Statoil OCS-EPA-R4012 080913

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Region 4 

Atlanta, Georgia 

Preliminary Determination & Statement of Basis

Outer Continental Shelf Air Permit OCS-EPA-R4012

For

Statoil Gulf Services, LLC

DeSoto Canyon Lease Blocks

August 9, 2013
Statoil OCS-EPA-R4012 080913

Table of Contents

Abbreviations and Acronyms ....................................................................................................................iii

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

2.0 Applicant Information........................................................................................................................... 1

2.1 Applicant Name and Address ........................................................................................................... 1

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

3.0 Proposed Project ................................................................................................................................... 2

3.1 Operating Scenario 1 (Maersk Developer) ....................................................................................... 3

3.2 Operating Scenario 2 (Transocean Discoverer Americas)................................................................ 4

3.3 Support Vessel Operations................................................................................................................ 5

4.0 Legal Authority and Regulatory Applicability ..................................................................................... 6

4.1 EPA Jurisdiction ............................................................................................................................... 6

4.2 OCS Air Regulations ........................................................................................................................ 6

4.3 Prevention of Significant Deterioration (PSD)................................................................................. 7

4.4 Title V............................................................................................................................................... 9

4.5 New Source Performance Standards (NSPS) ................................................................................... 9

4.5.1 Part 60 Subpart Dc ..................................................................................................................... 9

4.5.2 Subpart IIII............................................................................................................................... 10

4.5.3 Subpart K ................................................................................................................................. 13

4.5.4 Subpart Ka ............................................................................................................................... 14

4.5.5 Subpart Kb ............................................................................................................................... 14

4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)........................................ 14

5.0 Project Emissions................................................................................................................................ 15

5.1 Potential to Emit ............................................................................................................................. 15

5.2 Operating Scenario 1 (Developer) Emissions Source Analysis...................................................... 17

5.3 Operating Scenario 2 (Discoverer Americas) Emissions Source Analysis .................................... 18

5.4 Support Vessel Analysis................................................................................................................. 20

5.5 Compliance Methodology............................................................................................................... 21

6.0 Best Available Control Technology (BACT) and Recordkeeping Requirements.............................. 22

6.1 BACT Analysis Procedure.............................................................................................................. 22

6.2 Step 1: Identify all Available Control Technologies ...................................................................... 24

6.3 Step 2: Eliminate Technically Infeasible Control Options............................................................. 24

6.4 Step 3: Rank the Remaining Control Technologies by Effectiveness............................................ 28

6.5 Step 4: Evaluate the Energy, Environmental and Economic Impacts ............................................ 29

6.6 Step 5: Select BACT....................................................................................................................... 30

7.0 Summary of Air Quality Impact Analyses.......................................................................................... 32

7.1 Required Analyses.......................................................................................................................... 32

7.2 PSD Class II Air Quality Impact Assessment................................................................................. 33

7.2.1 Air Quality Model Selection.................................................................................................... 35

7.2.2 Characteristics of Modeled Operational Scenarios.................................................................. 35

7.2.3 Meteorological Data................................................................................................................. 38

7.2.4 Building Downwash................................................................................................................. 38

7.2.5 Receptor Locations .................................................................................................................. 38

7.2.6 Project Impact Assessment ...................................................................................................... 38

7.2.7 Ozone ....................................................................................................................................... 40

7.2.8 Additional Impact Assessments............................................................................................... 41

7.3 PSD Class I Areas Analyses........................................................................................................... 42
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7.3.1 Air Quality Model Selection.................................................................................................... 42

7.3.2 Modeling Procedures............................................................................................................... 42

7.3.4 Meteorological Data................................................................................................................. 43

7.3.5 Modeling Results..................................................................................................................... 43

8.0 Additional Requirements.................................................................................................................... 45

8.1 Endangered Species Act and Essential Fish Habitat of Magnuson-Stevens Act............................ 45

8.2 National Historic Preservation Act ................................................................................................. 46

8.3 Executive Order 12898 – Environmental Justice............................................................................ 46

9.0 Public Participation............................................................................................................................. 47

9.1 Opportunity for Public Comment ................................................................................................... 47

9.3 Administrative Record.................................................................................................................... 48

9.4 Final Determination ........................................................................................................................ 49
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Abbreviations and Acronyms

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

AQRV Air Quality Related Values

BACT Best Available Control Technology 

BOEM Bureau of Ocean Energy Management

Breton NWR Breton National Wildlife Refuge

BSEE Bureau of Safety and Environmental Enforcement

Developer Maersk Developer Drill Rig or the Rig

CAA Clean Air Act 

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

DOI United States Department of the Interior

Discoverer Americas Transocean Discoverer Americas Drill Ship or the Ship

EGOM Eastern Gulf of Mexico

EPA United States Environmental Protection Agency 

ESA Endangered Species Act

FLAG FLM Air Quality Related Workgroup

FLM Federal Land Manager

FWS United States Fish and Wildlife Service

g/kW-hr Grams per Kilowatt Hour

GHG Greenhouse Gas

HAP Hazardous Air Pollutants 

HIP High Injection Pressure

hp Horsepower 

IMO International Maritime Organization

km Kilometer

kPa Kilopascals

kW Kilowatt

kW-hr Kilowatt Hour

LND Low NOX Engine Design

m

3 Cubic Meters

MMBtu/hr Million British Thermal Units per Hour

MSA Magnuson-Stevens Fishery Conservation and Management Act

NAAQS National Ambient Air Quality Standards

NEI National Emissions Inventory

NESHAP National Emission Standards for Hazardous Air Pollutants 

NO2 Nitrogen Dioxide

NOAA National Oceanic and Atmospheric Administration

NOX Oxides of Nitrogen 

NMHC Non Methane Hydrocarbons

NSPS New Source Performance Standards 

NSR New Source Review 

OCS Outer Continental Shelf 
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OCSLA Outer Continental Shelf Lands Act

OSV Offshore Support Vessel

PM Particulate Matter

PM2.5 Particulate Matter (aerodynamic diameter less than or equal to 2.5 microns)

PM10 Particulate Matter (aerodynamic diameter less than or equal to 10 microns)

ppm Parts per Million

PSD Prevention of Significant Deterioration 

PTE Potential to Emit 

RICE Reciprocating Internal Combustion Engine

SAM Sulfuric Acid Mist

SCR Selective Catalytic Reduction

Statoil Statoil Gulf Services, LLC or the Applicant

SIL Significant Impact Level

SMC Significant Monitoring Concentration

SO2 Sulfur Dioxide 

Support Vessels Crew Boats and Offshore Support Vessels 

TPY or tpy Tons Per Year 

TRS Total Reduced Sulfur

TVP True Vapor Pressure

ug/m3 Micrograms per Cubic Meter

U.S.C. United States Code

VISTAS Visibility Improvement State and Tribal Association of the Southeast

VOC Volatile Organic Compounds 
Statoil OCS-EPA-R4012 080913

1.0 Introduction

Statoil Gulf Services, LLC (The Applicant or Statoil) has applied for an Outer Continental Shelf (OCS) 

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

Protection Agency (EPA) Region 4. Statoil has proposed the mobilization and operation of deepwater

drilling vessels and associated support fleets at multiple lease blocks on the OCS in the Gulf of Mexico. 

Statoil plans to drill using one of two operating scenarios and, dependant on the scenario, will use one of 

two dynamically positioned deepwater drilling vessels. The Maersk Developer drill rig, also referred to 

as Operating Scenario 1, or the Transocean Discoverer Americas drill ship, also referred to as Operating 

Scenario 2, along with associated support fleets will be used to conduct the permitted exploratory 

activities. Drilling operations will last for approximately 180 days per year at multiple locations within 

Statoil’s DeSoto Canyon lease blocks and are expected to occur for approximately five to ten years. This 

application and any resultant permitting action from this application are for exploratory drilling only. If 

resource discoveries are made during exploration activities, subsequent facilities, including any 

necessary production platforms, would be permitted separately.

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

sources in the Gulf of Mexico east of 87°30’ (87.5°).

1

The EPA has completed a review of Statoil’s

application in addition to all supplemental materials provided and is proposing to issue Permit Number

OCS-EPA-R4012 to Statoil for a multi-year exploratory drilling program subject to the terms and 

conditions described in the draft permit. The draft permit incorporates applicable requirements from the 

federal Prevention of Significant Deterioration (PSD) and title V operating permit programs, New 

Source Performance Standards (NSPS), and National Emission Standards for Hazardous Air Pollutants

(NESHAP) as required by the OCS air quality regulations in 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 applicable requirements, the legal and 

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

draft permit such as the best available control technology (BACT) analysis and Class II/Class I area 

impact analysis. Additional information can be found in the draft permit accompanying this preliminary 

determination, as well as in the application materials and administrative record for this project, as 

discussed in Section 9 of this document.

2

2.0 Applicant Information

2.1 Applicant Name and Address

Statoil Gulf Services, LLC

2103 CityWest Boulevard, Suite 800

Houston, Texas 77042

 

1

See CAA section 328. The Department of the Interior has jurisdiction for CAA implementation west of 87°30’.

2 The procedures governing 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 the draft permit. This Preliminary 

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

a Fact Sheet as required by 40 CFR § 124.8 and statement of basis as required by 40 CFR § 71.1(a)(5).
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2.2 Facility Location

Statoil proposes to conduct exploratory drilling at multiple sites within its DeSoto Canyon lease blocks

designated Lease Sale areas 213 and 222. These lease blocks (numbers 143, 187, 188, 230, 231, 625, 

669, 670, 671, 715, 716, 759, 760, and 804) are located in OCS waters of the Gulf of Mexico east of 

longitude 87.5°, approximately 160 miles southeast of the mouth of the Mississippi River and 200 miles 

southwest of Panama City, Florida as illustrated below. Each lease block is approximately five 

kilometers by five kilometers. 

Figure 2-1 Site Location

Image reproduced from Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services 

LLC dated September 2012, prepared by ENVIRON International Corporation Baton Rouge, Louisiana.

3.0 Proposed Project

Statoil proposes to operate either the Developer (Operating Scenario 1) or the Discoverer Americas

(Operating Scenario 2) deepwater drilling vessels and their associated support fleets to perform 

exploratory drilling activities for approximately 180 days per year at multiple locations within their

currently held lease blocks in the DeSoto Canyon area of the Gulf of Mexico. It is expected that drilling 

operations will occur for approximately five to ten years. Therefore, Statoil is applying for an OCS air 

permit that will incorporate PSD and title V operating permit program requirements.

Air pollutant emissions generated from the project include the criteria pollutants nitrogen dioxide (NO2), 

carbon monoxide (CO), particulate matter (PM), particulate matter with an aerodynamic diameter less 
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than or equal to 2.5 microns (PM2.5), particulate matter with an aerodynamic diameter less than or equal 

to 10 microns (PM10), and sulfur dioxide (SO2), as well as other regulated air pollutants including 

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

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

precursors for PM2.5. 

Emissions are primarily released from the combustion of diesel fuel in the drilling vessels’ main engines

and in smaller engines that supply power for operating drilling equipment and support vessels. 

Emissions may also be released from other equipment such as fuel and mud storage tanks and from 

activities such as cementing the wells, pumping heavy lubricating mud, painting, and welding. 

Based on emissions estimates and the applicable permitting thresholds, this project will have significant 

emissions of NOX and is subject to the PSD and title V programs for NOX as the measured pollutant for 

criteria pollutants NO2 and ozone and as a precursor to PM2.5. Any facility that emits a regulated New 

Source Review (NSR) pollutant at levels exceeding its PSD significant emission rate must perform a 

BACT analysis and comply with all subsequent regulatory obligations for that pollutant as described in 

Section 6.0 below.

Based on Statoil’s permit application, PM2.5 will be emitted at close to its significant emission rate in 

both operating scenarios. Therefore, EPA has also included a condition in the draft permit that limits the 

project’s total filterable and condensable PM2.5 emissions.

3.1 Operating Scenario 1 (Maersk Developer)

The Developer (Figure 3-1) is a self-powered, dynamically positioned semi-submersible drill rig with 

pontoon structures below the water surface and a platform above the surface. Positioning is achieved

using a computer controlled system and the rig’s propellers and thrusters. Therefore, the Developer will 

not require the use of towing or anchoring vessels as part of its support fleet.

The rig is equipped with eight main generator engines to provide propulsion and electrical power, two 

cementing unit engines, an emergency generator, four life boats, a fast rescue boat (also known as a man 

overboard boat), and storage vessels for fuel and waste oil. Electric powered well logging wireline units, 

vertical seismic profile compressors, forklifts, and cranes are used on the rig. However, since the electric

units do not have combustion engines, they are not addressed as a separate source of air emissions. 

Maintenance activities, such as welding and painting, also emit small amounts of air pollutants. Cement 

used in casing and drilling activities is mixed in an enclosed system on the Developer; therefore, no 

emissions to ambient air are expected from this source.

