03/30 /2012 BHPB PD OCS

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## UNITED STATES ENVIRONMENTAL PROTECTION AGENCY Region 4 Atlanta, Georgia

Preliminary Determination & Statement of Bas is Outer Continental Shelf Air Permit OCS

- EPA

- R40 08 for

BHP Billiton Petroleum, Inc. Sake Prospect Drilling Project

March 30, 2012i

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### 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 P ollutants (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

................................ ................................ ............................... 3 8 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 Administra tive Record

................................ ................................ ................................ .................... 45 9.4 Final Determination

................................ ................................ ................................ ........................ 46ii

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- R4008 ABBREVIATIONS AND ACRONYMS

AP

- 42 AP

- 42 Compilation of Air Pollutant Emissions Factors AQRV Air Quality Related Values BACT Best A vailable C ontrol T echnology BHPB BHP Billiton Petroleum BOEM Bureau of Ocean Energy Management Breton NWR Breton National Wildlife Refuge B tu British thermal unit CAA Clean Air Act CFR Code of Federal Regulations CO Carbon monoxide CO 2 Carbon Dioxide CO 2 e Carbon dioxide (CO 2 ) 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 NO 2 Nitrogen dioxide NOAA National Oceanic and Atmospheric Administration NO X 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 PM 2.5 Particulate matter with an aerodynamic diameter less than 2.5 microns PM 10 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 SO 2 Sulfur dioxide Support Vessels Work Boat, Supply Boat, and Crew Boat TPY tons per year TVP true vapor pressure VOC Volatile organic compound s1

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## 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 Protecti on Agency (EPA) Region 4 for the proposed mobilization and operation of a deepwater drilling vessel and associated support vessel s 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 dri lling vessels, either the C.R. Luigs for Operating Scenario 1 or the Development Driller 1 ( DD1 ) f or 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 G ulf 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

- R4 00 8
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 (NESH AP), 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 requirem ents, 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 S ee 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 Prel iminary 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)

.2

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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 drill ing 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 latitude s 28.15° to 28.50° N and longitude s 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 Missis sippi shoreline, and 125 miles south of the nearest Alabama and Florida shorelines as illustrated below in Figure 2

- 1

.

Figure 2

- 1 : Site Location 3

3 Site loca tion map supplied by BHPB in their application as Figure 1

- 2 on page 1

- 5.3

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- R4008 Figure 2

- 2 : BHPB’s Lease Blocks 4



## 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 app licable permitting regulations, qualifies as a “temporary source” for PSD permitting purposes

. Air pollutant emissions generated from the Sake Project include carbon mono xide (CO), nitrogen dioxide (NO 2 ) ; particulate matter (PM) which includes particulate matter with an aerodynamic diameter less than 10 microns (PM 10 ) and with an aerodynamic diameter less than 2.5 microns (PM 2.5 ) ; and sulfur dioxide (SO 2 ) (known as criteria pollutants), as well as other regulated air pollutants, including oxides of nitrogen (NO X ), volatile organic compounds (VOC), and greenhouse gases (GHGs). VOC and NO X are the measured precursors for the criteria pollutant ozone, and NO X and SO 2 are measured precursors for the criteria pollutant PM 2.5
. 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. D iesel engines are used to run crane s , a black start compressor, cementing operations, wireline units

,

4 Lease block map supplied by BHPB in their application as Figure 1

- 1 on page 1

- 4.4

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- R4008 and support vessels operating within 25 miles of the MODU . The emergency generator, life boats, and the fast rescue craft are also p owered by diesel engines and are routinely operated for testing and mainten an ce , releasing additional emissions . In addition

, there are PM/ PM 10 / PM 2.5 e missions from the mud and cement dust collectors

. VOC and GHG e missions are released from a mud degas sing unit and the storage tanks used to store diesel fuel, hydraulic oil, base oil, and jet A helifuel.

Based on emissions estimates, the Sake P roject has the potential to emit the regulated NSR pollutants CO, NO X , PM/ PM 10 / PM 2.5 , 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 sub sequent regulatory obligations that apply

.
3.1 Operating Scenario 1

T he 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 requi re towing or anchoring vessels. T he 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, a nd 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 an d 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 . T he 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 unit s are temporary installations that are brought onto the MODU for specific operations. Engi ne 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 Ve ssel Operations

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

. The

s pecific 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.5

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- R4008 To calculate annual emissions

, BHPB estimated the total comb ined 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 en gine rating. BHPB reviewed available crew boats and determined the Fast Skipper crew boat had the worst case emissions based on engine rating. T hese wors t case support vessels were then used to calculate support vessel emissions in conjunction with Air Pol lutant 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 dis cussed in Sec t i on 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
S ection 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 Regulation s
The OCS Air Regulations at 40 CFR part 55 implement s ection 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 C FR § 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.6

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- R4008 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 C FR §§ 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 appl y 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 s ection 112 of the CAA if rationally related to the attainment and maintenance of federal and state ambient air quality standards or the req uirements 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 BH PB ‟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 inspectio ns 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 th e 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 A ir 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 li mits 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 deter mined 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 cri teria, 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 em it 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 o f 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 d efines the term similarly and provides that:7

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- R4008 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 t he 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 55.1 4 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 emissi on 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, a ll 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 ai r pollutant defined in 40 CFR 52.21(b)(49)(i) as the aggregate group of the following six gases:

Carbon dioxide (CO 2 ); Nitrous oxide (N 2 O); Methane (CH 4 ); Hydrofluorocarbons (HFCs); Perfluorocarbons (PFCs); and Sulfur hexafluoride (SF 6 ).

