaluation engines ≤140 HP (DR-TP-12 to DR-TP-16 and 

SB-TP-05 to SB-TP-09)

 Third party EPA Tier II certified engines ≤126 HP (DR-TP-17 to DR-TP-21)

One flowback boiler (DR-TP-22)

One boom flare (DR-TP-23)

Eight pump engines on the Stimulation Vessel (SV-PE-01 thru SV-PE-08)

5.1.1. NOX BACT Analysis for the Drillship Main Engines (DR-ME-01 to DR-ME-08)

Deepwater drilling with a dynamically positioned drillship presents a unique set of challenges in

managing power while conducting work. The drillship is designed to operate in deep water in highly 

variable operational and environmental conditions. The need for power redundancy to manage the 

operating risks affects the power use levels, which in turn affects the air emissions.

The main propulsion engines are used to power the thrusters that hold the ship on location, as well as 

power the drilling equipment and other operational needs of the ship. The main propulsion engines 

operate at variable loads based on drilling and operational power demand, and extensive “reserve” 

power is required to adjust for loop currents and storms which can cause large variations in thruster 

power used. Hence, NOX emissions are not emitted from these engines at a steady state. These factors 

are important considerations in the BACT analysis for these engines.

Step 1 – Identify all Control Technologies

The first step in the EPA top-down, five-step analysis is to identify all available control technologies that 

are potentially suitable for the affected sources. EPA's RBLC search was used to obtain potential control 
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technologies for NOX from main propulsion engines at offshore sources. The most recent 10-year period 

was used to identify applicable control technologies. The results of the RBLC search are included in 

Appendix E. However, it should be noted that the control technologies evaluated in the “topdown” 

analysis for main engines were not limited to the controls listed in the RBLC database. The permits 

recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit applications) 

for similar OCS sources in Gulf of Mexico have also been reviewed in addition to surveying available 

literature to identify potential control technologies. The search results for potential control 

technologies for NOX from the main engines are listed below.

1. Selective Catalytic Reduction (SCR)

2. Selective Non-Catalytic Reduction (SNCR)

3. Direct Water Injection (DWI)

4. Exhaust Gas Recirculation (EGR)

5. Derate Engines

6. Water-in-fuel Emulsions 

7. Intake Air Humidification/Cooling 

8. NOX Adsorber

9. CSNOx Emissions Abatement System

10. Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042)

11. CAM Shaft Replacement/ Retooling of Engines

12. Lean De-NOX Catalyst (LNC) or Hydrocarbon SCR (HC-SCR)

13. Low NOX Engine (LNE) design 

14. Performance management system including Turbocharger with Aftercooler and High Fuel 

Injection Pressure System

15. 4-Way Catalyst Converter

16. Good Combustion and Manufacturer Recommended Maintenance Practices

17. Ignition Timing Retard (ITR) 

Step 2 – Eliminate Technically Infeasible Option

SCR – Infeasible.

SCR is a post-combustion NOX control technology. In SCR, ammonia (NH3) or urea diluted with air or 

steam is injected into the flue gas upstream of a catalytic reactor. The catalyst bed operates at 

temperatures between 600 and 800 °F, depending on the catalyst. On the catalyst surface, the NH3

reacts with NOX to form molecular nitrogen and water.

The primary variable affecting NOX reduction is temperature of the gas stream. If operating below the 

optimum temperature range, the catalyst activity is reduced allowing unreacted NH3 to slip through. If 

operating above the optimum temperature range, NH3 is oxidized, forming additional NOX and the 

catalyst may suffer thermal stress damage.

The highly variable power use inherent to operations on a dynamically positioned drillship creates 

circumstances that are unfavorable for the SCR process. The power load variability requires a 

corresponding high level of power redundancy to ensure reliable station keeping. This redundancy can 

result in lower levels of power capacity used over extended periods (e.g. during strong loop currents or
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winter storms). When the engines are run at lower capacity, the engine exhaust temperatures can drop 

to levels that reduce the effectiveness of SCR technology. 

Urea slip rates can occur that do not allow the catalytic reduction of NOX to the predicted levels. The 

volume of urea required for optimal SCR performance is substantial; approximately 20 to 25 g of urea 

solution/KW-hr engine output. Hence, additional tanks would be added onboard for urea storage. Since 

these additional storage tanks were not a part of initial drillship design, addition of these tanks will 

require considerable redesign to ensure load balancing and other critical criteria are complied with. 

Moreover, since limited space is available for critical drilling equipment, tubulars and consumables, the 

handling and storage of urea onboard presents difficult operational challenges.

Although SCR technology has been utilized at onshore sources, it has not been successfully proven as a 

viable control technology for sources such as main engines on the drillship. This technology has been 

proven successful for steady state load conditions. However, due to nature of operations, main engines 

on the drillship have frequent load variations, which could significantly impact emission control 

efficiency of SCR technology.

While the accommodation of SCRs is less difficult in the design stage of a drillship, post design addition 

of SCRs would require significant space reassignment and will impact deck load capacity and stability 

(i.e., center of gravity) of the currently designed drillship. However for completeness, Anadarko is 

including the cost analysis for SCR installation below which reaffirms the cost prohibitive nature of 

installing an SCR. 

SNCR – Infeasible.

This technology is technically infeasible to operate on the main engines of the BlackHornet drillship. 

This method of NOX reduction introduces new compounds (most commonly ammonia or urea) to the 

diesel exhaust which break down NOX molecules into nitrogen and oxygen, much like an SCR. SNCR 

systems can realize NOX reductions of 60%, but only at temperatures greater than 1,700 °F. At lower 

temperatures, the reaction proceeds too slowly, resulting in unused ammonia emitting from the stack. 

Because this temperature is well above the exhaust gas temperature range of the main engines, this 

option was not deemed to be technically feasible for this application.

In addition, this technology is also infeasible for the reasons provided for SCR above, pertaining to urea 

storage requirements and significant structural changes that will impact deck load capacity and stability. 

Due to the reasons discussed above, this technology is deemed as technologically infeasible. 

DWI – Infeasible.

This control technology involves reduction in combustion temperature by mixing steam or water with 

the air flow. Steam or water acts as a heat sink to reduce peak temperatures, thereby reducing the 

formation of NOX. NOX reductions of 25-35 percent can be achieved with water injection.12 This 

technology is in development stages for marine applications and cannot be used reliably at low loads (30-

50%) or variable loads. 

 

12 Based on Memorandum from Tanya Parise, Alpha-Gamma Technologies, Inc. to Sims Roy, EPA OAQPS ESD Combustion 

Group, titled NOx Control Technologies for Stationary Diesel ICE.
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Also, fresh water is necessary for this NOX reduction technology. Introducing salt water into the engines 

could result in serious deterioration due to corrosion and fouling. For this reason, implementing this 

strategy would require either production of fresh water through the use of desalination or distillation 

system or the storage of fresh water on board. Therefore, either pure water storage tanks would need to 

be constructed or the alternative of installing a desalination or distillation unit would incur additional 

costs for the unit. Both alternatives would also require additional space and would potentially require 

recertification of the vessel. 

Another concern with the use of water in the combustion process is the effect on PM/PM10/PM2.5 

emissions. The water in the cylinder reduces NOX, which is formed at high temperatures, by reducing 

the temperature in the cylinder during combustion. However, PM/PM10/PM2.5 oxidation is most efficient 

at high temperatures. Therefore, while water injection may lead to reduction in NOX emissions, there 

may be an increase in PM/PM10/PM2.5 emissions. There is also a potential for engine damage to occur as 

a result of the water contacting the combustion cylinder surface causing disintegration of lubricating oil 

film. Due to the reasons discussed above, this technology is deemed as technologically infeasible. 

EGR – Infeasible.

EGR works by re-circulating a fraction of an engine's exhaust gas back to the engine cylinders. In this 

technology, the amount of oxygen in the air/fuel mixture is reduced causing the engine to run less lean. 

This in turn lowers the operating temperature of the engine. Because NOX formation increases at higher 

temperature, a reduction in the operating temperature will result in a reduction in NOX formation. 

Applying EGR to a diesel RICE can reduce the power that is generated by the engine. This is because the 

EGR system reduces the specific heat ratio of the combustion gases in the power stroke, which in turn 

reduces the amount of power or work that can be extracted by the piston. The reduction in power 

generation could lead to potential safety hazards. 

Applying EGR may reduce the amount of fuel that is completely combusted thereby increasing the 

PM/PM10/PM2.5 emission rate. Due to the reasons discussed above, this technology is deemed as 

technologically infeasible. In addition, the technology is still under development for marine 

applications; hence, this technology is considered as technologically infeasible.

Derate Engines – Infeasible.

An engine can be derated by restricting its operation to lower levels of power than normal for the given 

application. Derating reduces cylinder pressures and temperatures and can lower NOX formation rates. 

Engine derating is accomplished by changing the injector nozzles with smaller holes to atomize the 

smaller amount of fuel used and the turbocharger nozzle rings can be allowed a lower exhaust gas spin 

the turbocharger faster, thus compressing a greater volume of air for a given volume of gas.

Derating reduces the engine's operating temperature, which can result in higher CO and VOC emissions. 

Further derating the engines will decrease the available power, which would cause an unreasonable 

safety risk. The safety concern would be that the drillship must have adequate power to handle storms 

(e.g., winter weather or hurricanes) and loop currents that periodically occur at the location. Due to the 

reasons discussed above, this technology is deemed as technologically infeasible.

Water-in-fuel Emulsions (emulsified diesel) – Infeasible.
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This technology would require derating of the engines, and emulsified diesel in marine vessels can cause 

fuel tank corrosion issues. Additionally, emulsified fuel systems were designed for and installed on 

slow-speed engines burning heavy fuel oil. The existing main engines on the BlackHornet drillship are 

designed and will be burning medium density fuel (diesel). Several significant engineering hurdles must 

be overcome in order to install a diesel/water emulsion system on board the BlackHornet drillship. 

The primary hurdle is the installation of a mixing tank. The current design of the drillship does not 

include a space for a mixing tank. The installation of a new tank would require extensive analysis, pipe 

fitting and modification to monitoring systems aboard the rig. The tank may also need to be pressurized 

to maintain the emulsion which would require the installation of booster pumps and the associated 

piping, power and monitoring systems inherent in such a configuration. The pressurized fuel would 

increase pressure head that already exists in the fuel lines and could lead to excessive fuel pressure to 

the engines. Over-pressurized fuel lines subjected to loads in excess of their design criteria would 

potentially fail with catastrophic results such as spilled fuel, engine room fires or worse. Such a problem 

would place the safety of the rig, personnel and environment in jeopardy. Installing an untested 

emulsified fuel system designed for heavy fuel oil use on the existing engines increases the potential for 

mechanical failure and poses a safety risk that is unacceptable for this project. Due to the reasons 

discussed above, this technology is deemed as technologically infeasible.

Intake Air Humidification/Cooling – Infeasible.

Intake Air Humidification consists of fogging or saturation of the intake air with water. These motors 

consist of evaporating water into the relatively hot scavenging air, which flows to the engine through the 

inlet air manifold. Installation of a Humid Air Motor (HAM) is an alternative to water injection currently 

being investigated by some diesel engine manufacturers.

Reductions in NOX emissions due to water injection can be expected using this technique but the long 

term effects of using seawater (if used) is not known. Such technology can require additional freshwater 

production and storage for humidification of the intake air. A high quantity of water need to be 

evaporated to create enough humid air to achieve the reductions sought, and are comparable with the 

fuel volumes. This requires heat input and is provided by heat exchange from the hot compressed air 

after the engine turbocharger. This implies that at low load there may not be sufficient heat, in which 

case the HAM system is not used. 

It is also hard to control the humidity adequately under varying loads (when it is most difficult to 

achieve optimum combustion). In addition, the technology is in development stages for marine 

applications, and not available for the main propulsion engines operating on the BlackHornet drillship. 

Therefore, considering the aforementioned reasons, Intake Air Humidification/Cooling is not technically 

feasible.

NOX Adsorber – Infeasible.

A NOX adsorber is a catalyst technology used to remove NOX in lean exhaust for diesel and gasoline fired 

engines. NOX adsorbers consist of ceramic monolith containing parallel channels, coated with precious

metal catalysts. During lean operation, NOX is stored in the form of nitrates produced by reactions 

between the NOx and catalyst. At regular intervals, a momentary reducing condition is produced inside 

the monolith by injecting reductant, causing the nitrates to decompose to nitrogen. 
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This technology has been used primarily for on-road diesel applications or off-road applications for 

smaller engines such as backhoes, graders, and wheel loaders. This technology is still a technology that 

is in experimental stages of development stages for marine applications.

CSNOx Emissions Abatement System – Infeasible.

This technology is currently in the licensing and commercial demonstration phases of development. 

This system is tested on engines operating at stable loads. While this technology is commercially 

available for certain types of marine uses, it has not been demonstrated in practice for variable load 

engines such as main engines on the drillship. Since significant research and development is required to 

design a working, deployable CSNOx system that is safe to operate on a drillship, this technology is 

considered technically infeasible. 

CAM Shaft Replacement/Retooling of Engines – Infeasible.

Clean Cam Technology Systems (CCTS) offers retrofit cam shaft reengineering kits for some diesel 

engines. The kits reduce NOX emissions by increasing the volume of the residual exhaust gas that 

remains in the combustion chamber after the power stroke.

CCTS cam shaft retrofit (Re-tooling) kits are only available for Detroit Diesel engines. This technology is 

only suitable for small engines since the cams are integral with the camshaft. The cams are mounted on 

the camshaft individually and can be easily replaced for smaller engines (most likely 2-stroke engines). 

