03/30/2012 BHPB PD OCS-EPA-R4008

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Region 4 

Atlanta, Georgia 

Preliminary Determination & Statement of Basis

Outer Continental Shelf Air Permit OCS-EPA-R4008

for

BHP Billiton Petroleum, Inc.

Sake Prospect Drilling Project

March 30, 2012
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03/30/2012 BHPB PD OCS-EPA-R4008

Table of Contents

1.0 Introduction........................................................................................................................................... 1

2.0 Applicant Information........................................................................................................................... 2

2.1 Applicant Name and Address ........................................................................................................... 2

2.2 Facility Location ............................................................................................................................... 2

3.0 Proposed Project ................................................................................................................................... 3

3.1 Operating Scenario 1......................................................................................................................... 4

3.2 Operating Scenario 2......................................................................................................................... 4

3.3 Support Vessel Operations................................................................................................................ 4

4.0 Legal Authority and Regulatory Applicability ..................................................................................... 5

4.1 EPA Jurisdiction ............................................................................................................................... 5

4.2 OCS Air Regulations ........................................................................................................................ 5

4.3 Prevention of Significant Deterioration (PSD)................................................................................. 6

4.4 Title V ............................................................................................................................................... 8

4.5 New Source Performance Standards (NSPS) ................................................................................... 8

4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)........................................ 12

5.0 Project Emissions................................................................................................................................ 13

5.1 C.R. Luigs (Operating Scenario 1) Main Engine Analysis............................................................. 14

5.2 C.R. Luigs (Operating Scenario 1) Smaller Emission Unit Analysis ............................................. 15

5.3 DD1 (Operating Scenario 2) Main Engine Analysis ...................................................................... 16

5.4 DD1 (Operating Scenario 2) Smaller Emission Unit Analysis....................................................... 16

5.5 Support Vessels............................................................................................................................... 17

5.6 Compliance Methodology............................................................................................................... 17

6.0 Best Available Control Technology (BACT) ..................................................................................... 18

6.1 BACT Analysis for Internal Combustion Engines ......................................................................... 19

6.2 BACT Analysis for Storage Tanks................................................................................................. 34

6.3 BACT Analysis for Mud and Cement Mixing................................................................................ 35

6.4 BACT Analysis for Mud Degassing............................................................................................... 35

7.0 Air Quality Impact Analyses Summary.............................................................................................. 36

7.1 Required Analyses.......................................................................................................................... 36

7.2 PSD Class I Areas Impact Analyses............................................................................................... 38

7.3 Conclusions..................................................................................................................................... 42

8.0 Additional Requirements.................................................................................................................... 42

8.1 Endangered Species Act and Essential Fish Habitat of Magnuson-Stevens Act............................ 42

8.2 National Historic Preservation Act ................................................................................................. 43

8.3 Executive Order 12898 – Environmental Justice............................................................................ 43

9.0 Public Participation............................................................................................................................. 44

9.1 Opportunity for Public Comment ................................................................................................... 44

9.2 Public Hearing ................................................................................................................................ 45

9.3 Administrative Record.................................................................................................................... 45

9.4 Final Determination ........................................................................................................................ 46
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ABBREVIATIONS AND ACRONYMS

AP-42 AP-42 Compilation of Air Pollutant Emissions Factors

AQRV Air Quality Related Values

BACT Best Available Control Technology 

BHPB BHP Billiton Petroleum

BOEM Bureau of Ocean Energy Management

Breton NWR Breton National Wildlife Refuge

Btu British thermal unit

CAA Clean Air Act 

CFR Code of Federal Regulations 

CO Carbon monoxide 

CO2 Carbon Dioxide

CO2e Carbon dioxide (CO2) equivalent

DD1 Development Driller 1

EPA United States Environmental Protection Agency 

ESA Endangered Species Act

FLM Federal Land Manager

GHG Green House Gas

GOM Gulf of Mexico

HAP Hazardous Air Pollutants 

hp Horsepower 

IC Internal Combustion 

kPa kilopascals

m

3 Cubic Meters

MSA Magnuson-Stevens Fishery Conservation and Management Act

NAAQS National Ambient Air Quality Standards

NESHAP National Emission Standards for Hazardous Air Pollutants 

NO2 Nitrogen dioxide

NOAA National Oceanic and Atmospheric Administration

NOX Oxides of nitrogen 

NSPS New Source Performance Standards 

NSR New Source Review 

OCS Outer Continental Shelf 

OCSLA Outer Continental Shelf Lands Act

Part 55 40 CFR part 55 

PM Particulate matter

PM2.5 Particulate matter with an aerodynamic diameter less than 2.5 microns 

PM10 Particulate matter with an aerodynamic diameter less than 10 microns 

ppm parts per million

PSD Prevention of Significant Deterioration 

PTE Potential to Emit 

rpm revolutions per minute 

SER Significant emission rate 

SO2 Sulfur dioxide 

Support Vessels Work Boat, Supply Boat, and Crew Boat 

TPY tons per year 

TVP true vapor pressure

VOC Volatile organic compounds
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03/16/2012 DRAFT PD OCS-EPA-R4008

1.0 Introduction

BHP Billiton Petroleum, Inc., (the Applicant or BHPB) has applied for an Outer Continental Shelf 

(OCS) air permit pursuant to section 328 of the Clean Air Act (CAA) from the United States 

Environmental Protection Agency (EPA) Region 4 for the proposed mobilization and operation of a 

deepwater drilling vessel and associated support vessels within 49 lease blocks in the DeSoto Canyon

area of the Gulf of Mexico. BHPB‟s application covers exploratory oil and gas drilling operations for up 

to 2 years at locations within specified lease blocks. BHPB intends to drill under one of two operating 

scenarios, and dependant on the scenario, will use one of two deepwater drilling vessels, either the C.R. 

Luigs for Operating Scenario 1 or the Development Driller 1 (DD1) for Operating Scenario 2. BHPB

will not establish any permanent production platforms in the proposed exploration areas under this 

permit. If resource discoveries are made during exploration activities, resultant facilities would be 

permitted separately.

EPA Region 4 is the agency responsible for implementing and enforcing CAA requirements for OCS 

sources in the Gulf of Mexico east of longitude 87°30„ (87.5° W).

1

The EPA has completed review of 

the application and supplemental materials and is proposing to issue Permit Number OCS-EPA-R4008

to BHPB for an exploratory drilling program subject to the terms and conditions described in the permit. 

The draft permit incorporates the applicable requirements from the federal Prevention of Significant 

Deterioration (PSD) and title V operating permit programs, New Source Performance Standards (NSPS) 

and National Emission Standards for Hazardous Air Pollutants (NESHAP), as required by the OCS Air 

Quality Regulations, 40 CFR part 55.

This document serves as a fact sheet, preliminary determination, and statement of basis for the draft 

permit. It provides an overview of the project, a summary of the applicable requirements, the legal and 

factual basis for the draft permit conditions, and the EPA‟s analysis of key aspects of the application and 

permit such as the best available control technology (BACT) analysis and air quality impact analysis. 

Additional information can be found in the draft permit accompanying this document, as well as in the 

application and administrative record for this project, as discussed in Section 9 of this document.

2

 

1

See CAA § 328. The Department of Interior has jurisdiction for Clean Air Act implementation west of 87°30‟.

2 The procedures govering the issuance of both OCS and PSD permits are set forth at 40 CFR Part 124, Subparts A and C. See 40 CFR §§ 

55.6(a)(3) and 124.1. Accordingly, EPA has followed the procedures of 40 CFR Part 124 in issuing this draft permit. This Preliminary 

Determination describes the derivation of the permit conditions and the reasons for them as provided in 40 CFR § 124.7, and also serves as 

a Fact Sheet as provided in 40 CFR § 124.8 and statement of basis required by 40 CFR § 71.1(a)(5).
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2.0 Applicant Information

2.1 Applicant Name and Address

BHP Billiton Petroleum, Inc.

1360 Post Oak Blvd., Suite 150

Houston, Texas 77056

2.2 Facility Location

BHPB plans to conduct exploratory drilling at multiple sites in the OCS waters of the Gulf of Mexico, 

DeSoto Canyon area, within lease blocks 499, 543-545, 586-592, 631-640, 676-685, 721-729, 768-773, 

and 815-817, Figure 2-2. These 49 contiguous lease blocks are located approximately within latitudes

28.15° to 28.50° N and longitudes 86.68° to 87.27° W, east of longitude 87.5° W. The center of the lease 

block area is located at latitude 28.31° N and longitude 86.96° W, approximately 120 miles southeast of 

the nearest Louisiana shoreline, 139 miles south southeast of the nearest Mississippi shoreline, and 125 

miles south of the nearest Alabama and Florida shorelines as illustrated below in Figure 2-1.

Figure 2-1: Site Location3

 

3

Site location map supplied by BHPB in their application as Figure 1-2 on page 1-5.
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03/28/2012 PD OCS-EPA-R4008

Figure 2-2: BHPB’s Lease Blocks4

3.0 Proposed Project

For this project, known as the Sake Prospect Drilling Project (Sake Project), BHPB proposes to conduct 

exploratory oil and natural gas drilling using a mobile offshore drilling unit (MODU) for a period of up 

to two years. For operational flexibility, BHPB plans to use either the Transocean ultra-deepwater 

MODU C.R. Luigs (Operating Scenario 1) or the Transocean semisubmersible MODU DD1 (Operating 

Scenario 2) and an associated support fleet in multiple locations within its DeSoto Canyon lease blocks 

as discussed above. BHPB is applying for an OCS air permit that will incorporate PSD preconstruction

air permit and title V operating permit program requirements. The project will last a maximum of two 

years, and based on applicable permitting regulations, qualifies as a “temporary source” for PSD 

permitting purposes.

Air pollutant emissions generated from the Sake Project include carbon monoxide (CO), nitrogen 

dioxide (NO2); particulate matter (PM) which includes particulate matter with an aerodynamic diameter 

less than 10 microns (PM10) and with an aerodynamic diameter less than 2.5 microns (PM2.5); and sulfur 

dioxide (SO2) (known as criteria pollutants), as well as other regulated air pollutants, including oxides of 

nitrogen (NOX), volatile organic compounds (VOC), and greenhouse gases (GHGs). VOC and NOX are 

the measured precursors for the criteria pollutant ozone, and NOX and SO2 are measured precursors for 

the criteria pollutant PM2.5.

These emissions are primarily released from the combustion of diesel fuel in the MODU‟s main diesel 

engines used for electric power generation for dynamic position station-keeping and drilling operations. 

Diesel engines are used to run cranes, a black start compressor, cementing operations, wireline units, 

 

4Lease block map supplied by BHPB in their application as Figure 1-1 on page 1-4.
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03/28/2012 PD OCS-EPA-R4008

and support vessels operating within 25 miles of the MODU. The emergency generator, life boats, and 

the fast rescue craft are also powered by diesel engines and are routinely operated for testing and 

maintenance, releasing additional emissions. In addition, there are PM/PM10/ PM2.5 emissions from the 

mud and cement dust collectors. VOC and GHG emissions are released from a mud degassing unit and 

the storage tanks used to store diesel fuel, hydraulic oil, base oil, and jet A helifuel. 

Based on emissions estimates, the Sake Project has the potential to emit the regulated NSR pollutants 

CO, NOX, PM/PM10/ PM2.5, VOC, and GHGs above their PSD significant emission rates. This triggers a 

PSD BACT analysis, air quality analysis, monitoring, reporting, and recordkeeping requirements for the 

applicable emission sources releasing these pollutants. The project must comply with all subsequent 

regulatory obligations that apply.

3.1 Operating Scenario 1

The C.R. Luigs is a dynamically positioned MODU equipped with a computer controlled system to 

automatically maintain the vessel's position and heading over the desired location using the vessel‟s own 

propellers and thrusters. The MODU travels under its own power to the next drill site and does not 

require towing or anchoring vessels. The C.R. Luigs is equipped with eight main diesel generator 

engines to provide power and propulsion, four crane diesel engines, one emergency diesel generator, 

two cementing unit diesel engines, four life boats, and one fast rescue craft powered by a diesel engine. 

In addition there is one mud degassing unit, two mud and cement dust collectors, and a black start 

hydraulic compressor. There are 29 tanks to store diesel fuel, one tank for hydraulic oil, one tank for 

base oil, and two tanks to store jet A helifuel. The diesel engines and storage tanks for the cementing 

nitrogen pump and wireline units are temporary installations that are brought onto the MODU for 

specific operations. Engine details and emission information are provided in Section 5.0 of this 

document and in BHPB‟s OCS permits application materials, which are included in the administrative 

record for this project as discussed in Section 9.0 of this document.

3.2 Operating Scenario 2

The DD1 is a semi-submersible MODU configured with large buoyant pontoon structures below the 

water surface and columns supporting a platform deck above the surface. The DD1 is equipped with 

eight main power plant generator diesel engines to provide power and propulsion, two cementing unit 

diesel engines, one emergency diesel generator, one mud degassing unit, two mud and cement dust 

collectors, and 21 tanks to store diesel fuel and hydraulic oil, one tank for base oil, and four tanks to 

store jet A helifuel. The four life boats and the one fast rescue craft are powered by diesel engines. The 

diesel engines and storage tanks for the cementing nitrogen pump and wireline units are temporary 

installations that are brought onto the MODU for specific operations. Engine details and emissions 

information are provided in Section 5.0 of this document and in BHPB‟s OCS permits application 

materials, which are included in the administrative record for this project as discussed in Section 9.0 of 

this document.

3.3 Support Vessel Operations

BHPB relies on a fleet of support vessels, including crew boats, supply boats, and work boats. The 

specific support vessels have not been assigned to this project or operating scenario. Proposed allowable 

emission rate limits for support vessels will apply to any support vessel within a defined category to 

allow flexibility. 
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To calculate annual emissions, BHPB estimated the total combined annual emission for all support boats 

operating within 25 miles of the MODU, using the vessels with the highest emission rates in the fleet. 

BHPB reviewed available work boats and determined the Allie work boat had the worst case emissions 

based on engine rating. BHPB reviewed available crew boats and determined the Fast Skipper crew boat 

had the worst case emissions based on engine rating. These worst case support vessels were then used to 

calculate support vessel emissions in conjunction with Air Pollutant Emissions Factors (AP-42).

Support vessel engine details and emissions information are provided in Section 5.0 of this document

and in BHPB‟s OCS permits application materials, which are included in the administrative record for 

this project as discussed in Section 9.0 of this document.

4.0 Legal Authority and Regulatory Applicability

4.1 EPA Jurisdiction

The 1990 CAA Amendments transferred authority for implementation of the CAA for sources subject to 

the Outer Continental Shelf Lands Act (OCSLA) from the Department of the Interior (DOI) to the EPA 

for all areas of the OCS, with the exception of the Gulf of Mexico, west of 87.5 degrees longitude.5

Section 328(a)(1) of the CAA requires the EPA to establish requirements to control air pollution from

OCS sources east of 87.5 degrees longitude, in order to attain and maintain federal and state ambient air 

quality standards and to comply with the provisions of part C (Prevention of Significant Deterioration) 

of title I of the CAA.

4.2 OCS Air Regulations

The OCS Air Regulations at 40 CFR part 55 implement section 328 of the CAA and establish the air 

pollution control requirements for OCS sources and the procedures for implementation and enforcement 

of the requirements. The regulations define “OCS source” by incorporating and interpreting the statutory 

definition of OCS source:

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 the 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 there from, within the 

meaning of section 4(a)(I) of OCSLA (43 U.S.C. §1331 et seq. ); or

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

aspects of the vessels will be regulated [40 CFR § 55.2; see also CAA § 328(a)(4)(C), 42 

U.S.C. § 7627].

 

5

Subsequently, the Consolidated Appropriations Act, 2012 (P.L. 112-74), transferred authority from EPA to DOI for areas 

offshore the North Slope of Alaska.
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Section 328 and part 55 distinguish between OCS sources located within 25 miles of a state's seaward 

boundary and those located beyond 25 miles of a state‟s seaward boundary [CAA § 328(a)(1); 40 CFR 

§§ 55.3(b) and (c)]. In this case, BHPB is seeking a permit for exploratory drilling operations that will 

be conducted exclusively beyond 25 miles of any states' seaward boundary.