Due to the natu re 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 thre shold for, the source based on CO 2 equivalent (CO 2 e) 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 CO 2 e 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 em issions.

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 tha n or equal to 75,000 TPY on a CO 2 e 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 CO 2 e basis and equal to or greater than 100/250 TPY on a mass basis.8

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- R4008 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 PM 10 41.15 34.94 15 Yes PM 2.5 40.16 33.96 10 Yes NO X a 1

, 699.60 1

, 306.04 40 Yes SO 2 b 0.91 0.88 40 No H 2 SO 4 0.03 0.03 7 No CO 373.69 308.53 100 Yes VOC c 81.61 74.36 40 Yes
GHGs (CO 2 e) 101,574.72 97,503.61 75,000 (subject to regulation threshold) Yes

Lead 0.02 0.02 0.60 No

a NO X is a measured pollutant for the criteria pollutants ozone and NO 2 and a precursor for PM 2.5 . b SO 2 is a precursor for the criteria pollutant PM 2.5 . 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 sou rce because emissions of NO X (under either operating scenario) exceed the major source applicability threshold of 250 TPY and, thus, is subject to PSD review for NO X (both as the measured pollutant for NO 2 and ozone and as a precursor to PM 2.5 ) and CO. PSD review also applies to PM, PM 10 , PM 2.5 , 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

a nalysis 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 t itle 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 NO X and CO, it is considered a major source under title V and part 71. An OCS source must apply for an opera ting 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 C FR 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 n ecessary 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 moni toring, recordkeeping and reporting requirements.9

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- R4008 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 regulat ions 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 c ommenced 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 engine s on C.R. Luigs and DD1 meet the above criteria. T he 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 C FR part 89).

Table 4

- 2: C.R. Luigs Engine Specifications Emissions Unit ID Description Manufacturer Model # Rating a ( 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

- 018 b Cementing Nitrogen Pump

Engine

EU

- 019 b POSU

- CA Primary Unit Engine/

Hydraulic Generator Combination

EU

- 020 b Wireline Unit Alternative #2

Engine FMCC Unit Type Two

EU

- 022 b Wireline Unit

– Power Plant

GSU

- W Generator

EU

- 023 b 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.10

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- R4008 Table 4

- 3: DD1 Engine Specifications Emissions Unit ID Description Manufacturer Model # Rating a ( 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

- 014 b Cementing Nitrogen Pump

Engine EU

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

EU

- 016 b POSU

- CA Primary Unit Engine/

Hydraulic Generator Combination

EU

- 017 b Wireline Unit Alternative #2

Engine FMCC Unit Type Two

EU

- 019 b Wireline Unit

– Power Plant

GSU

- W Generator

EU

- 020 b 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 J uly 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

T he 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.11

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- R4008 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 Descrip tion 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

T he 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 (m 3 ) 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 m 3 storing 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 m 3 but less than 151 m 3 storing a liquid with a maximum true vapor pressure less than 15.0 kPa. As Tables 4

- 6 and 4

- 7 show, none of the sto rage 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 m 3

.

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 2.2712

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- R4008 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 s ection 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 regulatio ns 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 s ection 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 s ection 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 H azardous A ir P ollutant ( HAP ) or 25 tons per year or more of all HAP s combined. See s ection 112(a)(1) and 40 CFR § 63.2. An “area source” is any source that is not a major source as defined in s ection 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 proje ct an area source of HAP s 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, the13

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- R4008 portable engines on C.R. Luigs and DD1 will be subpart IIII

- compliant and, thus

, no additional requirements apply under subpart ZZZZ

. T herefore, 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

- 0 01 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 u sing 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 emis sions factors

, EPA‟s TANKS 4.09d
program, and a 2005 Department of Interior emissions inventory study

. The total projected em issions for each operating scenario include emissions based on estimations of the wors t 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 Table s 5

- 1 and 5

- 2 below

.

Table 5

- 1 : Potential to Emit Emissions

– C.R. Luigs Operating Scenario 1

Emission Source PM

(TPY) PM 10

(TPY) PM 2.5

(TPY) NO X

(TPY) SO 2

(TPY) H 2 SO 4

(TPY) CO

(TPY) Total

VOC (TPY) Lead

(TPY) GHGs

(CO 2 e) (TPY)
Main Diesel Engines (8) 46.91 26.88 26.08 1,318.80 0.71 0.02 262.89 4 42.89 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 Craf

t 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

Cement ing 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 Collector s ( 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 9.44 E

- 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 Total s: 66.02 41. 15 40. 16 1 , 699.6 0. 91 0.03 373.69 81.61 0.02 101,574.714