However, it has not yet been developed for larger engines (e.g., 4- stroke). Therefore, it is not technically 

feasible for the main propulsion engines.

LNC or HC-SCR – Infeasible.

This technology is not commercially available for large marine engines of marine applications. Also, LNC 

systems operate best at consistent high loads, and are not amenable to load shifts. Therefore, it is not 

technologically feasible for the main engines.

Engine Replacement To Meet Higher Tier Standards (40 CFR Part 89, 94, or 1042) – Infeasible.

The main diesel engines meet the IMO Tier 2 standard of 9.7 g/Kw-hr for engines under Category 3 (i.e., 

>30 liter/cylinder displacement operating at 720 rpm). This emission standard is equal to the EPA Tier 

2 (40 CFR Part 1042) standards for NOX for this category of engine. Currently, there is no comparable 

engine available that meets lower emission standards without the use of add-on control technology. 

Therefore, replacement engines with higher Tier rating is not an option.

Moreover, certification to meet these standards is part of the inherent design of the engine and there is 

no upgrade available for an existing IMO Tier 2 certified engine to meet more stringent standards which 

will also require recertification from the engine manufacturer. Considering the aforementioned reason 

replacing the existing engine to meet a higher Tier standards is not a feasible option. 

4-Way Catalyst Converter – Infeasible.
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The main diesel engines will not be able to sustain constant steady state loads/exhaust temperatures for 

sufficient time periods that are critical for high catalyst performance, resulting in inconsistent emission 

control. Several non-combustible chemical elements that may be present in engine lube oils, such as 

phosphorous, lead and heavy metals, may collect over time and damage the catalyst. Therefore, it is not 

technically feasible for the main propulsion engines.

ITR – Infeasible.

Changing ignition timing is not an alternative for these engines due to intrinsic engine design. Alterations 

of the injection timing can impact value and turbo charger performance. Additionally, use of this 

technology can reduce engine power and combustion stability which can hinder operations. For these 

reasons this technology is infeasible for the main engines on BlackHornet drillship.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-1. Ranks of Technologies Feasible for Main Engines

Technology Efficiency Rank

SCR with Urea Injection 79%13 1

Performance management system including 

Turbocharger with Aftercooler and High Fuel 

Injection Pressure System

~30% 2

LNE design Baseline 3

Good Combustion and Manufacturer 

Recommended Maintenance Practices

Baseline N/A

All feasible technologies for the main propulsion engines are listed in Table 5-1. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

SCR – Based on the very conservative cost assumptions (i.e., low cost), the cost effectiveness analysis of 

SCR installation is estimated to be approximately $12,000 per ton of NOX reduced, making this option 

cost prohibitive. A detailed control cost effectiveness analysis is provided in Appendix E.

Performance Management System including Turbocharger with Aftercooler and High Fuel 

Injection Pressure System and Low NOx Design – The main engines are equipped with a performance 

management system (also called as “optimized supercharger with miller cycle technology” by the 

manufacturer), which is useful to reduce the NOX emission by optimizing the intake valve's closing 

timing especially, result in changing the effective compression and expansion ratio. In order to apply 

this technology, the high pressure ratio turbocharger is required to increase the charge air pressure and 

new developed Turbo charger with high pressure ratio is mounted on the main engines. The optimized 

supercharging with miller cycle has recently been designed to enhance the load management of the 

engines. Also, the main engines are equipped with high fuel injection pressure and low NOX design. 

Since Anadarko is proposing to implement this technology, a control cost analysis is not required.

 

13 Cost analysis presented in Appendix E
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Good Combustion and Manufacturer Recommended maintenance practice – Anadarko is proposing 

to supplement the good combustion practices outlined by the manufacturer with use of recommended 

operation and maintenance practices. Since Anadarko is proposing to implement this technology, a 

control cost analysis is not required.

Step 5 - Select BACT

The main engines on the drillship are certified to meet Tier 2 standards of the IMO’s 2008 NOX Technical 

Code (Regulation 13). In other words, at engine speeds of 720 rpm, these engines are designed to meet 

NOX emission limits of 9.7 g/kW-hr. Anadarko proposes compliance with NSPS IIII, IMO Tier 2 standards, 

LNE Design, Turbocharger with Aftercooler & High Injection Pressure, Optimized Supercharger with 

Miller Cycle and good combustion and manufacturer recommended maintenance practices as NOX BACT 

for the eight main engines. 

5.1.2. NOX BACT Analysis for Emergency Generators (DR-GE-01)

The emergency generator is a Cummins QSK60DMGE model engine. 

Step 1 – Identify all Control Technologies

The control technologies for the main propulsion engines discussed above were considered as the 

potential control technologies for the emergency generators.

Step 2 – Eliminate Technically Infeasible Options

SCR – Infeasible.

This control option is not technically feasible for use on the emergency generator, which only operates 

intermittently during short weekly periods. The SCR systems require a longer period of operating time 

in order to reach a minimum temperature before the system can operate. Hence, it is deemed as 

technically infeasible. 

SNCR – Infeasible.

This control technology is deemed technologically infeasible for the same reasons identified in Section 

5.1.1.

DWI – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

EGR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Derate Engines – Infeasible.
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This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1

Water-in-fuel Emulsions (emulsified diesel) – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Intake Air Humidification/Cooling – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

NOX Adsorber/Scrubber Technology – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

CAM Shaft Replacement/Retooling of Engines – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

LNC or HC-SCR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

ITR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-2. Ranks of Technologies Feasible for Emergency Generators

Technology Efficiency Rank

Low NOX Engine and Turbocharger with 

Aftercooler and High Injection Pressure

30% N/A

Good Combustion and Manufacturer 

Recommended Maintenance Practices

Baseline N/A

All feasible technologies for the emergency engines are listed in Table 5-2. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results
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The emergency engines on the drill ship are certified at construction to meet Tier 2 standards of the 

IMO’s 2008 NOX Technical Code (Regulation 13). 

The emergency generator only operates intermittently for short periods (2 hours per day and 100 hours 

per year) and it is primarily designed to handle during emergency situation. The emergency generator 

is certified to meet IMO Tier 2 standards and is the cleanest available engines in this category of engines. 

Since, the remaining identified technologies are proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes compliance with IMO Tier 2 standards, Turbocharger with Aftercooler and High 

Injection Pressure, and good combustion and manufacturer recommended maintenance practices as 

NOX BACT for the emergency generator. 

5.1.3. NOX BACT Analysis for Emergency Air Compressor Engine (DR-AC-01)

The air compressor diesel engine is a 52 HP HATZ 2 M41 model engine.

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for NOX from smaller diesel 

engines (< 500 HP) and review of the permits recently proposed/issued by U.S. EPA Region 4 and 

Region 10 (and corresponding permit applications) for similar OCS sources was conducted to obtain 

potential control technologies for NOX from smaller engines. The most recent 10-year period was used 

to identify applicable control technologies. The results of the RBLC search are included in Appendix E. 

The search results for potential control technologies for NOX from smaller diesel engines are listed 

below.

DWI

EGR

Derate Engines

Water-in-fuel Emulsions

Intake Air Humidification/Cooling

NOX Adsorber/Scrubber Technology

Replacement of Older Engines with Newer Engines to meet higher EPA Tier standards (40 CFR 

part 89, 94, or 1042)

CAM Shaft Replacement/ Retooling of Engines

LNC or HC-SCR

LNE design including (Turbocharger with After cooler and High Pressure Fuel Injection)

4-Way Catalyst Converter

ITR

Good Combustion and Manufacturer Recommended Maintenance Practices

Step 2 – Eliminate Technically Infeasible Options

DWI – Infeasible.
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This technology is not suitable for emergency air compressor engine which only operate intermittently 

during short weekly periods of engine operation since these engines do not operate under steady state 

conditions for a long time. In addition, as described in the Section 5.1.1, a significant quantity of fresh 

water is necessary for this NOX reduction technology. This control technology is deemed technically 

infeasible for the reasons discussed above and the reasons identified in Section 5.1.1.

EGR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Derate Engines – Infeasible.

The primary concern associated with derating the emergency air compressor engine is that derating 

engines would reduce available power, which is a safety concern during emergency situations where the 

engines are required to perform at full load. This control technology is deemed technically infeasible for 

this reasons and the reasons identified in Section 5.1.1. 

Water-in-fuel Emulsions (emulsified diesel) – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Intake Air Humidification/Cooling – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

NOX Adsorber/Scrubber Technology – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

CAM Shaft Replacement/ Retooling of Engines – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

LNC or HC-SCR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

LNE Design with Turbocharger, Aftercooler and High Pressure Fuel Injection System – Infeasible. 

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the existing air compressor engine with another air compressor engine that 

have this technology already installed. This technology is intrinsic to the engine design and retrofitting 

the air compressor diesel engines is not an option.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.
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ITR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-3. Ranks of Technologies Feasible for Emergency Air Compressor Engine

Technology Efficiency Rank

Replacement with Newer Engine varies 1

Good Combustion and Manufacturer 

Recommended Maintenance Practices

Baseline N/A

All feasible technologies for the air compressor are listed in Table 5-3. Control technologies are ranked 

by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Engines complying with 40 CFR 89 Tier 3 standards are the cleanest available engines in this category of 

equipment. Anadarko had previously obtained an initial cost estimate of $12,600 for replacing a similar 

air compressor engines compliant with 40 CFR 89 Tier 3 standards. 

The emergency air compressor only operates intermittently for short periods (0.5 hours per day and 100 

hours per year) and it is primarily designed to operate during emergency situation. The emergency air 

compressor is certified to meet EPA Tier 2 standards. Given the minimal operations of this equipment 

resulting in low emissions (i.e., <0.1 tons per year), Anadarko believes that replacement of existing air 

compressor engine with the cleanest available engine is cost prohibitive; hence a detailed cost analysis is 

not warranted.

Step 5 - Select BACT

Anadarko proposes 40 CFR 89, EPA Tier 2 standards and good combustion and manufacturer 

recommended maintenance practices as BACT for the emergency air compressor engine. 

5.1.4. NOX BACT Analysis for Third Party Engines (DR-TP-01 through DR-TP-11 and 

DR-TP-17 though DR-TP-21)

The temporary EPA Tier 2 certified third party engines are divided in the following engine categories: 

Third party engines ≤860 HP

Third party engines ≤300 HP

Third party engines ≤126 HP

Step 1 – Identify all Control Technologies

The third party engines on the drillship are a combination of small (<500 HP) and large (>500 HP) diesel 

engines, and the NOX control options identified for the drillship main engines are assumed to 

sufficiently account for all the possible control technologies for the third party engines. Therefore, the 
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same options identified for the drillship main propulsion engines and emergency air compressor are 

considered as the potential control technologies for the third party engines on the drillship. 

Step 2 – Eliminate Technically Infeasible Options

SCR – Infeasible. 

This control option is not technically feasible for use on the third party diesel engines, which only 

operate intermittently. These third party engines are brought onboard as required to perform specific 

operations and then sent back to the shore base once required task is completed. These engines do not 

permanently reside on the drillship. 

The SCR systems require a longer period of operating time under steady state conditions in order to 

reach a minimum temperature before the system can operate. Hence, this control technology is deemed 

technically infeasible for the reasons discussed above and the reasons identified in Section 5.1.1.

SNCR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

DWI – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

EGR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Derate Engines – Infeasible.

An engine can be derated by restricting its operation to lower levels of power than normal for the given 

application resulting in the decrease in available power. Since these engines are brought onboard to 

perform specific operations, these are selected based on the power requirements for a specific task. 

Hence, derating these engines could significantly impact the operations. Hence, it is deemed as 

technologically infeasible. 

Water-in-fuel Emulsions (emulsified diesel) – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Intake Air Humidification/Cooling – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

NOX Adsorber/Scrubber Technology – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 
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Replacement of Older Engines with Newer Engines– Infeasible.

The cleanest available engine for each category was found to be EPA Tier 3 or Tier 4 certified. However, 

upon further investigation, the vendors noted that EPA Tier 3 and Tier 4 certified engines constitute a 

small percentage (i.e., approximately less than 20%) of the total inventory for each category. 

Due to constantly changing schedules during the proposed operations, the availability of these third 

party engines changes on short notice. Hence, it is difficult to determine which specific engine would be 

brought onboard on any given day. Since availability of the EPA Tier 3 and Tier 4 engines is limited, 

there is no guarantee that these engines will be available when Anadarko would need them. Restricting 

these third party engines to EPA Tier 3 or Tier 4 certified engines will significantly impact the 

operations. Hence, this control technology is deemed technically infeasible

LNE Design with Turbocharger, Aftercooler and High Pressure Fuel Injection System – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.3. 

CAM Shaft Replacement/ Retooling of Engines – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

ITR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since all the remaining feasible technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since all the remaining feasible technologies are being proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes 40 CFR 89 EPA Tier 2 standards along with good combustion and manufacturer 

recommended maintenance practices as NOX BACT for the temporary third party engines. As indicated 

previously, the third party engines and the horsepower ratings shown in this application are for 

representation purposes only. However, a third party engine brought onto the drillship will at least be 

certified to 40 CFR 89 EPA Tier 2 standards, with equivalent or lower emissions than the engine 

represented.

5.1.5. NOX BACT Analysis for Third Party Well Evaluation Engines (DR-TP-12 
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through DR-TP-16) 

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for NOX from smaller diesel 

engines (< 500 hp) and review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 

10 (and corresponding permit applications) for similar OCS sources was conducted to obtain potential 

control technologies for NOX from smaller engines. The most recent 10-year period was used to identify 

applicable control technologies. The results of the RBLC search are included in Appendix E. The search 

results for potential control technologies for NOX from smaller diesel engines are listed below.