The OCS Air Regulations set forth the federal CAA requirements that apply to OCS sources. Sources 

located beyond 25 miles of a state's seaward boundaries are subject to the New Source Performance 

Standards (40 CFR part 60); the Prevention of Significant Deterioration pre-construction program (40 

CFR § 52.21) if the OCS source is also a major stationary source or a major modification to a major 

stationary source; standards promulgated under section 112 of the CAA if rationally related to the 

attainment and maintenance of federal and state ambient air quality standards or the requirements of part 

C of title I of the CAA; and the title V operating permit program (40 CFR part 71). See 40 CFR §§ 

55.13(a), (c), (d)(2), (e), and (f)(2), respectively. The applicability of these requirements to BHPB‟s 

exploration drilling program is discussed below.

The OCS regulations also contain provisions relating to monitoring, reporting, inspections, compliance, 

and enforcement. See 40 CFR §§ 55.8 and 55.9. Section 55.8(a) and (b) authorize the EPA to require 

monitoring, reporting and inspections for OCS sources and provide that all monitoring, reporting, 

inspection and compliance requirements of the CAA apply to OCS sources. These provisions, along 

with the provisions of the applicable substantive programs listed above, provide authority for the 

monitoring, recordkeeping, reporting and other compliance assurance measures included in this 

proposed permit.

4.3 Prevention of Significant Deterioration (PSD)

The PSD program, as set forth at 40 CFR § 52.21, is incorporated by reference into the OCS Air 

Regulations at 40 CFR § 55.13(d)(2), and is applicable to major OCS sources such as BHPB. The 

objective of the PSD program is to prevent significant adverse environmental impact from air emissions 

by a proposed new or modified source. The PSD program limits degradation of air quality to that which 

is not considered “significant.” The PSD program requires an assessment of air quality impacts of the 

proposed project, and also requires the utilization of the best available control technology (BACT) as 

determined on a case-by-case basis taking into account energy, environmental and economic impacts, 

and other costs.

Under the PSD regulations, a stationary source is “major” if, among other things, it emits or has the 

potential to emit (PTE) 100 ton per year (TPY) or more of a “regulated NSR pollutant” as defined in 40 

CFR § 52.21(b)(50) and which is “subject to regulation” as defined in 40 CFR § 52.21(b)(49) and the 

stationary source is one of a named list of source categories. In addition to the preceding criteria, any 

stationary source is also considered a major stationary source if it emits or has the potential to emit 250 

TPY or more of a regulated NSR pollutant [40 CFR § 52.21(b)(l)]. “Potential to emit” is defined as the 

maximum capacity of a source to emit a pollutant under its physical and operational design. “Any 

physical or operational limitation on the capacity of the source to emit a pollutant, including air 

pollution control equipment and restrictions on hours of operation or on the type or amount of material 

combusted, stored or processed, shall be treated as part of its design if the limitation or the effect it 

would have on emissions is enforceable.” See 40 CFR § 52.21(b)(4).

In the case of “potential emissions” from OCS sources, 40 CFR part 55 defines the term similarly and 

provides that:
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Pursuant to section 328 of the Act, 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” for an OCS source. This definition does not alter or affect the use of this 

term for any other purposes under 40 CFR §§ 55.13 or 55.14 of this part, except that vessel 

emissions must be included in the “potential to emit” as used in 40 CFR §§ 55.13 or 55.14 of 

this part (40 CFR § 55.2).

Thus, emissions from vessels servicing or associated with an OCS source that are within 25 miles of the 

OCS source are considered in determining the “potential to emit” or “potential emissions” of the OCS 

source for purposes of applying the PSD regulations. Emissions from such associated vessels are 

therefore counted in determining whether the OCS source is required to obtain a PSD permit, as well as 

in determining the pollutants for which BACT is required. 

Drillships and other vessels contain many emission sources that otherwise meet the definition of 

“nonroad engine” as defined in section 216(10) of the Clean Air Act. However, based on the specific 

requirements of CAA section 328, emissions from these otherwise nonroad engines on subject support 

vessels are considered as “potential emissions” from the OCS source. Similarly, all engines that are part 

of the OCS source are subject to the requirements of 40 CFR 55, applicable to the OCS source, 

including control technology requirements.

Also, beginning on January 2, 2011, greenhouse gases (GHGs) became subject to regulation under the 

PSD major source permitting program and a regulated NSR pollutant when emitted in amounts greater 

than certain applicability thresholds. GHGs are a single air pollutant defined in 40 CFR 52.21(b)(49)(i) 

as the aggregate group of the following six gases: 

Carbon dioxide (CO2);

Nitrous oxide (N2O);

Methane (CH4);

Hydrofluorocarbons (HFCs);

Perfluorocarbons (PFCs); and

Sulfur hexafluoride (SF6).

Due to the nature of GHGs and their incorporation into the definition of subject to regulation, the 

process for determining whether a source is emitting GHGs in an amount that would make the GHGs a 

regulated NSR pollutant includes a calculation of, and applicability threshold for, the source based on 

CO2 equivalent (CO2e) emissions as well as its GHG mass emissions. Consequently, when determining 

the applicability of PSD to GHGs, there is a two-part applicability process that evaluates both:

The sum of the CO2e emissions in TPY of the six GHGs, in order to determine whether 

the source‟s emissions are a regulated NSR pollutant; and, if so;

The sum of the mass emissions in TPY of the six GHGs, in order to determine if there is 

a major source or major modification of such emissions.

For PSD permits issued on or after July 1, 2011, PSD applies to the GHG emissions from a proposed 

new source if either of the following are true: (1) the source is subject to PSD for another pollutant and 

the potential to emit GHGs is greater than or equal to 75,000 TPY on a CO2e basis and greater than zero 

TPY on a mass basis; or (2) the potential emissions of GHGs from the new source would be equal to or 

greater than 100,000 TPY on a CO2e basis and equal to or greater than 100/250 TPY on a mass basis.
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Table 4-1 lists the PTE for each regulated NSR pollutant from the project, as well as the significant 

emission rate (SER) for each regulated NSR pollutant. Section 5.0 of this document and the permit 

application contain information on the emissions factors used to determine PTE.

Table 4-1: Potential to Emit for Regulated NSR Pollutants

Pollutant

C.R. Luigs

PTE

(TPY)

DD1

PTE

(TPY)

Significant 

Emission Rate 

(TPY)

PSD

Review 

Required?

PM 66.02 59.62 25 Yes

PM10 41.15 34.94 15 Yes

PM2.5 40.16 33.96 10 Yes

NOX

a

1,699.60 1,306.04 40 Yes

SO2

b

0.91 0.88 40 No

H2SO4 0.03 0.03 7 No

CO 373.69 308.53 100 Yes

VOCc81.61 74.36 40 Yes

GHGs (CO2e) 101,574.72 97,503.61 75,000 (subject to

regulation threshold) Yes

Lead 0.02 0.02 0.60 No

 a

NOX is a measured pollutant for the criteria pollutants ozone and NO2 and a precursor for PM2.5.

b

SO2 is a precursor for the criteria pollutant PM2.5.

c

VOC is a measured pollutant for the criteria pollutant ozone.

Because exploration drilling programs are not included in the list of source categories subject to a 100 

TPY applicability threshold, the requirements of the PSD program apply if the project PTE is at least 

250 TPY. From Table 4-1, it is evident that BHPB‟s Sake drilling project is a major PSD source because 

emissions of NOX (under either operating scenario) exceed the major source applicability threshold of 

250 TPY and, thus, is subject to PSD review for NOX (both as the measured pollutant for NO2 and 

ozone and as a precursor to PM2.5) and CO. PSD review also applies to PM, PM10, PM2.5, GHGs,, and 

VOC (as the measured pollutant for ozone) because emissions of these pollutants exceed the respective 

significant emission rate thresholds. Section 6.0 of this document contains a discussion of the BACT 

analysis required under PSD. Section 7.0 of this document discusses the applicable provisions of the air 

quality impact analysis.

4.4 Title V

The requirements of the title V operating permit program, as set forth at 40 CFR part 71, apply to major 

OCS sources located beyond 25 miles of states' seaward boundaries. Because the PTE for this project is 

greater than 100 TPY for NOX and CO, it is considered a major source under title V and part 71. An 

OCS source must apply for an operating permit as provided in 40 CFR § 71.5(a)(1)(i) within 12 months 

of first becoming an OCS source on its lease blocks. The OCS permit application submitted by BHPB 

seeks to obtain a title V operating permit in accordance with 40 CFR § 55.13(f)(2) and 40 CFR part 71 

concurrently with the PSD permit. Part 71 forms are included in Section 6 of BHPB‟s application 

received on October 20, 2010, and Attachment 2 of the application addendum received on 

February 11, 2011. The proposed permit includes requirements necessary to meet the requirements of 

the applicable title V operating permits program. For example, the draft permit includes requirements for 

submittal of annual compliance certifications and annual fee payments, based on actual emissions, as 

well as monitoring, recordkeeping and reporting requirements.
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4.5 New Source Performance Standards (NSPS)

An OCS source must comply with any NSPS for which the source has subject equipment. See 

40 CFR § 55.l3(c). In addition, per 40 CFR § 52.21(j)(1), the PSD regulations require each major 

stationary source or major modification to meet applicable NSPS. A specific NSPS subpart 

(40 CFR part 60) applies to a source based on source category, equipment capacity, and the date when 

the equipment commenced construction or modification. Potentially applicable NSPS for which the 

source may have subject equipment are discussed below.

4.5.1 Subpart IIII

NSPS, 40 CFR part 60, subpart IIII, applies to stationary compression-ignition (CI) internal combustion 

engines (ICE) that commenced construction after July 11, 2005, that are manufactured after 

April 1, 2006. Subpart IIII also applies to CI ICE that are modified or reconstructed after July 11, 2005. 

Looking at Tables 4-2 and 4-3 below, none of the permanently-installed engines on C.R. Luigs and DD1

meet the above criteria. The portable engines (i.e., cementing nitrogen pump and wireline engines) will 

meet subpart IIII- by complying with applicable standards for marine diesel engines (40 CFR part 94) or 

nonroad engine standards (40 CFR part 89).

Table 4-2: C.R. Luigs Engine Specifications

Emissions

Unit ID Description Manufacturer Model #

Ratinga

(hp/kW)

Mfg.

Year

EU-001 through

-008 Main Power Plant Engine 1 - 8 MAN B&W 9L32/40 5,875/4,381 1998

EU-009 through

-012 Crane Engines Caterpillar 3406 305/227 1998

EU-015 Emergency Generator Engine Caterpillar D3516A 2,064/1,539 1998

EU-016 and

-017 Cementing Engines 1 and 2 Caterpillar 3412C 860/641 2001

EU-018b Cementing Nitrogen Pump 

Engine

EU-019b POSU-CA Primary Unit Engine/

Hydraulic Generator Combination

EU-020b Wireline Unit Alternative #2 

Engine FMCC Unit Type Two

EU-022b Wireline Unit – Power Plant

GSU-W Generator

EU-023b Wireline Unit – Hydraulic 

Generator DHPS

EU-092 Black Start Air Compressor Hatz E673L5 6/4.5 1998

a

Given in horsepower (hp) and kilowatts (kW). Permit conditions may limit operation to less than rated capacity.

b

These units are portable (i.e., not permanent installations). Units may be substituted as permitted.
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Table 4-3: DD1 Engine Specifications

Emissions

Unit ID Description Manufacturer Model #

Ratinga

(hp/kW)

Mfg.

Year

EU-001 through

-008 Main Power Plant Engines 1 - 8 Caterpillar 3612 5,096/3,800 2002

EU-011 Emergency Generator Engine Caterpillar 3516 2,358/1,758 2003

EU-012 and

-013 Cementing Engines 1 and 2 Caterpillar 3412C 860/641 2001

EU-014b Cementing Nitrogen Pump 

Engine

EU-015 Cementing Batch Mixer Engine Caterpillar 3126 250/186 2004

EU-016b

POSU-CA Primary Unit Engine/

Hydraulic Generator 

Combination

EU-017b Wireline Unit Alternative #2 

Engine FMCC Unit Type Two

EU-019b Wireline Unit – Power Plant

GSU-W Generator

EU-020b Wireline Unit – Hydraulic 

Generator DHPS

a

Given in horsepower (hp) and kilowatts (kW). Permit conditions may limit operation to less than rated capacity.

b

These units are portable (i.e., not permanent installations). Units may be substituted as permitted.

4.5.2 Subpart K

NSPS, 40 CFR part 60, subpart K, applies to petroleum liquids tanks with a capacity of greater than 

40,000 gallons and that commence construction or modification after March 8, 1974, and prior to 

May 19, 1978, or have a capacity greater than 65,000 gallons and commence construction or 

modification after June 11, 1973, and prior to May 19, 1978. All storage tanks on C.R. Luigs and DD1

were constructed post-1978; therefore, subpart K is not applicable to any of the storage tanks based their 

respective construction date.

4.5.3 Subpart Ka

NSPS, 40 CFR part 60, subpart Ka, applies to petroleum liquids tanks with a capacity of greater than 

40,000 gallons that are used to store petroleum liquids and for which construction is commenced after 

May 18, 1978, and prior to July 23, 1984. All storage tanks on C.R. Luigs were constructed post-1984 

with the exception of the following:

Table 4-4: C.R. Luigs Storage Tanks Potentially Subject to Subpart Ka

Emissions

Unit ID Description

Construction

Date

Capacity

(Gal.)

EU-055 Wireline Unit Tank 1 1980 50

EU-056 Wireline Unit Tank 2 1980 20

EU-057 GSU-W Tank 1 1980 70

EU-058 DHPS-EA Tank 1 1980 70

The respective capacities of the above storage tanks are well below the applicability threshold of 40,000 

gallons; therefore, none of the storage tanks on C.R. Luigs are subject to subpart Ka.
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All of the storage tanks on DD1 were constructed post-1984 with the exception of the following:

Table 4-5: DD1 Storage Tanks Potentially Subject to Subpart Ka

Emissions

Unit ID Description

Construction

Date

Capacity

(Gal.)

EU-043 Wireline Unit Tank 1 1980 50

EU-044 Wireline Unit Tank 2 1980 20

EU-045 GSU-W Tank 1 1980 70

EU-046 DHPS-EA Tank 1 1980 70

The respective capacities of the above storage tanks are well below the applicability threshold of 40,000 

gallons; therefore, none of the storage tanks on DD1 are subject to subpart Ka.

4.5.4 Subpart Kb

NSPS, 40 CFR part 60, subpart Kb, applies to each storage vessel with a capacity greater than or equal 

to 75 cubic meters (m3) that is used to store volatile organic liquids for which construction, 

reconstruction, or modification is commenced after July 23, 1984. This subpart does not apply to storage 

vessels with a capacity greater than or equal to 151 m3storing a liquid with a maximum true vapor 

pressure (TVP) less than 3.5 kilopascals (kPa) or with a capacity greater than or equal to 75 m3but less 

than 151 m3storing a liquid with a maximum true vapor pressure less than 15.0 kPa. As Tables 4-6 and 

4-7 show, none of the storage tanks on C.R. Luigs and DD1 are subject to subpart Kb based on 

operating pressure being less than 3.5 kPa or capacity being less than 75 m3.

Table 4-6: C.R. Luigs Petroleum Storage Tanks

Emissions

Unit ID Description

Construction

Date

Capacity 

(m3)

Max.

TVP

(psia/kPa)

EU-029/-030 #7 Port/Starboard WT Storage Tanks 1998 1,221.34 0.022/0.15

EU-031/-032 #8 Port/Starboard WT Storage Tanks 1998 1,109.73 0.022/0.15

EU-033/-034 #8 Port/Starboard DB Storage Tanks 1998 533.72 0.022/0.15

EU-035/-036 #9 Port/Starboard Storage Tanks 1998 380.77 0.022/0.15

EU-037/-038 Port/Starboard Settling Tanks 1998 111.13 0.022/0.15

EU-039/-040 Port/Starboard Day Tanks 1998 111.13 0.022/0.15

EU-041/-042 Port Forward/Aft Crane Tanks 1998 0.95

EU-043/-044 Starboard Forward/Aft Crane Tanks 1998 0.95

EU-045 Emergency Generator Tank 1998 10.18

EU-046 Fast Rescue Craft Tank 2008 0.16

EU-047 to -050 Lifeboats 1 - 4 Tanks 1998 0.22

EU-051 Hydraulic Fluid Tank 1998 0.45

EU-052 Base Oil Storage Tank 1998 562 0.29/2.00

EU-053/-054 Cementing Engine 1 and 2 Tanks 2001 0.86

EU-055 Wireline Unit Tank 1 1980 0.19

EU-056 Wireline Unit Tank 2 1980 0.08

EU-057 GSU-W Tank 1 1980 0.26

EU-058 DHPS-EA Tank 1 1980 0.26

EU-059 POSU-CA Tank 2009 0.38

EU-090/-091 Helifuel Tanks 1999 2.27
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Table 4-7: DD1 Petroleum Storage Tanks

Emissions

Unit ID Description

Construction

Date

Capacity 

(m3)

Max.