Support vessels operating within 25 miles of the drill rig will include crew boats and offshore support 

vessels (OSVs) that will bring crew, supplies, and materials to the rig as needed during exploratory 

drilling activities. In addition, crew and time-sensitive supplies may be transported to and from the drill 

ship via helicopters.

Engine details and emissions information are provided in Section 5.0 of this document.
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Figure 3-1 Maersk Developer Drill Rig

Image reproduced from Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services 

LLC dated September 2012, prepared by ENVIRON International Corporation Baton Rouge, Louisiana.

3.2 Operating Scenario 2 (Transocean Discoverer Americas)

The Discoverer Americas is a dynamically positioned drill ship equipped with a computer controlled 

sensor system to maintain the vessel's position and heading over its location using the ship’s propellers 

and thrusters. As with the Developer, this drill ship does not require towing or anchoring vessels as part 

of its support fleet.

The Discoverer Americas’ equipment includes six main engines that power electrical equipment and 

serve as propulsion generators, two forklift engines, an emergency generator, two emergency air 

compressors, six life boats, a fast rescue boat (man overboard boat), a hot oil heater, and storage vessels 

for fuel and waste oil. The drill ship also uses electric-powered wireline units, vertical seismic profile 

compressors, cement units, and cranes. However, since these units do not have combustion engines, they 

are not addressed as separate sources of air emissions. Activities and equipment such as welding, 

painting, cement mixing, storage tanks, and drilling mud also emit small amounts of air pollutants. 

The drill ship is supported by various vessels operating within 25 miles. The support vessel fleet

associated with the Discoverer Americas consists of the same crew boats and OSVs that would be used 

to service the Developer, as discussed above. Since the fleet to be used is the same in both operating 

scenarios, the same emission calculations for crew boats and OSVs are used for both.

The Discoverer Americas drill ship is pictured below in Figure 3-2. Engine details and emissions 

information are provided in Section 5.0 of this document.
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Figure 3-2 Discoverer Americas Drill Ship

Image reproduced from Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services 

LLC dated September 2012, prepared by ENVIRON International Corporation Baton Rouge, Louisiana.

3.3 Support Vessel Operations

As discussed previously, Statoil will rely on a fleet of support vessels in two categories: OSVs and crew 

boats. Hence, specific support vessels are not necessarily assigned to a specific project, rig, or drill ship. 

Allowable emission rate limits included in the draft permit for support vessels will apply to any support 

vessel within each category. Normally, support vessels will keep under their own power when adjacent 

to the drilling vessel for loading or unloading purposes. The only expected physical connection would be 

in the form of product transfer hoses such as those used for refueling or drilling mud. Emissions from 

these connections are accounted for in the storage vessel emission estimates for each drilling vessel. 

To estimate annual emissions from representative crew boats and OSVs, Statoil estimated the total fuel 

usage for each type of vessel during a typical 180-day drilling campaign from actual fuel usage data and 

hours of operation for similar vessels in conjunction with Air Pollutant Emissions Factors (AP-42)3. To 

estimate maximum hourly emissions for each vessel category, Statoil compiled engine and emissions 

data for several vessels of each type. From that information, Statoil derived the worst case emissions

from each category of support vessel during any one hour of operation. Based on Statoil’s calculations, 

the potential emissions proposed for each type of support vessel are a reasonable estimate of emissions 

that would be expected from the highest emitting vessel in each category. 

Section 5.0 of this document includes details regarding the methodology used to determine air emissions 

from the support vessels.

 

3

See AP 42, Fifth Edition, Volume I, Chapter 3: Stationary Internal Combustion Sources, Sections 3.3 and 3.4, 1996.
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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° longitude. Subsequently, 

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

areas offshore the North Slope of Alaska. 

4.2 OCS Air Regulations

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

OCS sources under EPA’s jurisdiction, in order to attain and maintain federal and state ambient air 

quality standards and to comply with the provisions of part C (PSD) of title I of the CAA. The OCS Air

Regulations at 40 CFR part 55 implement section 328 of the CAA and establish the air pollution control 

requirements for OCS sources and the procedures for implementation and enforcement of these

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 (see 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 the OCSLA (see 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 [see 40 CFR § 55.2; see also CAA § 328(a)(4)(C) and 42 U.S.C. § 

7627].

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 [see CAA § 328(a)(1); 40 

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

will be conducted exclusively beyond 25 miles of any state’s seaward boundary.

Sources located beyond 25 miles of a state's seaward boundaries are subject to the NSPS in 40 CFR part 

60; the PSD pre-construction program in 40 CFR § 52.21, if the OCS source is also a major stationary 

source or a major modification to a major stationary source; standards promulgated under section 112 of 

the CAA, if rationally related to the attainment and maintenance of federal and state ambient air quality 

standards or the requirements of part C of title I of the CAA; and the title V operating permit program in 

40 CFR part 71. See 40 CFR §§ 55.13(a), (c), (d)(2), (e), and (f)(2), respectively. The applicability of 

these requirements to Statoil’s exploratory drilling program is discussed below.

The OCS regulations also contain provisions related to monitoring, reporting, inspections, compliance, 
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and enforcement. See 40 CFR §§ 55.8 and 55.9. Sections 55.8(a) and (b) provide that all monitoring, 

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

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

monitoring, recordkeeping, reporting and other compliance assurance measures included in the draft 

permit.

4.3 Prevention of Significant Deterioration (PSD)

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

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

project. 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 requires an assessment of air 

quality impacts from the proposed project and the utilization of BACT as determined on a case-by-case 

basis taking into account energy, environmental, and economic impacts, as well as 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); is “subject to regulation” as defined in 40 CFR § 52.21(b)(49); and is one of a 

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

considered a major stationary source if it emits or has a PTE of 250 TPY or more of a regulated NSR 

pollutant. See 40 CFR § 52.21(b)(l).

“Potential to emit” is defined as the maximum capacity of a source to emit a pollutant under its physical 

and operational design. See 40 CFR § 52.21(b)(4). In the case of “potential emissions” from OCS

sources, 40 CFR part 55 defines the term similarly and provides that:

Pursuant to section 328 of the Act, emissions from vessels servicing or associated with an OCS 

source shall be considered direct emissions from such a source while at the source, and while en

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

“potential to emit” for an OCS source. This definition does not alter or affect the use of this term 

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

must be included in the “potential to emit” as used in 40 CFR §§ 55.13 or 55.14 of this part. (40 

CFR § 55.2)

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

OCS source are considered in determining the PTE 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. 

The drilling vessels and support fleet vessels may contain emission sources that otherwise meet the 

definition of “nonroad engine” as defined in section 216(10) of the CAA. However, based on the 

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

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

of the OCS source are subject to the requirements of 40 CFR part 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 
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than certain applicability thresholds. GHGs are a single air pollutant defined in 40 CFR § 52.21(b)(49)(i) 

as the aggregate group of the following six gases: 

 Carbon dioxide (CO2);

 Nitrous oxide (N2O);

 Methane (CH4);

 Hydrofluorocarbons (HFCs);

 Perfluorocarbons (PFCs); and

 Sulfur hexafluoride (SF6).

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

determination of whether a source is emitting GHGs in an amount that triggers PSD applicability 

involves a calculation of the source’s CO2-equivalent (CO2e) emissions as well as its GHG mass

emissions. See the EPA’s PSD and Title V Guidance for Greenhouse Gases (March 2011) available 

online at www.epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf. 

Table 4-1 lists the PTE for each regulated NSR pollutant from the proposed project, as well as the

significant emission rate for each regulated NSR pollutant. The permit application materials and Section 

5.0 of this document contain information regarding the emissions factors used to determine PTE for the 

project. Emissions from support vessels servicing each drilling vessel were considered direct emissions 

while within 25 miles of the drilling vessel and are included in the PTE.

The requirements of the PSD program apply to this OCS source if the project PTE is at least 250 TPY

for any regulated pollutant. Statoil’s exploration drilling program is a major PSD source because 

emissions of NOX exceed the major source applicability threshold of 250 TPY. Therefore, Statoil is 

required to apply BACT and address air quality impact requirements for NOX, both as the measured

pollutant for NO2 and ozone and as a precursor to ozone and PM2.5. Based on the application materials, 

the PTE for all other regulated pollutants is below the applicable significant emissions rate, and a PSD 

review and BACT analysis are not required. Section 6.0 of this document contains a discussion of the 

BACT analysis.

Table 4-1 Potential to Emit for Regulated NSR Pollutants

Pollutant Scenario 1 

(Developer) 

PTE (TPY)

Scenario 2 

(Discoverer Americas)

PTE (TPY)

Significant Emission 

Rate 

(TPY)

PSD Review 

Required

CO 63.32 60.08 100 No

NOX

1

484.26 559.72 40 Yes

VOC227.65 24.82 40 No

PM 10.63 10.16 25 No

PM10 9.81 9.39 15 No

PM2.5 9.51 9.14 10 No

SO2

3

0.37 0.32 40 No

CO2e 39,333.51 34,077.77 75,000 (subject to 

regulation threshold)

No

 

 1NOX is a measured pollutant for the criteria pollutants ozone and NO2 and a precursor for ozone and PM2.5.

2 VOC is a measured pollutant for the criteria pollutant ozone.

3 SO2 is a precursor for the criteria pollutant PM2.5.
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4.4 Title V

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

OCS sources located beyond 25 miles of any state's seaward boundaries. See 40 CFR § 55.13(f)(2). 

Because the PTE for this project is greater than 100 TPY for NOX, it is considered a major source under 

title V and part 71. Therefore, Statoil must apply for an operating permit as provided in 40 CFR § 

71.5(a)(1)(i) within 12 months of first becoming an OCS source on its lease blocks. 

The OCS permit application submitted by Statoil seeks to obtain a title V operating permit in accordance 

with 40 CFR § 55.13(f)(2) and 40 CFR part 71 concurrently with the OCS preconstruction permit. Part 

71 forms for each operating scenario are included as Appendix A of Statoil’s application. The draft 

permit includes conditions necessary to meet the requirements of the title V operating permit program. 

For example, the draft permit will include requirements for submittal of annual compliance certifications 

and annual fee payments (based on actual emissions), as well as monitoring, recordkeeping, and 

reporting requirements.

4.5 New Source Performance Standards (NSPS)

An OCS source must comply with any NSPS applicable to their source category. See 40 CFR § 55.l3(c). 

In addition, per 40 CFR § 52.21(j)(1), the PSD regulations require that each major stationary source or 

major modification meet applicable NSPS. A specific NSPS subpart applies to a source based on source 

category, equipment capacity, and the date when the equipment commenced construction or 

modification. Potentially applicable NSPS are discussed below.

4.5.1 Part 60 Subpart Dc

Subpart Dc applies to steam generating units constructed after June 9, 1989, with a maximum heat input 

capacity between 10 and 100 MMBtu/hr. See 40 CFR § 60.40c. A steam generating unit is defined as 

any device that produces steam or heats any heat transfer medium from the combustion of any fuel. The 

Discoverer Americas is equipped with a hot oil heater (emission unit HTR) which was constructed after 

the applicability date. The 17.4 MMBtu/hr-rated unit heats a circulating thermal fluid which then heats 

the drill ship’s cargo tanks when operating in areas subject to sub-freezing temperatures. While located 

in the Gulf of Mexico, the heater is operated an estimated two hours per year for maintenance purposes 

only.

As laid out in 40 CFR § 60.42c(d), if oil is used as the fuel source, SO2 emissions shall not be in excess 

of 0.50 lb/MMBtu heat input; or, as an alternative, oil combusted in the unit shall contain less than 0.5 

percent sulfur by weight. Subpart 60.42c(h) allows for compliance with the emission limits or fuel oil 

sulfur limits under this section to be determined based on fuel supplier certification in addition to the 

appropriate reporting and recordkeeping requirements detailed in subpart 60.48c. Statoil proposes to use 

the same ultra low sulfur diesel that is used in the diesel engines on board the drill ship to fuel the heater. 

Compliance with this subpart will be demonstrated with certifications from the fuel supplier indicating a 

sulfur content of 0.0015 percent or less by weight.

Per subpart 60.46c(e), the monitoring requirements of subpart 60.46c are not applicable where 

compliance with the SO2 standard is based on fuel supplier certification. Furthermore, since it will not 

reach a state of representative operating conditions, the limited use of the heater for maintenance as 

described above will result in startup and shutdown emissions only. Startup and shutdown emissions do 

not constitute representative conditions for testing as are required in 40 CFR part 60 subpart A. 
10

Statoil OCS-EPA-R4012 080913

Therefore, the initial performance testing requirements as detailed in subpart 60.8 are not applicable to 

this unit.

There are no PM emissions standards or requirements pursuant to this subpart (see subpart 60.43c) for 

steam generating units with a maximum heat input of less than 30 MMBtu/hr.

4.5.2 Subpart IIII

NSPS 40 CFR part 60 subpart IIII applies to stationary compression-ignition internal combustion 

engines that commence construction after July 11, 2005, and were manufactured after April 1, 2006. 