DWI

EGR

Derate Engines

H/E process (water-in-fuel Homogenization and Emulsification)

Intake Air Humidification/Cooling

NOX Adsorber/Scrubber Technology

Replacement of Older Engines with Newer Engines

CAM Shaft Replacement/ Re-tooling of Engines

LNC or HC-SCR 

LNE design including Turbocharger, Aftercoolers, and High Pressure Fuel Injection

4-Way Catalyst Converter

Good Combustion and Manufacturer Recommended Maintenance Practices

ITR 

Step 2 – Eliminate Technically Infeasible Options

DWI – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

EGR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Derate Engines – Infeasible.

An engine can be derated by restricting its operation to lower levels of power than normal for the given 

application resulting in the decrease in available power. Since these engines are brought onboard to 

perform specific operations, these are selected based on the power requirements for a specific task. 

Hence, derating these engines could significantly impact the operations. Hence, it is deemed as 

technologically infeasible. 

H/E process – Infeasible.

Diesel and water emulsions were offered as a means of lowering the NOX output from the engines. 

These emulsion systems have been shown to reduce NOX by 15-20% in engines running heavy fuel oil 
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(HFO). Running an engine on fuel-water emulsions makes it theoretically possible to reduce NOX

emissions by up to 50%.14

This technology would require derating of the engines, and emulsified diesel in marine vessels can cause 

fuel tank corrosion issues. Additionally, emulsified fuel systems were designed for and installed on 

slow-speed engines burning heavy fuel oil. 

These engines are designed and will be burning medium density fuel (diesel). Several significant 

engineering hurdles must be overcome in order to install a diesel/water emulsion system. Hence, this 

technology is considered as technologically infeasible.

Intake Air Humidification/Cooling – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

NOX Adsorber/Scrubber Technology – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

Replacement of Older Engines with Newer Engines – Infeasible.

The five third party well evaluation diesel engines are pre-1998 engines and hence no engine 

certification is available. During one of the well evaluation activities these five diesel engines will be 

used to send information to a logging unit powered by third party engines. Since all of these engines are 

used to power different equipment that is performing a single operation they are all leased from the 

same third party vendor to avoid compatibility issues. The third party vendor Anadarko proposes to 

leases these engines from has no EPA Tier certified well evaluation engines in their fleet. Therefore, this 

is not considered a viable BACT option.

LNC or HC-SCR – Infeasible.

This technology is not typically not suitable for smaller portable engines such as well evaluation engines. 

Also, LNC systems operate best at consistent high loads, and are not amenable to long periods of engine 

idle or load shifts.

LNE Design with Turbocharger, Aftercooler and High Pressure Fuel Injection System – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.3

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1. 

 

14 Based on Non-Road Diesel Emission Reduction Study”.www.ecy.wa.gov/programs/air/PDFS/NonroadDieselStudy.pdf
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Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-4. Ranks of Technologies Feasible for Diesel Fired Engines

Technology Efficiency Rank

CAM Shaft Replacement/ 

Retooling of Engines

various 1

Good Combustion and 

Manufacturer Recommended 

Maintenance Practices

Baseline N/A

All feasible technologies for the diesel fired engines are listed in Table 5-4. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Clean Cam Technology Systems (CCTS) offers retrofit cam shaft reengineering kits for some diesel engines. 

The kits reduce NOX emissions by increasing the volume of the residual exhaust gas that remains in the 

combustion chamber after the power stroke.

CCTS cam shaft retrofit (retooling) kits are available for Detroit Diesel engines (model series 71 or 92.) 

The “well evaluation” engines proposed in this application are Detroit Diesel engines (model series 71) 

and hence this technology considered feasible. 

The proposed operating time for these engines is 125 hrs/year per engine. Given the engine’s minimal 

operating time, the resulting emissions are minimal. For example, NOX emissions per engine are 

approximately 0.3 tpy per engine. Therefore, Anadarko believes that detailed cost infeasibility is not 

warranted. Given the minimal operations of this equipment resulting in low emissions, Anadarko 

believes that CAM Shaft Replacement/ Retooling of the engines will be cost prohibitive.

Step 5 - Select BACT

Anadarko proposes good combustion practices and manufacturer recommended operating and 

maintenance practices as NOX BACT for the third party well evaluation engines. 

5.1.6. NOX BACT Analysis for Pumps on the Stimulation Vessel (SV-PE-01 through 

SV-PE-08)

The proposed Stimulation Vessel will have eight 2,250 HP pumps. The pumps described in this 

application are not certified for EPA Tier rating due to their manufacturing/model year.

Step 1 – Identify all Control Technologies

Similar to the drillship main propulsion engines, the pumps on the stimulation vessel also are large 

(>500 HP) diesel engines and the NOX control options are expected to be same as the main propulsion

engines. Therefore, the same options identified for the main propulsion engines are considered as the 

potential control technologies for the pumps on the stimulation vessel.
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Step 2 – Eliminate Technically Infeasible Options

SCR – Infeasible.

This control option is not technically feasible for use on the pumps, which only operate for short periods 

during the specific well completion scenario. SCR systems require a longer period of operating time in 

order to reach a minimum temperature before the system can operate. Installation of each SCR will 

require significant structural changes to support the SCRs and urea storage tanks. 

Hence, this control technology is deemed technically infeasible for the reasons discussed above and the 

reasons identified in Section 5.1.1.

SNCR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

DWI – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

EGR – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Derate Engines – Infeasible.

Derating the engine will reduce the available power and may not meet the power requirements. Since 

the pumps are expected to be operated at peak power, this control technology is deemed technologically 

infeasible.

Water-in-fuel Emulsions (emulsified diesel) – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Intake Air Humidification/Cooling – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

NOX Adsorber/Scrubber Technology – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

CAM Shaft Replacement/ Retooling of Engines – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

LNC or HC-SCR – Infeasible.
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This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

LNE Design with Turbocharger, Aftercooler and High Pressure Fuel Injection System – Infeasible. 

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the existing pumps with other pumps that have this technology already installed. 

This technology is intrinsic to the engine design and retrofitting the pumps is not an option. Therefore, 

this is not considered a viable BACT option.

Replacement of Older Engines with Newer Engines – Infeasible.

The certification to meet these standards is part of the inherent design of the engine and there is no 

upgrade available for an existing engine to meet EPA Tier 2 or higher standards. In order for these 

pumps to meet EPA Tier 2 (Part 89) standards or higher, the engines would have to be replaced with 

newer engines. Since these pumps are already installed on a Stimulation Vessel, replacing the existing 

pumps with the newer pumps will require significant engineering redesign and possible recertification 

of the Stimulation Vessel. Moreover, these pumps will operate for a limited time (i.e., approximately 201 

hours per year.) Hence, replacement of these pumps with the newer pumps is not considered a viable 

BACT option. Regardless, Anadarko performed a cost analysis to assess cost feasibility of this option.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.1.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-5. Ranks of Technologies Feasible for Pumps on Stimulation Vessel

Technology Efficiency Rank

Replacement of old engines with 

new engines

varies 1

Good Combustion and 

Manufacturer Recommended 

Maintenance Practices

Baseline N/A

All feasible technologies for the miscellaneous well completion engines are listed in Table 5-5. Control 

technologies are ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results
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Replacement of old engines with new engines –40 CFR 89 Tier 2 compliant engine was identified as 

the cleanest available engine in the stimulation vessel pump engine category (SV-PE-01 through SV-PE08) Anadarko performed the cost effectiveness analysis for replacing the existing engines with the 

newer engines meeting the EPA 40 CFR 89 tier 2 standards. The cost effectiveness for the engine 

replacement was estimated to be $75,788 per ton of NOX reduced, making this option cost prohibitive. A 

detailed control cost effectiveness analysis is provided in Appendix E.

Step 5 - Select BACT

Anadarko proposes good combustion and manufacturer recommended operating and maintenance 

practices as BACT for the pumps on the stimulation vessel.

5.1.7. NOX BACT Analysis for Flowback Boiler (DR-TP-22)

The proposed flowback boiler is a small 8 MMBtu/hr diesel fired combustion source. EPA's RBLC search 

was used to obtain potential control technologies for NOX from boilers and review of the permits 

recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit applications) 

for similar OCS sources was conducted to obtain potential control technologies for NOX from boilers. 

The most recent 10-year period was used to identify applicable control technologies. The results of the 

RBLC search are included in Appendix E. The search results for potential control technologies are listed 

below.

Flue Gas Recirculation (FGR)

Low NOX Burners

Good Combustion and Manufacturer Recommended Maintenance Practices

Step 2 – Eliminate Technically Infeasible Option

FGR – Infeasible.

The proposed flowback boiler does not have an FGR and retrofitting FGR on an existing unit will require 

significant design change. The FGR technology is best suited for new units as retrofitting FGR on the 

proposed boiler would require extensive modifications, such as installation of ductwork, recirculation 

fans, air foils for mixing re-circulated flue gas and combustion air, and controls for variable load 

operation. Also, there is a possibility of flame instability observed at high FGR rates leading to safety 

concerns. Hence, this control technology is considered as technologically infeasible.

Low NOX Burners– Infeasible.

This technology is considered technically infeasible because the proposed boiler was not constructed 

with low-NOX burners. Low-NOX burners produce longer flames, and therefore are potentially 

inappropriate for retrofit on smaller furnaces. Additionally, low-NOX burners operate in a lowertemperature, fuel-lean zone, which could result in increases of CO and VOC emissions from the boiler.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since good combustion and manufacturer recommended operating and maintenance practices are 
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the only feasible option, no ranking is required.

Step 4 – Evaluate Most Effective Controls and Document Results

The manufacturer recommended good combustion operating and maintenance requirements are 

considered as the most effective controls.

Step 5 - Select BACT

Anadarko proposes good combustion and manufacturer recommended operating and maintenance 

practices as the NOX BACT for the proposed flowback boiler.

5.1.8. NOX BACT Analysis for Boom Flare (DR-TP-23)

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for NOX from flares and review of 

the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit 

applications) for similar OCS sources was conducted to obtain potential control technologies for NOX

from flares. The most recent 10-year period was used to identify applicable control technologies. The 

results of the RBLC search are included in Appendix E. The search results for potential control 

technologies for NOX from flares are listed below.

Comply with 40 CFR 60.18

Good Combustion and Manufacturer Recommended Maintenance Practices

Step 2 – Eliminate Technically Infeasible Option

Comply with 40 CFR 60.18 – Feasible.

Good Combustion Practices – Feasible.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since both the identified technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since both the identified technologies are being proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes compliance with the requirements of 40 CFR 60.18 and manufacturer recommended

good combustion operating practices and maintenance requirements as the BACT for the boom flare.

A summary of the proposed NOX BACT emission limitation for each source associated with the project is 

provided below in Table 5-6.
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Table 5-6. Proposed NOX BACT Emission Limits 

Emission Unit

BACT 

Emission 

Limit

BACT Basis BACT Control Technologies

Drillship Main Engines 

(DR-ME-01 thru DR-ME-06)

9.7 g/kW-hr IMO 

Performance 

Test Data

EPA 40 CFR 1042 Tier 2

Standards, NSPS IIII, IMO Tier 2 

standards, LNE Design, 

Performance Management 

System including Turbocharger 

with Aftercooler and High Fuel 

Injection Pressure, good 

combustion and manufacturer 

recommended maintenance 

practices

Drillship Emergency 

Generators (DR-GE-01)

-- IMO Tier 2 

Standard

IMO Tier 2 standards, 

Turbocharger with Aftercooler 

& High Injection Pressure, good 

combustion and manufacturer 

recommended maintenance 

practices

Emergency Air Compressor 

Engine (DR-AC-01)

-- 40 CFR 89 EPA 

Tier 2 Standard 

40 CFR 89 EPA Tier 2 Standard, 

good combustion and 

manufacturer recommended 

maintenance practices

Third Party Engines (DR-TP-01 

through DR-TP-11 and DR-TP17 through DR-TP-21)

-- 40 CFR 89 EPA 

Tier 2 Standard

40 CFR 89 EPA Tier 2 Standard, 

good combustion and 

manufacturer recommended 

maintenance practices

Third Party Well Evaluation 

Engines (DR-TP-12 through 

DR-TP-16)

-- AP-42, Chapter 

3, Table 3.3-1

Good combustion and 

manufacturer recommended 

maintenance practices

Stimulation Vessel Pumps (SVPE-01 thru SV-PE-08)-- AP-42, Chapter 

3, Table 3.4-1

Good combustion and 

manufacturer recommended 

maintenance practices 

Flowback Boiler (DR-TP-22) -- AP-42, Chapter 

1, Table 1.3-1

Good combustion and 

manufacturer recommended 

maintenance practices

Boom Flare (DR-TP-23) -- AP-42, Chapter 

13, Table 13.5-1

Compliance with 40 CFR 60.18 

and Good combustion and 

manufacturer recommended 

maintenance practices
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5.2. CO AND VOC BACT ANALYSIS

The BACT assessment for CO and VOC was performed for the same sources described in Section 5.1. 

5.2.1. CO and VOC BACT Analysis for Drillship Main Propulsion Electrical Generator 

Engines (DR-ME-01 through DR-ME-08)

The main propulsion engines are used to power the thrusters that hold the ship on location, as well as 

power the drilling equipment and other operational needs of the ship. The main propulsion engines 

operate at variable loads based on drilling and operational power demand, and extensive “reserve” 

power is required to adjust for loop currents and subsea soil densities. Hence, CO emissions are not 

emitted from these engines at a steady state. These factors are important considerations in the BACT 

analysis for these engines.