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- R4008

Table 5

- 2 : Potential to Emit Emissions

– DD1 Operating Scenario 2

Emission Source PM

(TPY) PM 10

(TPY) PM 2.5

(TPY) NO X

(TPY) SO 2

(TPY) H 2 SO 4

(TPY) CO (TPY) Total

VOC (TPY) Lead

(TPY) GHGs

(CO 2 e) (TPY)
Main Diesel Engines (8) 46.26 26.50 25.72 1

, 007.02 0. 70 0.02 215.09 42.39 1. 34 E

- 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 Craf

t Engine (1) 3.91 E

- 03 3.91E

- 03 3.91E

- 03 5.50 E

- 02 1.88 E

- 05 5.87E

- 07 0.01 4.46 E

- 03 3.06 E

- 07 2.05 Cementing Unit Engines (4) 0. 41 0.2 5 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 engine s 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 ( SO 2 ) and sulfuric acid ( H 2 SO 4 ) 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 SO 2 formation during diesel fuel combustion, with the other 2% of the sulfur assumed to be converted to sulfuric acid ( H 2 SO 4 ). The H 2 SO 4 emissions

were assumed to condense to form total reduced sulfur (TRS) particulate matter, primarily as sulfate s in the atmosphere. Since the total amount of H 2 SO 4 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 fou r 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 a ll pollutants except NO X and CO were calculated using AP

- 42 emission factors and brake horsepower. NO X and CO were calculated based on stack test data included i n the February 201 1 application addendum.15

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- R4008 5.2 C.R. Luigs (Operating Scenario 1) Smaller Emissio n 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 Cater pillar 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/ PM 10 / PM 2.5 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 E U

- 01 7 : Cementing Units 1

- 2 C ementing units 1 and 2 are each powered by a n 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 eng ine.

EU

- 01 8 through EU

- 023: Cementing Nitrogen Pump , Wireline Units POSU

- CA Primary, Alt 2, Power P lant GSU

- W, and Hydraulic DHPS The se units are po r table and brought on the MODU as needed by a third party supplier. The exact engine available for use during the project ha d 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 Mot o rs 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 opera ting at 100% load for a maximum of 25 hours per
year.

EU

- 0 62 through EU

- 091 : Fuel, Oil, and Hydraulic Fluid Tanks Emissions are generated from the storage of diesel fuel, base o il, hydraulic fluid, and Jet A helicopter16

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- R4008 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 NO X and CO were calculated using AP

- 42 emission factors and brake horsepower. NO X and CO were calculated based on stack test data included in the February 201 1 application addendum.

5.4 DD1 (Operating Scenario 2 ) Smaller Emission Unit Analysis

The following is a description of the smaller emis sion 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/ PM 10 / PM 2.5 maximum hourly emission rate each was calculated based on a flow rat e 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

- 01 3, EU

- 15 : Cementing Units 1

- 2 and Batch Mixer T h e 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 a n 860 hp Cater pillar 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 P lant GSU

- W, and Hydraulic DHPS The se units are po r table and brought on the MODU as needed by a third party supplier. The exact engine available for use during the project ha d not been identified at the time of the application submittal . The worse case engine listed below was chosen to calculate emissio n 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 75017

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- R4008 hours per year per 300 hp engine, 1,700 hours per year for one 160 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 Mot o rs 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 Ste yr 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

- 0 26 through EU

- 047, EU

- 0 50 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 MOD U 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 boa ts 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) generator s , 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 bra ke 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 ad ding 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 a18

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- EPA

- R4008 requirement does not apply. However, the EPA unde rstands 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 NO X 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 requi rements 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 pri or written approval by the EPA.

The compliance d emonstration 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 moni toring requirements.

The c ompliance 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, gallo ns 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 c alculations 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 invento ry for the project, presented in Table 4

- 1 of the preliminary determination, NO X , CO, VOC, GHGs, and PM/PM 10 /PM 2.5 are the CAA

- regulated pollutants that will be emitted by BHPB in quantities exceeding the respective significant emission rate. Therefore, BA CT 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, an d 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 emiss ions allowed by any19

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- R4008 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 emi ssions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of bes t available control technology. The CAA contains a similar BACT def inition, 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 infe asible 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 summar y 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)

ce menting 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 th rough

- 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 no t 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.20

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- R4008 6.1.1 NO X BACT Analysis for Internal Com bustion Engines

NO X emissions are generated as both a result of high temperature combustion (thermal NO X ) and oxidation of nitrogen present in the fuel (fuel

- bound NO X ). Thermal NO X emissions increase with an increase in combustion temperature, and are ge nerally the main cause of NO X 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 appli cation 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 NO X emissions:

9. Newer/Cleaner Engines 10. De

- rating of Existing Engines 11. Wat er

- in

- Fuel Emulsions 12. NO X Absorber/Scrubber Technology 13. CSNO X Emission Abatement System 14. Camshaft Replacement/Retooling of Engines 15. Lean De

- NO X 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 NO X emissions from all diesel internal combustion engines ( o ptions 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 info rmation 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 SINO X 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).21

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- R4008 4

- Wa y 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

c atalyst 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 op erations. 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 fres hwater 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 engi nes onboard C.R. Luigs (EU

- 001 through

- 008) since, to match the available power output of the existing 8 engines, a n additional engine of the new/cleaner model would be required. T here is no available space for 9 main engine s 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 gener ator 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 des igned specifically for heavy density fuel applications; therefore, it is not technically feasible.