Relevant equipment specifications for the Developer and the Discoverer Americas are summarized in 

Tables 4-2 and 4-3, respectively. Engines installed on both vessels are subject to the emissions 

limitations and diesel fuel requirements of subpart IIII.

The life boats (LB-1 through LB-4 on the Developer and LB-1 through LB-6 on the Discoverer 

Americas) and the fast rescue boats (MOB-1 on both drilling vessels) are classified as vessels. 

Therefore, only stationary source aspects are regulated. As they are used for man overboard and 

emergency escape scenarios, these units do not have any stationary source aspects with respect to NOX

and are not subject to subpart IIII.

Developer

The main diesel engines installed on the Developer were constructed after the applicability date of July 

11, 2005. Therefore these engines are subject to the emissions limitations and diesel fuel requirements of 

subpart IIII. This requires compliance with 40 CFR § 94.8 standards for the 2006-model GEN-1 through 

GEN-8 main engines which have a displacement greater than 10 liters per cycle. A NOX emission 

standard of 11.5 g/kW-hr was calculated for each 900 rpm engine. To demonstrate compliance with this 

requirement, Statoil has provided the International Maritime Organization (IMO) certification indicating 

that these engines meet subpart 94.8 emissions standards. 

Compliance with the emissions standards contained in Table 1 of subpart IIII is required for the 2006-

model emergency generator engine (EGEN), which has a displacement less than 10 liters per cycle. This 

engine has been certified to achieve IMO standards. In addition, based on information from the 

manufacturer (Caterpillar), the emissions from this unit comply with EPA Tier 1 standards contained in 

40 CFR part 89. Although the model year 2006 would be subject to Tier 2 standards to meet the 

requirements of 40 CFR § 89.112, the Tier 1 certification emissions limits for nonroad engines listed in 

subpart 89.112 are equal to the emissions standards contained in Table 1 of subpart IIII. Therefore, IMO

certification and vendor test data is sufficient to demonstrate compliance with subpart IIII for this 

engine. 

Compliance with the emissions standards contained in Table 1 of subpart IIII is also required for the 

2006 model cementing unit engines (CMU-1 and CMU-2), which have a displacement less than 10 liters 

per cycle. These engines are certified to meet the more stringent emissions standards of 40 CFR § 94.8.

Therefore, the EPA Tier 2 certification for marine engines under subpart 94.8 is sufficient to 

demonstrate compliance with subpart IIII for these engines.

Discoverer Americas

The six main generator engines, the emergency diesel generator, the two emergency air compressor

engines, and the two forklift engines installed on the Discoverer Americas are subject to the emissions 

limitations and diesel fuel requirements of subpart IIII. 
11

Statoil OCS-EPA-R4012 080913

The main engines were installed prior to 2012 and have a displacement greater than 30 liters per cycle. 

Therefore, compliance with the NOX and PM emissions standards contained in 40 CFR § 60.4204 for 

the 2008 model, 720 rpm engines (GEN-1 through GEN-6) is required. Based on size, displacement, and 

rotational speed, the NOX emission standard is 12.1 g/kW-hr for these engines. A PM emission standard 

of 0.15 g/kW-hr must also be met. To demonstrate compliance, Statoil has provided IMO certification 

and engine data indicating that these engines meet the required emissions standards.

The two forklift engines (FORK-1 and FORK-2) must meet the Tier 2 standards for new nonroad 

engines set forth in Table 1 of 40 CFR § 89.112(a). Since the forklift engines are certified to meet the 

more stringent emissions standards of 40 CFR part 1039, the EPA Interim Tier 4 certification is

sufficient to demonstrate compliance with subpart IIII for the forklift engines.

Based on specific engine sizes, model dates, and displacements, 40 CFR part 60 subpart IIII requires the

emergency generator (EGEN) and emergency air compressor engines (ACOMP-1 and ACOMP-2) on 

the Discoverer Americas to comply with Tier 2 emissions standards for new marine engines as set forth 

in 40 CFR § 94.8 and new nonroad engines as set forth in § 89.112, respectively. Compliance with the 

NSPS specifically requires that these engines be certified to the EPA Tier 2 standards. Since the 

Discoverer Americas is not a U.S. flagged vessel, it was constructed to IMO rather than EPA Tier 

standards. While these standards are often similar for later model years, the IMO standards do not

require certification for these emergency engines. Since certification is an engine manufacturer process, 

it is not possible for these engines to obtain an EPA Tier certificate, even for emissions levels that meet 

the EPA certification requirements. See 40 CFR § 60.4211(c). Hence, compliance with the NSPS would 

require Statoil to replace these engines with engines certified to the emission standards in § 60.4205(b) 

that would be applicable for the same model year and maximum engine power. Since these engines have 

emission profiles very similar to those of an EPA Tier certified engines, as part of their permit 

application, Statoil is requesting exemptions from subpart IIII for the emergency generator and 

emergency air compressor engines. Pursuant to 40 CFR § 55.7, the EPA may grant an exemption from a 

part 55 requirement, if the Administrator or the delegated agency finds that compliance is technically 

infeasible or will cause an unreasonable threat to health and safety.

The existing emergency generator and emergency air compressor engines on the Discoverer Americas

were sized to meet the drill ship’s stringent space and weight distribution requirements in the vessel’s 

design phase. Based on consultations with Transocean, the drill ship owner, Statoil has determined that 

any replacement engine would have to meet exacting `output, weight, physical size, and shape 

restrictions dictated by the vessel’s design constraints. Statoil was not able to locate replacement engines

for this vessel that would meet all the necessary criteria and fit the design footprint of the original 

engines as summarized in email communications to the EPA dated July 17, 2013 and included in the 

administrative record. Furthermore, if suitable replacement engines could be found, replacing these

engines would likely require a redesign of the engine bed frame and vessel structural modifications that 

would subsequently require recertification of the vessel. Based on these source-specific technical 

barriers, the EPA concludes that replacement of the EGEN and ACOMP units for this operating scenario 

and this project is not technically feasible at this time. Thus, the EPA proposes to grant Statoil’s request 

for an exemption from subpart IIII. 

Any exemption under §55.7 would necessitate compliance with substitute emissions and/or work 

practice requirements based on the next most stringent standard available. The EPA determined that the 

next most stringent standards for the EGEN unit on the Discoverer Americas are IMO certification 
12

Statoil OCS-EPA-R4012 080913

standards for comparable engines. Detailed information regarding IMO certification standards from the 

Regulations for the Prevention of Air Pollution from Ships (Annex VI) document can be found at the 

IMO’s website, www.imo.org.

An exemption under §55.7 also requires an estimate of residual emissions derived from the difference 

between the estimated reductions that would be achieved by compliance with the original requirement 

and the estimated emission reductions that would be achieved by compliance with the proposed 

substitute requirements. In accordance with 40 CFR § 55.7(e)(3), Statoil must then obtain emission 

reductions of a sufficient quantity to offset the estimated residual emissions. Statoil calculated the 

differences in emissions that would be achieved by compliance with the original emission standards for 

each engine versus the estimated emissions from the substitute requirements. These calculations are 

included in the application materials located in the administrative record. The total residual emissions 

for the three engines (EGEN, ACOMP-1 and ACOMP-2) detailed below is approximately 0.13 tons of 

NOX and hydrocarbons combined, and approximately 0.00072 tons of particulate matter.

As discussed above, the emergency generator engine (EGEN) is a Category 2, commercial marine 

engine subject to emission standards located in 40 CFR part 94.8 Table A-1. The total NOX + nonmethane hydrocarbon (NMHC) emissions residual for the emergency generator engine is estimated to be

0.13 TPY. Potential emissions of CO and PM for the emergency generator under the substitute 

requirement are below the Tier 2 standards. 

The emergency air compressor engines (ACOMP-1 and ACOMP-2) are classified as nonroad engines 

subject to emission standards located in 40 CFR part 89.112 Table 1. The total NOX + NMHC emission 

residual for both of these engines combined is estimated to be 0.0066 TPY. Residual PM emissions are 

approximately 0.00072 TPY. Potential emissions of CO for the emergency air compressors under the 

substitute requirement are below the Tier 2 standards. 

Since this OCS source will be located beyond 25 miles from any States' seaward boundary, the EPA is 

authorized to determine an adequate emission offset ratio to be protective of State and Federal ambient 

air quality standards and to comply with part C of title I of the CAA. See 40 CFR 55.7(e)(3). With 

respect to this specific project, the residual emissions are so low as to be essentially equivalent to the 

original emissions standards. As such, the EPA has determined that, based on currently available data, 

the residual emissions are negligible and no emissions offsets will be required at this time. Taking into 

account the quality of the emissions factors currently available to estimate the substitute emissions and 

the uncertainty inherent in these estimates, this determination will be revisited by the EPA upon review 

of project specific stack testing data from the Discoverer Americas that is required by the draft permit. 

At that time, if the EPA determines that emissions reductions are appropriate, Statoil will work with the 

EPA to identify suitable offsets to satisfy this requirement.

Statoil must comply with all other applicable requirements of subpart IIII for these engines including 

recordkeeping, reporting, and the diesel fuel requirements of 40 CFR § 60.4207. Compliance with these 

permit requirements and the substitute control requirements will also meet the applicant’s obligations for 

these engines under 40 CFR § 63 subpart ZZZZ, as discussed below in Section 4.6.
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Statoil OCS-EPA-R4012 080913

Table 4-2 Developer Engine Specifications

Emissions

Unit ID

Engine Description Manufacturer

and Model

Displacement 

(L/cylinder)

Ratinga

(kW)

Ratinga

(hp)

Manufacture 

Date

GEN-1 Main Generator Engine 1 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-2 Main Generator Engine 2 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-3 Main Generator Engine 3 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-4 Main Generator Engine 4 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-5 Main Generator Engine 5 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-6 Main Generator Engine 6 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-7 Main Generator Engine 7 Wärtsilä 16V26A 17.0 4960 6651 8/2006

GEN-8 Main Generator Engine 8 Wärtsilä 16V26A 17.0 4960 6651 8/2006

EGEN Emergency Generator 

Engine

Caterpillar 3516B 4.9 1902 2551 11/2006

CMU-1 Cement Unit Engine 1 Caterpillar C15 2.4 373 500 10/2006

CMU-2 Cement Unit Engine 2 Caterpillar C15 2.4 373 500 9/2006

LB-1 Lifeboat 1 Engine BUKH --- 22 29 8/2007

LB-2 Lifeboat 2 Engine BUKH --- 22 29 8/2007

LB-3 Lifeboat 3 Engine BUKH --- 22 29 8/2007

LB-4 Lifeboat 4 Engine BUKH --- 22 29 8/2007

MOB-1 Fast Rescue Boat Engine Steyr Motors --- 122 163 3/2007

a

Permit conditions may limit operation to less than rated capacity. 

Table 4-3 Discoverer Americas Engine Specifications

Emissions

Unit ID

Engine Description Manufacturer and 

Model

Displacement 

(L/cylinder)

Ratinga

(kW)

Ratinga

(hp)

Manufacture 

Date

GEN-1 Main Generator Engine 1 STX MAN 14V32/40 32.2 7000 9387 3/2008

GEN-2 Main Generator Engine 2 STX MAN 14V32/40 32.2 7000 9387 3/2008

GEN-3 Main Generator Engine 3 STX MAN 14V32/40 32.2 7000 9387 3/2008

GEN-4 Main Generator Engine 4 STX MAN 14V32/40 32.2 7000 9387 3/2008

GEN-5 Main Generator Engine 5 STX MAN 14V32/40 32.2 7000 9387 4/2008

GEN-6 Main Generator Engine 6 STX MAN 14V32/40 32.2 7000 9387 4/2008

EGEN Emergency Generator 

Engine

STX MAN 7L27/38 21.8 2309 3097 2/2008

ACOMP-1 Emergency Air 

Compressor Engine 1

Duetz F3L912 0.9 37 50 1/2007

ACOMP-2 Emergency Air 

Compressor Engine 2

Duetz F4L912 0.9 51 68 1/2007

FORK-1 Forklift Engine 1 Mitsubishi 

8MVXL.0AAD

3.3 37 50 2008

FORK-2 Forklift Engine 2 Mitsubishi 

8MVXL.0AAD

3.3 37 50 2008

LB-1 Lifeboat 1 Engine BUKH --- 27 36 9/2006

LB-2 Lifeboat 2 Engine BUKH --- 27 36 9/2006

LB-3 Lifeboat 3 Engine BUKH --- 27 36 8/2006

LB-4 Lifeboat 4 Engine BUKH --- 27 36 9/2006

LB-5 Lifeboat 5 Engine BUKH --- 27 36 9/2006

LB-6 Lifeboat 6 Engine BUKH --- 27 36 9/2006

MOB-1 Fast Rescue Boat Engine Steyr Motors --- 158 212 9/2006

a Permit conditions may limit operation to less than rated capacity. 

4.5.3 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 
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Statoil OCS-EPA-R4012 080913

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. The Developer was built in 2006 and the Discoverer 

Americas in 2008. Therefore, storage tanks in either operating scenario are not subject to subpart K 

based on construction dates. 