Step 1 – Identify all Control Technologies

The first step in the EPA top-down, five-step analysis is to identify all available control technologies that 

are potentially suitable for the affected sources. EPA's RBLC search was used to obtain potential control 

technologies for CO and VOC from main propulsion engines at offshore sources. The most recent 10-

year period was used to identify applicable control technologies. The results of the RBLC search are

included in Appendix E. However, it should be noted that the control technologies evaluated in the 

“topdown” analysis for main diesel engines were not limited to the controls listed in the RBLC database. 

The permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit 

applications) for similar OCS sources in Gulf of Mexico have also been reviewed in addition to surveying 

available literature to identify potential control technologies. The search results for potential control 

technologies for CO and VOC from the main diesel engines are listed below.

DOC

CDPF

4-Way Catalyst Converter with Exhaust Gas Recirculation System

Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042)

LNE Design with Turbocharger with Aftercooler and High Fuel Pressure Injection

Good combustion practices

ITR 

Positive Crankcase Ventilation System (for VOCs only)

Step 2 – Eliminate Technically Infeasible Option

DOC – Infeasible.

DOCs contain precious metals impregnated onto a high geometric surface area carrier and are placed in 

the exhaust stream of the engine to reduce emissions of PM, Total Hydrocarbons (THC), and CO. The 

DOC works by oxidizing CO, gaseous hydrocarbons and liquid hydrocarbon particles (unburned fuel and 

oil) in the exhaust gas to CO2 and H2O. The reduction of PM, THC, and CO varies depending on the 
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catalyst formulations in the DOC. DOCs have been verified to reduce emissions of CO and THC by as 

much as 90 percent.15

Due to the large load variations typical of these exploratory drilling operations, the main propulsion

engines are not able to sustain constant steady state loads/exhaust temperatures for sufficient time 

periods that are necessary for high catalyst performance, resulting in limited control. Use of DOCs 

would also lead to some pressure drop across exhaust flow resulting in back pressure on the engine that 

could cause plugging of the engine, thus posing safety concerns for the types of offshore operations 

proposed. Several non-combustible chemical elements that may be present in engine lube oils, such as 

phosphorous, lead and heavy metals, may collect over time and damage the catalyst in the DOC. This 

technology has not been designed, engineered, or tested on a commercially available scale for safe 

operation on the large scale engines found on the BlackHornet drillship.

CDPF – Infeasible.

The catalyst in the CDPF filter could potentially reduce emissions of CO and THC by 90 percent but 

requires sufficient exhaust temperatures to facilitate regeneration by the catalyst.16

CDPFs add back pressure on the engines that could cause plugging of the engine, thus posing safety 

concerns for the types of offshore operations proposed. The pressure drop will also cause a reduction in 

fuel economy. Due to load variations, the main diesel engines cannot typically sustain the high exhaust 

temperatures necessary for optimal regeneration of the catalyst. This technology has not been designed, 

engineered, or tested on a commercially available scale for safe operation on the large scale engines 

found on the BlackHornet drillship.

Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042) –

Infeasible.

The main diesel engines meet the IMO Tier 2 standard for engines under Category 3 (i.e., >30 

liter/cylinder displacement operating at 720 rpm). IMO does not have an emission standard for CO. 

However, comparable EPA Standard (i.e., EPA Tier 2) does have emission standards for CO and VOC. 

Since certification is an engine manufacturer process, it is not possible for these engines to obtain an 

EPA Tier certificate at this point regardless whether these engines meet EPA Tier standards. Hence, 

these engines will need to be replaced with engines with EPA Tier 2 certification. The replacement of 

engine will essentially require redesign and recertification process. Hence, this is not a viable BACT 

option.

4-Way Catalyst Converter – Infeasible.

The main propulsion electrical engines will not be able to sustain constant steady state loads/exhaust 

temperatures for sufficient time periods that are critical for high catalyst performance, resulting in 

inconsistent emission control. Several non-combustible chemical elements that may be present in 

engine lube oils, such as phosphorous, lead and heavy metals, may collect over time and damage the 

catalyst. 

ITR – Infeasible. 

 

15 Based on Sections 4.3, Alternative Control Techniques Document: Stationary Diesel Engines (Final Report), Prepared For: 

Energy Strategies Group U.S. Environmental Protection Agency (EPA) Office of Air Quality Planning and Standards, March 

5, 2010.

16 Ibid
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Changing ignition timing is not an alternative for these engines due to the intrinsic engine design. 

Alterations of the injection timing can impact value performance. Additionally, use of this technology 

can reduce engine power and combustion stability that can hinder operations. For these reasons this 

technology is infeasible.

Positive Crankcase Ventilation System (for VOCs only) – Infeasible.

Installation of a Positive Crankcase Ventilation system involves changes to the design of the engines, 

making this technology to be most feasibly installed when the drillship is designed. This technology is 

intrinsic to the engine design. Furthermore, engine manufacturers have strict restrictions on installing 

upgrades to avoid violating warranty. Retrofitting the engine with this system will require significant 

redesign of the drillship including a possibility of recertification. Requiring this technology would 

essentially mean having to replace the existing engines with other engines that have this technology 

already installed.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-7. Ranks of Technologies Feasible for Main Diesel Engines

Technology Efficiency Rank

LNE Design with Turbocharger with Aftercooler 

and High Fuel Pressure Injection

~ 30% 2

Good Combustion Practices Baseline N/A

All feasible technologies for the main diesel engines are listed in Table 5-7. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Since Anadarko is proposing to implement all feasible control technologies, a control cost analysis is not 

required.

Step 5 - Select BACT

Anadarko proposes LNE design including Turbocharger with Aftercooler and High Fuel Injection 

Pressure along with good combustion and manufacturer recommended operation and maintenance 

practices.

5.2.2. CO and VOC BACT Analysis for Drillship Emergency Generator (DR-GE-01)

Step 1 – Identify all Control Technologies

Similar to the above addressed main propulsion electrical generator engines, the emergency generator 

is also a large (>500 HP) diesel engine, and the CO control options are expected to be same as the main 

diesel engine. Therefore, the same options identified for the main diesel engines are considered as the 

potential control technologies for the emergency generator.
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Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

Positive Crankcase Ventilation System (for VOCs only) – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-8. Ranks of Technologies Feasible for Emergency Engine

Technology Efficiency Rank

Replacement of Engine to meet higher EPA 

Tier standards

varies 1

LNE Design 30% N/A

Good Combustion Practices Baseline N/A

All feasible technologies for the emergency generator are listed in Table 5-8. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Engines complying with 40 CFR 89 Tier 2 standards are the cleanest available engines in this category of 

engines. There is no add on technology due to which IMO Tier 2 engines could be classified as EPA Tier 

2 engines. The only possible option is to replace the existing engine with EPA Tier 2 certified engine and 

this option will require significant redesigning and possible recertification.

The emergency generator only operates intermittently for short periods (2 hours per day and 100 hours 

per year) and it is primarily designed to handle during emergency situation. Given the small emissions 

and trivial emission reduction benefit, Anadarko believes a comprehensive cost assessment is not 

warranted.

Step 5 - Select BACT
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Anadarko proposes LNE design along with good combustion and manufacturer recommended 

maintenance practices as BACT for the drillship emergency generator.

5.2.3. CO and VOC BACT Analysis for Air Compressor Engine (DR-AC-01)

The air compressor engine is a HATZ 2M41 engine with 39 HP rating.

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for CO and VOC from smaller 

emergency diesel engines (< 500 HP) and review of the permits recently proposed/issued by U.S. EPA 

Region 4 and Region 10 (and corresponding permit applications) for similar OCS sources was conducted 

to obtain potential control technologies for CO and VOC from smaller engines. The most recent 10-year 

period was used to identify applicable control technologies. The results of the RBLC search are included 

in Appendix E. The search results for potential control technologies for CO and VOC from smaller diesel 

engines are listed below.

DOC

CDPF

4-Way Catalyst Converter

ITR 

Replacement of Engine to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042)

LNE Design with Turbocharger and High Pressure Fuel Injection

Good combustion practices (Manufacturer recommended operations and maintenance)

Positive Crankcase Ventilation System (for VOCs only)

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

LNE Design with Turbocharger and High Pressure Fuel Injection – Infeasible.

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is installed. Requiring this technology would essentially 

mean having to replace the existing compressor engine with other air compressor diesel engines that 

have this technology already installed. This technology is intrinsic to the engine design and retrofitting 

the air compressor diesel engines is not an option.
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Positive Crankcase Ventilation System (for VOCs only) – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-9. Ranks of Technologies Feasible for Emergency Air Compressor Engine

Technology Efficiency Rank

Replacement of Engine to meet higher EPA 

Tier standards

1

Good Combustion Practices Baseline N/A

All feasible technologies for the air compressor are listed in Table 5-9. Control technologies are ranked 

by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Engines complying with 40 CFR 89 Tier 3 standards are the cleanest available engines in this category of 

equipment. Anadarko previously obtained an initial cost estimate of $12,600 for replacing a similar 

engine with air compressor engines compliant with 40 CFR 89 Tier 3 standards. Given the minimal 

operations of this equipment resulting in low emissions, Anadarko believes that replacement of existing 

air compressor engine with the cleanest available engine is cost prohibitive and a detailed cost analysis 

is not warranted.

Step 5 - Select BACT

Anadarko proposes 40 CFR 94 EPA Tier 2 standards and good combustion and manufacturer 

recommended maintenance practices as CO and VOC BACT for the emergency air compressor.

5.2.4. CO and VOC BACT Analysis for Drillship Third Party Engines (DR-TP-01 

through DR-TP-11 and DR-TP-17 though DR-TP-21)

The temporary EPA Tier 2 certified third party engines include the following engine categories: 

Third party engines ≤860 HP (DR-TP-01 and DR-TP-02)

Third party engines ≤300 HP (DR-TP-03 to DR-TP-11)

Third party engines ≤126 HP (DR-TP-17 to DR-TP-21)

Step 1 – Identify all Control Technologies

The third party engines on the drillship are a combination of small (<500 HP) and large (>500 HP) diesel 

engines, and the CO and VOC control options identified for the main propulsion electrical generator

engines are assumed to sufficiently account for all the possible control technologies for the third party 

engines. Therefore, the same options identified for the drillship main diesel engines are considered as 

the potential control technologies for the third party engines on the drillship. 
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Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042) –

Infeasible.

The cleanest available engine was found to be EPA Tier III or Tier IV certified. However, upon further 

investigation, the vendors noted that EPA Tier III and Tier IV certified engines constitute a small 

percentage (i.e., approximately less than 20%) of the total inventory. 

Due to constantly changing schedules during the proposed operations, the availability of these third 

party engines changes on short notice. Hence, it is difficult to determine which specific engine would be 

brought onboard on any given day. Since availability of the EPA Tier III and Tier IV engines is limited, 

there is no guarantee that these engines will be available when Anadarko would need them. Restricting 

these third party engines to EPA Tier III or Tier IV certified engines will significantly impact the 

operations. Hence, this option is not a viable BACT option.

Positive Crankcase Ventilation System (for VOCs only) – Infeasible. 

This control technology is deemed technically infeasible since it is an intrinsic part of engine design and 

restricting the temporary third party engines to be equipped with this technology could have significant 

operational impact as described above.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-10. Ranks of Technologies Feasible for the Third Party Engines

Technology Efficiency Rank

LNE design 30% 1

Good Combustion Practices Baseline N/A

All feasible technologies for the third party engines are listed in Table 5-10. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Anadarko proposes 40 CFR 89 EPA Tier 2 standards, the highest ranked among the feasible options, as 

BACT for CO control from the third party engines. Therefore control cost analysis is not required.
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Step 5 - Select BACT

Anadarko proposes 40 CFR 89 EPA Tier 2 standards and LNE Design along with good combustion 

practices as CO BACT for the third party engines. Anadarko proposes good combustion practices as VOC 

BACT. As indicated previously, the third party engines and the horsepower ratings shown in this 

application are for representation purposes only. However, a well completion engine brought onto the 

drillship will at least be certified to 40 CFR 89 EPA Tier 2 or higher standards, with equivalent or lower 

emissions than the engine represented.

5.2.5. CO and VOC BACT Analysis for Third Party Well Evaluation Engines (DR-TP12 through DR-TP-16) 

Step 1 – Identify all Control Technologies

The third party well evaluation engines on the drillship are four 140 HP diesel engines, and the CO 

control options identified for the main propulsion electrical generator engines are assumed to 

sufficiently account for all the possible control technologies for the third party engines. Therefore, the 

same options identified for the drillship main diesel engines are considered as the potential control 

technologies for the third party engines on the drillship. 

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

LNE Design – Infeasible. 

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the existing well evaluation compressor diesel engines with other air 

compressor diesel engines that have this technology already installed. This technology is intrinsic to the 

engine design and retrofitting the air compressor diesel engines is not an option.

Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042) –

Infeasible.

The five third party well evaluation diesel engines are pre-1998 engines and hence no engine 

certification is available. During one of the well evaluation activities these five diesel engines will be 

used to send information to a logging unit powered by third party engines. Since all of these engines are 

used to power different equipment that is performing a single operation they are all leased from the 

same third party vendor to avoid compatibility issues. The third party vendor Anadarko leases these 
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engines from currently has no EPA Tier certified well evaluation engines in their fleet. Therefore, this is 

not considered a viable BACT option.