TVP

(psia/kPa)

EU-026 Fuel Tank 005 (F.O. TK 1S) 2002 811.70 0.022/0.15

EU-027 Fuel Tank 006 (F.O. TK 2S) 2002 811.70 0.022/0.15

EU-028 Fuel Tank 007 (F.O. TK 1P) 2002 811.70 0.022/0.15

EU-029 Fuel Tank 008 (F.O. TK 2P) 2002 811.70 0.022/0.15

EU-030 Fuel Tank 009 (F.O. TK 1S) 2002 31.61

EU-031 Fuel Tank 010 (F.O. TK 2S) 2002 27.16

EU-032 Fuel Tank 011 (F.O. TK 1S) 2002 54.98

EU-033 Base Oil Storage Tank 2002 730 0.29/2.00

EU-034 Emergency Generator Tank 2002 10.18

EU-035 Fast Rescue Craft Tank 2008 0.16

EU-036 to -039 Lifeboats 1 - 4 Tanks 2002 0.22

EU-040/-041 Cementing Engine 1 and 2 Tanks 2001 0.86

EU-042 Batch Mixer Engine Fuel Tank 2001 0.27

EU-043 Wireline Unit Tank 1 1980 0.19

EU-044 Wireline Unit Tank 2 1980 0.08

EU-045 GSU-W Tank 1 1980 0.26

EU-046 DHPS-EA Tank 1 1980 0.26

EU-047 POSU-CA Tank 2009 0.38

EU-078 to -081 Helifuel Tanks 2005 3.07

4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)

Applicable NESHAP promulgated under section 112 of the CAA apply to OCS sources if rationally 

related to the attainment and maintenance of federal and state ambient air quality standards or the 

requirements of part C of title I of the CAA. See 40 CFR § 55.13(e). In addition, the PSD regulations 

require each major stationary source or major modification to meet applicable standards under 

40 CFR part 61, which are NEHSAPs. See 40 CFR §52.21 (j)(1). No source categories on board 

C.R. Luigs or DD1 are currently regulated by NESHAPs promulgated at 40 CFR part 61.

In addition to the NESHAP promulgated at 40 CFR 61, the NESHAP regulations set forth in 40 CFR 

part 63 apply to a source based on the source category listing, and the regulations generally establish 

different standards for new and existing sources pursuant to CAA section 112. These standards are 

commonly referred to as the Maximum Achievable Control Technology (MACT) standards and apply 

only if the affected source is a “major source” as defined in CAA section 112 and 40 CFR § 63.2. A 

major source is generally defined as a source that has a PTE of 10 tons per year or more of any single 

Hazardous Air Pollutant (HAP) or 25 tons per year or more of all HAPs combined. See section 112(a)(1) 

and 40 CFR § 63.2. An “area source” is any source that is not a major source as defined in section 

112(a)(2) and 40 CFR § 63.2. BHPB has estimated less than 25 TPY for all HAPs combined and less 

than 10 TPY for any single HAP from the C.R. Luigs and DD1. This makes the project an area source of 

HAPs under either operating scenario.

4.6.1 Subpart ZZZZ

NESHAP, 40 CFR part 63, subpart ZZZZ, applies to stationary reciprocating internal combustion 

engines (RICE) located at major and area sources of HAP emissions. As discussed in Section 4.5.1, the 
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portable engines on C.R. Luigs and DD1 will be subpart IIII-compliant and, thus, no additional 

requirements apply under subpart ZZZZ. Therefore, only the following engines are subject to 

40 CFR part 63, subpart ZZZZ, as amended on March 9, 2011: EU-001 through -012 and -015 through -

017 on C.R. Luigs and EU-001 through -008, -011 through -013, and -015 on DD1. Under this rule, 

existing stationary engines located at an area source of HAP emissions must comply with the 

requirements in Table 2d and the operating limitations in Tables 1b and 2b in subpart ZZZZ that apply 

no later than May 3, 2013. Compliance with the numerical emission limitations established in subpart 

ZZZZ is based on the results of testing the average of three 1-hour runs using the testing requirements 

and procedures set forth in 40 CFR §63.6620. Any future substitutions for the portable engines, by 

virtue of being subpart IIII-compliant, will be exempt from subpart ZZZZ.

5.0 Project Emissions

This section describes the emission calculation basis for each emission source. The emission 

calculations are based on AP-42 factors, EPA publications, EPA nonroad engine emission limits, stack 

testing, analysis of fuel sulfur content, vendor-supplied emissions factors, EPA‟s TANKS 4.09d 

program, and a 2005 Department of Interior emissions inventory study. The total projected emissions for 

each operating scenario include emissions based on estimations of the worst case total number of hours 

each emission unit could run each year. Emissions from support vessels are based on the worst case PTE 

support vessel out of all the individual support vessels that are available. A summary of the PTE from 

regulated NSR pollutants are given in Tables 5-1 and 5-2 below.

Table 5-1: Potential to Emit Emissions – C.R. Luigs Operating Scenario 1

Emission 

Source

PM 

(TPY)

PM10

(TPY)

PM2.5

(TPY)

NOX

(TPY)

SO2 

(TPY)

H2SO4

(TPY)

CO 

(TPY)

Total 

VOC

(TPY)

Lead 

(TPY)

GHGs 

(CO2e) 

(TPY)

Main Diesel Engines 

(8) 46.91 26.88 26.08 1,318.80 0.71 0.02 262.89 442.89 1.36E-02 78,005.05

Crane Engines (4) 5.88 5.88 5.88 82.83 0.03 8.83E-04 17.85 6.72 5.42E-04 3,083.39

Emergency 

Generator Engine (1) 0.04 0.02 0.02 1.49 0.001 2.05E-05 0.34 0.04 1.26E-05 72.06

Lifeboat Engines (4) 4.29E-03 4.29E-03 4.29E-03 6.05E-02 2.06E-05 6.44E-07 1.30E-02 4.90E-03 3.96E-07 2.25

Fast Rescue Craft 

Engine (1) 3.85E-03 3.85E-03 3.85E-03 5.43E-02 1.85E-05 5.78E-07 1.17E-02 4.40E-03 3.55E-07 2.02

Cementing Unit 

Engines (3)

0.38 0.23 0.22 8.69 0.01 1.79E-04 3.30 0.38 1.10E-04 628.92

Mud & Cement Dust 

Collectors (2)

1.08 1.08 1.08 - - - - - - -

Mud Degassing 

Operation (1) - - - - - - - 19.39 - 982.67

Wireline Unit 

Engines (4)

0.60 0.60 0.60 8.92 0.005 1.54E-04 2.90 1.17 9.44E-05 536.63

MODU Storage 

Tanks (33) - - - - - - - 5.70E-01 - -

Black Start 

Compressor (1) 1.65E-04 1.65E-04 1.65E-04 2.033E-03 7.93E-04 2.48E-08 5.01E-04 1.89E-04 1.52E-08 8.66E-02

Work Boats (2) 9.70 5.58 5.42 246.82 0.15 4.57E-03 76.01 8.90 2.80E-03 16,080.92

Work Boats Storage 

Tanks (52)

- - - - - - - 9.47E-02 - -

Fast Crew Boats (1) 1.41 0.87 0.85 31.94 0.02 6.19E-04 10.38 1.33 3.80E-04 2,180.77

Crew Boat Storage 

Tanks (2) - - - - - - - 6.02E-03 - -

Emission Unit 

Totals:

66.02 41.15 40.16 1,699.6 0.91 0.03 373.69 81.61 0.02 101,574.7
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Table 5-2: Potential to Emit Emissions – DD1 Operating Scenario 2

Emission 

Source

PM 

(TPY)

PM10

(TPY)

PM2.5

(TPY)

NOX

(TPY)

SO2 

(TPY)

H2SO4

(TPY)

CO 

(TPY)

Total 

VOC

(TPY)

Lead 

(TPY)

GHGs 

(CO2e) 

(TPY)

Main Diesel Engines 

(8) 46.26 26.50 25.72 1,007.02 0.70 0.02 215.09 42.39 1.34E-02 76,920.91

Emergency 

Generator Engine (1) 0.05 0.03 0.03 1.60 0.001 2.21E-05 0.37 0.04 1.36E-05 77.84

Lifeboat Engines (4) 1.21E-02 1.21E-02 1.21E-02 1.71E-01 5.82E-05 1.82E-06 3.67E-02 1.38E-02 1.12E-06 6.35

Fast Rescue Craft 

Engine (1) 3.91E-03 3.91E-03 3.91E-03 5.50E-02 1.88E-05 5.87E-07 0.01 4.46E-03 3.06E-07 2.05

Cementing Unit 

Engines (4) 0.41 0.25 0.25 9.50 0.01 2.03E-04 3.73 0.57 1.25E-04 715.48

Mud & Cement Dust 

Collectors (2)

1.08 1.08 1.08 - - - - - - -

Mud Degassing 

Operation (1) - - - - - - - 19.39 - 982.67

Wireline Unit 

Engines (4)

0.60 0.60 0.60 8.92 0.005 1.54E-04 2.90 1.17 9.44E-05 536.63

MODU Storage 

Tanks (26) - - - - - - - 0.44 - -

Work Boats (2) 9.70 5.58 5.42 246.82 0.15 4.57E-03 76.01 8.90 2.80E-03 16,080.92

Work Boats Storage 

Tanks (52)

- - - - - - - 9.47E-02 - -

Fast Crew Boats (1) 1.41 0.87 0.85 31.94 0.02 6.19E-04 10.38 1.33 3.80E-04 2,180.77

Crew Boat Storage 

Tanks (2) - - - - - - - 6.02E-03 - -

Emission Unit 

Totals: 59.52 34.94 33.96 1,306.04 0.88 0.03 308.53 76.60 0.02 97,503.61

BHPB has proposed to only use ultra low sulfur diesel fuel for all diesel engines for both operating 

scenarios and all support vessels. The sulfur content of ultra low sulfur diesel fuel is based on a 

maximum sulfur content of 15 parts per million (ppm). Sulfur dioxide (SO2) and sulfuric acid (H2SO4)

emissions were calculated by a mass balance method. Based on a draft EPA document, EPA 420-R-03-

008 titled “Draft Regulatory Impact Analysis: Control of Emissions from Nonroad Diesel Engines” 

dated April 2003, BHPB used a 98% conversion factor for SO2 formation during diesel fuel combustion, 

with the other 2% of the sulfur assumed to be converted to sulfuric acid (H2SO4). The H2SO4 emissions

were assumed to condense to form total reduced sulfur (TRS) particulate matter, primarily as sulfates in 

the atmosphere. Since the total amount of H2SO4 from both operating scenarios was calculated to be

0.03 TPY, the potential TRS PM contribution is minimal.

5.1 C.R. Luigs (Operating Scenario 1) Main Engine Analysis

The C.R. Luigs’ electrical power is provided by eight identical MAN B&W model 9L32 diesel engines 

(EU-001through EU-008) with a rated power output of approximately 5,875 hp each and an emergency 

generator (EU-015) powered by a 2,064 hp Caterpillar model D3516A diesel engine.

Emissions estimates for the C.R. Luigs‟ main engines were based on 6,570 hours of operation per year 

per engine. Based on the maximum electricity requirement of 15,000 kW and a maximum rating of 

4,320 kW per engine, annual emissions were calculated with all eight engines operating at an average of 

43% load. The maximum hourly emissions were calculated by assuming four main engines operating at 

93.8% load. The hourly and annual emissions for the emergency generator were calculated based on 

operating at 90% load for a maximum of 60 hours per year, using AP-42 emission factors and brake 

horsepower. For the main engines all pollutants except NOX and CO were calculated using AP-42 

emission factors and brake horsepower. NOX and CO were calculated based on stack test data included 

in the February 2011 application addendum.
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5.2 C.R. Luigs (Operating Scenario 1) Smaller Emission Unit Analysis

The following is a description of the smaller emission units and how emissions estimates were 

calculated for each, using AP-42 emission factors and brake horsepower for the diesel engines:

EU-009 through EU-012: Port Forward, Port Aft, Starboard Forward, and Starboard Aft Cranes

The four cranes are each powered by a 305 hp Caterpillar model 3406 diesel engine. The hourly and 

annual emissions were calculated based on operating at 100% load for a maximum of 4,380 hours per 

year per engine.

EU-013: Mud and Cement Mixing Dust Collectors

Dry mud and cement are mixed with water to be used in drilling operations. Particulate matter in the 

form of dust is generated and controlled by using a dust collector. The PM/PM10/ PM2.5 maximum 

hourly emission rate each was calculated based on a flow rate of 90,000 cubic foot per hour and a 

discharge rate of 0.0096 grains per cubic foot provided by the manufacture. The annual emissions were 

calculated based on 8,760 hours of operation.

EU-016 through EU-017: Cementing Units 1-2 

Cementing units 1 and 2 are each powered by an 860 hp Caterpillar model 3412 CDITA diesel engine. 

The hourly and annual emissions were calculated based on operating at 100% load for a maximum of 

600 hours per year per 860 hp engine.

EU-018 through EU-023: Cementing Nitrogen Pump, Wireline Units POSU-CA Primary, Alt 2, 

Power Plant GSU-W, and Hydraulic DHPS

These units are portable and brought on the MODU as needed by a third party supplier. The exact 

engine available for use during the project had not been identified at the time of the application

submittal. The worse case engine listed below was chosen to calculate emission calculations and the 

potential to emit. The replacement engine for the project will meet the equivalent or a higher EPA Tier 

standard. The cementing nitrogen pump representative worst case engine is a 490 hp Caterpillar model 

3406 diesel engine. The representative worst case POSU-CA primary and alt 2 wireline units are each 

powered by a 300 hp Caterpillar model C-7 DITA diesel engine. The representative worst case power

plant GSU-W and hydraulic DHPS wireline units are each powered by a 160 hp diesel engine.

EU-024: Fast Rescue Craft

The fast rescue craft is powered by one 142 hp Steyr Motors model M0144M38 diesel engine. The 

hourly and annual emissions were calculated based on operating at 100% load for a maximum of 25

hours per year.

EU-025 through EU-028: Lifeboats

The four lifeboats are each powered by a 39 hp Bukh model DV36-39 marine diesel engine. The hourly 

and annual emissions were calculated based on operating at 100% load for a maximum of 25 hours per 

year per engine.

EU-092: Black Start Air Compressor

The black start air compressor is powered by one 6 hp Hatz model E673L5 diesel engine. The hourly 

and annual emissions were calculated based on operating at 100% load for a maximum of 25 hours per 

year.

EU-062 through EU-091: Fuel, Oil, and Hydraulic Fluid Tanks

Emissions are generated from the storage of diesel fuel, base oil, hydraulic fluid, and Jet A helicopter 
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fuel in tanks. The EPA TANKS 4.09d computer software program was used to calculate VOC 

emissions, using the properties of fuel oil number 2 for diesel and Jet A and the base oil vapor pressure 

for base oil.

5.3 DD1 (Operating Scenario 2) Main Engine Analysis

The DD1 electrical power is provided by eight identical Caterpillar model 3612 DITA diesel engines 

(EU-001through EU-008) with a rated power output of approximately 5,096 hp each and an emergency 

generator (EU-0151) powered by a 2,229 hp Caterpillar model 3516 diesel engine.

Emissions estimates for the DD1’s main engines were based on 6,570 hours of operation per year per 

engine. Based on the maximum electricity requirement of 18,000 kW and a maximum rating of 3,800 

kW per engine, annual emissions were calculated with all eight engines operating at an average of 49% 

load. The maximum hourly emissions for the main engines were calculated by assuming five main 

engines operating at 94.8% load. The hourly and annual emissions for the emergency generator were 

calculated based on operating at 90% load for a maximum of 60 hours per year, using AP-42 emission 

factors and brake horsepower. For the main engines all pollutants except NOX and CO were calculated 

using AP-42 emission factors and brake horsepower. NOX and CO were calculated based on stack test

data included in the February 2011 application addendum.