4.5.4 Subpart Ka

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

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

May 18, 1978, and prior to July 23, 1984. The Developer was built in 2006 and the Discoverer Americas

in 2008. Therefore, all storage tanks are not subject to subpart Ka based on their construction dates.

4.5.5 Subpart Kb

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

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

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

capacity greater than or equal to 151 m3storing a liquid with a maximum true vapor pressure (TVP) less 

than 3.5 kilopascals (kPa) or with a capacity greater than or equal to 75 m3but less than 151 m3storing a 

liquid with a maximum true vapor pressure less than 15.0 kPa. As indicated in the application materials, 

no storage tanks on the Developer or the Discoverer Americas are subject to Subpart Kb based on 

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

4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)

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

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

requirements of part C of title I of the CAA. See 40 CFR § 55.13(e). 

NESHAP regulations set forth in 40 CFR part 63 apply to a source based on its source category listing. 

Many part 63 NESHAPs apply only if the affected source is a “major source” as defined in Section 112 

and 40 CFR § 63.2. A major source is generally defined as a source that has a PTE of 10 tons per year or 

more of any single hazardous air pollutant (HAP) or 25 tons per year or more of all HAP combined. See

section 112(a)(1) and 40 CFR § 63.2. An area source is any source that is not a major source as defined 

in section 112(a)(2) and 40 CFR § 63.2. In both operating scenarios, Statoil has estimated emissions of 

less than 25 TPY for all HAPs combined and less than 10 TPY for each individual HAP. This makes the 

project an area source of HAPs under either operating scenario.

The regulations also establish different standards for new and existing sources pursuant to CAA section 

112. Area source engines rated above 500 hp that are constructed after December 19, 2002 and engines 

with a rating of 500 hp or less that are constructed after June 12, 2006 are considered “new”

reciprocating internal combustion engines (RICE).

The eight main generator engines (GEN-1 through GEN-8), the emergency diesel generator (EGEN), 

and the two cementing unit engines (CMU-1 and CMU-2) installed on the Developer drill rig were 

constructed after the applicability dates. The six main generator engines (GEN-1 through GEN-6), the 

emergency diesel generator (EGEN), the two forklift engines (FORK-1 and FORK-2), and the two 

emergency air compressor engines (ACOMP-1 and ACOMP-2) installed on the Discoverer Americas 

drill ship were also constructed after June 12, 2006. Therefore, 40 CFR 63 subpart ZZZZ requires that 
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Statoil OCS-EPA-R4012 080913

these engines comply with the requirements of 40 CFR 60 subpart IIII as discussed above in Section 

4.5.2. No further requirements under subpart ZZZZ apply to these engines.

Emissions from the life boat engines and the fast rescue boats on the Developer and the Discoverer 

Americas were included in the OCS source’s PTE and emissions modeling, as required by 40 CFR part 

55. These vessels are also subject to operating limits, and to monitoring, recordkeeping and reporting 

requirements to ensure they will not exceed the potential emissions assumed in the application and 

impact review. However, these units do not have any stationary source aspects with respect to NOX

emissions, as they are used for man overboard and emergency escape scenarios, and are not subject to 

subpart ZZZZ standards.

5.0 Project Emissions

5.1 Potential to Emit

This section describes the calculation basis for air emissions generated during exploratory drilling 

operations from each emission source. The calculations are based on AP-42 factors, EPA publications, 

analysis of fuel sulfur content, vendor compliance certifications, and vendor-supplied emissions factors. 

The total projected emissions include estimates based on fuel consumption from the diesel engines. 

Emissions from other sources on the drilling vessels and support vessels are based on worst case PTE 

conditions for the individual sources. Summaries of the PTE from regulated NSR pollutants are given in 

Tables 5-1 and 5-2 below. The estimated Operating Scenario 1 and 2 emission estimates are based on 

exploration activities lasting approximately 180 days per calendar year. Statoil is requesting permit 

limits be established based on emission rates as opposed to operating days to allow operating flexibility.

Emissions calculations are included in Section 3 and Appendix B of Statoil’s September 2012 

application which were modified and corrected in the updated emissions calculations submitted to the 

EPA in Statoil’s Second Response to EPA Incompleteness Determination dated January 28, 2013 and 

subsequent email communications dated April 25, 2013.

4 All documents are included in the 

administrative record as discussed in Section 9.0 of this document.

Table 5-1 Potential to Emit Emissions – Operating Scenario 1 (Developer)

Emission Source Total VOC 

(TPY)

NOx 

(TPY)

CO (TPY) SO2 (TPY) PM (TPY) PM10 

(TPY)

PM2.5 

(TPY)

GHGs 

(CO2e) 

(TPY)

Lead 

(TPY)

Wärtsilä Diesel 

Generator Engines

18.23 346.90 16.58 0.28 6.38 6.38 6.38 29,613.84 5.25e-03

Emergency Diesel 

Generator Engine

3.55e-02 0.76 0.28 5.47e-04 2.46e-02 2.02e-02 1.96e-02 57.63 1.02e-05

Lifeboat Engines 1.750e-03 8.582e-03 6.293e-03 7.566e-06 6.865e-04 5.644e-04 5.476e040.80 1.41e-07

Fast Rescue Boat 

Engines

0.00 0.01 0.01 1.06e-05 6.43e-04 5.29e-04 5.13e-04 1.12 1.99e-07

Cement Unit Engines 0.08 0.36 0.25 3.26e-04 0.010 0.008 0.008 34.36 6.09e-06

Offshore Support 

Vessels

4.29 108.99 33.46 0.07 2.97 2.44 2.37 6,966.08 1.23e-03 

Crewboats 1.76 27.24 12.75 0.03 0.77 0.63 0.61 2,635.57 4.67e-04

 

4 Emissions summary tables included in Appendix B of the September 2012 application incorrectly label the Discoverer Americas as 

Operating Scenario 1 and the Developer Operating Scenario 2 in the appendix headings. This does not affect the data included in the tables 

or the resultant analysis.
16

Statoil OCS-EPA-R4012 080913

Emission Source Total VOC 

(TPY)

NOx 

(TPY)

CO (TPY) SO2 (TPY) PM (TPY) PM10 

(TPY)

PM2.5 

(TPY)

GHGs 

(CO2e) 

(TPY)

Lead 

(TPY)

Tanks and Fugitive 

Emissions

3.26 -- -- -- 0.48 0.33 0.12 24.11 --

Total 27.65 484.26 63.32 0.37 10.63 9.81 9.51 39,333.51 0.00697

Table 5-2 Potential to Emit Emissions – Operating Scenario 2 (Discoverer Americas)

 

Emission Source Total VOC 

(TPY)

NOx 

(TPY)

CO (TPY) SO2 (TPY) PM (TPY) PM10 

(TPY)

PM2.5 

(TPY)

GHGs 

(CO2e) 

(TPY)

Lead 

(TPY)

STX MAN Diesel 

Generator Engines

15.01 422.49 13.09 0.23 5.25 5.25 5.25 24,381.00 4.32e-03

Emergency Diesel 

Generator Engine

0.03 0.88 0.02 4.88e-04 0.02 0.02 0.02 51.42 9.12e-06

Lifeboat Engines 3.3e-03 1.60e-02 1.17e-02 1.41e-05 1.28e-03 1.05e-03 1.02e-03 1.48 2.63e-07

Fast Rescue Boat 

Engines

3.2e-03 0.02 0.01 1.38e-05 8.36e-04 6.88e-04 6.67e-04 1.46 2.58 e-07

Air Compressor

Engines

4.4e-04 0.01 1.18e-03 1.92e-06 4.74e-04 3.89e-04 3.78e-04 0.20 3.59e-08

Forklift Engines 0.03 0.09 0.10 1.29e-04 0.01 4.8e-03 4.66e-03 13.57 2.41e-06

Offshore Support 

Vessels

4.29 108.99 33.46 0.07 2.97 2.44 2.37 6,966.08 1.23e-03 

Crewboats 1.76 27.24 12.75 0.03 0.77 0.63 0.61 2,635.57 4.67e-04

Tanks and Fugitive 

Emissions

3.72 -- -- -- 1.14 1.04 0.88 24.11 --

Hot Oil Heater 3.18e-05 2.55e-03 0.64 2.71e-05 4.20e-04 1.27e-04 3.18e-05 2.87 1.57e-07

Total 24.82 559.72 60.08 0.32 10.16 9.39 9.14 34,077.77 6.04e-03

 

No information has been identified by Statoil or by the EPA indicating a potential for fluoride emissions 

from the combustion of diesel fuel in internal combustion engines. In addition, no fluoride emission 

factor resulting from diesel combustion has been identified. Therefore, fluoride emissions resulting from 

the combustion of diesel are not considered to be present in engine emissions.

The potential emissions of SO2 for proposed activities in the Gulf of Mexico are based on an emission 

factor developed using a mass balance approach. The factor is based on the sulfur content of ultra low 

sulfur diesel (0.0015 percent by weight). It is assumed that 100 percent of the sulfur in the fuel is 

oxidized to SO2. However, to obtain a conservative estimate, Statoil calculated potential total reduced 

sulfur (TRS) and sulfuric acid mist (SAM) emissions 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. The basis of the potential TRS emissions is that 1 percent by weight of the sulfur in 

the fuel is emitted as TRS rather than being oxidized to SO2 and could be converted to TRS or reduced 

sulfur compounds. With either designation, the potential emissions of TRS are calculated to be less than 

0.01 TPY in each scenario, considerably less than the relevant PSD significant emissions rate of 10 

TPY. 

Similar to the TRS or reduced sulfur compound calculations, the basis for the potential SAM emissions 

is 2.247 percent by weight of the sulfur in the fuel being converted to SO4, which is then converted to 

sulfuric acid. The potential SAM emissions calculated with this methodology are estimated to be less 

than 0.014 TPY in Scenario 1 and less than 0.012 TPY in Scenario 2, considerably less than the relevant 
17

Statoil OCS-EPA-R4012 080913

PSD significant level of 7 TPY. Detailed emission calculations for TRS and SAM are included in 

Appendix B of the September 2012 application and updated in Statoil’s January 2013 response to EPA’s 

incompleteness determination and subsequent email communications dated April 25, 2013.

Fugitive emissions from each drilling scenario were based on the number of fugitive components 

(piping, valves, flanges, etc...) identified on each drilling vessel’s fuel system piping and 

instrumentation diagrams in conjunction with emissions factors contained in Table 2-4 of the Protocol 

for Equipment Leak Emission Estimates (EPA-453/R-95-017). Calculations for fugitive emissions and 

potential emissions from drilling mud are included in Section 3 and Appendix B of Statoil’s September 

2012 application, which were modified and corrected in the updated emissions calculations submitted to 

the EPA in Statoil’s Second Response to EPA Incompleteness Determination dated January 28, 2013.

Calculations for emissions from maintenance activities, such as painting and welding on both drilling 

vessels, as well as cement mixing on the Discoverer Americas were included in email communications 

to the EPA dated April 25, 2013. Cement mixing on the Developer is a completely enclosed, selfcontained operation with no air emissions. Emissions from painting were based on an estimated amount 

of paint and paint thinner used during a 180 day drilling campaign, assuming 100% spray application for 

a conservative estimate. Welding emissions were calculated based on an estimated number of welding 

electrodes used per 180-day drilling campaign. Emissions from dry cement mixing on the Discoverer

Americas were based on the design flow rate of the mixer’s dust collector.

An additional potential source of emissions in either operating scenario are gases contained in drilling 

mud circulating from the well to the drilling vessel which may contain hydrocarbons, particularly if the 

drill bit is passing through rock in a hydrocarbon zone. These gases can then volatilize to the 

atmosphere. Statoil has calculated emissions from the drilling mud using an estimate of one day of 

drilling in hydrocarbon-containing rock per well and an estimated four wells drilled annually.

5.2 Operating Scenario 1 (Developer) Emissions Source Analysis

The following is a description of the Developer’s emission units and how emissions were calculated for 

each source. Since potential emissions of regulated air pollutants are estimated to be less than 2 TPY and 

HAP emissions are estimated to be less than 1,000 lb/yr from the lifeboat engines, fast rescue boat 

engines, mud degassing, welding activities, painting, and storage vessels, they are considered 

insignificant activities with respect to title V permit requirements per 40 CFR 71.5(c)(11)(ii).

Because Statoil has requested that the permit not restrict exploratory drilling activities to 180 days per 

year for operational flexibility, an annual fuel limitation of 2,650,333 gallons of diesel fuel on a rolling 

12-month basis has been included in the draft permit. This estimate is based on emissions and fuel use 

estimates for a typical 180-day drilling campaign as provided in the application materials. If the drilling 

vessels are used sequentially during any rolling 12-month period, the annual fuel use limitation must be 

prorated based on daily use.

