Environmental solutions delivered uncommonly well 

Anadarko Petroleum Corporation 

BlackHornet PSD/Title V Permit Application 

Operations in the Eastern Gulf of Mexico 

Revision 1 

Prepared	By:	

TRINITY CONSULTANTS

301	Main	Street,	Suite	900	

Baton	Rouge,	LA	70816	

(225)	292‐2661	

September	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 DR‐

TP‐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‐TP‐

17 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‐ME‐

01 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 DR‐

TP‐17 though DR‐TP‐21)..................................................................................................................................................................120

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

5.3.11. PM/PM10/PM2.5BACT 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	 NW	 167	 U.S.	Fish	&	Wildlife	 	 95	

149	 St.	Marks	NWR	 NE	 285	 U.S.	Fish	&	Wildlife	 	 101	

149	

Bradwell	Bay	

Wilderness	 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	pre‐

construction	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	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 

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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 1,363	 40	 Yes

CO	 540	 100	 Yes

PM	 35	 25	 Yes

PM10	 32	 15	 Yes

PM2.5 32	 10	 Yes

SO2	 1	 40	 No	

VOC	 121	 40	 Yes

Pb	 0.02	 0.6	 No	

H2SO4 0.03	 7	 No	

GHG	 111,108	 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. 
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 

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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‐TP‐	

09	

Third	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	short‐

term	(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,	

9H32/40V	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/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	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	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 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	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/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	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 94 Control of Emissions From Marine Compression‐Ignition –Particulate	matter	(PM,	

PM10,	and	PM2.5),	NOX,	and	CO	emissions	estimates	for	the	fast	rescue	craft	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.		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	AP‐

42,	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	(JP‐

4)	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,	Tables	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.

			

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	

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	
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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.	

Fuel Based Emission Factor Derivation:	
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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,	1	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.			

3.4.5. 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.	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 43 

Trinity Consultants

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:	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 44 

Trinity Consultants

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:	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 45 

Trinity Consultants

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:	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 46 

Trinity Consultants

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.	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 47 

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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.			
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 48 

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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	
Anadarko Petroleum Corporation| Diamond BlackHornet EGOM PSD/Title V Permit Application 49 

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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	from	Main	Engines	

(TB‐ME‐01	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‐GE‐

02)	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	BSFC	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	TB‐

ME‐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‐ME‐

03)	and	Generators	(TB‐GE‐01	and	TB‐GE‐02)	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	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‐ME‐

02),	representative	Thrusters	(SV‐BT‐01	through	SV‐ST‐01),	representative	Drop‐down	Engines	(SV‐

DD‐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/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.	

3.4.20. 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/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.	

3.4.22. 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/HP‐

hr	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	504	

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,	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.	

3.4.24. 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/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.	

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	28,800	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	28,800	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	

4,800	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	

4,800	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	

4,800	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	

4,800	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 ManufacturingYear

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	 32.2	

DR‐ME‐08	 Main	Propulsion	Electrical	

Generator	Engine	#8	 2012	

12,069	 32.2	

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		 7.85	 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.	

*The	factor	represents	emission	limit	for	NOx	+	NMHC	
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Table 4‐4. Emergency Generator Residual Emissions

Pollutant PTE Emissions (tpy) EPA Tier 2 (tpy)

Residual

Emissions

(tpy)

NOx	+	NMHC	 1.64	 1.34	 +0.30	

CO	 0.08	 0.73	 ‐‐	

PM	 0.089	 0.042	 +0.047	

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. ENGANGERED 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‐PE‐

08)	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	more	than	$30,000	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	lower‐

temperature,	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‐TP‐

17	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	(SV‐

PE‐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‐TP‐

01	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.		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) 

Step 1 – Identify all Control Technologies
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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	multi‐

angle	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/PM2.5BACT 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	

LNE	design,	ULSD	and	

Good	Combustion	

Practices	

Air	Compressor	Diesel	Engine	

(DR‐AC‐01)	

‐‐ 40	CFR	89 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	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‐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	(SV‐

PE‐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