5.4 DD1 (Operating Scenario 2) Smaller Emission Unit Analysis

The following is a description of the smaller emission units and how emissions estimates were 

calculated for each, using AP-42 emission factors and brake horsepower for the diesel engines:

EU-009: Mud and Cement Mixing Dust Collectors

Dry mud and cement are mixed with water to be used in drilling operations. Particulate matter in the 

form of dust is generated and controlled by using a dust collector. The PM/PM10/ PM2.5 maximum 

hourly emission rate each was calculated based on a flow rate of 90,000 cubic foot per hour and a 

discharge rate of 0.0096 grains per cubic foot provided by the manufacture. The annual emissions were 

calculated based on 8,760 hours of operation.

EU-012 through EU-013, EU-15: Cementing Units 1-2 and Batch Mixer 

The cementing batch mixer is powered by a 250 hp Caterpillar model 3126 diesel engine, and the two 

cementing units 1-2 are each powered by an 860 hp Caterpillar model 3412 diesel engine. The hourly 

and annual emissions were calculated based on operating at 100% load for a maximum of 600 hours per 

year per 860 hp engine and 600 hours per year per 250 hp engine.

EU-014, EU-016 through EU-020: Cementing Nitrogen Pump, Wireline Units POSU-CA Primary, 

Alt 2, Power Plant GSU-W, and Hydraulic DHPS

These units are portable and brought on the MODU as needed by a third party supplier. The exact 

engine available for use during the project had not been identified at the time of the application

submittal. The worse case engine listed below was chosen to calculate emission calculations and the 

potential to emit. The replacement engine for the project will meet the equivalent or a higher EPA Tier 

standard. The cementing nitrogen pump representative worst case engine is a 490 hp Caterpillar model 

3406 diesel engine. The representative worst case POSU-CA primary and alt 2 wireline units are each 

powered by a 300 hp Caterpillar model C-7 DITA diesel engine. The representative worst case power

plant GSU-W and hydraulic DHPS wireline units are each powered by a 160 hp diesel engine. The 

hourly and annual emissions were calculated based on operating at 100% load for a maximum of 750 
17

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hours per year per 300 hp engine, 1,700 hours per year for one160 hp engine, and 1,300 hours per year 

for the other 160 hp engine.

EU-021: Fast Rescue Craft

The fast rescue craft is powered by one 142 hp Steyr Motors model M0144M38 diesel engine. The 

hourly and annual emissions were calculated based on operating at 100% load for a maximum of 25 

hours per year.

EU-022 through EU-025: Lifeboats

The four lifeboats are each powered by a 110 hp Steyr Motors model M0144M38 diesel engine. The 

hourly and annual emissions were calculated based on operating at 100% load for a maximum of 25 

hours per year per engine.

EU-026 through EU-047, EU-050 through EU-081: Fuel and Oil Tanks

Emissions are generated from the storage of diesel fuel, base oil, lube oil, and Jet A helicopter fuel in 

tanks. The EPA TANKS 4.09d computer software program was used to calculate VOC emissions, using 

the properties of fuel oil number 2 for diesel and Jet A and the base oil vapor pressure for base oil.

5.5 Support Vessels

The estimated emissions from the support vessels were determined by assuming a maximum of two 

work boats and a crew boat operating within 25 miles of the MODU at any given time. For all work 

boats operating within 25 miles at any given time, the maximum number of hours the main propulsion 

and power diesel engines run shall not exceed 7,500 hours per year. The maximum number of hours the 

work boat emergency diesel engines run shall not exceed 500 hours per year. For all crew boats 

operating within 25 miles at any given time, the maximum number of hours their main power diesel 

engines run shall not exceed 800 hours per year.

The emissions for the two work boats were estimated by assuming each work boat was identical to the 

worst case Allie work boat. The Allie has the following marine diesel engines: two 3,299 hp (Tier 1) 

propulsion, two 1,341 hp (Tier 1) generators, one 1,100 hp (Tier 1) SDT, and one 250.6 hp (Tier 1) 

emergency generator. Worst case hourly emissions were calculated from an engine load of 35% and a 

maximum fuel use of 183.3 gal/hr for the entire Allie workboat. From AP-42 Appendix A, the diesel fuel 

heating value of 137,000 Btu/gallon and a brake specific fuel consumption of 7,000 Btu/hp-hr was used 

to convert to hp-hr. Using AP-42 emissions factors and a 5% good engineering safety factor, the 

emissions were estimated for the hourly and annual emissions. 

The emissions from the crew boats were estimated by assuming each crew boat was identical to the 

worst case Fast Skipper crew boat, which has one 165 hp generator and two 2,2260 hp (Tier 1) marine 

diesel engines. Worst case hourly and annual emissions were calculated from an engine load of 100%

and operating a maximum of 800 hours per year for all crew boats. A brake specific fuel consumption of 

7,000 Btu/hp-hr was used to convert to hp-hr. The total hourly and annual emissions from all support 

vessels for the project where then calculated by adding the emission estimates for the work boats and 

crew boats.

5.6 Compliance Methodology

Continuous Emissions Monitoring (CEMS) instrumentation is often required to track specific emissions 

if monitoring of those emissions is critical to ensure that a requirement is being met, or to show that a 
18

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requirement does not apply. However, the EPA understands the unique issues involved in requiring 

CEMS for emission units on deepwater drilling rigs and an alternative system may be necessary to 

monitor pollutants. In consideration of the complexity of continuous compliance monitoring on a 

deepwater MODU in the marine environment, permit Specific Condition 6.10 allows BHPB to choose 

monitoring systems for NOX for the main generator diesel units (EU-001 through EU-008 on the

C.R Luigs and EU-001 through EU-008 on the DD1). Condition 6.10 describes the requirements for an 

EPA-approved continuous emissions monitoring system, for an EPA-approved alternative parametric 

monitoring method, and for a stack testing emissions monitoring system that may be used with prior 

written approval by the EPA.

The compliance demonstration method for the emergency generator diesel units (EU-015 on C.R. Luigs

and EU-011 on DD1), the small on-board diesel engines (EU-009 through -012 and EU-016 through 

EU-028 on C.R. Luigs and EU-012 through -017 and EU -019 through EU-025 on DD1) will include 

monitoring and maintaining a contemporaneous record of the unit ID, date/time the engine started, 

date/time the engine shut down, the printed name and signature of the person operating the equipment, 

as well as applicable NSPS and NESHAP monitoring requirements.

The compliance demonstration for the support vessels for both operating scenarios shall include 

monitoring and maintaining a contemporaneous record of operating time within the 25 mile radius and 

during standby time at the MODU, gallons of diesel fuel on the support vessel entering the 25 mile 

radius, and gallons of diesel fuel on the support vessel exiting the 25 mile radius. Support vessels must 

also show compliance by monitoring and maintaining a contemporaneous record of the sulfur content 

upon receiving each fuel shipment as specified in permit Specific Condition 6.4.2.

BHPB is required to supply the EPA with all records upon request. In addition, BHPB will provide a 

semi-annual report of its emissions information and calculations in accordance with all relevant permit 

conditions, including General Condition 5.17.

6.0 Best Available Control Technology (BACT)

A new major stationary source subject to PSD requirements is required to apply BACT for each 

pollutant subject to regulation under the CAA that it would have the potential to emit in significant 

amounts. See 40 CFR § 52.21(j). Based on the emission inventory for the project, presented in Table 4-1 

of the preliminary determination, NOX, CO, VOC, GHGs, and PM/PM10/PM2.5 are the CAA-regulated 

pollutants that will be emitted by BHPB in quantities exceeding the respective significant emission rate. 

Therefore, BACT must be determined for each emission unit on the drillship C.R. Luigs or 

semisubmersible DD1 that emits these pollutants while operating as an OCS source.

BACT is defined in the applicable permitting regulations at 40 CFR § 52.21(b)(12), in part, as:

an emissions limitation (including a visible emission standard) based on the maximum degree of 

reduction for each pollutant subject to regulation under the 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 
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applicable standard under 40 CFR parts 60 and 61. If the Administrator determines that technological or 

economic limitations on the application of measurement technology 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. The CAA contains a similar BACT definition, although the 1990 

CAA amendments added “clean fuels” after “fuel cleaning or treatment” in the above definition. See

CAA § 169(3).

On December 1, 1987, the EPA issued a memorandum describing the top-down approach for 

determining BACT. See, e.g., In re Prairie State Generating Co., 13 E.A.D. 1 (EAB 2006). In brief, the 

top-down approach provides that all available control technologies be ranked in descending order of 

control effectiveness. Each alternative is then evaluated, starting with the most stringent, until BACT is 

determined. The top-down approach consists of the following steps:

Step 1: Identify all available control technologies.

Step 2: Evaluate technical feasibility of options from Step 1 and eliminate options that are 

technically infeasible based on physical, chemical and engineering principles. 

Step 3: Rank the remaining control technologies from Step 2 by control effectiveness, in terms of 

emission reduction potential.

Step 4: Evaluate the most effective controls from Step 3, considering economic, environmental 

and energy impacts of each control option. If the top option is not selected, evaluate the 

next most effective control option.

Step 5: Select BACT (the most effective option from Step 4 not rejected).

Below is a summary of EPA‟s top-down BACT analysis for C.R. Luigs and DD1.

6.1 BACT Analysis for Internal Combustion Engines

The following engines on C.R. Luigs are included in this section of the BACT analysis: eight (8) main 

power plant engines (EU-001 through -008), four (4) crane engines (EU-009 through -012), one (1) 

emergency generator engine (EU-015), two (2) cementing engines (EU-016 and -017), one (1) 

cementing nitrogen pump engine (EU-018), four (4) wireline engines (EU-019, -020, -022, and -023), 

and one (1) black start air compressor (EU-092).

The following engines on DD1 are also included in this section: eight (8) main power plant engines 

(EU-001 through -008), one (1) emergency generator engine (EU-011), and two (2) cementing engines 

(EU-012 and -013), one (1) cementing nitrogen pump engine (EU-014), one (1) cementing batch mixer 

engine (EU-015), and five (5) wireline engines (EU-016 through -020).

These engines will not produce emissions at a steady rate. The main power plant engines of both 

C.R. Luigs and DD1 operate at variable load based on drilling and operational power demand. The 

emergency generator engines will be tested periodically, but not operated continuously. In addition, 

engine efficiency and performance typically degrade over time, resulting in increased emissions. These 

factors are important considerations in the BACT analysis for these units.
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6.1.1 NOX BACT Analysis for Internal Combustion Engines

NOX emissions are generated as both a result of high temperature combustion (thermal NOX) and 

oxidation of nitrogen present in the fuel (fuel-bound NOX). Thermal NOX emissions increase with an 

increase in combustion temperature, and are generally the main cause of NOX emissions from a 

combustion source.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application 

submitted in October 2010 and application addendum submitted in February 2011: 

1. Selective Catalytic Reduction (SCR)

2. 4-Way Catalyst Converter with Exhaust Gas Recirculation System

3. Fuel Ignition Timing Retard

4. Turbocharger and Aftercooler

5. Aftercooling with High Pressure Fuel Injection (HPFI) System

6. Water Injection

7. Good Combustion Practices

8. Transocean Diesel Engines with Turbochargers (DEWT) Measurement System on Main

Power Plant Engines

The EPA requested additional information regarding the BACT analysis from the applicant and received 

supplemental information on September 30, 2011. The supplemental information includes the following 

additional control technologies as part of Step 1 of the top-down BACT analysis for NOX emissions: 

9. Newer/Cleaner Engines

10. De-rating of Existing Engines

11. Water-in-Fuel Emulsions

12. NOX Absorber/Scrubber Technology

13. CSNOX Emission Abatement System

14. Camshaft Replacement/Retooling of Engines

15. Lean De-NOX Catalyst or Hydrocarbon SCR

16. Intake Air Humidification/Cooling

Step 2: Eliminate technically infeasible control options

After analyzing the 16 control technology options, ten of the options were eliminated as technically 

infeasible for the control of NOX emissions from all diesel internal combustion engines (options 2, 3, 6 

and 10 through 16). Below is a summary of the reasons for eliminating each of these options from 

further consideration in the top-down BACT analysis for this project. For detailed descriptions and 

references, please refer to the application submitted (to EPA) in October 2010 and supplemental 

information submitted in February 2011, September 2011, October 2011, December 2011, and 

January 2012, respectively.

SCR: With the exception of the eight main engines on DD1 (EU-001 through EU-008), which are 

already configured to vent to an existing Siemens SINOX exhaust gas treatment system, this option is 

technically infeasible for all other internal combustion engines due to limited space availability for the 

SCR unit themselves as well as the necessary ancillary equipment (e.g., urea storage tanks).
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4-Way Catalyst Converter with Exhaust Gas Recirculation System: This option is technically 

infeasible since recirculating exhaust gases can reduce the engine power, thus impairing the ability to 

safely maintain the vessels‟ position and perform other functions associated with drilling operations. 

Furthermore, due to the large load variations typical of such drilling operations, there exists the inability 

to sustain constant steady-state loads/exhaust temperatures for sufficient time periods necessary for high 

catalyst performance. Also, several non-combustible chemical elements that may be present in engine 

lube oils (e.g., phosphorous, lead, and heavy metals) may collect over time and damage the catalyst.

Fuel Ignition Timing Retard: This option is technically infeasible since it involves derating the engine 

and reducing the peak power available from the engine, thus, impairing the ability to safely maintain the 

vessels‟ position and perform other functions associated with drilling operations. Furthermore, ignition 

timing increases exhaust temperatures, which may adversely impact exhaust valve life and turbocharger 

performance.

Turbocharger and Aftercooler: This option is technically infeasible on the older model wireline 

engines (EU-022 and -023 on C.R. Luigs and EU-019 and -020 on DD1) because it would involve major

design changes to the engines.

Water Injection: This option requires freshwater that would have to be produced through desalination, 

distillation, or the storage of freshwater onboard. There is not space available on either C.R. Luigs or 

DD1 to accommodate the equipment necessary for such processes; thus, this option is technically 

infeasible.

Newer/Cleaner Engines: This option is technically infeasible for the main engines onboard C.R. Luigs

(EU-001 through -008) since, to match the available power output of the existing 8 engines, an 

additional engine of the new/cleaner model would be required. There is no available space for 9 main 

engines on the MODU.

Engine Derating: This option is technically infeasible since it reduces peak power available from the 

engine, thus, impairing the ability to safely maintain the vessels‟ position and perform other functions 

related to drilling operations. Furthermore, the emergency generator engines will need to be able to 

operate at peak power when the main engines are inoperable.

Water-In-Fuel Emulsions: The internal combustion engines on C.R. Luigs and DD1 are designed to 

burn diesel, which is a medium density fuel. This option is designed specifically for heavy density fuel 

applications; therefore, it is not technically feasible.

NOX Absorber/Scrubber Technology: This option is currently in development for application to diesel 

engines; therefore, it is not technically feasible for the engines aboard C.R. Luigs and DD1.

CSNOX Emission Abatement System: This technology is currently in the licensing and commercial 

demonstration phase of development. While this technology is commercially available for certain types 

of marine uses, it has not been demonstrated in practice for use aboard a dynamically positioned mobile 

off shore drilling unit (i.e., vessels with variable load engines); therefore, it is technically infeasible for 

this project.

Camshaft Replacement/Retooling of Engines: This option is intended for application on smaller 

engines (i.e., mostly 2-stroke engines) and has not yet been developed for larger engines (e.g., 4-stroke); 

therefore, it is not technically feasible for the engines onboard C.R. Luigs and DD1.
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03/28/2012 PD OCS-EPA-R4008

Lean De-NOX Catalyst or Hydrocarbon SCR: This option is technically infeasible since it is not 

commercially available for large marine engines.

Intake Air Humidification/Cooling: This option is currently in development for marine applications; 

therefore, it is not technically feasible for the engines aboard C.R. Luigs and DD1.

Steps 3/4/5:

With respect to the DD1’s main engines (EU-001 through -008), the applicant has demonstrated that the 

efforts required to commission the existing SCR units (Siemens SINOX system) would prove cost 

prohibitive. Even properly adjusting the interest rate to a more appropriate seven percent (from the ten 

percent used by the applicant) only reduces the cost effectiveness to $18,510 per ton of NOX removed 

(from $19,283 per ton calculated by the applicant).

Although newer/cleaner engines option was eliminated as technically infeasible for the main engines of 

C.R. Luigs, this option is feasible for the remaining diesel internal combustion engines. However, engine 

replacement was determined to be cost prohibitive for the remaining engines based on the relatively 

small potential reductions in NOX emissions compared to the anticipated cost of replacement, 

particularly for the Tier-certified engines.