GEN-1 through GEN-8: Main Diesel Generator Engines 

The Developer’s electrical power is provided by eight identical Wärtsilä 16V26A diesel generator 

engines (main engines) with a rated power output of approximately 6,651 hp each. Emissions estimates 

for the main engines were based on an anticipated 180 days of drilling operation per year (4,320 hours 

annually) and maximum emission factors based on AP-42 results and vendor-supplied data. Emissions 

estimates were calculated for normal operating conditions based on three engines operating at 60% load 

and five engines on standby at 0% load. Maximum hourly emissions were calculated based on five
18

Statoil OCS-EPA-R4012 080913

engines at 60% load and three engines on standby at 0% load to account for the most engines running 

during any hour of operation at their highest power rating. SO2 emissions were estimated based on 

chemical analysis of the sulfur content of the diesel fuel. Specific emission factors used to estimate the 

project’s emissions are included in Section 3 of Statoil’s September 2012 application. 

EGEN: Emergency Generator Engine

The emergency generator’s diesel engine is powered by a Caterpillar (3516B) 2,551 hp engine. It 

provides emergency power to the drilling rig and is run periodically to ensure that the engine will 

operate properly in the event of an emergency. This planned operation time for routine testing and 

maintenance of 39 hours per year at 100% capacity was used for emission calculations and has been 

included as a limit in the draft permit to ensure consistency with the assumptions used in the application 

and impact review. A total of 0.76 TPY NOX is estimated for this engine.

CMU-1 and CMU-2: Cement Unit Diesel Engines

The cementing units are used to produce and pump cement around the well casing during drilling 

operations to provide stability to the casing. Each unit has a 500 hp Caterpillar C15 diesel engine. 

Emissions were calculated for these units using an estimated annual operating schedule of 60 hours per 

year for each unit, which has been included as a condition in the draft permit to ensure consistency with 

the assumptions used in the application and impact assessment. A total of 0.36 TPY NOX combined is 

estimated for these engines.

LB-1 through LB- 4: Life Boats

The 29 hp engines powering each life boat are operated during maintenance checks, safety checks and in 

the event of an emergency. Planned operating time of 12 hours per year at maximum capacity was used 

for the emission calculations for each unit. An operational limit reflecting the planned operation time for

routine testing, drills, and maintenance is included in the draft permit to ensure consistency with the 

assumptions used in the application and impact assessment.

MOB: Fast Rescue Boat

The 163 hp engine in the fast rescue boat, also known as a man overboard boat, is operated during 

maintenance checks, safety checks and in the event of an emergency. Planned operating time of 12 hours 

per year at maximum capacity was used for the emission calculations. An operational limit reflecting the 

planned operation time for routine testing, drills, and maintenance is included in the draft permit to 

ensure consistency with the assumptions used in the application and impact assessment.

ST Units: Storage Units

Emissions are generated from the storage of diesel fuel, aviation fuel for the helicopters, and waste oil in 

tanks. Refueling and unloading emissions associated with the support vessels are included in the storage 

unit emissions calculations. The default EPA TANKS 4.09d computer software program was used for 

diesel and waste oil calculations. The EPA TANKS 4.09d default properties for Jet Naphtha were used 

for the aviation fuel estimates.

5.3 Operating Scenario 2 (Discoverer Americas) Emissions Source Analysis

The following is a description of the Discoverer Americas’ emission units and how emissions were 

calculated for each emission source. Since potential emissions of regulated air pollutants are estimated 

to be less than 2 TPY and HAP emissions are estimated to be less than 1,000 lb/yr from the emergency 

air compressors, oil heater, mud degassing, lifeboat engines, fast rescue boat engines, painting, welding 
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activities, cement mixing, and storage vessels, they are considered insignificant activities with respect to 

title V permit requirements per 40 CFR 71.5(c)(11)(ii).

Because Statoil has requested that the permit not restrict exploratory drilling activities to 180 days per 

year for operational flexibility, an annual fuel limitation of 2,179,983gallons of diesel fuel on a rolling 

12-month basis has been included in the draft permit. This estimate is based on emissions and fuel use 

estimates for a typical 180-day drilling campaign as provided in the application materials.

GEN-1 through GEN-6: Main Diesel Generator Engines 

The Discoverer Americas’ electrical power is provided by six identical STX Engine Company MAN 

14V32/40 diesel generator engines (main engines) with a rated power output of approximately 9,387 hp 

each. Emissions estimates for the main engines were based on an anticipated 180 days of drilling 

operation per year (4,320 hours annually) and maximum emission based on AP-42 factors and vendorsupplied data. Emissions estimates were calculated for normal operating conditions based on three 

engines operating at 35% load and three engines on standby at 0% load. Maximum hourly emissions 

were calculated based on four engines at 80% load and two engines on standby at 0% load to account for 

the most engines running during any hour of operation at their highest power rating. SO2 emissions were 

estimated based on chemical analysis of the sulfur content of the diesel fuel. Specific emission factors 

used to estimate the project’s emissions are included in Section 3 of Statoil’s September 2012 

application. 

EGEN: Emergency Diesel Engine

The emergency generator’s diesel engine is powered by an STX Engine Company 7L27/38 engine rated 

at 3,097 hp. It provides emergency power to the drill ship and is run periodically to ensure the engine 

will operate properly in the event of an emergency. The planned operation time for routine testing and 

maintenance of 41 hours per year at 100% capacity was used for emission calculations and has been 

included as a condition in the draft permit to ensure consistency with the assumptions used in the 

application and impact assessment. A total of 0.88 TPY NOX is estimated for this engine.

ACOMP-1 and ACOMP-2: Emergency Air Compressor Unit Diesel Engines 

The emergency air compressors are used in the event the main air compressors are not operational. 

These engines are run periodically to ensure proper operation in the event of an emergency. One unit is 

equipped with a 50 hp Duetz F3L912 diesel engine and the other unit with a 68 hp Duetz F4L912 diesel 

engine. Planned operation time of three hours per year for each unit at 100% capacity was used for the 

emission calculations. This planned operation time for routine testing and maintenance of three hours 

per unit per year at 100% capacity was used for emission calculations and has been included as a 

condition in the draft permit to ensure consistency with the assumptions used in the application and impact 

assessment. A total of 0.01 TPY NOX is estimated for these engines.

FORK-1 and FORK-2: Forklifts

Two forklifts, each powered by a 50 hp Mitsubishi diesel engine, are used for moving equipment and 

supplies on board the drilling vessel. Emissions were calculated for these units using an estimated 

annual operating schedule of 237 hours per year for each unit. An operational limit is included as a 

condition in the draft permit to ensure consistency with the assumptions used in the application and impact 

assessment. A total of 0.09 TPY NOX combined is estimated for these engines.
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LB-1 through LB- 4: Life Boats

The 36 hp engines powering the life boats are operated during maintenance checks, safety checks and in 

the event of an emergency. Planned operating time of 12 hours per year at maximum capacity was used 

for the emission calculations for each unit. An operational limit reflecting the planned operation time for 

routine testing, maintenance, and drills is included in the draft permit to ensure consistency with the 

assumptions used in the application and impact assessment.

MOB: Fast Rescue Boat

The 212 hp engine in the fast rescue boat, also known as a man overboard boat, is operated during 

maintenance checks, safety checks and in the event of an emergency. Planned operating time of 12 hours 

per year at maximum capacity was used for the emission calculations. An operational limit reflecting the 

planned operation time for routine testing, maintenance, and drills is included in the draft permit to 

ensure consistency with the assumptions used in the application and impact assessment.

HTR Unit: Hot Oil Heater

The 17.4 MMBtu/hr diesel powered cargo tank heater will not be used while the drill ship is in the

eastern Gulf of Mexico with the exception of planned operating time for maintenance and testing. 

Calculations for emissions from this unit were based on its operating two hours per year. A total of 

0.003 TPY NOX is estimated for this unit. An operational limit is included as a condition in the draft permit to 

ensure consistency with the assumptions used in the application and impact assessment.

ST Units: Storage units

Emissions are generated from the storage of diesel fuel, aviation fuel for the helicopters, and waste oil in 

tanks. Refueling and unloading emissions associated with the support vessels are included in the storage 

unit emissions calculations. The default EPA TANKS 4.09d computer software program was used for 

diesel and waste oil calculations. The EPA TANKS 4.09d default properties for Jet Naphtha were used 

for the aviation fuel estimates.

5.4 Support Vessel Analysis 

Various support vessels will be used to transport personnel, supplies, and fuel to the drilling vessels for

the duration of exploratory drilling. Availability of specific support vessels during the operation was not 

known at the time of application. As discussed previously, Statoil relies on a support fleet belonging to 

two categories, OSVs and crew boats. Representative emission factors for these sources are available in 

the application materials, which are included in the administrative record referenced at the end of this

document. The same fleet of support vessels will be used for both operating scenarios. Therefore, the 

emissions calculations described here and in Statoil’s application materials apply to either operating 

scenario.

Statoil based the estimated annual crew boat and offshore support vessel emissions on total fuel used 

during the year (180 days of drilling operations) for similar vessels during similar historical drilling 

campaigns. Actual fuel usage data was used in conjunction with AP-42 emission factors to estimate 

annual emissions associated with these activities. Crew boat calculations were based on 618 operating 

hours per year with a result of 235,176 gallons of diesel consumed per year when within 25 miles of the 

drilling vessel. To estimate annual emissions from OSVs, Statoil based the calculations on 2,570

operating hours annually with a result of 621,468 gallons of diesel consumed per year when within 25 

miles of the drilling vessel. 
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Statoil based estimated maximum hourly emissions for crew boat and OSV emissions using specific 

engine data and emissions information for several vessels in each category. From that information, 

Statoil derived the worst case emissions that could reasonably be expected from each type of support 

vessel during any one hour of operation. 

The OSV (Peyton Candies) and crew boat (Sybil Graham) were identified as the highest emitting 

support fleet vessels. Statoil used the maximum possible emissions from each of these vessels to 

estimate support vessel emissions in the application based on maximum load. However, these are 

conservative worst-case assumptions, and do not represent how these boats will typically operate. 

Detailed emission factors for these sources are available in Statoil’s application materials, which are

included in the administrative record referenced at the end of this document.

5.5 Compliance Methodology

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

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

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

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

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

deepwater drill ship in the marine environment, the draft permit allows Statoil to choose monitoring 

systems for NOX for the main generator diesel units (GEN-1 through GEN-8 on the Developer drill rig 

and GEN-1 through GEN-6 on the Discoverer Americas drill ship) and describes the use of an EPAapproved continuous emissions monitoring system, an EPA-approved alternative parametric monitoring 

method, or a stack testing emissions monitoring system that may be used with prior written approval by 

the EPA.

The compliance demonstration method for the emergency generator diesel units (EGEN on both the 

Developer and the Discoverer Americas, ACOMP-1 and ACOMP-2 on the Discoverer Americas), the 

smaller on-board diesel engines (CMU-1 and CMU-2 on the Developer, FORK-1 and FORK-2 on the 

Discoverer Americas) and the emergency vessels (LB-1 through 4 on the Developer, LB-1 through LB-6 

on the Discoverer Americas, and MOB on both drilling vessels) will include monitoring and maintaining 

a contemporaneous record of the hours of engine operation using an engine hour meter, or 

recordkeeping of unit ID, date/time the engine started, date/time the engine shut down, the printed name 

of the person operating the equipment and the signature of the person operating the equipment. These 

units must also meet any applicable NSPS and NESHAP monitoring requirements. The recorded hours 

of operation will be used along with the appropriate emissions factors for each engine to determine the 

total NOX emitted.

Compliance demonstration for the support vessels under both operating scenarios as specified in the 

draft permit shall include monitoring and maintaining a contemporaneous record of operating and 

standby time within the 25 mile radius of the drilling vessel, determining and recording the sulfur 

content upon receiving each fuel shipment, gallons of diesel fuel on the support vessel entering the 25 

mile radius and gallons of diesel fuel on the support vessel exiting the 25 mile radius.

Statoil will supply the EPA with all records upon request. In addition, Statoil will provide a semi-annual 

report of its emissions information and calculations in accordance with all relevant permit conditions.
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6.0 Best Available Control Technology (BACT) and Recordkeeping 

Requirements

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 PTE in significant amounts. See 40 

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

preliminary determination, NOX is the only regulated NSR pollutant that will be emitted by Statoil in 

quantities exceeding the significant emission rate. Therefore, BACT must be determined for each 

emission unit on the drilling vessels (Developer or Discoverer Americas) which emits NOX while the 

drill ship is operating as an OCS source with the exception of the life boat and fast rescue craft engines.

The life boats and the fast rescue boats are included in the OCS source’s PTE and emissions modeling, 

as required by 40 CFR part 55, and are subject to operating limits, monitoring, recordkeeping and 

reporting requirements to ensure they will not exceed the potential emissions assumed in the application 

and impact review. Vessels operating within 25 miles of the OCS source are not subject to BACT 

requirements unless they are attached to the OCS, and then only the stationary source aspects of the 

vessel are regulated. See 40 CFR § 55.2. These units do not have any stationary source aspects with 

respect to NOX emissions, as they are used for man overboard and emergency escape scenarios only. 