NO X Absorber/Scrubber Technology: This option is currently in development for application to diesel engines; therefore, it is not technically feasible for t he engines aboard C.R. Luigs and DD1

.

CSNO X 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 ha s 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

.22

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- R4008 Lean De

- N O X 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 SINO X syste m) 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 NO X removed (from $19,283 per ton calculat ed 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 . H owever, engine replacement was determined to be cost prohibitive for the remaining engines based on the relatively small potential reductions in NO X 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

.

T he 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 NO X emissions measurement program. The applicant and Transocean refer to this sys tem 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 NO X concentration measurement program will trigger an alarm if the NO X 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 m onitor PM/PM 10 /PM 2.5 , CO, VOCs, and CO 2
. 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 engine s . 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 201 0 contain s 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); th us , the main engines of C.R. Luigs (EU

- 001 through

- 008) h ave never been issued emission certificates . Therefore, the NO X 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, cor rected 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 signific ant load variations required by the operations on the vessel , EPA has determined an averaging period of 24 hours is appropriate in this case.23

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- R4008 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 200 0 NO X Technical Code (Regulation 13). At engine speeds of 900 rpm, the engines on the DD1 were designed to meet a NO X emission limit of 11.5 g/kW

- hr operating at engine test bed conditions, which can vary sign ificantly 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 summa rizes EPA‟s BACT determinations for the diesel internal combustion engines with respect to NO X emissions. The respective emission limits are based on stack test data, vendor data, Tier certification, or AP

- 42.

Table 6

- 1: NO X BACT Conclusion Emissions Unit ID BACT Control Options NO X BACT Limits * Vessel: C.R. Luigs EU

- 001 through

- 008 Turbocharger and a ftercooler,

HPFI w/ a ftercooler, and g ood

c ombustion p ractices 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 a ftercooler,

HPFI w/ a ftercooler, and g ood

c ombustion p ractices 3.10 x 10 - 2 lb/hp

- hr (18.8 g/kW

- hr) 82.83 tons per year

4300 hours of operation each EU

- 015 Turbocharger and a ftercooler,

HPFI w/ a ftercooler, and g ood

c ombustion p ractices 2.40 x 10 - 2 lb/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) m arine

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 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) EU

- 018 EPA Tier 1 (or better) n on

- r oad

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 1.51 x 10 - 2 lb/hp

- hr (9.18 g/kW

- hr)

EU

- 019 and

- 020 EPA Tier 3 (or better) n on

- r oad

e ngine

, t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 6.58 x 10 - 3 lb/hp

- hr (4.00 g/kW

- hr) 8.92 tons per year

750 hours of operation each (EU

- 019 and

- 020) 1700 hours of oper ation (EU

- 022) 1300 hours of operation (EU

- 023) EU

- 022 and

- 023 EPA Tier 2 (or better) n on

- r oad

e ngine

, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 1.09 x 10 - 2 lb/hp

- hr (6.63 g/kW

- hr)

EU

- 092 Good c ombustion p ractices 3.10 x 10 - 2 lb/hp

- hr (18.8 g/kW

- hr) Vessel: DD1 EU

- 001 through

- 008 Turbocharger and a ftercooler,

HPFI w/ a ftercooler, and g ood

c ombustion p ractices with use of DEWT measurement system 12.1 g/kW

- hr ( 8.10 g/kW

- hr, corrected to 95% NO)24

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- R4008 EU

- 011 Turbocharger and a ftercooler,

HPFI w/ a ftercooler, and g ood

c ombustion p ractices 2.40 x 10 - 2 lb/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) m arine

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 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 and

- 015) EU

- 014 EPA Tier 1 (or better) n on

- r oad

e ngine , t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 1.51 x 10 - 2 lb/hp

- hr (9.18 g/kW

- hr)

EU

- 015 EPA Tier 2 (or better) n on

- r oad

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 1.09 x 10 - 2 lb/hp

- hr (6.63 g/kW

- hr)

EU

- 016 and

- 017 EPA Tier 3 (or better) n on

- r oad

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 6.58 x 10 - 3 lb/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) n on

- r oad

e ngine , t urbocharger and

a ftercooler, HPFI w/ a ftercooler, and g ood c ombustion p ractices 1.09 x 10 - 2 lb/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 bas ed 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 (CO 2 ) occurs when the combustion process maintains sufficient temperature, residence time, and oxygen sup ply. 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 n ot 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 submi tted 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 Crank case Ventilation (PCV) (for VOCs only) 5. Good Combustion Practices 6. Fuel Injection Timing Retard25

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- R4008 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 a dditional 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 wer e eliminated as technically infeasible for all diesel internal combustion engines ( o ptions 1 through 3 and 6). O ption 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 ), an d 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 availa ble 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 ) b ecause 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 pro hibitive 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 a ll of the engines aboard C.R. Luigs and DD1 . Tables 6