Although option 4, turbocharger and aftercooler, was determined to be technically infeasible for the 

older model wireline engines, it already exists on the remaining engines. Also, option 5 (aftercooling 

with HPFI system) already exists on all of the engines aboard C.R. Luigs and DD1.

The applicant also has proposed to supplement the good combustion practices outlined by the respective 

manufacturer of the main engines of C.R. Luigs and DD1 with the use of a NOX emissions measurement 

program. The applicant and Transocean refer to this system as “DEWT Measurement.” This is a 

parametric monitoring system that Transocean developed to enhance the load management of the 

engines, ensure good combustion efficiency, and maintain load levels to between 35 and 45%. The NOX

concentration measurement program will trigger an alarm if the NOX concentration reaches a specified 

threshold at which time the operator will investigate the cause of the emission increase and correct the 

underlying problem quickly. Transocean confirmed that this system can also monitor PM/PM10/PM2.5, 

CO, VOCs, and CO2. 

As part of the DEWT measurement system, a maintenance plan will require BHPB to perform regularly 

scheduled evaluations, inspections, and required maintenance (as necessary) to ensure proper operation 

of the main engines. As part of the maintenance plan, daily engine checks will trend parameters defined 

in permit Condition 6.10.1.3.2. The engine maintenance plan outlines specific procedures based on total 

hours of operation. The application submitted in October 2010 contains additional information 

describing the DEWT measurement system.

The keel-laying of C.R. Luigs occurred prior to the date requiring emission certification (on or after 

January 1, 2000); thus, the main engines of C.R. Luigs (EU-001 through -008) have never been issued 

emission certificates. Therefore, the NOX BACT emission limit for these engines has been established 

using the emissions test data submitted by the applicant in the October 2011 application addendum: 

18.1 g/kW-hr (or 12.1 g/kW-hr, corrected to 95% NO). EPA believes that, as more data becomes 

available and as a result of using the DEWT measurement system and enhanced maintenance, a lower 

BACT limit can be expected for these engines in future permitting of this vessel. Given the significant 

load variations required by the operations on the vessel, EPA has determined an averaging period of 24 

hours is appropriate in this case.
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The main engines on DD1 (EU-001 through -008) were certified at construction to meet Tier 1 standards 

of the International Maritime Organization (IMO)‟s 2000 NOX Technical Code (Regulation 13). At 

engine speeds of 900 rpm, the engines on the DD1 were designed to meet a NOX emission limit of 11.5

g/kW-hr operating at engine test bed conditions, which can vary significantly from the onsite drilling 

conditions. With a margin of compliance of plus five percent, this limit becomes 12.1 g/kW-hr. EPA 

believes that with the use of good combustion practices and the DEWT measurement system, a BACT 

limit of 12.1 g/kW-hr (or 8.1 g/kW-hr, corrected to 95% NO) is achievable for the DD1‟s main engines. 

Given the significant load variations required by the operations on the MODU, EPA has determined an 

averaging period of 24 hours is appropriate in this case.

Table 6-1 below summarizes EPA‟s BACT determinations for the diesel internal combustion engines 

with respect to NOX emissions. The respective emission limits are based on stack test data, vendor data, 

Tier certification, or AP-42.

Table 6-1: NOX BACT Conclusion

Emissions 

Unit ID BACT Control Options NOX BACT Limits*

Vessel: C.R. Luigs

EU-001 

through

-008

Turbocharger and aftercooler, 

HPFI w/ aftercooler, and good 

combustion practices with use of 

DEWT measurement system

18.1 g/kW-hr

(12.1 g/kW-hr, corrected to 95% NO)

EU-009 

through

-012

Turbocharger and aftercooler, 

HPFI w/ aftercooler, and good 

combustion practices

3.10 x 10-2lb/hp-hr

(18.8 g/kW-hr)

82.83 tons per year

4300 hours of operation 

each

EU-015 Turbocharger and aftercooler, 

HPFI w/ aftercooler, and good 

combustion practices

2.40 x 10-2lb/hp-hr

(14.6 g/kW-hr)

1.49 tons per year

60 hours of operation

EU-016 and

-017

EPA Tier 1 (or better) marine 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

9.80 g/kW-hr 8.69 tons per year

600 hours of operation each

(EU-016 and -017)

100 hours of operation

EU-018 EPA Tier 1 (or better) non-road (EU-018)

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

1.51 x 10-2lb/hp-hr

(9.18 g/kW-hr)

EU-019 and

-020

EPA Tier 3 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

6.58 x 10-3lb/hp-hr

(4.00 g/kW-hr)

8.92 tons per year

750 hours of operation each

(EU-019 and -020)

1700 hours of operation

(EU-022)

1300 hours of operation 

(EU-023)

EU-022 and 

-023

EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

1.09 x 10-2lb/hp-hr

(6.63 g/kW-hr)

EU-092 Good combustion practices 3.10 x 10-2lb/hp-hr (18.8 g/kW-hr)

Vessel: DD1

EU-001 

through

-008

Turbocharger and aftercooler, 

HPFI w/ aftercooler, and good 

combustion practices with use of 

DEWT measurement system

12.1 g/kW-hr

(8.10 g/kW-hr, corrected to 95% NO)
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EU-011 Turbocharger and aftercooler, 

HPFI w/ aftercooler, and good 

combustion practices

2.40 x 10-2lb/hp-hr

(14.6 g/kW-hr)

1.60 tons per year

60 hours of operation

EU-012 and

-013

EPA Tier 1 (or better) marine 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

9.80 g/kW-hr 9.50 tons per year

600 hours of operation each

(EU-012 and -013)

100 hours of operation each

EU-014 EPA Tier 1 (or better) non-road (EU-014 and -015)

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

1.51 x 10-2lb/hp-hr

(9.18 g/kW-hr)

EU-015 EPA Tier 2 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

1.09 x 10-2lb/hp-hr

(6.63 g/kW-hr)

EU-016 and

-017

EPA Tier 3 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

6.58 x 10-3lb/hp-hr

(4.00 g/kW-hr)

8.92 tons per year

750 hours of operation each

(EU-016 and -017)

1700 hours of operation

(EU-019)

1300 hours of operation

(EU-020)

EU-019 and 

-020

EPA Tier 2 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

and good combustion practices

1.09 x 10-2lb/hp-hr

(6.63 g/kW-hr)

*Short-term limits are based on a 24-hour average and long-term limits (including hours of operation) are based on a rolling 

12-month period.

6.1.2 CO and VOC BACT Analyses for Internal Combustion Engines

Incomplete combustion of the diesel fuel in the combustion chamber forms CO and VOC. Insufficient 

residence time during the final step in the oxidation of hydrocarbons during combustion will produce 

CO. The maximum oxidation of CO to carbon dioxide (CO2) occurs when the combustion process 

maintains sufficient temperature, residence time, and oxygen supply. Also, most VOCs found in diesel 

exhaust are the result of unburned fuel, although some are formed as combustion products. VOC 

compounds participate in atmospheric photochemical reactions. These reactions can result in the 

formation of ozone. VOCs do not include methane, ethane, and other compounds that have negligible 

photochemical reactivity.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application 

submitted in October 2010 and application addendum submitted in February 2011:

1. Diesel Oxidation Catalyst

2. Catalytic Diesel Particulate Filter (CDFP)

3. 4-Way Catalyst Converter with Exhaust Gas Recirculation System

4. Closed Crankcase Ventilation (CCV)/Positive Crankcase Ventilation (PCV)

(for VOCs only)

5. Good Combustion Practices

6. Fuel Injection Timing Retard
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The EPA requested additional information regarding the BACT analysis from the applicant and received 

supplemental information on September 30, 2011. The supplemental information includes the following 

additional control technologies as part of Step 1 of the top-down BACT analysis for CO and VOC 

emissions:

7. Newer/Cleaner Engines

8. HPFI with Aftercooler

From other OCS projects, EPA is aware of the following additional technology option:

9. Transocean DEWT Measurement System on Main Power Plant Engines

Step 2: Eliminate technically infeasible control options

After analyzing the nine control technology options for the control of CO and VOC emissions, four were 

eliminated as technically infeasible for all diesel internal combustion engines (options 1 through 3 and 

6). Option 4 was eliminated as technically infeasible for the wireline engines (EU-019 through -023 on 

C.R. Luigs and EU-016 through -020 on DD1), and option 7 was eliminated as technically infeasible for 

the main engines on C.R. Luigs (EU-001 through -008). Below is a summary of the reasons for 

eliminating each of these options from further consideration in the top-down BACT analysis for this 

project. For detailed descriptions and references, please refer to the application submitted (to EPA) in 

October 2010 and supplemental information submitted in February 2011, September 2011, 

October 2011, and December 2011, respectively.

Diesel Oxidation 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 C.R. Luigs and DD1.

CDFP: This technology has not been designed, engineered or tested on a commercially available scale 

for safe operation on the large scale engines found on C.R. Luigs and DD1.

4-Way Catalyst Converter with Exhaust Gas Recirculation System: This option is technically 

infeasible for these pollutants for the same rationale provided above in Section 6.1.1.

Fuel Injection Timing Retard: This option is technically infeasible for these pollutants for the same 

rationale provided above in Section 6.1.1.

CCV/PCV: This option is technically infeasible for the wireline engines (EU-019 through -023 on C.R. 

Luigs and EU-016 though -020 on DD1) because it would involve major design changes to the engines.

Newer/Cleaner Engines: This option is technically infeasible for the main engines on C.R. Luigs

(EU-001 through -008) for these pollutants for the same rationale provided above in Section 6.1.1.

Steps 3/4/5:

Although newer/cleaner engines were determined to be technically infeasible for the main engines on 

C.R. Luigs, this option is feasible for the remaining diesel internal combustion engines; however, this 

option was determined to be cost prohibitive for CO and VOC control for the same rationale provided in 

Section 6.1.1. Although CCV/PCV was determined to be technically infeasible for the wireline engines, 

this option already exists on the remaining engines. Also, option 8 already exists on all of the engines 

aboard C.R. Luigs and DD1. Tables 6-2 and 6-3 below summarize EPA‟s BACT determinations for the 
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03/28/2012 PD OCS-EPA-R4008

diesel internal combustion engines with respect CO and VOC emissions. The respective emission limits 

are based on stack test data, vendor data, Tier certification, or AP-42.

Table 6-2: CO BACT Conclusions

Emissions 

Unit ID BACT Control Options CO BACT Limits*

Vessel: C.R. Luigs

EU-001 

through

-008

HPFI w/ aftercooler and good 

combustion practices with use of 

DEWT measurement system

2.42 g/kW-hr

EU-009 

through

-012

HPFI w/ aftercooler and good 

combustion practices

6.68 x 10-3lb/hp-hr

(4.06 g/kW-hr)

17.85 tons per year

4,380 hours of operation each

EU-015 HPFI w/ aftercooler and good 

combustion practices

5.50 x 10-3lb/hp-hr

(3.34 g/kW-hr)

0.34 ton per year

60 hours of operation

EU-016 and

-017

EPA Tier 1 (or better) marine 

engine, HPFI w/ aftercooler, and 

good combustion practices

5.50 x 10-3lb/hp-hr

(3.34 g/kW-hr)

3.30 tons per year

600 hours of operation each

(EU-016 and -017)

100 hours of operation

(EU-018)

EU-018 EPA Tier 1 (or better) non-road 

engine, HPFI w/ aftercooler and 

good combustion practices

1.87 x 10-2lb/hp-hr

(11.4 g/kW-hr)

EU-019 and

-020

EPA Tier 3 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

5.76 x 10-3lb/hp-hr

(3.50 g/kW-hr)

2.90 tons per year

750 hours of operation each

(EU-019 and -020)

1700 hours of operation

(EU-022)

1300 hours of operation

(EU-023)

EU-022 and 

-023

EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

5.76 x 10-3lb/hp-hr

(3.50 g/kW-hr)

EU-092 Good combustion practices 6.68 x 10-03 lb/hp-hr (4.06 g/kW-hr)

Vessel: DD1

EU-001 

through

-008

HPFI w/ aftercooler and good 

combustion practices with use of

DEWT measurement system

1.98 g/kW-hr

EU-011 HPFI w/ aftercooler and good 

combustion practices

5.50 x 10-3lb/hp-hr

(3.34 g/kW-hr)

0.37 tons per year

60 hours of operation

EU-012 and

-013

EPA Tier 1 (or better) marine 

engine, HPFI w/ aftercooler, and 

good combustion practices

5.50 x 10-3lb/hp-hr

(3.34 g/kW-hr)

3.73 tons per year

600 hours of operation each

(EU-012 and -013)

100 hours of operation each

(EU-014 and -015)

EU-014 EPA Tier 1 (or better) non-road 

engine, HPFI w/ aftercooler and 

good combustion practices

1.87 x 10-2lb/hp-hr

(11.4 g/kW-hr)

EU-015 EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

5.76 x 10-3lb/hp-hr

(3.50 g/kW-hr)

EU-016 and

-017

EPA Tier 3 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

5.76 x 10-3lb/hp-hr

(3.50 g/kW-hr)

2.90 tons per year

750 hours of operation each

(EU-016 and -017)

1700 hours of operation

(EU-019)

EU-019 and 

-020

EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, and 

5.76 x 10-3lb/hp-hr

(3.50 g/kW-hr)
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good combustion practices 1300 hours of operation

(EU-020)

*Short-term limits are based on a 24-hour average and long-term limits (including hours of operation) are based on a rolling 

12-month period.

Table 6-3: VOC BACT Conclusions

Emissions 

Unit ID BACT Control Options VOC BACT Limits*

Vessel: C.R. Luigs

EU-001 

through

-008

PCV, HPFI w/ aftercooler, and 

good combustion practices with use 

of DEWT measurement system

6.42 x 10-4lb/hp-hr (0.39 g/kW-hr)

EU-009 

through

-012

PCV, HPFI w/ aftercooler, and 

good combustion practices

2.51 x 10-3lb/hp-hr

(1.53 g/kW-hr)

6.72 tons per year

4300 hours of operation each

EU-015 PCV, HPFI w/ aftercooler, and 

good combustion practices

6.42 x 10-4lb/hp-hr

(0.39 g/kW-hr)

0.04 ton per year

60 hours of operation

EU-016 and

-017

EPA Tier 1 (or better) marine 

engine, CCV, HPFI w/ aftercooler, 

and good combustion practices

6.42 x 10-4lb/hp-hr

(0.39 g/kW-hr)

0.38 ton per year

600 hours of operation each

(EU-016 and -017)

100 hours of operation

(EU-018)

EU-018 EPA Tier 1 (or better) non-road 

engine, CCV, HPFI w/ aftercooler, 

and good combustion practices

2.14 x 10-3lb/hp-hr

(1.30 g/kW-hr)

EU-019 and

-020

EPA Tier 3 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

2.51 x 10-3lb/hp-hr

(1.53 g/kW-hr)

1.17 tons per year

750 hours of operation each

(EU-019 and -020)

1700 hours of operation

(EU-022)

1300 hours of operation

(EU-023)

EU-022 and 

-023

EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

2.51 x 10-3lb/hp-hr

(1.53 g/kW-hr)

EU-092 Good combustion practices 2.51 x 10-3lb/hp-hr (1.53 g/kW-hr)

Vessel: DD1

EU-001 

through

-008

PCV, HPFI w/ aftercooler, and 

good combustion practices with use 

of DEWT measurement system

6.42 x 10-4lb/hp-hr (0.39 g/kW-hr)

EU-011 PCV, HPFI w/ aftercooler, and 

good combustion practices

6.42 x 10-4lb/hp-hr

(0.39 g/kW-hr)

0.04 ton per year

60 hours of operation

EU-012 and

-013

EPA Tier 1 (or better) marine 

engine, CCV, HPFI w/ aftercooler, 

and good combustion practices

6.42 x 10-4lb/hp-hr

(0.39 g/kW-hr)

0.57 ton per year

600 hours of operation each

(EU-012 and -013)

100 hours of operation each

(EU-014 and -015)

EU-014 EPA Tier 1 (or better) non-road 

engine, CCV, HPFI w/ aftercooler, 

and good combustion practices

2.14 x 10-3lb/hp-hr

(1.30 g/kW-hr)

EU-015 EPA Tier 2 (or better) non-road 

engine, CCV, HPFI w/ aftercooler, 

and good combustion practices

2.51 x 10-3lb/hp-hr

(1.53 g/kW-hr)

EU-016 and

-017

EPA Tier 3 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

2.51 x 10-3lb/hp-hr

(1.53 g/kW-hr)

1.17 tons per year

750 hours of operation each

(EU-016 and -017)
28

03/28/2012 PD OCS-EPA-R4008

EU-019 and 

-020

EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, and 

good combustion practices

2.51 x 10-3lb/hp-hr

(1.53 g/kW-hr)

1700 hours of operation

(EU-019)

1300 hours of operation

(EU-020)

*Short-term limits are based on a 24-hour average and long-term limits (including hours of operation) are based on a rolling 

12-month period.