The main generator engines on a drilling vessel continuously operate at variable loads based on drilling 

and operational power demand. Consequently, NOX emissions are not emitted from these engines at a 

steady state. In addition, engine efficiency and performance typically degrades over time, resulting in 

increased NOX emissions. These factors are important considerations in the BACT analysis for these 

engines.

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

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

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

combustion source. 

6.1 BACT Analysis Procedure

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-bycase basis, taking into account energy, environmental, and economic impacts and other costs, 

determines is achievable for such source or modification through application of production 

processes or available methods, systems, and techniques, including fuel cleaning or treatment or 

innovative fuel combustion techniques for control of such pollutant. In no event, shall 

application of best available control technology result in emissions of any pollutant which would 

exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the 

Administrator determines that technological or economic limitations on the application of 

measurement technology to a particular emissions unit would make the imposition of an 

emissions standard infeasible, a design, equipment, work practice, operational standard, or 

combination thereof, may be prescribed instead to satisfy the requirement for the application of 

best available control technology. 
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The CAA contains a similar BACT definition, although the 1990 CAA amendments added “clean fuels” 

after “fuel cleaning or treatment” in the above definition. See CAA § 169(3).

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

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

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

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

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

Step 1: Identify all available control technologies.

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

technically infeasible based on physical, chemical and engineering principles. 

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

emission reduction potential.

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

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

most effective control option.

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

Statoil conducted a NOX BACT analysis for all large (>500 hp) diesel engines operating on the 

Developer (Operating Scenario 1) and the Discoverer Americas (Operating Scenario 2). This analysis 

included the eight main generator engines on the Developer (GEN-1 through GEN-8), six main 

generator engines on the Discoverer Americas (GEN-1 through GEN-6), and the emergency generator 

engines (EGEN) on both drilling vessels.

Statoil also submitted a NOX BACT analysis for the smaller (<500 hp) diesel engines on both drilling 

vessels in their application materials. This analysis included the cement unit engines (CMU-1 and CMU2) on the Developer and the emergency air compressor engines (ACOMP-1 and ACOMP-2) and forklift 

engines (FORK-1 and FORK-2) operating on the Discoverer Americas. 

The diesel-fired cargo tank heater (HTR) on the Discoverer Americas is not included in the diesel engine 

BACT discussion that follows. However, this unit is subject to BACT and appropriate BACT limits are 

included in Tables 6-2 and 6-3 below, as well as in the draft permit. As discussed previously, the heater 

will not be used in the warm waters of the Gulf of Mexico with the exception of testing and 

maintenance. Statoil expects that this will require two hours of operation per year and that PTE from the 

heater would be approximately 0.003 TPY. Based on this information, replacement of the unit or the use 

of any available NOX-reducing add-on technologies would prove economically infeasible. Therefore, the 

EPA has determined that limiting the unit’s operation to less than two hours per year and requiring good 

combustion and maintenance practices for the heater represents BACT for the HTR unit for this project. 

As a unit subject to subpart Dc, as discussed in Section 4.5.1 above, this unit will also be subject to 

monitoring, recordkeeping, and reporting requirements. Statoil has also proposed to limit the use of fuel 

for the heater to diesel containing less than 0.0015 sulfur percent by weight. 
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6.2 Step 1: Identify all Available Control Technologies

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

application submitted in September 2012: 

1. Exhaust Gas Recirculation

2. Ignition Timing Retard 

3. Combustion Air Chiller/Intake Air Cooling 

4. Water Injection 

5. Fuel Water Emulsions

6. Intake Air Humidification

7. Engine Re-Tooling (engine rebuild kits)

8. Derating the Engine

9. NOX Adsorber (NOX Traps)

10. Lean NOX Catalyst or Hydrocarbon SCR 

11. CSNOX Emissions Abatement System

12. Low NOX Engine Design (LND)

13. Engine Replacement to meet higher EPA Tier standards (40 CFR part 89, 94, or 1042)

14. Selective Catalytic Reduction (SCR)

15. High Injection Pressure (HIP)

16. Turbocharger with Aftercooler

17. Good Combustion Practices (GCP)

A description for each technology is included in the September 2012 application, which is contained in 

the administrative record described in Section 9.3 of this document.

6.3 Step 2: Eliminate Technically Infeasible Control Options

A summary of the rationale for either eliminating a technology from further consideration in the topdown BACT analysis for this project or for carrying it through the BACT analysis is listed below for the 

identified options.

Exhaust Gas Recirculation: This technology is in development stages for marine applications and has 

primarily been applied to smaller high speed diesel engines (cars and trucks) and not to large, medium 

bore, medium speed engines such as the main generator engines and emergency generator engines. In 

addition, use of exhaust gas recirculation can increase engine oil acidity, resulting in inefficiency and 

increased engine wear and potentially reducing engine power output which can hinder safe drilling 

operations.

Ignition Timing Retard and Intake Air Coolers: Although not specifically discussed as technically 

infeasible in the application, the EPA is aware that these options are technically infeasible since it would 

require derating the engine (see discussion of engine derating below in this section) and reducing power 

available from the engine. This would affect the ability to safely maintain the vessels’ position if used on 

the large engines and impair the operation of other engines while performing functions associated with 

drilling operations. Furthermore, ignition timing increases exhaust temperatures, which may adversely 

impact exhaust valve life and turbocharger performance.

Water Injection: This technology is in development stages for marine applications and cannot be used 

at low loads (30-40%). In addition, large quantities of fresh water are required with use of water 
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injection. Fresh water storage requirements are problematic with the limited space available on drilling

vessels. Furthermore, based on information provided by engine manufacturer Wärtsilä, water injection

can cause damage to engine components, turbochargers, and air coolers. This technology could also 

decrease the available power, which would cause a safety risk on the drilling vessels. Similarly, the 

combination of exhaust gas recirculation and water injection is also considered technically infeasible.

Fuel-Water Emulsions: Emulsified fuel systems were designed for and installed on slow-speed engines 

burning heavy fuel oil. The existing engines on the Developer and the Discoverer Americas are designed 

for and will be burning medium density fuel (diesel) and will be operated at varying loads. Installing an 

untested emulsified fuel system designed for heavy fuel oil use on the existing engines increases the 

potential for mechanical failure and poses an unacceptable safety risk. In addition, this technology is 

considered technically infeasible due to problems associated with limited storage space for the fresh 

water that is required for emulsion and concerns regarding fuel tank corrosion from the circulating fuelwater emulsion.

Intake Air Humidification: Intake air humidification systems require up to double the volume of fresh 

water for vaporization that the water injection and emulsion systems discussed above involve. 

Limitations of available space to store the water and to install the necessary heat exchanger render the 

installation of an intake air humidification system technically infeasible on these offshore drilling 

vessels. Additionally, the heat required to vaporize the water is provided by the hot air from the engine 

turbocharger, which at low loads may not provide enough heat to operate the system. As discussed 

previously, the main engines operate at varying loads and often at low loads.

CAM Shaft Retrofit Kits/Re-Tooling: According to the kit manufacturer, the camshaft retooling kit is 

only available for two-stroke Detroit Diesel engines (model series 71 or 92) and has not been developed 

for engines such as those used on the drilling vessels. 

Derate Engines: While derating the engines can potentially reduce NOX emissions, this would likely

decrease available power to the engines. A decrease in available power reduces the vessel’s ability to 

maintain correct positioning during storms and loop current events and can impair the performance of 

the auxiliary engines during drilling activities, thereby causing an unacceptable safety risk on the 

drilling vessels. 

NOX Adsorber: This technology is in the development stage and has been used primarily for on-road 

diesel applications or off-road applications for smaller engines such as backhoes, graders, and wheel 

loaders. According to the technology provider (Johnson Matthey Catalyst), neither technology is 

available for engines currently equipped on the drilling vessels. 

Lean NOX Catalyst or Hydrocarbon SCR: As with the adsorber technology discussed above, these 

technologies are in the development stage and have been used primarily for on-road diesel applications 

or off-road applications for smaller engines such as backhoes, graders, and wheel loaders. Neither 

technology is available for engines currently equipped on the drilling vessels.

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

demonstration phases of development. Ecospec, the manufacturer, has tested the system on engines 

operating at stable loads and found the technology reduces approximately 66% of NOX emissions as 

well as 70% of CO2 and 99% of SO2 emissions. While this technology is commercially available for 
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certain types of marine uses, it has not been demonstrated in practice for variable load engines and is 

therefore technically infeasible for this project. 

Low NOX Engine Design (LND): Although identified as an available control technology in Step 1 of 

the BACT analysis, the EPA understands that this would be technically infeasible because LND is 

inherent to engine design and would necessitate a replacement of any engine not manufactured with 

LND. Engine replacement is discussed separately in this section.

Engine Replacement for the Developer Main Generator Engines (GEN-1 through GEN-8): Based 

on data provided with the application materials, the main generator engines on the Developer meet EPA 

40 CFR part 94 Tier 2 NOX emission standards. Although these engines were manufactured prior to the 

2007 model year applicability date for Tier 2 emission standards established for engines of this size, 

Statoil has demonstrated that they comply with the appropriate EPA Tier 2 standard with manufacturer 

emissions testing and IMO certification. Currently, there is no comparable “newer” engine on the market 

able to meet lower emission standards without the use of add-on control technology. Therefore,

replacement engines would not be required for these engines and this option is not carried through the 

next step of the BACT analysis.

Engine Replacement for the Discoverer Americas Main Generator Engines (GEN-1 through GEN6): Based on data provided with the application materials, the main generator engines on the Discoverer 

Americas meet EPA 40 CFR part 94 Tier 1 NOX emission standards. Statoil has demonstrated that they 

comply with the EPA Tier 1 standard with manufacturer emissions testing and IMO certification. 

Comparable lower NOX-emitting replacements for the existing Category 3 marine engines would have to 

be newly constructed to the more stringent EPA Tier 2 standards in 40 CFR part 1042. Replacement of 

these engines with comparable units having a more stringent certification rating was considered 

technically feasible depending on the ability to satisfy size, space and weight restrictions for each engine 

while maintaining the same power rating and displacement to avoid any possible safety risk from a loss 

of power. Therefore, this option was carried through the next steps of the BACT analysis for these 

engines as discussed in Sections 6.4 and 6.5.

Engine Replacement for the Developer and Discoverer Americas Emergency Generator Engines 

(EGEN): The emergency generator engines on the Discoverer Americas and the Developer currently 

meet EPA Tier 1 NOX emissions standards and are certified to meet IMO Tier 1 emission standards, 

based on documentation provided in the application materials. Compliance with the appropriate 40 CFR 

part 1042 Tier 3 and Tier 4 standards is an inherent part of engine design and no engine modifications or 

retrofits are currently available. Therefore, to meet more stringent standards, the engines would have to 

be replaced with newer engines capable of the same performance under the same operating conditions. 

However, in each case, the emergency generator engine was sized to meet vessel space and weight 

distribution requirements in the vessel’s design phase. Replacement of the engine may require a redesign 

of the engine bed frame and structural modifications of the vessel that could subsequently require 

recertification of the ship or rig. As discussed above in connection with the exemption of the emergency 

generator engine on the Discoverer Americas from 40 CFR part 60 subpart IIII, the EPA concluded that 

replacing the emergency generator engine with a subpart IIII-compliant engine is technically infeasible. 

Likewise, based on the technical limitations identified in the application materials, EPA concludes that 

replacing the emergency generator engines for the Developer and Discoverer Americas is technically 

infeasible as BACT for this project. Note that Statoil included cost information in their application; 

however, since EPA considers this option technically infeasible it was not relied upon in making our 

determination. 
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Engine Replacement for the Developer and Discoverer Americas Small Diesel Engines: After 

analyzing the identified control technologies, all were eliminated as technically infeasible for control of 

NOX emissions from the smaller diesel engines on the Developer and the Discoverer Americas except 

replacement with engines meeting stricter EPA Tier certification standards. Existing units CMU-1 and 

CMU-2 on the Developer are EPA Tier 2 certified. Likewise, the units FORK-1 and FORK-2 on the 

Discoverer Americas are EPA Tier 4 certified. No comparable, higher rated engines are currently 

available to replace these units. 

The emergency air compressor engines on the Discoverer Americas (ACOMP-1 and ACOMP-2) have 

not been shown to comply with any EPA or IMO standard. Therefore, these engines are evaluated 

further in the BACT analysis with respect to engine replacement. As with the larger diesel engines 

discussed previously, the emergency air compressor engines were sized to meet the drill ship’s space 

and weight distribution requirements in the vessel’s design phase. Replacement of the engine with the 

most stringent 40 CFR part 1042 Tier 4 design could require a redesign of the engine bed frame and 

vessel structural modifications that could subsequently require recertification of the ship. As discussed 

above in connection with the exemption of the emergency air compressor engines on the Discoverer 

Americas from 40 CFR part 60 subpart IIII, EPA concluded that replacing the emergency air compressor 

engines with subpart IIII-compliant engines is technically infeasible. Likewise, based on the technical 

limitations described in the application materials, EPA concludes that replacing the emergency air 

compressor engines would be technically infeasible as BACT for this project. Note that Statoil included 

cost information in their application; however, since EPA considers this option technically infeasible it 

was not relied upon in making our determination.