Positive Crankcase Ventilation System (for VOCs only) – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.4.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Good combustion practices (manufacturer recommended operation and maintenance) are the only 

feasible option. Therefore, ranking is not required.

Step 4 – Evaluate Most Effective Controls and Document Results

Good combustion practices are the only feasible option. Therefore, ranking is not required.

Step 5 - Select BACT

Anadarko proposes good combustion and manufacturer recommended operation and maintenance 

practices as CO and VOC BACT for the third party well evaluation diesel engines.

5.2.6. CO and VOC BACT Analysis for Representative Stimulation Vessel Pumps (SVPE-01 thru SV-PE-08)

The proposed Stimulation Vessel will have eight 2,250 HP pump engines. 

Step 1 – Identify all Control Technologies

Similar to the main propulsion electrical generator engines, the pump engines on the stimulation vessel 

also are large (>500 HP) diesel engines and the CO and VOC control options are expected to be same as 

the main diesel engine. Therefore, the same options identified for the main diesel engines are 

considered as the potential control technologies for the pumps on the stimulation vessel.

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.

ITR – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Section 5.2.1.
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LNE Design – Infeasible.

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the pumps with another engine that has this technology already installed. This 

technology is intrinsic to the engine design and retrofitting the pumps is not an option.

Positive Crankcase Ventilation System (for VOCs only) – Infeasible. 

This control technology is deemed technically infeasible for the same reasons identified in Sections 5.2.4 

and 5.1.6.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-11. Ranks of Technologies Feasible for Pumps on Stimulation Vessel

Technology Efficiency Rank

Replacement of engines to meet 

higher EPA tier standards.

varies 1

Good Combustion Practices N/A N/A

All feasible technologies for the miscellaneous well completion engines are listed in Table 5-11. Control 

technologies are ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Replacement of engines to meet higher EPA tier standards – 40 CFR 89 Tier 2 compliant engine was 

identified as the cleanest available engine in the stimulation vessel pump engine category (SV-PE-01 

through SV-PE-08). Anadarko previously performed the cost effectiveness analysis for replacing the 

existing engines with the newer engines meeting the EPA 40 CFR 89 tier 2 standards. However, 40 CFR 

89 Tier 2 emission factor results in higher emissions than the existing engine, for which emissions were 

calculated using AP-42 factor. Therefore, it is not possible to perform a representative cost effectiveness 

analysis.

Step 5 - Select BACT

Anadarko proposes good combustion practices and manufacturer recommended operation and 

maintenance practices as BACT for the pumps on the stimulation vessel.

5.2.7. CO and VOC BACT Analysis for Flowback Boiler (DR-TP-22)

The proposed flowback boiler is a small 8 MMBtu/hr diesel fired combustion source. An RBLC search 

for potential control options for CO from a small boiler (<10 MMBtu/hr) did not produce any results. 

Also, a review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 for similar 

OCS sources did not result in any potential control technologies. Therefore, Anadarko proposes good 

combustion practices (manufacturer recommended operation and maintenance) as BACT for the 

flowback boiler.
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5.2.8. CO and VOC BACT Analysis for Boom Flare (DR-TP-23)

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for CO from flares and review of 

the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit 

applications) for similar OCS sources was conducted to obtain potential control technologies for CO from 

flares. The most recent 10-year period was used to identify applicable control technologies. The results 

of the RBLC search are included in Appendix E. The search results for potential control technologies for 

CO from flares are listed below.

Comply with 40 CFR 60.18

Good Combustion Practices (Manufacturer recommended operation and maintenance)

Step 2 – Eliminate Technically Infeasible Option

Comply with 40 CFR 60.18 – Feasible.

Good Combustion Practices – Feasible.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since both the identified technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since both the identified technologies are being proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes compliance with the requirements of 40 CFR 60.18 and good combustion practices

(manufacturer recommended operation and maintenance) as the BACT for the boom flare.

A summary of the proposed CO and VOC BACT emission limitation for each source associated with the 

project is provided below in Table 5-12.

Table 5-12. Proposed CO & VOC BACT Emission Limits

Emission Unit BACT Emission Limit BACT Basis BACT Control 

Technologies

Drillship Main Propulsion 

Electrical Engines 

(DR-ME-01 thru DR-ME-08)

2.49 g/kW-hr – CO

0.43 g/kW-hr - VOC

AP-42, Chapter 

3, Table 3.4-1

LNE design including 

Turbocharger with 

Aftercooler and High 

Fuel Pressure 

Injection, and Good 

Combustion Practices

Drillship Emergency Diesel 

Engine (DR-GE-01)

-- AP-42, Chapter 

3, Table 3.4-1

LNE design and Good 

Combustion Practices

Emergency Air Compressor 

Engine (DR-AC-01)

-- 40 CFR 89 EPA 

Tier 2 Standard

EPA Tier 2 Standard
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Emission Unit BACT Emission Limit BACT Basis BACT Control 

Technologies

Good Combustion 

Practices

Third Party Engines (DR-TP01 through DR-TP-11 and 

DR-TP-17 through DR-TP-21)

-- 40 CFR 89 EPA 

Tier 2 Standard

(CO)

AP-42, Chapter 

3, Table 3.4-1

(VOC)

40 CFR 89 EPA Tier 2 

Standard and LNE 

design

Third Party Well Evaluation 

Engines (DR-TP-12 through 

DR-TP-16)

-- AP-42, Chapter 

3, Table 3.3-1

Good Combustion 

Practices

Stimulation Vessel Pumps 

(SV-PE-01 thru SV-PE-08)

-- AP-42, Chapter 

3, Table 3.4-1

Good Combustion 

Practices

Flowback Boiler (DR-TP-22) -- AP-42, Chapter 

1, Table 1.3-1

Good Combustion 

Practices

Boom Flare (DR-TP-23) -- AP-42, Chapter 

13, Table 13.5-1

Compliance with 40 

CFR 60.18 and Good 

Combustion Practices
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5.3. PM/PM10/PM2.5 BACT ANALYSIS

The emission sources of PM/PM10/PM2.5 on the drillship that are used for the proposed drilling 

operation are as listed below:

Eight main propulsion electrical generator engines (DR-ME-01 to DR-ME-08)

Emergency generator (DR-GE-01)

Emergency Air compressor (DR-AC-01)

Third party engines: 

Third party engines ≤860 HP (DR-TP-01 and DR-TP-02)

Third party engines ≤300 HP (DR-TP-03 to DR-TP-11)

Third party well evaluation engines ≤140 HP (DR-TP-12-DR-TP-16 and 

SB-TP-05 to SB-TP-09)

Third party engines ≤126 HP (DR-TP-16 to DR-TP-21)

One flow back boiler (DR-TP-22)

One boom flare (DR-TP-23)

Painting Operation (DR-PO-01)

Welding Operation (DR-WO-01)

Stimulation Vessel – 8 pumps (SV-PE-01 thru SV-PE-08)

5.3.1. PM/PM10/PM2.5 BACT Analysis for the Drillship Main Propulsion Electrical 

Generator Engines (DR-ME-01 to DR-ME-08)

The main propulsion electrical generator engines are used to power the thrusters that hold the ship on 

location, as well as power the drilling equipment and other operational needs of the ship. The main 

propulsion engines operate at variable loads based on drilling and operational power demand, and 

extensive “reserve” power is required to adjust for loop currents and subsea soil densities. Hence, 

PM/PM10/PM2.5 emissions are not emitted from these engines at a steady state. These factors are 

important considerations in the BACT analysis for these engines.

Step 1 – Identify all Control Technologies

The first step in the EPA top-down, five-step analysis is to identify all available control technologies that 

are potentially suitable for the affected sources. EPA's RBLC search was used to obtain potential control 

technologies for PM/PM10/PM2.5 from main diesel engines at offshore sources. The most recent 10-year 

period was used to identify applicable control technologies. The results of the RBLC search are included 

in Appendix E. However, it should be noted that the control technologies evaluated in the “top-down” 

analysis for main propulsion engines were not limited to the controls listed in the RBLC database. The 

permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit 

applications) for similar OCS sources in Gulf of Mexico have also been reviewed in addition to surveying

available literature to identify potential control technologies. The search results for potential control 

technologies for PM/PM10/PM2.5 from the main diesel engines are listed below.

Baghouse

Use of Ultra Low Sulfur Diesel (ULSD) Fuel/ Low Ash Fuel

DOC

CDPF
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Positive Crankcase Ventilation (PCV)

4-Way Catalyst Converter

Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042)

Good combustion (Manufacturer recommended operation and maintenance) practices

LNE design including Turbocharger with Aftercooler and High Fuel Injection Pressure

Fuel Injection Timing Retard

Step 2 – Eliminate Technically Infeasible Option

Baghouse – Infeasible.

Baghouses are considered to be technically infeasible for all engines, as use of a baghouse would lead to 

a high pressure drop across exhaust flow resulting in excessive back pressure on the engine that could 

cause plugging of the engine, thus posing safety concerns for the types of offshore operations proposed. 

The pressure drop will also cause a reduction in fuel economy. To avoid an unacceptable pressure drop 

across the baghouse, the use of a large fabric area would be required which in turn would require a 

significant amount of space on a vessel.17 Required space would include the size of the baghouse itself 

as well as the removal system for the collected material. Installation of a baghouse would require 

significant space reassignment on a drillship, which is unavailable, and therefore may require 

recertification of the vessel itself.

DOC – Infeasible.

Due to the large load variations typical of these exploratory drilling operations, the main propulsion

engines are not able to sustain constant steady state loads/exhaust temperatures for sufficient time 

periods that are necessary for high catalyst performance, resulting in limited control. Use of DOCs 

would also lead to some pressure drop across exhaust flow resulting in back pressure on the engine that 

could cause plugging of the engine, thus posing safety concerns for the types of offshore operations 

proposed. Several non-combustible chemical elements that may be present in engine lube oils, such as 

phosphorous, lead and heavy metals, may collect over time and damage the catalyst in the DOC. This 

technology has not been designed, engineered, or tested on a commercially available scale for safe 

operation on the large scale engines found on the BlackHornet drillship.

CDPF – Infeasible.

The catalyst in the CDPF filter reduces emissions of PM/PM10/PM2.5 and THC by 90 percent but requires 

sufficient exhaust temperatures to facilitate regeneration by the catalyst.18

CDPFs add back pressure on the engines that could cause plugging of the engine, thus posing safety 

concerns for the types of offshore operations proposed. The pressure drop will also cause a reduction in 

fuel economy. Due to load variations, the main propulsion engines onboard the BlackHornet drillship 

cannot typically sustain the high exhaust temperatures necessary for optimal regeneration of the 

catalyst. This technology has not been designed, engineered or tested on a commercially available scale 

for safe operation on the large scale engines found on the BlackHornet drillship.

 

17 Based on Air Pollution Control Technology Fact Sheet for Fabric Filter, U.S. EPA, EPA-452/F-03-025.

18 Based on Alternative Control Techniques Document: Stationary Diesel Engines (Final Report), Prepared For: Energy 

Strategies Group U.S. Environmental Protection Agency (EPA) Office of Air Quality Planning and Standards, March, 2010.
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Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042) – Not 

Applicable.

The main propulsion electrical generator engines will comply with PM standards specified in NSPS IIII, 

which is the most stringent PM emission standard for this category of engines. Hence, there is no 

requirement to identify a different engine. 

4-Way Catalyst Converter – Infeasible.

The main propulsion engines will not be able to sustain constant steady state loads/exhaust 

temperatures for sufficient time periods that are critical for high catalyst performance, resulting in 

inconsistent emission control. Several non-combustible chemical elements that may be present in 

engine lube oils, such as phosphorous, lead and heavy metals, may collect over time and damage the 

catalyst. 

Fuel Injection Timing Retard – Infeasible. 

Changing ignition timing is not an alternative for these engines due to the intrinsic engine design. 

Alterations of the injection timing can impact value performance. Additionally, use of this technology 

can reduce engine power and combustion stability that can hinder operations. For these reasons this 

technology is infeasible.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-13. Ranks of Technologies Feasible for Main Diesel Engines

Technology Efficiency Rank

LNE design including Turbocharger with 

Aftercooler and High Fuel Injection Pressure

30% 1

Use of ULSD varies 2

Good Combustion Practices Baseline N/A

All feasible technologies for the main propulsion engines are listed in Table 5-13 above. Control 

technologies are ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Since Anadarko is proposing to implement all feasible technologies, no cost feasibility is required.

Step 5 - Select BACT

Anadarko proposes compliance with NSPS IIII, LNE design including Turbocharger with Aftercooler and 

High Fuel Injection Pressure, and ULSD usage along with good combustion and manufacturer 

recommended operation and maintenance practices as PM/PM10/PM2.5 BACT for all main propulsion 

electrical generator engines.
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5.3.2. PM/PM10/PM2.5 BACT Analysis for Drillship Emergency Generator (DR-GE-01)

Step 1 – Identify all Control Technologies

Similar to the main propulsion engines, the emergency generator is also a large (>500 HP) diesel engine, 

and the PM/PM10/PM2.5 control options are expected to be same as the main propulsion engines. 

Therefore, the same options identified for the main diesel engines are considered as the potential 

control technologies for the emergency generator

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-14. Ranks of Technologies Feasible for the Emergency Diesel Engine

Technology Efficiency Rank

Replacement of Engines to meet higher EPA Tier 

standards

Varies 1

LNE design including Turbocharger and High Fuel 

Injection Pressure N/A 2

ULSD N/A 3

Good Combustion Practices Baseline N/A

All feasible technologies for the emergency generator engine are listed in Table 5-14. Control 

technologies are ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Engines complying with 40 CFR 89 Tier 2 standards are the cleanest available engines in this category of 

engines. There is no add on technology due to which IMO Tier 2 engines could be classified as EPA Tier 

2 engines. The only possible option is to replace the existing engine with EPA Tier 2 certified engine and 

this option will require significant redesigning and possible recertification.