6.1.3 PM/PM10/PM2.5 BACT Analysis for Internal Combustion Engines

Diesel particulate emissions are primarily products of incomplete combustion of diesel fuel and 

lubrication oil in the combustion chamber. The majority of the PM emissions from stationary diesel 

engines are PM2.5; therefore, BACT for PM/PM10/PM2.5 is addressed concurrently since any control 

technology available for the control of PM2.5 will also effectively control PM and PM10.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application 

submitted in October 2010 and application addendum submitted in February 2011:

1. Baghouse (Fabric Filter)

2. Diesel Oxidation Catalyst

3. Diesel Particulate Filter/CDPF

4. 4-Way Catalyst Converter with Exhaust Gas Recirculation System

5. Low Sulfur/Low Ash Fuel

6. Fuel Injection Timing Retard

7. CCV/PCV (for VOCs only)

8. Turbocharger and Aftercooler

9. Good Combustion Practices

The EPA requested additional information regarding the BACT analysis from the applicant and received 

supplemental information on September 30, 2011. The supplemental information includes the following 

additional control technologies as part of Step 1 of the top-down BACT analysis for PM/PM10/PM2.5

emissions:

10. Newer/Cleaner Engines

11. HPFI with Aftercooler

From other OCS projects, EPA is aware of the following additional technology option:

12. Transocean DEWT Measurement System on Main Power Plant Engines

Step 2: Eliminate technically infeasible control options

After analyzing the 12 control technology options for the control of PM/PM10/PM2.5 emissions, five

were eliminated as technically infeasible for all diesel internal combustion engines (options 1 through 4 

and 6). Option 7 was eliminated as technically infeasible for the wireline engines (EU-019 through -023 

on C.R. Luigs and EU-016 through -020 on DD1), option 8 was eliminated as technically infeasible for 

the older model wireline engines (EU-022 and -023 on C.R. Luigs and EU-019 and -020 on DD1), and 

option 10 was eliminated as technically infeasible for the main engines on C.R. Luigs (EU-001 through 

-008). Below is a summary of the reasons for eliminating each of these options from further 
29

03/28/2012 PD OCS-EPA-R4008

consideration in the top-down BACT analysis for this project. For detailed descriptions and references, 

please refer to the application submitted (to EPA) in October 2010 and supplemental information 

submitted in February 2011, September 2011, October 2011, and December 2011, respectively.

Baghouse (Fabric Filter): This technology is large and generally used for land-based sources. Due to 

space constraints, there is no available space on the vessels for this option.

Diesel Oxidation Catalyst: This option is technically infeasible for these pollutants for the same 

rationale provided above in Section 6.1.2.

Diesel Particulate Filter/CDPF: This control option is technically infeasible to due added back 

pressure on the engines that could cause plugging of the engines, thus posing safety concerns. Also, the 

engines cannot typically achieve the necessary exhaust temperatures (due to load variations) for optimal 

regeneration of the filter substrate/catalyst, thus resulting in plugging.

4-Way Catalyst Converter with Exhaust Gas Recirculation System: This option is technically 

infeasible for these pollutants for the same rationale provided above in Section 6.1.1.

Fuel Injection Timing Retard: This option is technically infeasible for these pollutants for the same 

rationale provided above in Section 6.1.1.

CCV/PCV: This option is technically infeasible for the wireline engines (EU-019 through -023 on 

C.R Luigs and EU-016 though -020 on DD1) because it would involve major design changes to the 

engines.

Turbocharger and Aftercooler: This option is technically infeasible on the older model wireline 

engines (EU-022 and -023 on C.R. Luigs and EU-019 and -020 on DD1) for these pollutants for the 

same rationale provided in Section 6.1.1.

Newer/Cleaner Engines: This option is technically infeasible for the main engines on C.R. Luigs

(EU-001 through -008) for these pollutants for the same rationale provided above in Section 6.1.1.

Steps 3/4/5:

Although newer/cleaner engines were determined to be technically infeasible for the main engines on 

C.R. Luigs, this option is feasible for the remaining diesel internal combustion engines; however, this 

option was determined to be cost prohibitive for PM/PM10/PM2.5 control for the same rationale provided 

in Section 6.1.1. Although CCV/PCV was determined to be technically infeasible for the wireline 

engines, this option already exists on the remaining engines. Although option 8 was determined to be 

technically infeasible for the older model wireline engines, it already exists on the remaining engines. 

Also, option 11 already exists on all of the engines aboard C.R. Luigs and DD1. Table 6-4 below 

summarizes EPA‟s BACT determinations for the diesel internal combustion engines with respect 

PM/PM10/PM2.5 emissions. The respective emission limits are based on vendor data, Tier certification, 

or AP-42.
30

03/28/2012 PD OCS-EPA-R4008

Table 6-4: PM/PM10/PM2.5 BACT Conclusions

Emissions 

Unit ID BACT Control Options PM/PM10/PM2.5 BACT Limits*

Vessel: C.R. Luigs

EU-001 

through

-008

Turbocharger and aftercooler, 

PCV, HPFI w/ aftercooler, good 

combustion practices with the use 

of DEWT measurement system, 

and ultra low sulfur fuel

PM: 7.00 x 10-4lb/hp-hr (0.43 g/kW-hr)

PM10: 4.01 x 10-4lb/hp-hr (0.24 g/kW-hr)

PM2.5: 3.89 x 10-4lb/hp-hr (0.24 g/kW-hr)

EU-009 

through

-012

Turbocharger and aftercooler, 

PCV, HPFI w/ aftercooler, good 

combustion practices, and ultra 

low sulfur fuel

2.20 x 10-3lb/hp-hr

(1.34 g/kW-hr)

5.88 tons per year

4300 hours of operation each

EU-015 Turbocharger and aftercooler, 

PCV, HPFI w/ aftercooler, good 

combustion practices, and ultra 

low sulfur fuel

PM: 7.00 x 10-4lb/hp-hr

(0.43 g/kW-hr)

PM10: 4.01 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM2.5: 3.89 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM: 0.04 ton per year

PM10/PM2.5: 0.02 ton per year

60 hours of operation

EU-016 and

-017

EPA Tier 1 (or better) marine 

engine, turbocharger and 

aftercooler, CCV, HPFI w/ 

aftercooler, good combustion 

practices, and ultra low sulfur fuel

PM: 7.00 x 10-4lb/hp-hr

(0.43 g/kW-hr)

PM10: 4.01 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM2.5: 3.89 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM: 0.38 ton per year

PM10: 0.23 ton per year

PM2.5: 0.22 ton per year

600 hours of operation each

(EU-016 and -017)

100 hours of operation

EU-018 EPA Tier 1 (or better) non-road (EU-018)

engine, turbocharger and 

aftercooler, CCV, HPFI w/ 

aftercooler, good combustion 

practices, and ultra low sulfur fuel

8.88 x 10-4lb/hp-hr

(0.54 g/kW-hr)

EU-019 and

-020

EPA Tier 3 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

good combustion practices, and 

ultra low sulfur fuel

3.29 x 10-4lb/hp-hr

(2.00 g/kW-hr)

0.60 ton per year

750 hours of operation each

(EU-019 and -020)

1700 hours of operation

(EU-022)

1300 hours of operation

(EU-023)

EU-022 and 

-023

EPA Tier 2 (or better) non-road 

engine, HPFI w/ aftercooler, good 

combustion practices, and ultra 

low sulfur fuel

3.29 x 10-4lb/hp-hr

(2.00 g/kW-hr)

EU-092 Ultra low sulfur fuel and good 

combustion practices

2.20 x 10-3lb/hp-hr (1.34 g/kW-hr)

Vessel: DD1

EU-001 

through

-008

Turbocharger and aftercooler, 

PCV, HPFI w/ aftercooler, good 

combustion practices with the use 

of DEWT measurement system, 

and ultra low sulfur fuel

PM: 7.00 x 10-4lb/hp-hr (0.43 g/kW-hr)

PM10: 4.01 x 10-4lb/hp-hr (0.24 g/kW-hr)

PM2.5: 3.89 x 10-4lb/hp-hr (0.24 g/kW-hr)
31

03/28/2012 PD OCS-EPA-R4008

EU-011 Turbocharger and aftercooler, 

PCV, HPFI w/ aftercooler, good 

combustion practices, and ultra 

low sulfur fuel

PM: 7.00 x 10-4lb/hp-hr

(0.43 g/kW-hr)

PM10: 4.01 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM2.5: 3.89 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM: 0.05 ton per year

PM10/PM2.5: 0.03 ton per year

60 hours of operation

EU-012 and

-013

EPA Tier 1 (or better) marine 

engine, turbocharger and 

aftercooler, CCV, HPFI w/ 

aftercooler, good combustion 

practices, and ultra low sulfur fuel

PM: 7.00 x 10-4lb/hp-hr

(0.43 g/kW-hr)

PM10: 4.01 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM2.5: 3.89 x 10-4lb/hp-hr

(0.24 g/kW-hr)

PM: 0.41 ton per year

PM10: 0.25 ton per year

PM2.5: 0.25 ton per year

600 hours of operation each

(EU-012 and -013)

100 hours of operation each

EU-014 EPA Tier 1 (or better) non-road (EU-014 and -015)

engine, turbocharger and 

aftercooler, CCV, HPFI w/ 

aftercooler, good combustion 

practices, and ultra low sulfur fuel

8.88 x 10-4lb/hp-hr

(0.54 g/kW-hr)

EU-015 EPA Tier 2 (or better) non-road 

engine, turbocharger and 

aftercooler, CCV, HPFI w/ 

aftercooler, good combustion 

practices, and ultra low sulfur fuel

3.29 x 10-4lb/hp-hr

(2.00 g/kW-hr)

EU-016 and

-017

EPA Tier 3 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

good combustion practices, and 

ultra low sulfur fuel

3.29 x 10-4lb/hp-hr

(2.00 g/kW-hr)

0.60 ton per year

750 hours of operation each

(EU-016 and -017)

1700 hours of operation

(EU-019)

1300 hours of operation

(EU-020)

EU-019 and 

-020

EPA Tier 2 (or better) non-road 

engine, turbocharger and 

aftercooler, HPFI w/ aftercooler, 

good combustion practices, and 

ultra low sulfur fuel

3.29 x 10-4lb/hp-hr

(2.00 g/kW-hr)

*Short-term limits are based on a 24-hour average and long-term limits (including hours of operation) are based on a rolling 

12-month period.

6.1.4 GHG BACT Analysis for Internal Combustion Engines

The majority of GHG emissions from the diesel internal combustion engines are in the form of carbon 

dioxide (CO2). CO2 is formed in the combustion chamber as a result of complete combustion of diesel 

when the carbon in the fuel is converted to CO2. A GHG BACT analysis was required for new sources 

with significant emissions of GHGs as of January 2, 2011.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application 

submitted in October 2010 and application addendum submitted in February 2011:

1. Carbon Capture Storage/Sequestration (CCS)

2. Alternative/Biomass Fuel Sources
32

03/28/2012 PD OCS-EPA-R4008

3. CSNOX Emissions Abatement System

4. Good Combustion Practices

The EPA requested additional information regarding the BACT analysis from the applicant and received 

supplemental information on September 30, 2011. The supplemental information includes the following 

additional control technologies as part of Step 1 of the top-down BACT analysis for GHG emissions:

5. Newer/Cleaner Engines

From other OCS projects, EPA is aware of the following additional technology option:

6. Transocean DEWT Measurement System on Main Power Plant Engines

Step 2: Eliminate technically infeasible control options

After analyzing the five control technology options for the control of GHG emissions, three were 

eliminated as technically infeasible for all diesel internal combustion engines (options 1 through 3). 

Option 5 was eliminated as technically infeasible for the main engines on C.R. Luigs (EU-001 through -

008). Below is a summary of the reasons for eliminating each of these options from further 

consideration in the top-down BACT analysis for this project. For detailed descriptions and references, 

please refer to the application submitted (to EPA) in October 2010 and supplemental information 

submitted in February 2011, September 2011, October 2011, and December 2011, respectively.

CCS: This control option is technically infeasible due to space constraints. The space needed for the 

equipment necessary to capture and separate CO2 from engine exhaust is not available on either of the 

vessels. Furthermore, the mobile nature of the source renders attachment to a fixed pipeline for CO2

transport infeasible.

Alternative/Biomass Fuel Sources: The current supply market for biodiesel is not stable enough to be 

considered a viable option for this project.

CSNOX Emissions Abatement System: This technology is currently in the licensing and commercial 

demonstration phase of development. While this technology is commercially available for certain types 

of marine uses, it has not been demonstrated in practice for use aboard a dynamically positioned mobile 

off shore drilling unit (i.e., vessels with variable load engines); therefore, it is technically infeasible for 

this project.

Newer/Cleaner Engines: This option is technically infeasible for the main engines on C.R. Luigs

(EU-001 through -008) with regard to GHGs for the same rationale provided above in Section 6.1.1.

Steps 3/4/5:

Although newer/cleaner engines were determined to be technically infeasible for the main engines on 

C.R. Luigs, this option is feasible for the remaining diesel internal combustion engines; however, this 

option was determined to be cost prohibitive for GHGs for the same rationale provided in Section 6.1.1. 

Table 6-5 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 part 98.
33

03/28/2012 PD OCS-EPA-R4008

Table 6-5: GHG BACT Conclusions

Emissions 

Unit ID BACT Control Options BACT Limits* (as CO2e)

Vessel: C.R. Luigs

EU-001 

through

-008

Good combustion practices

with use of DEWT 

measurement system

1.16 lb/hp-hr (705 g/kW-hr) 78,005 tons per year

6,570 hours of operation

EU-009 

through

-012

Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr) 3,083 tons per year

4,380 hours of operation each

EU-015 Good combustion practices 1.16 lb/hp-hr (705 g/kW-hr) 72.06 tons per year

60 hours of operation

EU-016 and

-017

Good combustion practices 1.16 lb/hp-hr (705 g/kW-hr) 628.9 tons per year

600 hours of operation each

(EU-016 and -017)

100 hours of operation

(EU-018)

EU-018 Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr)

EU-019 and

-020

Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr) 536.6 tons per year

750 hours of operation each

(EU-019 and -020)

1700 hours of operation

(EU-022)

1300 hours of operation

(EU-023)

EU-022 and 

-023

Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr)

EU-092 Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr)

Vessel: DD1

EU-001 

through

-008

Good combustion practices

with use of DEWT 

measurement system

1.16 lb/hp-hr (705 g/kW-hr) 79,921 tons per year

6,570 hours of operation

EU-011 Good combustion practices 1.16 lb/hp-hr (705 g/kW-hr) 77.84 tons per year

60 hours of operation

EU-012 and

-013

Good combustion practices 1.16 lb/hp-hr (705 g/kW-hr) 715.5 tons per year

600 hours of operation each

(EU-012 and -013)

100 hours of operation each

(EU-014 and -015)

EU-014 Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr)

EU-015 Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr)

EU-016 and

-017

Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr) 536.6 tons per year

750 hours of operation each

(EU-016 and -017)

1700 hours of operation

(EU-019)

1300 hours of operation

(EU-020)

EU-019 and 

-020

Good combustion practices 1.15 lb/hp-hr (699 g/kW-hr)

*Short-term limits are based on a 24-hour average and long-term limits (including hours of operation) are based on a rolling 

12-month period. All GHG emission limits are in the form of CO2e.
34

03/28/2012 PD OCS-EPA-R4008

6.2 BACT Analysis for Storage Tanks

Both C.R. Luigs and DD1 have various types of storage tanks subject to BACT review for emissions of 

VOC. Both C.R. Luigs and DD1 will include diesel fuel storage tanks, helifuel storage tanks, a base oil 

storage tank, a fast rescue craft fuel tank, and lifeboat fuel tanks. C.R. Luigs will also include a hydraulic 

fluid storage tank. On C.R. Luigs, the following tanks are included in this analysis: EU-029 through -045 

and -053 through -059 (diesel fuel storage tanks); EU-046 (fast rescue craft fuel tank); EU-047 through -

050 (lifeboat fuel tanks); EU-051 (hydraulic fluid storage tank); EU-052 (base oil storage tank); and EU090 through -091 (helifuel storage tanks). On DD1, the following tanks are part of this analysis: EU-026 

through -032, -034, and -040 through -047 (diesel fuel storage tanks); EU-033 (base oil storage tank); 

EU-035 (fast rescue craft fuel tank); EU-036 through -039 (lifeboat fuel tanks); and EU-078 through 

-081 (helifuel storage tanks). The fuel in these tanks will generate VOC emissions resulting from both 

breathing and working (i.e., loading) losses.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application 

submitted in October 2010 and application addendum submitted in February 2011:

1. Vapor Recovery Unit

2. Thermal Oxidation System

3. Adsorption System

4. Internal Floating Roof or External Floating Roof

From other OCS projects, EPA is aware of the following additional technology option:

5. Submerged Loading

Step 2: Eliminate technically infeasible control options

After analyzing the above control technologies, all of the options were eliminated as technically 

infeasible for control of VOC emissions from the tanks on the C.R. Luigs and DD1. Below is a summary 

of the reasons for eliminating each of the above options from further consideration in the top-down 

BACT analysis for this project. For detailed descriptions and references, particularly related to options 1 

through 4, please refer to the application submitted (to EPA) in October 2010 and supplemental 

information submitted in February 2011, September 2011, October 2011, and December 2011, 

respectively.