SCR for the Discoverer Americas Main Generator Engines (GEN-1 through GEN-6): The main 

generator engines on the drilling vessels operate at highly variable loads based on power needs related to 

specific drilling activities, environmental conditions, and safety needs. This means that these engines 

rarely operate at a steady load for any extended period of time. These operating conditions result in 

inconsistent exhaust gas temperatures that affect the operation and effectiveness of an SCR system. The 

temperature of the exhaust gas is critical to selecting the correct catalyst, reducing the amount of 

unreacted reducing agent (e.g., urea) released, and minimizing the creation of additional NOX from the 

reducing agent. Therefore, the NOX reduction efficiency would likely be considerably less than the 90 

percent that is representative of the reduction efficiency of SCR under steady loads. Weight and space 

constraints are additional technical considerations on drilling vessels, which are typically designed for 

maximum space utilization and efficiency. Therefore, additional space for the SCR equipment and 

reducing agent storage tanks that was not originally part of the vessel design is often unavailable. 

Additionally, drilling vessels are required to stay within specified overall weight and weight distribution 

limits to ensure that safety requirements for stability and buoyancy are met.

Based on information contained in Statoil’s September 2012 application, space limitations on the 

Discoverer Americas would not allow installation of the SCR equipment and urea storage tank without 

removal of a main generator engine. Engine removal would reduce available power to the vessel 

creating a safety risk and could affect the vessel’s ability to maintain correct positioning during storms 

and loop current events. Therefore, SCR is considered to be technically infeasible as BACT for the main 

generator engines installed on the Discoverer Americas.

SCR for the Developer Main Generator Engines (GEN-1 through GEN-8): Many of the technical 

considerations discussed above for the main generator engines installed on the Discoverer Americas

apply to the Developer’s main generator engines as well. This includes space constraints, inconsistent 
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exhaust gas temperatures, and reduced efficiency of the SCR system. Wärtsilä, the engine manufacturer, 

estimated that a storage tank of roughly the same size and weight as one of the main generator engines 

would be required for this project. However, since it may be possible to install the SCR systems without

removal of existing equipment, as opposed to conditions on the Discoverer Americas, the applicant 

determined that this technology could be considered technically feasible for the Developer’s main 

generator engines. Therefore, SCR was carried through Steps 3 and 4 of the BACT determination for 

these engines. The applicant performed a cost analysis which is discussed in Section 6.5 of this 

document. 

SCR for the Developer and Discoverer Americas Emergency Generator Engines (EGEN): Based on 

technical references, SCR technology is not feasible for standby engines such as the emergency 

electrical generator that will be run intermittently and in emergency situations only. Note that Statoil

included cost information in their application; however, since EPA considers this option technically 

infeasible it was not relied upon in making our determination.

SCR for small (<500hp) diesel engines: Based on vendor information and literature searches, SCR 

technology is not available for the smaller engines on board the drilling vessels.

Turbocharger and Aftercooler: All of the diesel engines on the Developer and the Discoverer 

Americas are equipped with a turbocharger and aftercooler.

6.4 Step 3: Rank the Remaining Control Technologies by Effectiveness

The control options not eliminated as technically infeasible in Step 2 of the top-down BACT analysis 

were then ranked by effectiveness. Table 6-1 lists the control technologies that have not been ruled out 

as technically infeasible options. These options are then ranked by effectiveness for the main generator 

engines and the emergency generator engines on each drilling vessel as well as the emergency air 

compressor engines on the Discoverer Americas.

Table 6-1: Step 3 Control Technologies Ranked by Effectiveness

Engine Rank Control Description NOx Control 

Effectiveness

Developer

Main Generator Engines

(GEN-1 through GEN 8)

1 SCR with urea injection Up to 75%

2 40 CFR part 94 Tier 2 Compliant Design

including turbocharger, aftercooler, HIP and 

low NOX tuning with good combustion 

practices

Baseline

Discoverer Americas

Main Generator Engines

(GEN-1 through GEN-6)

1 40 CFR part 1042 Tier 2 standards (i.e., 

engine replacement for existing engines)

Up to 20%

2 40 CFR part 94 Tier 1 compliant design 

including turbocharger, aftercooler and HIP

with good combustion practices

Baseline

Developer

Emergency Generator

(EGEN)

1 40 CFR part 94 Tier 1 compliant design 

including turbocharger, aftercooler and 

electronic fuel injection with good 

combustion practices

Baseline

Discoverer Americas

Emergency Generator

(EGEN)

1 40 CFR part 94 Tier 1 compliant design 

including turbocharger, aftercooler and HIP 

with good combustion practices

Baseline
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Discoverer Americas

Emergency Air Compressor Engines

(ACOMP-1 and ACOMP-2)

1 Turbocharger and aftercooler with good 

combustion practices

Baseline

6.5 Step 4: Evaluate the Energy, Environmental and Economic Impacts

SCR with Urea Injection on Developer Main Generator Engines: Use of any SCR system comes 

with additional environmental concerns. SCR systems can allow ammonia to pass through un-reacted

releasing ammonia into the atmosphere when exhaust temperatures are too low for the ammonia to react 

or the catalyst has degraded, a condition referred to as ammonia slip. The released ammonia is reactive 

in the atmosphere, generating odors, fine particulate matter, visibility concerns, and measurable opacity 

problems. Depleted catalysts from SCR systems can be considered hazardous wastes requiring 

appropriate management and disposal. In addition, when used on the OCS, transportation, storage, and 

handling of large quantities of urea for injection pose a potential threat to the surrounding marine 

environment from leaks and spills. 

In their September 2012 application and a January 2013 revised cost analysis, Statoil examined the 

environmental concerns discussed above, as well as the cost effectiveness of installing and operating 

SCR to control NOX emissions from the Developer’s main engines. Statoil provided estimates from 

engine manufacturer Wärtsilä and additional information indicating that a 75% reduction in NOX could 

be achieved with installation of SCR. The emissions reductions were based on the applicant’s originally 

proposed NOX BACT emission limit of 8.2 g/kW-hr for an engine without SCR and 2.0 g/kW-hr for an 

engine with SCR. The estimated average cost effectiveness of reducing the resultant 32.74 TPY of NOX

from each of the eight main engines was $22,286 per ton removed. Therefore, Statoil concluded that 

SCR should be eliminated as BACT as cost ineffective. 

As discussed previously, the main generator engines on a drilling vessel continuously operate at variable 

loads based on drilling and operational power demand. Consequently, NOX is not emitted from these 

engines at a steady state and exhaust temperature varies. The EPA believes that inconsistent exhaust gas 

temperatures from engines working at constantly varying loads and often at very low loads, as these 

engines do, would make an SCR system technically infeasible. At a minimum, the efficiency of the SCR 

system would be reduced and would likely be rendered ineffective for much of the engines’ operating 

time. This would contribute to significant ammonia slip when exhaust temperatures fall below 

approximately 300°C. However, since Statoil feels that the technology could potentially be feasible, the 

EPA evaluated the cost analysis included in the application materials.

The EPA’s independent cost analysis excluded the estimated Direct Annual Costs from Statoil’s analysis 

because there was no supporting documentation. As a result, the total cost effectiveness of installing and 

operating an SCR was calculated to be approximately $20,171 per ton of NOX removed. Therefore, the 

EPA concludes that requiring SCR to control NOX emissions is not cost effective and is not BACT for 

the Developer’s main generator engines.

Meeting Higher EPA Tier 2 Standards (40 CFR part 1042) with Engine Replacement of Main 

Generator Engines on the Discoverer Americas: Since Tier 2 standards of 40 CFR part 1042 are 

intrinsic to an engine’s original design, the Discoverer Americas’ main engines would have to be 

replaced with newer engines designed to meet the lower standards. The applicant provided information 

regarding the cost effectiveness of replacing the Discoverer Americas’ Category 3 main engines with 
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newer diesel engines meeting EPA Tier 2 emission standards found in 40 CFR part 1042 to achieve a 

control efficiency of approximately 20%. Based on the originally proposed BACT emissions limit for 

the EPA Tier 1 compliant engines of 12.07 g/kW-hr of NOX emissions and the calculated EPA Tier 2 

standards for Category 3 engines with 720 rpm of 9.7 g/kW-hr, the applicant estimated that 10.37 TPY

of NOX from each of the six main generator engines would be removed. Statoil estimated 100 days of 

downtime (16.7 days per engine) would be needed to replace the six engines at $500,000 per day. They 

calculated the average cost effectiveness to be approximately $85,821 per ton removed, and concluded 

that replacing the main engines is not cost effective and should be eliminated as BACT. 

The applicant based the cost effectiveness of replacing the main engines on the Discoverer Americas

solely on the downtime associated with the vessel. The EPA considers the cost associated with the 

downtime of the ship to be an appropriate retrofit cost similar to that of “lost production” as discussed in 

Chapter 2 of the EPA Air Pollution Control Cost Manual. Since the purpose of an exploratory drill ship

is to gather information about a potential well site for the operator, it is reasonable to equate the loss of 

this information with the idea of lost production typical of a more traditional manufacturing facility. 

When evaluating the replacement of engines on the Discoverer Americas as well as the SCR 

installations discussed above, it is appropriate to consider the daily lease rate paid by the applicant as 

“lost production” in the capital cost portion of the BACT cost analyses, but only for those days that 

information gathering activities would have taken place. The EPA concluded that the cost analysis 

submitted by the applicant was done appropriately and is conservative since it does not include any 

capital or annual costs in addition to lost production costs. Therefore, the EPA concludes that requiring 

replacement of the main engines on the Discoverer Americas with newer engines to control NOX

emissions from this particular project is not cost effective and is not BACT.

It should be noted that calculations in the September 2012 application erroneously used eight engines to 

determine the start-up costs related to 100 days of vessel downtime (12.5 days per engine) resulting in 

$6,250,000 Total Indirect Cost per engine. If 100 days are needed to replace six engines (16.7 days per 

engine), as was confirmed in Statoil’s December 2012 submittal, the cost would be $8,333,333 and the 

cost effectiveness would be $112,504 per ton of NOX removed. The conclusion that this is not cost 

effective and not BACT for these engines would not change.

6.6 Step 5: Select BACT

After taking into account energy, economic and environmental impacts discussed above in Step 4 of the 

BACT analysis, the EPA determined that the control options ranked in Step 3 of the top-down BACT 

analysis for diesel engines on the Developer and Discoverer Americas are BACT as summarized in 

Table 6-2. The EPA’s BACT conclusion for the cargo tank heater on the Discoverer Americas is also 

included in Table 6-2.

Developer Main Engines: The EPA proposes NOX emission limits of 8.6 g/kW-hr as BACT for the 

main engines on the Developer. This limit is based on IMO certification data included with the 

application materials and a 5% margin of compliance to account for the variability of each engine’s NOX

emission rate with the varying engine load level and the number of operating hours each engine has 

logged since significant maintenance was last performed. Given the significant load variations required 

by the operations on the drill rig, the EPA has determined an averaging period of 24 hours is appropriate 

in this case. 

Discoverer Americas Main Engines: The EPA proposes NOX emission limits of 12.7 g/kW-hr as 

BACT for the main engines on the Discoverer Americas based on IMO certification data included with 
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the application materials and a 5% margin of compliance to account for the variability of each engine’s

NOX emission rate with the varying engine load level and the number of operating hours each engine has 

logged since significant maintenance was last performed. Consistent with EPA’s past BACT 

determinations for engines on vessels with NOx emissions of 12.7g/k-W-hr, EPA has included 

requirements for an Enhanced Performance Management System (EPMS). The EPMS designed by the 

owner of the drillship, Transocean, is intended to enhance the fuel oil, lubricant oil and power 

management of the main engines on the Discoverer Americas to ensure good combustion efficiency, 

maintain load levels to an average of 40% and minimize emissions. Given the significant load variations 

required by the operations on the drill ship and the information provided by the applicant and vendor, 

the EPA has determined an averaging period of 24 hours is appropriate in this case. 

Emergency Generator Engines: The applicant proposed a NOX emission limit of 9.2 g/kW-hr for the 

emergency generator on the Developer and an operating time of 39 hours per year. However, since the 

emergency generator will only operate approximately 1.5 hours per week, measuring compliance with a 

numeric emission limit would be unreasonably burdensome and costly. Therefore, the EPA has 

determined that BACT for the emergency generator engine is use of work practice standards including 

good combustion practices and operating in accordance with the manufacturer’s specifications. 

The applicant proposed a NOX emission limit of 9.8 g/kW-hr for the emergency generator on the 

Discoverer Americas. However, since the emergency generator will operate less than two hours per 

week (41 hours per year), measuring compliance with a numeric emission limit would be unreasonably 

burdensome and costly. Therefore, the EPA has determined that BACT for the emergency generator is 

use of work practice standards including good combustion practices and operating in accordance with 

the manufacturer’s specifications.