The emergency generator only operates intermittently for short periods (2 hours per day and 100 hours 

per year) and it is primarily designed to handle during emergency situation. Given the small emissions 

and trivial emission reduction benefit, Anadarko believes a comprehensive cost assessment is not 

warranted.
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Step 5 - Select BACT

Anadarko proposes LNE design and ULSD usage along with good combustion and manufacturer 

recommended maintenance practices as PM/PM10/PM2.5 BACT for the drillship emergency generator.

5.3.3. PM/PM10/PM2.5 BACT Analysis for the Air Compressor Engine (DR-AC-01)

The air compressor diesel engine is a HATZ 2M41, 38.5 HP engine.

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for PM/PM10/PM2.5 from smaller 

emergency diesel engines (< 500 HP) and review of the permits recently proposed/issued by U.S. EPA 

Region 4 and Region 10 (and corresponding permit applications) for similar OCS sources was conducted 

to obtain potential control technologies for PM/PM10/PM2.5 from smaller engines. The most recent 10-

year period was used to identify applicable control technologies. The results of the RBLC search are 

included in Appendix E. The search results for potential control technologies for PM/PM10/PM2.5 from 

smaller diesel engines are listed below.

DOC

CDPF

4-Way Catalyst Converter

Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042)

LNE design including Turbocharger and High Pressure Fuel Injection

USLD Fuel

Good combustion practices (manufacturer recommended operation and maintenance)

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

LNE Design – Infeasible. 

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the existing air compressor diesel engines with other air compressor diesel 

engines that have this technology already installed. This technology is intrinsic to the engine design and 

retrofitting the air compressor diesel engines is not an option.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness
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Table 5-15. Ranks of Technologies Feasible for the Emergency Diesel Engine

Technology Efficiency Rank

Replacement of Engines to meet higher EPA Tier 

standards varies 1

ULSD N/A N/A

Good Combustion Practices Baseline N/A

Step 4 – Evaluate Most Effective Controls and Document Results

Engines complying with 40 CFR 89 Tier 3 standards are the cleanest available engines in this category of 

equipment. Anadarko previously obtained an initial cost estimate of $12,600 for replacing a similar air 

compressor with an air compressor engines compliant with 40 CFR 89 Tier 3 standards. An email 

communication with the vendor is provided in the Appendix B of this submittal. Given the minimal 

operations of this equipment resulting in low emissions, Anadarko believes that replacement of existing 

emergency engine with the cleanest available engine is cost prohibitive.

Step 5 - Select BACT

Anadarko proposes compliance with EPA Tier 2 standards, use of ULSD fuel along with good combustion

and manufacturer recommended operation and maintenance practices as PM/PM10/PM2.5 BACT.

5.3.4. PM/PM10/PM2.5 BACT Analysis for Drillship Third Party Engines (DR-TP-01 

through DR-TP-11 and DR-TP-17 though DR-TP-21)

Step 1 – Identify all Control Technologies

The third party engines on the drillship are a combination of small (<500 HP) and large (>500 HP) diesel 

engines, and the PM/PM10/PM2.5 control options identified for the main drillship engines are assumed to 

sufficiently account for all the possible control technologies for the third party engines. Therefore, the 

same options identified for the drillship main diesel engines are considered as the potential control 

technologies for the third party engines on the drillship. 

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.
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Replacement of Engines to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042) –

Infeasible.

The cleanest available engine was found to be EPA Tier III or Tier IV certified. However, upon further 

investigation, the vendors noted that EPA Tier III and Tier IV certified engines constitute a small 

percentage (i.e., approximately less than 20%) of the total inventory. 

Due to constantly changing schedules during the proposed operations, the availability of these third 

party engines changes on short notice. Hence, it is difficult to determine which specific engine would be 

brought onboard on any given day. Since availability of the EPA Tier III and Tier IV engines is limited, 

there is no guarantee that these engines will be available when Anadarko would need them. Restricting 

these third party engines to EPA Tier III or Tier IV certified engines will significantly impact the 

operations. Hence, this option is not a viable BACT option.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-16. Ranks of Technologies Feasible for the Third Party Engines

Technology Efficiency Rank

LNE design 30% 1

Good Combustion Practices (Manufacturer 

Recommended operation and maintenance 

procedures).

Baseline N/A

All feasible technologies for the third party engines are listed in Table 5-16. Control technologies are 

ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Anadarko proposes compliance with 40 CFR 89 EPA Tier 2 standards, the highest ranked among the 

feasible options, as BACT for the third party diesel engines. Therefore control cost analysis is not 

required.

Step 5 - Select BACT

Anadarko proposes 40 CFR 89 EPA Tier 2 standards and LNE design along with good combustion and 

manufacturer recommended operation and maintenance practices as PM/PM10/PM2.5 BACT for the third 

party engines. As indicated previously, the third party engines and the horsepower ratings shown in 

this application are for representation purposes only. However, a well completion engine brought onto 

the drillship will at least be certified to 40 CFR 89 EPA Tier 2 or higher standards, with equivalent or 

lower emissions than the engine represented.

5.3.5. PM/PM10/PM2.5 BACT Analysis for Third Party Well Evaluation Engines (DR-TP12 through DR-TP-16) 
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Step 1 – Identify all Control Technologies

The third party well evaluation engines on the drillship are four 140 HP diesel engines, and the 

PM/PM10/PM2.5 control options identified for the drillship main propulsion engines are assumed to 

sufficiently account for all the possible control technologies for the third party engines. Therefore, the 

same options identified for the drillship main diesel engines are considered as the potential control 

technologies for the third party engines on the drillship.

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

Replacement of Engines to meet higher EPA Tier standards – Infeasible.

The five third party well evaluation diesel engines are pre-1998 engines and hence no engine 

certification is available. During one of the well evaluation activities these five diesel engines will be 

used to send information to a logging unit powered by third party engines. Since all of these engines are 

used to power different equipment that is performing a single operation they are all leased from the 

same third party vendor to avoid compatibility issues. The third party vendor Anadarko leases these 

engines from currently has no EPA Tier certified well evaluation engines in the fleet. Therefore, this is 

not considered a viable BACT option.

LNE Design – Infeasible. 

Incorporation of this control technology will involve redesigning the engines, making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the existing well evaluation compressor diesel engines with other air 

compressor diesel engines that have this technology already installed. This technology is intrinsic to the 

engine design and retrofitting the air compressor diesel engines is not an option.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

ULSD fuel usage is the only feasible option followed by good combustion practices (manufacturer 

recommended operation and maintenance practices). Therefore, ranking is not required.

Step 4 – Evaluate Most Effective Controls and Document Results

ULSD fuel usage is the only feasible option. Therefore, ranking is not required.
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Step 5 - Select BACT

Anadarko proposes ULSD fuel usage along with good combustion and manufacturer recommended 

operation and maintenance practices as PM/PM10/PM2.5 BACT for the third party well evaluation 

engines.

5.3.6. PM/PM10/PM2.5 BACT Analysis for Representative Pump Engines on the 

Stimulation Vessel (SV-PE-01 thru SV-PE-08)

The proposed Stimulation Vessel will have eight 2,250 HP pump engines. 

Step 1 – Identify all Control Technologies

Similar to the main propulsion electrical generator engines, the pump engines on the stimulation 

vessel also are large (>500 HP) diesel engines and the PM/PM10/PM2.5 control options are expected 

to be same as the main diesel engine. Therefore, the same options identified for the main diesel 

engines are considered as the potential control technologies for the pump engines on the 

stimulation vessel.

Step 2 – Eliminate Technically Infeasible Options

DOC – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

CDPF – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

PCV – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

4-Way Catalyst Converter – Infeasible.

This control technology is deemed technically infeasible for the same reasons identified in Section 5.3.1.

LNE Design – Infeasible.

Incorporation of this control technology will involve redesigning the pumps making this technology to 

be most feasibly installed when the engine is manufactured. Requiring this technology would essentially 

mean having to replace the existing pumps with another engine that has this technology already 

installed. This technology is intrinsic to the engine design and retrofitting the pumps is not an option.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness
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Table 5-17. Ranks of Technologies Feasible for the Pumps on Stimulation Vessel

Technology Efficiency Rank

Replacement of Engines to meet higher 

EPA Tier standards

varies 1

ULSD Fuel N/A 2

Good Combustion Practices (Manufacturer 

recommended operation and maintenance 

practices)

N/A N/A

All feasible technologies for the representative pump engines are listed in Table 5-17. Control 

technologies are ranked by efficiency in a descending order.

Step 4 – Evaluate Most Effective Controls and Document Results

Replacement of Engines to meet higher EPA Tier standards – 40 CFR 89 Tier 2 compliant engine was 

identified as the cleanest available engine in the stimulation vessel pump engine category (SV-PE-01 

through SV-PE-08). Anadarko previously performed the cost effectiveness analysis for replacing the 

existing engines with the newer engines meeting the EPA 40 CFR 89 tier 2 standards. As shown in 

Section 5.1.6, this option was concluded as cost prohibitive. 

Step 5 - Select BACT

Anadarko proposes use of ULSD along with good combustion and manufacturer recommended operation 

and maintenance practices as BACT for the pump engines on the stimulation vessel.

5.3.7. PM/PM10/PM2.5 BACT Analysis for Flowback Boiler (DR-TP-22)

Step 1 – Identify all Control Technologies

The proposed flowback boiler is a small 8 MMBtu/hr diesel fired combustion source. EPA's RBLC search 

was used to obtain potential control technologies for PM/PM10/PM2.5 from boilers and review of the 

permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding permit 

applications) for similar OCS sources was conducted to obtain potential control technologies for 

PM/PM10/PM2.5 from boilers. The most recent 10-year period was used to identify applicable control 

technologies. The results of the RBLC search are included in Appendix E. The search results for 

potential control technologies for PM/PM10/PM2.5 from the main diesel engines are listed below.

Low Sulfur Fuel (ULSD)

Good Combustion Practices (Manufacturer Recommended Operation and Maintenance Practices).

Step 2 – Eliminate Technically Infeasible Option

ULSD – Feasible.

Good Combustion Practices – Feasible.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness
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Since both the identified technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since both the identified technologies are being proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes ULSD fuel usage and good combustion and manufacturer recommended operation 

and maintenance practices as the BACT for the boiler.

5.3.8. PM/PM10/PM2.5 BACT Analysis for Boom Flare (DR-TP-23)

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for PM/PM10/PM2.5 from flares 

and review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and 

corresponding permit applications) for similar OCS sources was conducted to obtain potential 

control technologies for PM/PM10/PM2.5 from flares. The most recent 10-year period was used to 

identify applicable control technologies. The results of the RBLC search are included in Appendix E. 

The search results for potential control technologies for PM/PM10/PM2.5 from flares are listed 

below.

Comply with 40 CFR 60.18

Good Combustion Practices (Manufacturer Recommended Operation and Maintenance Practices).

Step 2 – Eliminate Technically Infeasible Option

Comply with 40 CFR 60.18 – Feasible.

Good Combustion Practices – Feasible.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since both the identified technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since both the identified technologies are being proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes compliance with the requirements of 40 CFR 60.18 and good combustion and 

manufacturer recommended operation and maintenance practices as the BACT for the boom flare.
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5.3.9. PM/PM10/PM2.5 BACT Analysis for Cement and Mud Mixing Operations (DR-DC01 thru DR-DC-03)

Step 1 – Identify all Control Technologies

A RBLC search for potential control options for PM/PM10/PM2.5 from cement and mud mixing operations 

did not produce any results. Also, a review of the permits recently proposed/issued by U.S. EPA Region 

4 and Region 10 for similar OCS sources was performed. The search results for potential control 

technologies for PM/PM10/PM2.5 from flares are listed below.

Dust Collectors

Step 2 – Eliminate Technically Infeasible Option

Dust Collectors – Feasible.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since dust collectors is the only control option identified, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since dust collectors are the only control option identified, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes dust collectors with proper maintenance and operations as PM/PM10/PM2.5 BACT for 

the cement and mud mixing operations.

5.3.10. PM/PM10/PM2.5 BACT Analysis for Painting Operations (DR-PO-01)

An RBLC search for potential control options for VOC from painting operations on a drillship did not 

produce any results. Also, a review of the permits recently proposed/issued by U.S. EPA Region 4 and 

Region 10 for similar OCS sources did not result in any potential control technologies. Therefore, 

Anadarko evaluated various transfer efficiencies related to painting operations.

In marine environments, the paint could be applied with air assisted paint gun, airless paint gun, and by 

use of roller or brush. The transfer efficiency of each paint application method is provided in the Table 

below. 
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Table 5-18. Paint Application and Transfer Efficiencies

Paint Application Method Transfer Efficiency Information Source

Air assisted spray gun 30% Coating Operations Instructions for Emission 

Calculation Spreadsheet - Minnesota Pollution 

Control Agency

Airless spray gun 50% - 80% Phone and email communications with the 

equipment vendor 

Roller - N/A

The paint application method is generally dictated by the characteristics of work areas. An airless spray 

gun would be used to paint large deck areas or bulkheads since greater volume of paint and fine control 

is not required. An air assisted spray gun would be required to paint piping, brackets, and other multiangle items due to paint volume and precision requirements. An airless gun requires a great deal of 

pressure to atomize the material for spray. Due to this pressure, a volume of material that comes out of 

the gun is increased making this method as a preferred painting method on flat surfaces or tank 

applications. However, while utilizing this method for painting multi-angle items, a lot of the paint 

material is lost creating overspray and waste. A conventional air assisted gun provides a solution to this 

overspray issue due to its operational mechanism. Therefore, use of air assisted spray gun is preferred 

for painting small or multi-angle items. 