Vapor Recovery Unit: This option is technically infeasible due to limited space availability.

Thermal Oxidation System: This option is technically infeasible due to limited space availability.

Adsorption System: This option is not effective for controlling low concentrations of VOC generated 

by diesel and base oil storage tanks. Furthermore, this option is technically infeasible since it would 

require additional space that is not available on either vessel.

Internal Floating Roof or External Floating Roof: This option is not effective for controlling VOC 

emissions from stored liquids of low vapor pressures, such as diesel and base oil. Furthermore, this 

option is technically infeasible since it would require additional space that is not available on either 

vessel.
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03/28/2012 PD OCS-EPA-R4008

Submerged Loading: This technology is technically infeasible due to limited space availability.

Steps 3/4/5:

Based on a review of the available control technologies, EPA has determined that BACT is use of good 

maintenance practices. This will limit tank leakage and excessive VOC emissions. The amount of VOC 

emissions emitted from the tanks in contingent upon both the fuel type and the amount of fuel. 

Therefore, the applicant will maintain records of the tank identification, volume, and fuel type stored. 

EPA has determined that the tanks will have VOC BACT limits of 0.57 and 0.44 ton per year on a 12-

month rolling total basis for C.R. Luigs and DD1, respectively, as determined by EPA‟s TANKS 4.0.9d 

program.

6.3 BACT Analysis for Mud and Cement Mixing

Both the C.R. Luigs and DD1 have mud and cement mixing operations (EU-013 and EU-009, 

respectively) subject to BACT review for emissions of PM/PM10/PM2.5.

Step 1: Identify all available control technologies

The applicant identified the following available control technologies in their OCS permit application 

submitted in October 2010 and application addendum submitted in February 2011:

1. Dust Collector

The applicant states that a review of the RBLC database did not reveal any other potential control 

technologies for the mud and cementing operations aboard either the C.R. Luigs or DD1.

Step 2: Eliminate technically infeasible control options

The one identified control technology was not eliminated as infeasible.

Steps 3/4/5:

Based on a review of the available control technologies, EPA has determined that BACT is the use of a 

dust collector with proper maintenance and operation to ensure a control efficiency of 99.95 percent. 

This will limit excessive PM/PM10/PM2.5 emissions. EPA has determined the mud and cement mixing 

operations (for each vessel) will have a PM/PM10/PM2.5 BACT limit of 1.08 tons per year on a 12-month 

rolling total basis.

6.4 BACT Analysis for Mud Degassing

Both the C.R. Luigs and DD1 have mud degassing operations (EU-014 and EU-010, respectively) 

subject to BACT review for emissions of VOC and GHGs (CO2e). 

Step 1: Identify all available control technologies

The applicant states that a review of the RBLC database did not reveal any potential control 

technologies to capture and control fugitive emissions from the mud degassing operations aboard either 

the C.R. Luigs or DD1.
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03/28/2012 PD OCS-EPA-R4008

Step 2: Eliminate technically infeasible control options

There were no control technologies identified in Step 1.

Steps 3/4/5:

Based on a review of the available control technologies, EPA has determined that BACT for VOC and 

CO2e emissions from mud degassing is no add-on controls. EPA has determined the mud degassing 

operations (for each vessel) will have a VOC BACT limit of 19.39 TPY and a GHG BACT limit of

982.7 tons of CO2e per year, both on a 12-month rolling total basis.

7.0 Air Quality Impact Analyses Summary

7.1 Required Analyses

The PSD permitting regulations for proposed major new sources generally require applicants to perform 

an air quality impacts analysis for those pollutants that the project emits in significant quantities, as 

discussed in Section 4.3 and provided in Table 4.1. However, the PSD regulations also provide that 

certain provisions of the analysis are not required for temporary sources that meet specific conditions. 

The PSD regulations at 40 CFR § 52.21(i)(3) provide exemptions from the following analyses: source 

air quality analysis (40 CFR § 52.21(k)), preconstruction and post-construction monitoring (40 CFR § 

52.21(m)), and additional impact analysis (40 CFR § 52.21(o)), if the allowable emissions of that 

pollutant from the source: (i) would impact no Class I area and no area where the applicable increment is 

known to be violated, and (ii) would be temporary. EPA considers sources operating for less than two 

years in a given location to be temporary sources. See Amended Regulations for Prevention of 

Significant Deterioration of Air Quality, 45 Fed. Reg. 52676, 52719, 52728 (August 7, 1980). 

For sources impacting Federal Class I areas, 40 CFR § 52.21(p) requires EPA to consider any 

demonstration by the Federal Land Manager (FLM) that emissions from the proposed source would 

have an adverse impact on air quality related values, including visibility impairment. If EPA concurs 

with the demonstration, the rules require that EPA shall not issue the PSD permit.

The maximum allowable PSD increments are listed in 40 CFR § 52.21(c) and given in Table 7-1 below. 

There are no increments for ozone. There are PSD Class I, II and III increments applicable to areas 

designated Class I, II and III. Class I areas are defined in 40 CFR § 52.21(e). Mandatory Class I areas 

(which may not be redesignated to Class II or III) are international parks, national wilderness areas

larger than 5,000 acres, memorial parks larger than 5,000 acres, and national parks larger than 6,000 

acres.
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03/28/2012 PD OCS-EPA-R4008

Table 7-1: Ambient Air Quality Concentration Values (Showing only project PSD pollutants)

Pollutant 

and Averaging Period

National Ambient Air 

Quality Standards

(μg/m3(ppm))

PSD Increments

(μg/m3)

PSD Significant 

Impact Levels 

(μg/m3)

PSD De 

Minimis

Impact 

Levels 

(μg/m3)

Primary Secondary Class I Class II Class 

I

Class II

Particulate Matter (PM10) 24-hr

 Annual

150

None

150

None

8

a

4

30a

17

0.3

0.2

5

1

10

Particulate Matter (PM2.5) 24-hr

 Annual

35c

15d

35c

15d

2

a

1

9

a

4

0.07

0.06

1.2

0.3

4

Carbon Monoxide 1-hr

 8-hr

40,000 (35)a

10,000 (9)a

None

None

2000

500 575

Ozone 1-hr

8-hr (1997)

8-hr (2008)

(0.12)

(0.08)e

(0.075)e

(0.12)

(0.08)e

(0.075)e

100f

Nitrogen Dioxide 1-hr

 Annual

188g, h (0.100)

100 (0.053)

None

100 (0.053) 2.5 25 0.1

7.55h(0.004)b

1 14

a Not to exceed more than once a year

b Recommended interim SIL

c Achieved when the average of the annual 98th percentile 24-hour concentration averaged over the years modeled is ≤ standard. 

d Achieved when the average of the annual mean concentration over the number of years modeled is < standard.

e Achieved when the average of the annual fourth-highest daily maximum 8-hour average concentrations is less than or equal to the 

standard. 

f Measured in tons/year of volatile organic compounds.

g Achieved when the 98th percentile of the annual distribution of the daily maximum 1-hour average concentrations averaged over the 

number of years modeled is < standard.

h Values in ug/m3

are estimates. These may change when values and/or ppm to μg/m3conversion procedures are provided by the EPA. 

7.1.1 BHPB’s Qualification as a Temporary Source

BHPB has requested an air quality permit for less than two years of potential exploratory drilling 

activity in the lease blocks in the Desoto Canyon region of the Gulf of Mexico. Since the project will 

operate for no more than two years, and the permit allows for a maximum of two years of operation, the 

project is considered a temporary source under the applicable PSD regulations. Therefore, the following 

sections address the impact related criterion for temporary source exemption in 40 CFR § 52.21(i)(3).

7.1.2 PSD Increment Criterion

The second criterion that must be met for an exemption under 40 CFR § 52.21(i)(3) requires that the 

project emissions must not impact any PSD Class I area, or any area where the applicable increment is 

already violated. The Desoto Canyon lease blocks are located in the Central Gulf of Mexico with the 

nearest block located approximately 120 miles from the nearest shoreline (Louisiana). There are no 

known areas in the Eastern Gulf of Mexico violating the NO2 or particulate matter (PM10, PM2.5) PSD 

increments. Therefore, the proposed project‟s emissions will not impact any area where applicable 

increments are known to be violated. Nor, based on the analysis discussed below, does EPA believe the 

project‟s emissions will significantly impact any onshore areas.
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7.2 PSD Class I Areas Impact Analyses

The nearest PSD Class I area to the Desoto Canyon lease blocks is Breton National Wildlife Refuge 

located on the southeast coast of Louisiana, approximately 214 km from the nearest proposed drilling 

location. Other PSD Class I areas included in the impact analyses are St. Marks National Wildlife 

Refuge and Bradwell Bay Wilderness, both located in Florida approximately 290 and 292 km, 

respectively, from the nearest drilling location. BHPB evaluated its potential impact on the three Class I 

areas‟ Air Quality Related Values (i.e., visibility, nitrogen, and sulfur deposition) and PSD increments. 

The Federal Land Manager for Bradwell Bay Wilderness identified the AQRV of concern as deposition 

and ozone. The Federal Land Manager for each PSD Class I area (i.e., U.S. Fish & Wildlife Service, 

U.S. Forest Service, or National Park Service) has the charge to protect the AQRV while the EPA 

ensures compliance with the PSD increments. The U.S. Fish and Wildlife Service is the Federal Land 

Manager for Breton National Wildlife Refuge and St. Marks National Wildlife Refuge, and the U.S. 

Forest Service is the Federal Land Manager for the Bradwell Bay Wilderness. The EPA-required 

assessments of PSD Class I increments were addressed using the same model and modeling procedures 

used and approved by the Federal Land Manager for the AQRV assessment.

7.2.1 Screening Procedure for Air Quality Related Values

As indicated above, visibility, nitrogen deposition, and sulfate deposition are all AQRV of concern at the 

identified PSD Class I areas. In addition, ozone is an AQRV of concern for Bradwell Bay Wilderness.

The Federal Land Managers uses a “Q/D” screening procedure to determine if refined air quality impact 

modeling is needed to quantify estimated project impacts. See Federal Land Managers‟ Air Quality 

Related Values Workgroup (FLAG) Phase I Report (Revised October 2010. The Q value is the sum of 

the annual emissions (in tons per year based on 24-hour maximum allowable emissions) of all the 

pollutants affecting visibility emitted from the project (i.e., NOX, PM10, PM2.5, SO2, and sulfuric acid). 

The D value is the distance, in km, of the project from the PSD Class I area. The Federal Land Manager 

considers Q/D values less than or equal to 10 to be insignificant (i.e., project‟s emissions would not 

significantly impact the Class I areas). 

Although the project‟s emissions are based on less than a full year operation, the Q value in this 

screening analysis should be annualized. Annualized emissions are based on the maximum 24-hour 

permitted emissions (i.e., MODU and support boat operations) that are assumed to occur for each 365-

day period. 

The applicant‟s Q/D analysis for each of the PSD Class I areas resulted in all values greater than 10, the 

Federal Land Manager‟s FLAG guidance threshold value. Based on the project‟s emissions and the 

distance of the project from each of these Class I areas, the Federal Land Managers required a Class I 

AQRV modeling analysis.

7.2.2 Model Selection and Modeling Procedures

The EPA-preferred model for long-range transport assessments – CALPUFF Version 5.8 (release 

070623) - was used to evaluate potential AQRV and PSD increment impacts at each of the three nearest 

PSD Class I areas. The recommendations of the Interagency Workgroup on Air Quality Modeling and 

the Federal Land Manager Air Quality Related Values Workgroup (FLAG) were followed in performing 

these impact assessments. The CALPUFF modeling options used in the impact assessments were the 

defaults recommended by FLAG draft Revised Phase I Report (June 2008) and the EPA. 
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The CALPUFF modeling assessment used the maximum emissions from the MODU and supporting 

crew and work vessels. The supporting vessel emissions corresponded to those produced by the largest 

vessel, at their maximum proposed load conditions, expected to be potentially available for the project. 

The MODU emissions were estimated for the ultra-deepwater C.R. Luigs which represents the worse 

case MODU as compared to the DD1, which is expected to have lower operating emissions. The drilling 

phase of the project produces the largest emissions. The worst-case emissions for all averaging periods 

of concern (i.e., hourly, daily, and annual) were used in the modeling. 

The worst-case project emissions from all vessels were modeled as though emitted from a single MODU

stack. The stack exit parameters used were based on the stack associated with the main MODU engine,

which is the largest source of emission from the proposed drilling operations. The worst-case 100% load 

stack exit parameters, the operational scenario producing the maximum MODU emissions, were used as 

any changes in these parameters associated with lower loads would not result in appreciably higher 

impacts considering the long transport distance (214 to 292 km). 

In addition, to ensure the impact assessment included the operating scenario that would produce the 

worst-case impacts, the MODU was located at the closest corner of the lease block nearest the PSD 

Class I area of concern. 

7.2.3 Meteorological Data

The three-year meteorological dataset (2001-2003) developed by the Visibility Improvement State and 

Tribal Association of the Southeast (VISTAS) was used for the PSD Class I impact assessment. This 

dataset covers the Gulf of Mexico region of interest. These meteorological data were processed using the 

regulatory version of CALMET (Version 5.8 Level 070623). The dataset was developed using 

observations from 100 to 109 surface stations, 10 upper air stations, 9 overwater stations and 92 to 103 

precipitation stations, depending on the meteorological year. 

7.2.4 Model Outputs

The CALPUFF-estimated hourly concentrations were averaged for comparison with the annual and 24-

hour PM10/PM2.5 and NO2 Class I PSD significant impact levels and increment. Extinction coefficients 

for 24-hour daily periods and annual total deposition fluxes were estimated. The highest estimated 

values for the 3-year period were used in comparisons with the significant impact levels and Deposition 

Analysis Thresholds. Maximum and 98 percentile modeled changes in extinction from vessel emissions 

were compared to the Federal Land Manager target value that is associated with the just perceptible 

change in extinction.

7.2.5 Atmospheric Chemistry

The NOX chemistry in CALPUFF depends on input ambient ammonia concentration. A concentration of 

3 parts per billion (ppb) was used for background ammonia, as requested by the Federal Land Manager. 

Reaction rates are influenced by background ozone concentrations. Ozone data from the monitor in 

Sumatra, Florida were used because of the proximity to the modeling domain and the availability and 

completeness of the record.
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7.2.6 Modeling Results

The maximum Class I area estimated NO2 and PM10/PM2.5 impacts from the proposed exploratory 

drilling emissions are provided in Table 7-2. The PM10 modeling results were conservatively assumed 

for PM2.5. The accepted PSD Class I significant impact levels (SIL) are also provided in this table. The 

maximum modeled concentrations associated with the proposed project emissions are much less than the 

SIL. Therefore, the project is not considered to have significant impacts on the PSD Class I increments.

The CALPUFF estimates of deposition of acid-forming compounds from the project‟s emissions are 

provided in Table 7-3. This table also contains the Federal Land Manager accepted Deposition Analysis 

Thresholds (DAT) established for areas east of the Mississippi. The DAT is defined as the additional 

amount of nitrogen or sulfur deposition within a PSD Class I area below which estimated project 

impacts are considered negligible. See Federal Land Manager‟s Air Quality Related Values Workgroup, 

Phase I Report (Revised June 2008). The estimated project deposition rates are much less than the DAT. 