- 2 and 6

- 3 below summarize EPA‟s BACT determinations for the26

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- 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/ a ftercooler and g ood

c ombustion p ractices with use of DEWT measurement system 2.42 g/kW

- hr

EU

- 009 through

- 012 HPFI w/ a ftercooler and g ood

c ombustion p ractices 6.68 x 10 - 3 lb/hp

- hr (4.06 g/kW

- hr) 17.85 tons per year

4,380 hours of operation e ach

EU

- 015 HPFI w/ a ftercooler and g ood

c ombustion p ractices 5.50 x 10 - 3 lb/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) m arine

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 5.50 x 10 - 3 lb/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) n on

- r oad

e ngine, HPFI w/ a ftercooler and
g ood c ombustion p ractices 1.87 x 10 - 2 lb/hp

- hr (11.4 g/kW

- hr)

EU

- 019 and

- 020 EPA Tier 3 (or better) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 5.76 x 10 - 3 lb/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) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 5.76 x 10 - 3 lb/hp

- hr (3.50 g/kW

- hr)

EU

- 092 Good c ombustion p ractices 6.68 x 10 - 03 lb/hp

- hr (4.06 g/kW

- hr) Vessel: DD1 EU

- 001 through

- 008 HPFI w/ a ftercooler and g ood

c ombustion p ractices with use of DEWT measurement system 1.98 g/kW

- hr

EU

- 011 HPFI w/ a ftercooler and g ood

c ombustion p ractices 5.50 x 10 - 3 lb/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) m arine

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 5.50 x 10 - 3 lb/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) n on

- r oad

e ngine, HPFI w/ a ftercooler and
g ood c ombust ion p ractices 1.87 x 10 - 2 lb/hp

- hr (11.4 g/kW

- hr)

EU

- 015 EPA Tier 2 (or better) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 5.76 x 10 - 3 lb/hp

- hr (3.50 g/kW

- hr)

EU

- 016 and

- 017 EPA Tier 3 (or better) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 5.76 x 10 - 3 lb/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) n on

- r oad

e ngine , HPFI w/ a ftercooler, and 5.76 x 10 - 3 lb/hp

- hr (3.50 g/kW

- hr)27

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- R4008

g ood c ombustion p ractices 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/ a ftercooler, and

g ood c ombustion p ractices with use of DEWT measurement system 6.42 x 10 - 4 lb/hp

- hr (0.39 g/kW

- hr)

EU

- 009 through

- 012 PCV, HPFI w/ a ftercooler, and

g ood c ombustion p ractices 2.51 x 10 - 3 lb/hp

- hr (1.53 g/kW

- hr) 6.72 tons per year

4300 hours of operation each

EU

- 015 PCV, HPFI w/ a ftercooler, and

g ood c ombustion p ractices 6.42 x 10 - 4 lb/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) m arine

e ngine, CCV, HPFI w/ a ftercooler, and g ood c ombustion p ractices 6.42 x 10 - 4 lb/hp

- hr (0.39 g/kW

- hr) 0.38 ton per year

600 hours of operation each (EU

- 016 and

- 017) 100 h ours of operation (EU

- 018) EU

- 018 EPA Tier 1 (or better) n on

- r oad

e ngine, CCV, HPFI w/ a ftercooler, and g ood c ombustion p ractices 2.14 x 10 - 3 lb/hp

- hr (1.30 g/kW

- hr)

EU

- 019 and

- 020 EPA Tier 3 (or better) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 2.51 x 10 - 3 lb/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) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 2.51 x 10 - 3 lb/hp

- hr (1.53 g/kW

- hr)

EU

- 092 Good c ombustion p ractices 2.51 x 10 - 3 lb/hp

- hr (1.53 g/kW

- hr) Vessel: DD1 EU

- 001 through

- 008 PCV, HPFI w/ a ftercooler, and

g ood c ombustion p ractices with use of DEWT measurement system 6.42 x 10 - 4 lb/hp

- hr (0.39 g/kW

- hr)

EU

- 011 PCV, HPFI w/ a ftercooler, and

g ood c ombustion p ractices 6.42 x 10 - 4 lb/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) m arine

e ngine, CCV, HPFI w/ a ftercooler, and g ood c ombustion p ractices 6.42 x 10 - 4 lb/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) n on

- r oad

e ngine, CCV, HPFI w/ a ftercooler, and g ood c ombustion p ractices 2.14 x 10 - 3 lb/hp

- hr (1.30 g/kW

- hr)

EU

- 015 EPA Tier 2 (or better) n on

- r oad

e ngine, CCV, HPFI w/ a ftercooler, and g ood c ombustion p ractices 2.51 x 10 - 3 lb/hp

- hr (1.53 g/kW

- hr)

EU

- 016 and

- 017 EPA Tier 3 (or better) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 2.51 x 10 - 3 lb/hp

- hr (1.53 g/kW

- hr) 1.17 tons per year

750 hours of operation each (EU

- 016 and

- 017)28

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- R4008 EU

- 019 and

- 020 EPA Tier 2 (or better) n on

- r oad

e ngine, HPFI w/ a ftercooler, and
g ood c ombustion p ractices 2.51 x 10 - 3 lb/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/PM

10 /PM 2.5 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 majo rity of the PM emissions from stationary diesel engines are PM 2.5 ; therefore, BACT for PM/PM 10 /PM 2.5 is addressed concurrently since any control technology available for the control of PM 2.5 will also effectively control PM and PM 10
. 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 an alysis for PM/PM 10 /PM 2.5 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 1 2 control technology options for the control of PM/PM 10 /PM 2.5 emissions, five were eliminated as technically infeasible for all diesel internal combustion engines ( o ptions 1 through 4 and 6). O pt ion 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. Luig s 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 further29

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- R4008 consideration in the top

- do wn 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, respec tively.