Anadarko also considered the possibility of using roller or brush application for the proposed 

operations. However, Anadarko found this painting technique unsuitable due to following reasons:

 Marine coatings are designed to perform at certain thicknesses. The proper film thickness 

for these materials to perform as designated by the product data sheet is approximately 5 

mils thick. The only way to achieve these film thicknesses in a single application is to 

spray the coating. A single application with a roller will generate approximately 1.5 mils 

in thickness per application. A surface would have to be painted 3 to 4 times per coat to 

achieve the manufactures’ requirements for coating performance.

 To achieve good film continuity most of the marine coatings are designed to be sprayed. 

The atomization of the coating promotes a good flow of the material and creates a tight 

surface that has low moisture permeation which is essential for creating a barrier system 

and makes them work.

 Throughout the drilling and well completion operations, painting crew will be dealing 

with several areas where a brush or roller could not reach and hence, the material must be 

sprayed.

Hence, Anadarko is proposing a combination of air assisted and airless gun for the proposed painting 

operations. Anadarko proposes best management practices as BACT for the painting operations. The 

best management practices will include down spraying of paint and use of a containment system such as 

a shroud or a barrier around the section of the ship being painted to prevent the airborne paint from 

drifting into the atmosphere.
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5.3.11. PM/PM10/PM2.5 BACT Analysis for Welding Operations (DR-WO-01)

Step 1 – Identify all Control Technologies

A RBLC search for potential control options for PM/PM10/PM2.5 from welding operations did not 

produce many results. Also, a review of the permits recently proposed/issued by U.S. EPA Region 4 and 

Region 10 for similar OCS sources was performed. The results of the RBLC search are included in 

Appendix E. However, it should be noted that the control technologies evaluated in the “top-down” 

analysis for these operations were not limited to the controls listed in the RBLC database. The search 

results for potential control technologies for PM/PM10/PM2.5 from flares are listed below.

Emission Limit/Welding Rod Usage Limit

Best Management Practices

Routing to Control Device

Body Shop

Step 2 – Eliminate Technically Infeasible Option

Routing to Control Device – Infeasible

The welding process results in negligible fugitive emissions, which cannot feasibly be captured and 

routed to a control device with any significant control efficiency. 

Body Shop – Infeasible

Due to available space constraints on the drillship, performing the welding operations in a separate 

body shop with options to route emissions via control device is technically infeasible. 

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Table 5-19. Ranks of Technologies Feasible for the Welding Operations

Technology Efficiency Rank

Emission Limit/Welding Rods Usage Limit N/A N/A

Best Management Practices N/A N/A

All feasible technologies for the welding operations are listed in Table 5-19. Anadarko is proposing all 

the feasible options as BACT. Therefore, ranking is not required.

Step 4 – Evaluate Most Effective Controls and Document Results

Since all the identified technologies are being proposed as BACT, a cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes emission limitation/welding rods usage limit and best management practices as 

PM/PM10/PM2.5 BACT for the welding operations.
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A summary of the proposed PM/PM10/PM2.5 BACT emission limitation for each source associated with the 

project is provided below in Table 5-20.

Table 5-20. Proposed PM/PM10/PM2.5 BACT Emission Limits

Emission Unit BACT Emission Limit BACT Basis BACT Control 

Technologies

Drillship Main Diesel Engines 

(DR-ME-01 thru DR-ME-06)

PM/PM10/PM2.5 –

2.47E-04 lb/Hp-hr 

(0.15 g/KW-hr)

NSPS IIII 

Standards

NSPS IIII standards, 

LNE design including 

Turbocharger with 

Aftercooler and High 

Fuel Pressure 

Injection, ULSD and 

Good Combustion 

Practices

Drillship Emergency Diesel 

Engine (DR-GE-01)

-- AP-42, Chapter 3, 

Table 3.4-1

EPA Tier 2, LNE design, 

ULSD and Good 

Combustion Practices

Air Compressor Diesel Engine 

(DR-AC-01)

-- 40 CFR 94 EPA 

Tier 2 Standard

ULSD, EPA Tier 2 

Standard

Good Combustion 

Practices

Third Party Engines (DR-TP-01 

through DR-TP-11 and DR-TP-17 

through DR-TP-21)

-- 40 CFR 89 EPA 

Tier 2 Standard

40 CFR 89 EPA Tier 2 

Standard and LNE 

design

Third Party Well Evaluation 

Engines (DR-TP-12 through DRTP-16)

-- AP-42, Chapter 3, 

Table 3.3-1

Good Combustion 

Practices

Stimulation Vessel Pumps (SVPE-01 thru SV-PE-08)-- AP-42, Chapter 3, 

Table 3.4-1

Good Combustion 

Practices

Flowback Boiler (DR-WC-05) -- AP-42, Chapter 1, 

Table 1.3-1

Good Combustion 

Practices

Boom Flare (DR-WC-06) -- AP-42, Chapter 1, 

Table 1.4-2

Compliance with 40 

CFR 60.18 and Good 

Combustion Practices

Cement and Mud Mixing 

Operations (DR-DC-01 thru 

DR-DC-03)

-- AP-42, Chapter 11, 

Table 11.12-2

Dust Collectors

Painting Operations (DR-PO-01) -- Paint Composition Best Management 

Practices

Welding Operations (DR-WO-01) -- AP-42, Chapter 12, 

Table 12.19-1

Best Management 

Practices
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5.4. VOC BACT ANALYSIS FOR STORAGE TANKS AND PAINTS

The storage tanks subject to VOC BACT are listed below:

5.4.1. VOC BACT Analysis for Storage Tanks (DR-DT-01 thru DR-DT-09 and DR-FT01 thru DR-FT-03)

Step 1 – Identify all Control Technologies

EPA's RBLC search was used to obtain potential control technologies for VOC from storage tanks and 

review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and corresponding 

permit applications) for similar OCS sources was conducted to obtain potential control technologies for 

VOC from storage tanks. The most recent 10-year period was used to identify applicable control 

technologies. The results of the RBLC search are included in Appendix E. The search results for 

potential control technologies for VOC from flares are listed below.

Vapor Recovery Unit (VRU)

Thermal Oxidation (TO)

Adsorption System

Internal or External Floating Roof Tank (IFR/EFR)

Submersible Fill Pipe (SFP)

Step 2 – Eliminate Technically Infeasible Option

VRU – Infeasible.

A VRU and associated vapor collection system would require a significant amount of space on the 

drillship. This installation would require significant space reassignment and significant alterations to 

the drillship that would result in modifications to the drillship design and recertification of the drillship.

TO - Infeasible.

A thermal oxidation system and associated vapor collection system would require a significant amount 

of space on the drillship. This installation would require significant space reassignment and significant 

alterations to the drillship that would result in modifications to the drillship design and recertification of 

the drillship. Furthermore, the auxiliary fuel combustion that would be necessary for an incinerator will 

generate emissions of other pollutants such as NOX and CO that may exceed the small benefit in VOC 

emission reductions because of the small amount of VOC emissions from the tanks.

Adsorption System - Infeasible.

Adsorption systems are not as efficient when controlling low concentrations of VOC that are generated 

from diesel or base oil storage tanks as opposed to the higher VOC concentrations that would be 

generated from storage of higher vapor pressure materials such as gasoline. Additionally, an adsorption 
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system will require a significant amount of space on the drillship. This installation would require 

significant space reassignment and significant alterations to the drillship that would result in 

modifications to the drillship design and recertification of the drillship.

IFR/EFR - Infeasible.

Internal and external floating roof tanks are typically utilized to control VOC emissions from stored 

liquids with high vapor pressures. As diesel fuel and base oil are low vapor pressure liquids, emissions 

of VOC from the storage tanks are expected to be minimal and the associated VOC emissions decrease 

associated with installation of a floating roof would be minimal. Additionally, the tanks on the 

BlackHornet are well integrated into the design of the drillship. Retrofitting such storage tanks with a 

floating roof would require significant space reassignment and significant alterations to the drillship in 

order to create enough space to complete the installation. These alterations would result in 

modifications to the drillship design and potentially require recertification of the drillship.

SFP - Infeasible.

While the accommodation of SFP is not difficult in the design stage of a new tank, equipping an existing 

tank on a marine vessel is expected to be a difficult hurdle. Installation will require significant space for 

handling of the equipment and safe access for the personnel. Moreover, storage tanks result in a very 

small amount of VOC emissions. Therefore, installing SFPs will only result in a very small reduction in 

the VOC emissions, would be cost prohibitive.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

There are not technologies that were identified as feasible.

Step 4 – Evaluate Most Effective Controls and Document Results

There are not technologies that were identified as feasible.

Step 5 - Select BACT

Anadarko proposes good maintenance practices as BACT for the storage tanks.

5.4.2. VOC BACT Analysis for Mud Degassing Operations (DR-VG-01)

An RBLC search for potential control options for VOC from mud degassing operations did not produce 

any results. Also, a review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 

for similar OCS sources did not result in any potential control technologies. Therefore, Anadarko 

proposes VOC BACT limit of 5.36 tpy on a 12-month rolling total basis.
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5.4.3. VOC BACT Analysis for Painting Operations (DR-PO-01)

An RBLC search for potential control options for VOC from painting operations on a drillship did not 

produce any results. Also, a review of the permits recently proposed/issued by U.S. EPA Region 4 and 

Region 10 for similar OCS sources did not result in any potential control technologies. Therefore,

Anadarko proposes best management practices as BACT for the painting operations. The best 

management practices will include down spraying of paint and use of a containment system such as a 

shroud or a barrier around the section of the ship being painted to prevent the airborne paint from 

drifting into the atmosphere.

Furthermore, the proposed coatings were selected based on following criteria: regulatory requirements, 

long term performance, waste reduction, and efficiency of application. All of the proposed paint 

materials are compliant with EPA the marine coatings requirements as specified in EPA 453/R-94-

032.

19 The VOC contents of a coating greatly influence the prospective application area (e.g., flat or 

metallic) as well as method of application (e.g., spray or roller). 

A summary of the proposed VOC BACT emission limitation for each source associated with the project is 

provided below in Table 5-21.

Table 5-21. Proposed VOCBACT Emission Limits

Emission Unit BACT Basis BACT Control 

Technologies

Storage Tanks TANKS 4.09.d Best Management 

Practices

Mud Degassing Operations 

(DR-VG-01)

Minerals 

Management 

Service Guidance

Best Management 

Practices

Painting Operations (DR-PO-01) Paint + Thinner

Composition

Best Management 

Practices

5.5. GREENHOUSE GAS (GHG) BACT ANALYSIS 

On May 13, 2010, the U.S. EPA issued the final “Prevention of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule” specifying that as of January 2, 2011, all new industrial sources that 

are major sources for any NSR regulated pollutants other than GHGs, and will emit or have the 

potential to emit 75,000 tons per year or more of total GHGs, on a CO2 equivalent (CO2e) basis will 

need to determine the Best Available Control Technology for their GHG emissions.20

 

19 Alternate Control Techniques: Surface Coating Operations at Shipbuilding and Ship Repair Facilities, April 

1994. Available online at: http://www.epa.gov/glo/SIPToolkit/ctg_act/199404_voc_epa453_r-94-

032_coating_shipbuilding_repair.pdf

20 CO2 equivalent encompasses a list of six Greenhouse Gases, including carbon dioxide, methane, nitrous 

oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. 
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5.5.1. GHG BACT Analysis for the Diesel Fired Internal Combustion Engines

The majority of Greenhouse Gas emissions from diesel engines are in the form of carbon dioxide 

(CO2). CO2 is formed during complete combustion of diesel in the combustion chamber when carbon 

in the fuel is converted to CO2. 

Step 1 – Identify all Control Technologies

The first step in the EPA top-down, five-step analysis is to identify all available control technologies 

that are potentially suitable for the affected sources. The results of the RBLC search did not identify 

GHG control technologies since GHG emission control is still an emergency area of technology. 

However, it should be noted the control technology analysis for all internal combustion engines 

were not limited to the controls listed in the RBLC database. The permits recently proposed/issued 

by U.S. EPA Region 4 and Region 10 (and corresponding permit applications) for similar OCS sources 

in Gulf of Mexico have also been reviewed in addition to surveying available literature to identify 

potential control technologies. The following technologies were identified as potentially applicable 

for controlling CO2e emissions from the diesel engines:

Carbon Capture Storage (CCS);

Alternative/Biomass Fuel Sources;

CSNOx Emissions Abatement System; 

Good Combustion and Manufacturer Recommended Maintenance Practices.

Step 2 – Eliminate Technically Infeasible Option

CCS – Infeasible.

Carbon Capture and Storage/ Carbon Sequestration refers to the processes in which CO2 that would 

otherwise be emitted into the atmosphere, is captured and stored. This process requires the 

separation and capture of CO2 at the point of emissions, transportation of the captured CO2 to the 

storage location, and storing the captured CO2 in deep underground geologic formations in such a 

way that it will remain permanently stored. Potential sites for underground storage of CO2 are 

mature oil and natural gas reservoirs, deep unmineable coal seams, deep saline formations, oil and 

gas rich organic shales, and basalt formations21. Injection of captured CO2 into the ocean at great 

depths has also been proposed as a potential option to isolate CO2 from the atmosphere for 

centuries22.