Therefore, the project associated Class I area deposition should be negligible. 

Because of the lack of a model to assess single source ozone impacts at Bradwell Bay Wilderness and 

the fact that these PSD Class I areas are considered NOX limited for the formation of ozone, the Federal 

Land Manager accepts the deposition assessment as a surrogate for the assessment of ozone impacts to 

vegetation. The above deposition assessment shows impact less than the DAT. Hence, this also

demonstrates the project‟s emissions are not expected to cause significant ozone impacts at Bradwell 

Bay Wilderness. The above Class I area NO2 increment assessment revealing impacts less than the SIL 

provide additional assurance that the project will not cause significant ozone impacts. 

The visibility parameter of concern at Breton and St. Marks NWR is regional haze. The project‟s 

contribution to regional haze is addressed as the 24-hour change in extinction. The Federal Land 

Manager considers a five percent change in extinction to be just perceptible. The Federal Land 

Managers accepted procedures were used to provide estimates of the change in extinction associated 

with project emissions. The CALPUFF post-processor CALPOST performs the two accepted 

procedures, known as Method 2 and Method 8. Method 8 is the updated approved method employing the 

IMPROVE extinction equation using monthly relative humidity adjustment factors, annual background 

aerosol concentrations, and 98th percentile modeled values at each receptor. 

The Method 2-estimated project associated changes in visibility extinction resulted in a number of days 

with more than 5 percent change in extinction for both Breton (average 31 days/year) and St. Marks 

(average 5 days/year) NWR. The Method 8 estimates of project associated changes in visibility 

extinction provide further information for the evaluation of visibility impacts. On a daily basis the 

project‟s emissions resulted in no days exceeding 5 percent change in extinction. Table 7-4 provides a 

summary of the results of the Method 2 and Method 8 modeling analyses. This table reveals the Method 

8 98th percentile values are less than the target 5 percent change in extinction.
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Table 7-2: BHPB Maximum Modeled Class 1 Increment Concentrations (ug/m3)

PSD Class I Area Parameter Class I 

Modeling

Significance 

Level

(ug/m3)

Year

2001 2002 2003

Breton NWR

NO2 – Annual 0.1 0.0129 0.0223 0.0184

PM10/PM2.5 – 24 hour 0.3/0.07 0.0356 0.0348 0.0498

PM10/PM2.5 - Annual 0.2/0.06 0.0016 0.0026 0.0031

St. Marks NWR 

and Bradwell Bay 

Wilderness*

NO2 – Annual 0.1 0.0048 0.0018 0.0042

PM10/PM2.5 – 24 hour 0.3/0.07 0.0117 0.0197 0.0171

PM10/PM2.5 - Annual 0.2/0.06 0.0007 0.0006 0.0009

* Because St. Marks NWR and Bradwell Bay Wilderness are within 2 km of each other and more than 200 km distance 

from the proposed project, they were modeled together by including all receptors form both areas. Therefore, the 

maximum concentration provided is the worst-case concentration for both Class I areas.

Table 7-3: BHPB Estimated Class I Area Deposition Fluxes (kg/ha/yr)

PSD Class I 

Area

Parameter Class I 

DAT 

Year

2001 2002 2003

Breton NWR Nitrogen 0.01 0.00361 0.00713 0.00628

Sulfur 0.01 0.000010 0.000022 0.000018

St. Marks NWR 

and Bradwell 

Bay Wilderness*

Nitrogen 0.01 0.00311 0.00296 0.00457

Sulfur 0.01 0.000005 0.000005 0.000008

* Because St. Marks NWR and Bradwell Bay Wilderness are within 2 km of each other and more than 200 km distance 

from the proposed project, they were modeled together by including all receptors form both areas. Therefore, the 

maximum concentration provided is the worst-case deposition for both Class I areas.

Table 7-4: Summary of BHPB

Estimated Change in Extinction for PSD Class I Areas

PSD Class I 

Area

Method Parameter Year

2001 2002 2003

Breton NWR Method 

2

Highest Value (%) 40.51 28.41 33.81

Number Days > 5% 

Change

26 38 29

Number Days > 10% 

Change

13 12 12

Method 

8

98th Percentile Highest 

Value (%)

4.94 3.37 3.54

Number Days > 5% 

Change

0 0 0

Number Days > 10% 

Change

0 0 0

St. Marks NWR Method 

2

Highest Value (%) 9.84 27.04 17.24

Number Days > 5% 

Change

7 3 5

Number Days > 10% 

Change

0 2 1
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Method 

8

98th Percentile Highest 

Value (%)

1.44 0.82 1.53

Number Days > 5% 

Change

0 0 0

Number Days > 10% 

Change

0 0 0

7.3 Conclusions

Because the draft permit limits BHPB‟s exploratory drilling project in the Desoto Canyon lease blocks 

to no more than 2 years, the project qualifies as a temporary emissions source for purposes of PSD 

permitting. The CALPUFF impact modeling for the closest PSD Class I areas of Breton National 

Wildlife Refuge, St. Marks National Wildlife Refuge, and Bradwell Bay Wilderness demonstrated 

impacts less than the PSD Class I area significant impact levels for all areas and proposed project PSD 

pollutants. The AQRV impact modeling assessment of sulfur and nitrogen deposition demonstrates 

impacts that are less than the Federal Land Manager Deposition Analysis Thresholds for all areas. This 

deposition result, combined with the less than significant NO2 impacts, indicates no significant project 

caused ozone impacts at Bradwell Bay Wilderness. Finally, the project‟s estimated impact on Class I 

area regional haze visibility demonstrated impact within the Federal Land Manager‟s acceptable 

perceptibly level at both Breton and St. Marks National Wilderness Areas. The reported evaluations 

from both the U.S Fish and Wildlife Service, and U.S. Forest Service support these conclusions. 

Therefore, the estimated maximum emissions from the proposed drilling activities are not expected to 

significantly impact any PSD Class I area. 

8.0 Additional Requirements

8.1 Endangered Species Act and Essential Fish Habitat of Magnuson-Stevens Act

Section 7(a)(2) of the Endangered Species Act (ESA) requires federal agencies, in consultation with the 

National Oceanic and Atmospheric Administration (NOAA) Fisheries Service and/or the U.S. Fish and 

Wildlife Service (collectively, “the Services”), to ensure that any action authorized, funded, or carried 

out by the agency is not likely to jeopardize the continued existence of a species listed as threatened or 

endangered, or result in the destruction or adverse modification of designated critical habitat of such 

species. See 16 U.S.C. §1536(a)(2); see also 50 CFR §§ 402.13 and 402.14. The federal agency is also 

required to confer with the Services on any action which is likely to jeopardize the continued existence 

of a species proposed for listing as threatened or endangered or which will result in the destruction or 

adverse modification of critical habitat proposed to be designated for such species. See

16 U.S.C. §1536(a)(4); see also 50 CFR 402.10. Further, the ESA regulations provide that where more 

than one federal agency is involved in an action, the consultation requirements may be fulfilled by a 

designated lead agency on behalf of itself and the other involved agencies. See 50 CFR § 402.07. 

Section 305(b)(2) of the Magnuson-Stevens Fishery Conservation and Management Act (MSA) requires 

federal agencies to consult with NOAA with respect to any action authorized, funded, or undertaken by 

the agency that may adversely affect any essential fish habitat identified under the MSA. The Bureau of 

Ocean Energy Management (BOEM) of the Department of the Interior is the lead federal agency for 

authorizing oil and gas exploration activities on the OCS. Therefore, BOEM served as the lead agency 

for ESA section 7 and MSA compliance for BHPB‟s exploration activities. In accordance with section 7 

of the ESA, BOEM consults prior to a lease sale with NOAA Fisheries and FWS to ensure that a sale 
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proposal will not cause any protected species to be jeopardized by oil and gas activities on a lease. In 

addition, BOEM requests annual concurrence from the Services to ensure current activities remain 

consistent with the terms and conditions of the Biological Opinion issued for the lease sale activities.

Since the BOEM consultations address the same exploratory drilling activities authorized by the air 

permit that the EPA is issuing to BHPB, EPA relied in part on those conclusions for our preliminary 

determination. Based upon the best available data and informal consultation with the Services, EPA 

determined that the issuance of this OCS permit to BHPB for exploratory drilling is not likely to cause 

any adverse effects on listed species and essential fish habitats beyond those already identified, 

considered and addressed in the prior consultations. The proposed OCS permit includes a condition 

requiring BHPB to comply with all other applicable federal regulations. EPA received concurrence from 

the Fish and Wildlife Service that our section 7 ESA consultation requirements were met on August 12, 

2010. This letter is included in the administrative record described in Section 9.3 of this document.

8.2 National Historic Preservation Act

Section 106 of the National Historic Preservation Act (NHPA) requires federal agencies to take into 

account the effects of their undertakings on historic properties. Section 106 requires the lead agency 

official to ensure that any federally funded, permitted, or licensed undertaking will have no effect on 

historic properties that are on or may be eligible for the National Register of Historic Places. The BOEM 

is the lead agency permitting BHPB activity in the DeSoto Canyon lease blocks 499, 543-545, 586-592, 

631-640, 676-685, 721-729, 768-773, and 815-817. The environmental effects of lease block sale were 

analyzed in a multi-sale Environmental Impact Statement, covering sales in 2007 through 2012 which is 

accessible on the web at http://www.gomr.boemre.gov/PDFs/2007/2007-018-Vol1.pdf.

BOEM typically conducts section 106 consultation at the pre-lease stage by prior agreement with the 

Advisory Counsel for Historic Preservation rather than at the individual post-lease permit level. In order 

to reach a Finding of No Significant Impact, mitigation is carried out at the post-lease plan level by 

requiring remote sensing survey of the seafloor in areas considered to have a high probability for 

archaeological resources. At the time this lease was sold, was not considered to have a high probability 

for containing archaeological remains such as a shipwreck. Any cultural resources discovered during 

that inspection are required by regulation to be reported to BOEM with 72 hours. No significant 

archaeological properties are anticipated in this location, but should anything be discovered there as a 

result of the operator's investigations, BOEM would enter into consultation with the State Historic 

Preservation Office and the Advisory Counsel for Historic Preservation.

8.3 Executive Order 12898 – Environmental Justice

Executive Order 12898, entitled “Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations,” directs federal agencies, including EPA, to the extent 

practicable and permitted by law, to identify and address, as appropriate, disproportionately high and 

adverse human health or environmental effects of regulatory programs, policies, and activities on 

minority populations or low-income populations. See Executive Order 12898, 59 Fed. Reg. 7629 

(February 11, 1994). Consistent with Executive Order 12898 and the EPA‟s environmental justice 

policy (OEJ 7/24/09), in making decisions regarding permits, such as OCS permits, the EPA gives 

appropriate consideration to environmental justice issues on a case-by-case basis, focusing on whether 

its action would have disproportionately high and adverse human health or environmental effects on 

minority or low-income populations.
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The EPA has concluded that this proposed OCS air permitting action for BHPB‟s exploratory drilling 

operation on the Gulf of Mexico would not have a disproportionately high adverse human health or 

environmental effects on minority or low-income populations. The drill site is located approximately 

120 miles southeast of the nearest Louisiana shoreline, 139 miles south southeast of the nearest 

Mississippi shoreline, and 125 miles south of the nearest Alabama and Florida shorelines. The EPA is 

not aware of any minority or low-income population that that may frequently use the area for 

recreational or commercial reasons. In addition, the project‟s emissions impacts will be dispersed over a 

wide area with no elevated concentration levels affecting any onshore populated area. Finally, given the 

project‟s temporary nature, it will have a minimal air impact on all populations. See Section 7.0 of this 

document pertaining to air quality impact.

9.0 Public Participation

9.1 Opportunity for Public Comment

These proceedings are subject to the EPA procedures for decision making, set forth at 40 CFR part 124. 

As provided in part 124, the EPA is seeking public comment on the BHPB OCS air permit OCS-EPAR4008 during the public comment period as specified in the public notice. Public notice is also being

issued as required under 40 CFR § 55.7 and 40 CFR § 71.

Any interested person may submit written comments on the draft permit during the public comment 

period. If you believe any condition of the permit is inappropriate, you must raise all reasonably 

ascertainable issues and submit all reasonably available arguments supporting your position by the end 

of the comment period. Any documents supporting your comments must be included in full and may not 

be incorporated by reference unless they are already part of the record for this permit or consist of state 

or federal statutes or regulations, EPA documents of general applicability, or other generally available 

referenced materials. 

Comments should focus on the proposed air quality permit, the permit terms, and the air quality aspects 

of the project. The objective of the OCS air quality program, including the PSD program to which this 

source is subject, is to prevent significant adverse environmental impact from air emissions by a new or 

modified OCS source. If you have more general concerns regarding non-air quality impacts, such as 

offshore leasing, drilling safety, discharge, etc., these should be addressed during the leasing and 

permitting proceedings of the BOEM, which is the lead approval agency for this project.

All timely comments will be considered in making the final decision, included in the record, and 

responded to by the EPA. The EPA may group similar comments together in our response, and will not 

respond to individual commenters directly. 

All comments on the draft permit must be received by email or postmarked by May 7, 2012. Requests 

for a Public Hearing (see below) must be received by email or mail by April 20, 2012. An extension of 

the 30-day comment period may be granted if the request for an extension adequately demonstrates why 

additional time is required to prepare comments. Comments can be sent or delivered in writing to the 

address below or submitted electronically via www.regulations.gov, which can be accessed through the 

EPA Region 4 website listed in Section 9.2 below. All comments will be included in the public docket 

without change and may be made available to the public, including any personal information provided, 

unless the comment includes Confidential Business Information or other information in which disclosure 

is restricted by statute. Information that you consider Confidential Business Information or otherwise 
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protected should be clearly identified as such and should not be submitted through e-mail. If you send email directly to the EPA, your email address will be captured automatically and included as part of the 

public comment. Please note that an e-mail or postal address must be provided with your comments if 

you wish to receive direct notification of the EPA‟s final decision regarding the permit and the EPA‟s 

response to comments submitted during the public comment period. For questions on the draft permit, 

please contact: Mr. Andrew Porter at 404-562-9184 or porter.andrew@epa.gov.

Submit comments on the draft permit and requests for a public hearing to:

EPA Region 4, APTMD

61 Forsyth Street, SW

Atlanta, GA 30303

ATTN: Andrew Porter

Fax: (404) 562-9019

Email: R4OCSpermits@epa.gov

9.2 Public Hearing 

EPA has discretion to hold a public hearing if we determine there is significant public interest in the 

draft permit. Requests for a public hearing must be received by EPA by email or mail by April 20, 2012, 

at the address given above, and state the nature of the issues proposed to be raised in the hearing. You 

may submit oral or written comments on the draft permit at the public hearing. You do not need to 

attend the public hearing to submit written comments. If there is significant public interest, EPA will 

hold a public hearing on the draft OCS permit on May 3, 2012, at the location given in the public notice. 

If no timely request for a public hearing is received, or EPA determines that there is not significant 

interest, the hearing will be cancelled. An announcement of cancellation will be posted on the EPA‟s 

website at: http://www.epa.gov/region4/air/permits/ocspermits/ocspermits.html, or you may call EPA at 

the contact number above to determine if the public hearing will be held.

9.3 Administrative Record

The administrative record contains the application, supplemental information submitted by BHPB, and 

correspondence, including e-mails, between BHPB and its consultants, and EPA clarifying various 

aspects of BHPB‟s application. The draft permit and the administrative record are available for public 

review on EPA‟s website at http://www.epa.gov/region4/air/permits/ocspermits/ocspermits.html and at 

the EPA Region 4 office at the addresses listed below. Please call in advance for available viewing 

times.

EPA Region 4 Office

61 Forsyth Street, SW

Atlanta, GA 30303

Phone: (404) 562-9643

To request a copy of the draft permit, preliminary determination or notice of the final permit action, 

please contact: Ms. Rosa Yarbrough, Permit Support Specialist at (404) 562-9643 or 

R4OCSpermits@epa.gov.
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9.4 Final Determination

A final decision to issue a final permit, or to deny the application for the permit, shall be made after all 

timely comments have been considered. Notice of the final decision shall be sent to each person who has 

submitted written comments or requested notice of the final permit decision, provided the EPA has 

adequate contact information.