Baghouse (Fabric Filter): This technology is large and generally used for land

- based sources. D ue to space constraints, there is no available space on the vessels for this option.

Diesel Oxidation Catalyst: This option is technically infeasible f or 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 safe ty 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 provid ed 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/PM 10 /PM 2.5 control for the same rationale provided in Section 6.1.1. Although CCV/P CV 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 remai ning 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/PM 10 /PM 2.5 emissions. The respective emission limi ts are based on vendor data, Tier certification, or AP

- 42.30

03/28/2012 PD OCS

- EPA

- R4008 Table 6

- 4: PM/PM 10 /PM 2.5 BACT Conclusions Emissions Unit ID BACT Control Options PM/PM 10 /PM 2.5 BACT Limits * Vessel: C.R. Luigs EU

- 001 through

- 008 Turbocharger and a ftercooler,

PCV, HPFI w/ a ftercooler, g ood

c ombustion p ractices with the use of DEWT measurement system

, and u ltra l ow s ulfur f

uel PM: 7.00 x 10 - 4 lb/hp

- hr (0.43 g/kW

- hr)

PM 10 : 4.01 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM 2.5 : 3.89 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr)

EU

- 009 through

- 012 Turbocharger and a ftercooler,

PCV, HPFI w/ a ftercooler, g ood

c ombustion p ractices, and u ltra l ow s ulfur f

uel 2.20 x 10 - 3 lb/hp

- hr (1.34 g/kW

- hr) 5.88 tons per year 4300 hours of operation each

EU

- 015 Turbocharger and a ftercooler,

PCV, HPFI w/ a ftercooler, g ood

c ombustion p ractices, and u ltra l ow s ulfur f

uel PM: 7.00 x 10 - 4 lb/hp

- hr (0.43 g/kW

- hr) PM 10 : 4.01 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM 2.5 : 3.89 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM: 0.04 ton per year PM 10 /PM 2.5 : 0.02 ton per year 60 hours of operation

EU

- 016 and

- 017 EPA Tier 1 (or better) m arine

e ngine, t urbocharger and

a ftercooler, CCV, HPFI w/

a ftercooler, g ood c ombustion
p ractices, and u ltra l ow s ulfur f uel PM: 7.00 x 10 - 4 lb/hp

- hr (0.43 g/kW

- hr) PM 10 : 4.01 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM 2.5 : 3.89 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM: 0.38 ton per year PM 10 : 0.23 ton per year PM 2.5 : 0.22 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) n on

- r oad

e ngine, t urbocharger and

a ftercooler, CCV, HPFI w/

a ftercooler, g ood c ombustion
p ractices, and u ltra l ow s ulfur f uel 8.88 x 10 - 4 lb/hp

- hr (0.54 g/kW

- hr)

EU

- 019 and

- 020 EPA Tier 3 (or better) n on

- r oad

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler,
g ood c ombustion p ractices, and

u ltra l ow s ulfur f

uel 3.29 x 10 - 4 lb/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) n on

- r oad

en gine, HPFI w/ a ftercooler, g ood

c ombustion p ractices, and u ltra l ow s ulfur f

uel 3.29 x 10 - 4 lb/hp

- hr (2.00 g/kW

- hr)

EU

- 092 Ultra l ow s ulfur f uel and g ood

c ombustion p ractices 2.20 x 10 - 3 lb/hp

- hr (1.34 g/kW

- hr)

Vessel: DD1 EU

- 001 through

- 008 Turbocharger and a ftercooler,

PCV, HPFI w/ a ftercooler, g ood

c ombustion p ractices with the use of DEWT measurement system

, and u ltra l ow s ulfur f

uel PM: 7.00 x 10 - 4 lb/hp

- hr (0.43 g/kW

- hr)

PM 10 : 4.01 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM 2.5 : 3.89 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr)31

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- R4008 EU

- 011 Turbocharger and a ftercooler,

PCV, HPFI w/ a ftercooler, g ood

c ombustion p ractices, and u ltra l ow s ulfur f

uel PM: 7.00 x 10 - 4 lb/hp

- hr (0.43 g/kW

- hr) PM 10 : 4.01 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM 2.5 : 3.89 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM: 0.05 ton per year PM 10 /PM 2.5 : 0.03 ton per year 60 hours of operation