The diesel fired engines on the BlackHornet Drillship and associated project operations are designed 

for and rely on air-fired combustion, a process that exhausts CO2 diluted with nitrogen, wherein the 

flue gas contains a relatively small percentage (under 20% by volume) of CO2. For effective carbon 

sequestration, the CO2 in the exhaust gases must be separated and concentrated. Currently an 

effective method for recovering CO2 from combustion exhaust is by using amine absorbers and 

cryogenic coolers.

 

21 Carbon Sequestration Atlas of the United States and Canada, U.S. Department of Energy, Office of Fossil Energy, National Energy 

Technology Laboratory.

22 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change (IPCC), 2005 - Bert Metz, Ogunlade Davidson, 

Heleen de Coninck, Manuela Loos and Leo Meyer (Eds.), Cambridge University Press, UK.
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Currently there are no known mature oil and natural gas reservoirs in relative proximity of the areas 

proposed for exploratory drilling that can potentially be considered for geological sequestration. 

Furthermore, the exhaust from diesel engines is diluted with nitrogen in the air and the CO2 must be 

separated prior to transport for storage. This separation has to be achieved using an absorption 

process that uses the chemical reaction of an aqueous alkaline solvent, usually an amine, with the 

exhaust gases. This process will require the addition of equipment such as absorber columns, stripper 

columns, condensers, reboilers, heat exchangers, etc. Installation of such equipment would require 

significant space reassignment on the drillship, which is unavailable. 

Before deploying technologies that will inject captured and separated CO2 into the ocean at great 

depths, such technologies would require further development and field testing. Currently such 

technologies have only been tested in laboratory experiments. Furthermore, putting CO2 directly into 

the deep ocean means that the chemical environment of the deep ocean would be altered immediately. 

Given only rudimentary understanding of deep-sea ecosystems, only a limited and preliminary 

assessment of potential ecosystem effects can be given23.

Even if the above constraints are overcome, separated CO2 from the drillship would have to be 

transported using pipelines to the storage location. Given the mobile nature of the exploratory drilling 

operations and thus the emission units, it will be infeasible to connect the drillship with a static 

pipeline infrastructure to transport CO2.

Biomass Fuel Sources- Biodiesel – Infeasible

Biodiesel is a fuel made from plant or animal feedstocks, and may be used in conventional diesel 

engines. Biodiesel is comprised of specific chemical components defined by ASTM as "mono-alkyl 

esters of long chain fatty acids derived from vegetable oils or animal fats." In the United States, most 

biodiesel is made from soybean oil. However, canola oil, sunflower oil, recycled cooking oils, palm 

oil, animal fats, and other oils are also used as feedstocks. Biodiesel in its pure form is known as 

B100, but it can be blended with conventional diesel fuel. The most common blends are B5 (5 

percent biodiesel and 95 percent conventional diesel) and B20 (20 percent biodiesel and 80 percent 

conventional diesel)24. Because biodiesel is made using feedstock that contain carbon taken from 

the biosphere, the combustion of biodiesel does not add new carbon and so does not add to GHG 

emissions. However, the production of biodiesel may involve use of fossil fuel based carbon.

The diesel fired engines onboard the BlackHornet Drillship and associated project operations are not 

designed to burn biodiesel and there could be potential engine performance issues from use of 

biodiesel. Use of biodiesel may result in degradation of some fuel lines and gaskets (e.g. those made 

from nitrile and natural rubber). Biodiesel use also results in reduced power and fuel efficiency of 

engines, thus impairing the ability to safely maintain the vessel's position and perform other functions 

related to the proposed offshore operations such as drilling, cementing, and wireline. Requirements 

for handling and using biodiesel may differ from requirements for petroleum-based diesel. For 

example, biodiesel can gel at low temperatures and may require special handling in cold climates 

 

23 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change (IPCC), 2005 - Bert Metz, Ogunlade Davidson, 

Heleen de Coninck, Manuela Loos and Leo Meyer (Eds.), Cambridge University Press, UK.

24 Guidance for Biodiesel Producers and Biodiesel Blenders/Users, Transportation and Regional Programs Division Office of 

Transportation and Air Quality, U.S. Environmental Protection Agency, EPA420-B-07-019, November 2007.
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during winter. There may also be degradation of biodiesel due to long storage times25. Biodiesel 

combustion also results in increase in NOX emissions and decrease in PM, CO, and VOC emissions26.

CSNOx Emission Abatement System – Infeasible

ECOSPEC Global Technology PTE Ltd has patented the CSNOx emissions abatement system that is 

designed to convert CO2 in exhaust gases from ship engines into bicarbonates, using Ultra Low 

Frequency (ULF) wave electrolysis treatment to increase the alkalinity of the seawater injected into 

a scrubber. Seawater is pumped in to the control system from the ocean using suction pumps, 

making the system ideal for offshore applications. The system has been tested onboard a 100,000-

tonne oil tanker, at 50% gas load (equivalent to approximately 5 MW engine output), yielding a CO2

removal efficiency of 77%27 28.

The CSNOX technology has been designed for and tested on vessels that operate at stable loads 

continuously. Such operations provide exhaust gases that are consistent in their composition and 

properties over long periods of time, thereby facilitating efficient operation of the control processes. 

Due to the large load variation swing demanded by the proposed exploratory drilling operations on 

the drill floor and other applications, the diesel fired engines onboard the BlackHornet drillship and 

associated project operations will not be able sustain constant steady state loads for sufficient time 

periods. The CSNOX technology has not been tested or proven effective for engines with these types 

of load variations.

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since all the remaining feasible technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Anadarko proposes all the feasible options, as BACT for the diesel fired engines. Therefore, control 

cost analysis is not required.

Step 5 - Select BACT

Anadarko proposes good combustion and manufacturer recommended maintenance practices for all 

diesel fired internal combustion engines associated with this project operation. Additionally all 

control technologies that aid improve the combustions efficiencies of the various diesel engines 

discussed in the previous sections of the BACT are also proposed as BACT for GHGs.

5.5.2. GHG BACT Analysis for Mud Degassing Operations (DR-VG-01)

A RBLC search for potential control options for GHG from mud degassing operations did not produce 

any results. Also, a review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 

 

25 Guidance for Biodiesel Producers and Biodiesel Blenders/Users, Transportation and Regional Programs Division Office of 

Transportation and Air Quality, U.S. Environmental Protection Agency, EPA420-B-07-019, November 2007.

26 A Comprehensive Analysis of Biodiesel Impacts on Exhaust Emissions, Draft Technical Report Assessment and Standards Division, 

Office of Transportation and Air Quality, U.S. Environmental Protection Agency, EPA420-P-02-001, October 2002.

27 CSNOX Brochure from http://www.ecospec.com , last accessed on August 28, 2010.

28 Regulatory Impact Analysis: Control of Emissions of Air Pollution from Category 3 Marine Diesel Engines, Assessment and Standards 

Division, Office of Transportation and Air Quality, U.S. Environmental Protection Agency, December 2009.
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10 for similar OCS sources did not result in any potential control technologies. Therefore, Anadarko 

proposes GHG BACT limit of 271.37 tpy on a 12-month rolling total basis.

5.5.3. GHG BACT Analysis for Flowback Boiler (DR-TP-22)

A RBLC search for potential control options for GHG from boiler operations did not provide a 

specific control technology. Also, a review of the permits recently proposed/issued by U.S. EPA 

Region 4 and Region 10 for similar OCS sources did not result in any potential control technologies. 

Therefore, Anadarko proposes good combustion practices along with manufacturer recommended 

operations and maintenance practices as BACT.

5.5.4. GHG BACT Analysis for Boom Flare (DR-TP-23)

Step 1 – Identify all Control Technologies

A review of the permits recently proposed/issued by U.S. EPA Region 4 and Region 10 (and 

corresponding permit applications) for similar OCS sources was conducted for flaring operations on a 

MODU did not produce any results. The most recent 10-year period was used to identify applicable 

control technologies. The search results for potential control technologies for GHG from flares are 

listed below.

Comply with 40 CFR 60.18

Good Combustion and Manufacturer Recommended Maintenance Practices

Proper Equipment Design and Maintenance

Maintain Presence of Flame at Flare Tip at all times

Flare gas minimization

Step 2 – Eliminate Technically Infeasible Option

Maintain Presence of Flame at Flare Tip at all times – Infeasible.

Since the boom flare is portable this option is not feasible.

Flare Gas Minimization – Infeasible.

Redesigning to meet this operation would likely require a reconfiguration of piping during a well 

control situation and is not feasible. This would include rerouting gas that would have been sent to 

the flare back to the process to minimize emissions which are infeasible during off shore drilling 

process. 

Step 3 – Rank Remaining Control Technologies by Control Effectiveness

Since all the remaining feasible technologies are being proposed as BACT, no ranking is required

Step 4 – Evaluate Most Effective Controls and Document Results

Since all the remaining feasible technologies are being proposed as BACT, a cost analysis is not 

required.
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Step 5 - Select BACT

Anadarko proposes manufacturer recommended good combustion operating practices, and proper

maintenance of flare as the BACT for the boom flare.

Table 5-21 below summarizes EPA’s BACT determinations for the diesel internal combustion engines 

with respect GHG emissions. The respective emission limits are based on AP-42 and the emission 

factors for CO2e were determined using the global warming potentials obtained from 40 CFR 98

Subpart C.
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A summary of the proposed GHG BACT emission limitation for each source associated with the project 

is provided below in Table 5-22.

Table 5-22. Proposed CO2e BACT Emission Limits

Emission Unit BACT Emission 

Limit BACT Basis BACT Control Technologies

Drillship Main Engines 

(DR-ME-01 thru DR-ME-06)

699 g/KW-hr

CO2e

40 CFR 98 

Subpart C

LNE Design with 

Turbocharger with 

Aftercooler & High Injection 

Pressure, Optimized 

Supercharger with Miller 

Cycle,

Good combustion and 

manufacturer 

recommended maintenance 

practices

Drillship Emergency 

Generators (DR-GE-01)

-- 40 CFR 98 

Subpart C

Turbocharger with 

Aftercooler & High Injection 

Pressure, 

Good combustion and 

manufacturer 

recommended maintenance 

practices 

Emergency Air Compressor 

Engine (DR-AC-01)

-- 40 CFR 98 

Subpart C

Good combustion and 

manufacturer 

recommended maintenance 

practices 

Third Party Engines -- 40 CFR 98 

Subpart C

Good combustion and 

manufacturer 

recommended maintenance 

practices 

Stimulation Vessel Pumps (SVPE-01 thru SV-PE-07)-- 40 CFR 98 

Subpart C

Good combustion and 

manufacturer 

recommended maintenance 

practices 

Flowback Boiler (DR-TP-22) -- 40 CFR 98 

Subpart C

Good combustion and 

manufacturer 

recommended maintenance 

practices 

Boom Flare (DR-TP-23) -- 40 CFR 98 

Subpart C

Good combustion and 

manufacturer 

recommended maintenance 

practices 

Mud degasser Vent (DR-VG-01) -- 40 CFR 98 

Subpart C

Best management practices 

and manufacturer 

recommended maintenance 

practices
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6. PART 71 FORMS
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APPENDIX A – PLOT PLAN
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APPENDIX B – EMISSION CALCULATIONS
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APPENDIX C – LIST OF INSIGNIFICANT ACTIVITIES
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APPENDIX D – AIR DISPERSION MODELING ANALYSIS
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APPENDIX E – BACT ANALYSIS SUPPORTING DOCUMENTATION
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APPENDIX F – ENVIRONMENTAL IMPACT ASSESSMENT
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APPENDIX G -1 – SPECIFICATION SHEETS: DRILLSHIP
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APPENDIX G-2 – SPECIFICATION SHEETS: THIRD PARTY EPA TIER II 

CERTIFIED ENGINES
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APPENDIX G-3 – SPECIFICATION SHEETS: NON-EPA TIERED WELL 

EVALUATION ENGINES
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APPENDIX G-4 – TANKS 4.09 OUTPUT FOR DRILLSHIP TANKS
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APPENDIX G-5 – SPECIFICATION SHEETS: DUST COLLECTORS
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APPENDIX G-6 – SPECIFICATION SHEETS: MSDS - PAINTS/BASE/THINNER
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APPENDIX G-7 – TANKS 4.09 OUTPUT FOR SUPPLY BOAT TANKS
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APPENDIX G-8 – DRILLSHIP MAIN ENGINE MANUFACTURER MAINTENANCE
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APPENDIX G-9 – THIRD PARTY FLOWBACK BOILER
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APPENDIX G-10 – SPECIFICATION SHEETS: SUPPLY BOAT
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APPENDIX G-11 – ANCHOR HANDLING BOAT
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APPENDIX G-12 – SPECIFICATION SHEETS: TUG
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APPENDIX G-13 – SPECIFICATION SHEETS – BARGE
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APPENDIX G-14 – TANKS 4.09 OUTPUT FOR CONDENSATE TANKS
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 

Trinity Consultants

APPENDIX G-15 – SPECIFICATION SHEETS – STIMULATION VESSEL
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 

Trinity Consultants

APPENDIX G-16 – SPECIFICATION SHEETS – WELL EVALUATION VESSEL
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 

Trinity Consultants

APPENDIX G-17 – TANKS 4.09 OUTPUT FOR ANCHOR BOAT TANKS
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 

Trinity Consultants

APPENDIX G-18 – MSDS OF ULTRA LOW SULFUR DIESEL