EU

- 012 and

- 013 EPA Tier 1 (or better) m arine

e ngine, t urbocharger and

a ftercooler, CCV, HPFI w/

a ftercooler, g ood c ombustion
p ractices, and u ltra l ow s ulfur f uel PM: 7.00 x 10 - 4 lb/hp

- hr (0.43 g/kW

- hr) PM 10 : 4.01 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM 2.5 : 3.89 x 10 - 4 lb/hp

- hr (0.24 g/kW

- hr) PM: 0.41 ton per year PM 10 : 0.25 ton per year PM 2.5 : 0.25 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) n on

- r oad

e ngine, t urbocharger and

a ftercooler, CCV, HPFI w/

a ftercooler, g ood c ombustion
p ractices, and u ltra l ow s ulfur f uel 8.88 x 10 - 4 lb/hp

- hr (0.54 g/kW

- hr)

EU

- 015 EPA Tier 2 (or better) n on

- r oad

e ngine, t urbocharger and

a ftercooler, CCV, HPFI w/

a ftercooler, g ood c ombustion
p ractices, and u ltra l ow s ulfur f uel 3.29 x 10 - 4 lb/hp

- hr (2.00 g/kW

- hr)

EU

- 016 and

- 017 EPA Tier 3 (or better) n on

- r oad

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler,
g ood c ombustion p ractices, and

u ltra l ow s ulfur f

uel 3.29 x 10 - 4 lb/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) n on

- r oad

e ngine, t urbocharger and

a ftercooler, HPFI w/ a ftercooler,
g ood c ombustion p ractices, and

u ltra l ow s ulfur f

uel 3.29 x 10 - 4 lb/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 (CO 2 ). CO 2 is formed in the combustion chamber as a result of complete combustion of diesel when the carbon in the fuel is converted to CO 2 . 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 (C C S) 2. Alternative/Biomass Fuel Sources32

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- EPA

- R4008 3. CSNO X Emissions Abatement System 4. Good Combustion Practices

The EPA requested additional information regarding the BACT analysis from the applicant and received supplemental information on Septem ber 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 t echnology 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 t echnically infeasible for all diesel internal combustion engines ( o ptions 1 through 3 ). O ption 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.

C C S: This control option is technically infeasible due to space constraints. The space needed for the equipment necessary to capture and separate CO 2 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 CO 2 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.

CSNO X Emissions Abatement System: This technology is currently in the licensing and commercial demonstration phase of development. While this techn ology 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 infea sible 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 rationa le 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 CO 2 e were determined us ing the global warming potentials obtained from 40 CFR part 98.33

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- R4008 Table 6

- 5: GHG BACT Conclusions Emissions Unit ID BACT Control Options BACT Limits * (as CO 2 e) Vessel: C.R. Luigs EU

- 001 through

- 008 Good co mbustion p ractices

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 c ombustion p ractices 1.15 lb/hp

- hr (699 g/kW

- hr) 3,083 tons per year 4,380 hours of operation each

EU

- 015 Good c ombustion p ractices 1.16 lb/hp

- hr (705 g/kW

- hr) 72.06 tons per year 60 hours of operation EU

- 016 and

- 017 Good c ombustion p ractices 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 c ombustion p ractices 1.15 lb/hp

- hr (699 g/kW

- hr)

EU

- 019 and

- 020 Good c ombustion p ractices 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 c ombustion p ractices 1.15 lb/hp

- hr (699 g/kW

- hr)

EU

- 092 Good c ombustion p ractices 1.15 lb/hp

- hr (699 g/kW

- hr) Vessel: DD1 EU

- 001 through

- 008 Good c ombustion p ractices

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 c ombustion p ractices 1.16 lb/hp

- hr (705 g/kW

- hr) 77.84 tons per year 60 hours of operation EU

- 012 and

- 013 Good c ombustion p ractices 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 c ombustion p ractices 1.15 lb/hp

- hr (699 g/kW

- hr) EU

- 015 Good c ombustion p ractices 1.15 lb/hp

- hr (699 g/kW

- hr)

EU

- 016 and

- 017 Good c ombustion p ractices 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 c ombustion p ractices 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 CO 2 e.34

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- 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 (lif eboat fuel tanks); EU

- 051 (hydraulic fluid storage tank); EU

- 052 (base oil storage tank); and EU

090 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 brea thing 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 submitte d 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 f

or 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 inf easible 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.35

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- 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 bo th 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 rollin g 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 BAC T review for emissions of PM/PM 10 /PM 2.5
. 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 techni cally 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/PM 10 /PM 2.5 emissions. EPA has determined the mud and cement mixing operations (for each vessel) will have a PM/PM 10 /PM 2.5 BACT limit of 1.08 tons per ye ar 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 ( CO 2 e )

. Step 1: Identify all avail able 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

.36

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- R4008 Step 2: El iminate 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 CO 2 e 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 CO 2 e 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 so urces. 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 permi t.

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 def ined 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

a cres.37

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- R4008 Table 7

- 1 : Ambient Air Quality Concentration Values ( Showing only project PSD pollutants)

Pollutant and Averaging Period National Ambient Air Quality Standards (μg/m 3 (ppm) ) PSD Increments (μg/m 3 ) PSD Significant

Impact Levels (μg/m 3 ) PSD De

Minimis Impact Levels (μg/m 3 ) Primary Secondary Class I Class II Class I Class II

Particulate Matter (PM 10 ) 24

- hr Annual 150

None 150

None 8 a

4 30 a

17 0.3 0.2 5

1 10

Particulate Matter (PM 2.5 ) 24

- hr Annual 35 c

15 d 35 c

15 d 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 100 f

Nitrogen Dioxide 1

- hr

Annual 188 g, h (0.100)

100 (0.053) None

100 (0.053) 2.5 25 0.1 7.55 h (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 98 th 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 annu al 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/m 3 are estimates. These may change when values and/or ppm to μg/m 3 conve rsion procedures are provided by the EPA.

7.1.1 BHPB’s Qualification as a Temporary Source

BHP B 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 sectio ns 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 a n exemption under 40 CFR § 52.21(i)(3) require s that the project emissions must not im pact 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 NO 2 or particulate matter (PM 10 , PM 2.5 ) 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.38

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- R4008 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 Refu g e and Bradwell Bay Wilderness, both located in Florida approximately 290 and 292 km, respectively, from the nearest drilling location. BHP B 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 Wild life Refuge and St. Marks National Wildlife Refu g e , 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

A s 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 f rom the project ( i.e., NO X , PM 10 , PM 2.5 , SO 2 , 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 max imum 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 Procedure s

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 Workg roup 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 dr aft Revised Phase I Report (June 2008) and the EPA.39

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- R4008 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 th eir 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 op erating 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 propose d 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 co nsidering 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 C lass 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 datase t 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 PM 10 /PM 2.5 and NO 2 Class I PSD sig nificant 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 De position 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 Chemistr y

The NO X 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 conc entrations. 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.40

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- R4008 7.2.6 Modeling Results

The maximum Class I area estimated NO 2 and PM 10 /PM 2.5 impacts from the proposed exploratory drilling emissions are provided in Table 7

- 2. The PM 10 modeling results were conservatively assumed for PM 2.5 . The accepted PSD Class I significant impact levels (SIL) are also provided in this table. The maximum model ed 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 o r 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 m uch 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 NO X 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, t his also demonstrates the project‟s emissions are not expected to cause significant ozone impacts at Bradwell Bay Wilderness. The above Class I area NO 2 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 pe rcent 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
proc edures, 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 98 th percentile modeled values at ea ch 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 provid es a summary of the results of the Method 2 and Method 8 modeling analyses. This table reveals the Method 8 98 th percentile values are less than the target 5 percent change in extinction

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- R4008 T able 7

- 2 : BHP B Maximum Modeled Class 1 Increment Concentrations (ug/m 3 ) PSD Class I Area Parameter Class I Modeling Significance Level (ug/m 3 ) Year

2001 2002 2003

Breton NWR NO 2 – Annual 0.1 0.0129 0.0223 0.0184

PM 10 /PM 2.5 – 24 hour 0.3/0.07 0.0356 0.0348 0.0498 PM 10 /PM 2.5 - Annual 0.2/0.06 0.0016 0.0026 0.0031

St. Marks NWR and Bradwell Bay Wilderness* NO 2 – Annual 0.1 0.0048 0.0018 0.0042

PM 10 /PM 2.5 – 24 hour 0.3/0.07 0.0117 0.0197 0.0171 PM 10 /PM 2.5 - 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 a nd 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 : BHP B 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 a nd 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 BHP B Est imated 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 98 th 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 2 142

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- R4008

Method 8 98 th 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 B HPB ‟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 Nationa l Wildlife Refuge, St. Marks National Wildlife Refu g e , 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 sulfu r 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 NO 2 impacts, indicates no significant project caused oz one 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 Are as . 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 C lass 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 th e 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 confe r 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 designa ted 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 be half 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 activi ties on the OCS. Therefore, BOEM served as the lead agency for ESA s ection 7 and MSA compliance for BHPB‟s exploration activities. In accordance with s ection 7 of the ESA, BOEM consults prior to a lease sale with NOAA Fisheries and FWS to ensure that a sal e43

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- R4008 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 Biol ogical 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 de termination. 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 fis h 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 s ection 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, permitt ed, 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 arch aeological 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 report ed 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 Preservati on 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 appr opriate, 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). Consist ent 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.44

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- R4008 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 so uth 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 reason s. 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 populatio ns. 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

- EPA

R4008 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 m ay 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 p osition 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 regulat ions, 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 offs hore 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 extensio n 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 acce ssed 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 Confident ial Business Information or other information in which disclosure is restricted by statute. Information that you consider Confidential Business Information or otherwise45

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- R4008 protected should be clearly identified as such and should not be submitted through e

- ma il. If you send e

mail 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 notific ation 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 c omments 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 w ritten 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/ocsp ermits/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 admi nistrative 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 ad dresses 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 act ion, please contact: Ms. Rosa Yarbrough, Permit Support Specialist at ( 404 ) 562

- 9643 or R4OCSpermits@epa.gov

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- R4008 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 not ice of the final permit decision, provided the EPA has adequate contact information.