Small Diesel Engines: The application indicates that each cementing unit on the Developer will be used 

on an as needed basis during drilling operations and would operate for up to 60 hours per year. Statoil 

anticipates that each emergency air compressor engine on the Discoverer Americas would be operated 

less than three hours per year during routine checks of their operation, and each forklift on the Discover 

Americas would operate for 237 hours per year. Given the limited use of these emission units, the EPA 

has determined that BACT is more appropriately implemented as work practice standards to include 

either the use of EPA Tier-certified engines and/or good combustion practices. Furthermore, to maintain 

consistency with the emission estimates in the permit application, the draft permit includes operational 

limits for these units. 

Table 6-2: BACT Conclusions

Operating Scenario 1 Emission Units Control Option Emission 

Limit

Developer Main Generator Engines 

(GEN-1 through GEN-8)

Use of main engines with 40 CFR 94 

Tier 2 compliant design (including 

low NOX tuning, turbocharger, aftercooler, and high injection pressure) 

with good combustion practices based 

on current manufacturer 

recommendations.

8.6 g/kW-hr

Developer Emergency Generator

Engine

(EGEN)

Use of engine with 40 CFR 94 Tier 1

compliant design (including 

turbocharger, after cooler and 
32

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electronic fuel injection) with good 

combustion practices based on current 

manufacturer recommendations.

Developer Cementing Unit Engines

(CMU-1 and CMU-2)

Use of engine with 40 CFR 94 

compliant design and good 

combustion practices. 

Operating Scenario 2

Discoverer Americas Main Generator Engines 

(GEN-1 through GEN-6)

Use of main engines with 40 CFR 94 

Tier 1 compliant design (including 

turbocharger, after cooler and high 

injection pressure) with good 

combustion practices based on current 

manufacturer recommendations.

12.7 g/kW-hr

Discoverer Americas Emergency Generator

Engine

(EGEN)

Use of engine with 40 CFR 94 Tier 1

compliant design (including 

turbocharger, after cooler and high 

injection pressure) with good 

combustion practices based on current 

manufacturer recommendations with 

use of EPMS and NOx measurement 

system.

Discoverer Americas Forklift Engines

(FORK-1 and FORK-2)

Use of engine with 40 CFR 1039 

(Non-road) Interim Tier 4 compliant 

design with good combustion 

practices based on current 

manufacturer recommendations.

Discoverer Americas Emergency Air 

Compressor Engines

(ACOMP-1 and ACOMP2)

Use of engine with turbocharger and 

after cooler with good combustion 

practices based on current 

manufacturer recommendations.

Discoverer Americas Cargo Tank Heater

(HTR)

Use of good combustion practices 

based on current manufacturer 

recommendations.

7.0 Summary of Air Quality Impact Analyses

7.1 Required Analyses

The PSD rules at 40 CFR § 52.21(k) require the permit applicant to demonstrate that, for all regulated 

air pollutants that would be emitted at or in excess of the significant emissions rates provided in 

40 CFR § 52.21(b)(23)(i), the allowable emission increases from a proposed new major stationary 

source, in conjunction with all other applicable emission increases or reductions at the source, would not 

cause or contribute to a violation of any NAAQS nor cause or contribute to a violation of any applicable 

“maximum allowable increase” over the baseline concentration in any area (known as PSD increments).5

 

5

The maximum allowable PSD increments are listed in 40 CFR § 52.21(c).
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The ambient air quality impact analysis must be based on air quality models, databases, and other 

requirements specified in 40 CFR part 51, Appendix W, Guideline on Air Quality Models.

As discussed in Section 4 above and provided in Table 4-1, under the proposed OCS permit for 

exploration drilling operations in the Gulf of Mexico, the potential emissions from the proposed OCS 

source would be above the PSD significant emission rate for NOX. Emissions of other measured air 

pollutants do not equal or exceed the significant emission rates. NOX is the measured pollutant for NO2

and ozone. Therefore, the NO2 and ozone NAAQS and NO2 PSD increments are relevant to the air 

quality impact assessment. 

As required by the May 8, 2008, final rules governing NSR implementation for fine particulate matter, 

73 Fed. Reg. 28,321 (May 16, 2008), PSD permits must address directly emitted PM2.5 as well as the 

pollutants responsible for secondary formation of PM2.5 which include SO2, NOX, VOC, and ammonia. 

Direct project emissions of PM2.5 will not be significant, but the project will have increases of NOX

greater than the threshold of 40 tons per year. Therefore, Statoil must address compliance with the 24-

hour and annual PM2.5 NAAQS. 

Under 40 CFR § 52.21(m), a PSD permit application must include an air quality analysis in connection 

with the demonstration required by 40 CFR §52.21(k). For each pollutant for which a NAAQS or PSD 

increment exists, 40 CFR § 52.21(m)(1)(iv) requires the analysis to include at least one year of preconstruction ambient air quality monitoring data, unless the EPA approves a shorter monitoring period 

(not less than four months). 40 CFR § 52.21(i)(5)(i) allows exemption from the requirement for preconstruction ambient monitoring if the net emissions increase of a pollutant from the proposed source or 

modification would cause air quality impacts less than the ambient monitoring thresholds (i.e., 

Significant Monitoring Concentrations) listed in 40 CFR § 52.21(i)(5)(i), which are provided in Table 7-

1. 40 CFR § 52.21(m)(2) requires post-construction ambient air quality monitoring if the EPA 

determines it is necessary to determine the effect that emissions from the source or modification may 

have on air quality.

An additional impact analysis is required by 40 CFR § 52.21(o), including an analysis of the impairment 

to visibility, soils and vegetation that would occur as a result of the proposed source modification, or 

that would occur as a result of any commercial, residential, industrial and other growth associated with 

the source modification. Analysis for vegetation having no significant commercial or recreational value 

is not required.

For sources impacting Federal Class I areas,640 CFR § 52.21(p) requires the 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 the EPA concurs 

with the demonstration, the rules require that the EPA shall not issue the PSD permit.

7.2 PSD Class II Air Quality Impact Assessment

An air quality impact assessment was performed for the operation of both the Maersk Developer and 

Transocean Discoverer Americas deepwater drilling vessels and associated support vessels. The 

 

6

Class I areas are defined in 40 CFR § 52.21(e). Mandatory Class I areas (which may not be redesignated to Class II or III) are international parks, national 

wilderness areas larger than 5,000 acres, memorial parks larger than 5,000 acres, and national parks larger than 6,000 acres.
34

Statoil OCS-EPA-R4012 080913

modeled operating scenario of each vessel was that which produced the worst-case impact for each 

vessel and operation. 

As discussed in Section 4.0, the estimates of maximum annual emissions of all pollutants from the two 

possible drilling vessels and their respective supporting vessels resulted in estimated emissions of NOX

greater than the significant emissions rate. Hence, NOX is subject to ambient impact assessment. This 

pollutant is also a measured pollutant for ozone and a precursor for PM2.5. Therefore, impact 

assessments are also provided for ozone and PM2.5.

An impact assessment addressing the project’s potential impact on the ambient NAAQS and PSD 

increment is performed in two stages. The initial stage estimates the impact of only the project’s 

emissions to determine if they will cause a significant ambient impact, i.e., an impact equal to or greater 

than the PSD significant impact levels. If no project pollutant subject to review causes a significant 

impact, the project is not considered to significantly contribute to any NAAQS or PSD increment 

violation. Therefore, there is no need to perform the second stage modeling that includes the project and 

applicable other emission sources in a cumulative assessment to determine NAAQS and PSD increment 

compliance subsequent to the project’s operation. 

The modeling procedures took into consideration the January 22, 2013, decision by the federal Court of 

Appeals for the District of Columbia Circuit (D.C. Circuit) concerning use of the PM2.5 significant 

monitoring concentration (SMC) and significant impact levels (SIL) as the basis for exemption from 

pre-construction air quality monitoring and cumulative NAAQS and PSD increment compliance 

modeling. See Sierra Club v. EPA, 705 F.3d 458 (D.C. Cir. 2013). The D.C. Circuit vacated and 

remanded the PM2.5 SILs. Accordingly, project impacts less than the SILs cannot serve as the sole

justification for eliminating cumulative NAAQS and PSD increment compliance modeling. While 

permit applicants may continue to use the PM2.5 SILs in their analysis, they must provide additional 

information and justification to support a conclusion that a project’s impacts will not cause or contribute 

to a NAAQS or PSD increment exceedance.

The court also vacated the PM2.5 SMC. As a result of the court’s decision, project impacts less than the 

SMC can no longer be used to exempt the project from pre-construction ambient air quality monitoring. 

However, permit applicants may use existing air quality observations in lieu of pre-construction 

monitoring if supporting information demonstrates that the existing ambient air quality data provides

representative or conservative ambient concentrations for the impact area.

The ambient impact modeling was performed using dispersion and transport models and modeling 

techniques that follow the EPA regulatory guidelines (see 40 CFR Part 51, Appendix W) and applicable 

guidance memorandum (see Support Center for Atmospheric Modeling (SCRAM); 

http://www.epa.gov/scram001/). 

Since the proposed drilling will occur at several locations within the DeSoto Canyon lease blocks, the 

worst case emissions were assumed to be located at the drilling site where the greatest onshore and 

nearshore impacts could occur. The OCS project impact area for the Class II area analysis, the area 

containing modeling receptors, was established 25 nautical miles from any state’s seaward boundary,

extending shoreward until the project’s estimated impact is less than the significant impact level. For 

this project the nearest Class II area receptor is more than 50 km from the closest drilling location. 
35

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7.2.1 Air Quality Model Selection

Because the closest Class II area receptor is more than 50 km from the nearest proposed drilling 

location, the air quality impact analyses involve long-range transport and dispersion conditions. The 

EPA’s preferred model for long-range transport assessments (CALPUFF/CALMET modeling system 

Version 5.8 (release 070623)) was selected to estimate potential impacts in the OCS Class II area. It 

should be noted that this same EPA-preferred long-range transport and dispersion model is appropriate 

for the PSD Class I impact assessment. In addition, the Class II coherent plume visibility assessment 

was performed using the VISCREEN model (Version 88341). Figure 7-1 provides the modeling domain 

used in the PSD Class II and Class I assessments as well as locations of other significant features (e.g.,

nearest PSD Class I area).

Figure 7-1 CALPUFF Modeling Domain

Image reproduced from the Revised Air Quality Impact Assessment dated June 2013 from ENVIRON.

7.2.2 Characteristics of Modeled Operational Scenarios

The primary NOX emission sources associated with the proposed exploration drilling activities are the 

diesel-fired engines on the drillships. Additionally, the OCS air regulations define the OCS source to 

include direct emissions from vessels servicing the OCS sources while en route to and from the source 

when within 25 miles of the drilling operation. Therefore, the impacts from the associated fleet of 

vessels that support the primary drilling activity were included. 

The Developer drillship and support vessel NOX emission sources include the following:

• Main Diesel Generator Engines (8),

• Emergency Generator Engine (1),

Modeling Domain – Dark Blue

25-nautical mile Receptors – Red

Class I Receptors – Purple

Radii – Light Blue
36

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• Cementing Unit Diesel Engines (2),

• Life Boat Engines (4),

• Rescue Boat Engine (1),

• Fuel Storage Vessels,

• Fugitives Emissions (diesel fuel system),

• Support Vessels (e.g., crew boats), and

• Painting and Welding Activities.

The Discoverer Americas drillship and support vessel NOX emission sources include the following:

• Main Diesel Generator Engines (6)

• Emergency Generator Engine (1)

• Life Boat Engines (6)

• Rescue Boat Engine (1)

• Emergency Air Compressor Engines (2)

• Forklift Engines (2)

• Fuel Storage Vessels

• Fugitives Emissions (diesel fuel system)

• Support Vessels (e.g., crew boats), and

• Painting, Cement/Mud Mixing, and Welding Activities.

The basis for the maximum short-term (1 to 24 hour) and long-term (annual) emission rates modeled for 

these sources are discussed below.

The Developer is a self-powered, dynamically positioned semi-submersible drilling vessel with pontoon 

structures below the water surface and a platform above the surface. The Discoverer Americas is a 

dynamically positioned drill ship. Each vessel uses a computer controlled sensor system to maintain 

position and heading over its location using the vessel’s propellers and thrusters. Neither drilling vessel 

requires towing or anchoring vessels as part of its fleet. Because of the long distance to the nearest 

modeled receptor, the vessel orientation and building downwash considerations should not significantly 

affect the modeled impacts. 

Multiple operating scenarios for each drilling vessel were considered including a range of emissions and 

release parameters (including partial loads) and varying locations of associated support vessels. These 

scenarios were evaluated to determine which scenario would result in maximum short-term and longterm impacts at the modeled receptors. The following described operating scenarios were determined to 

produce the worst-case impacts.

For each drilling vessel scenario (Maersk Developer or Transocean Discoverer Americas), two sets of 

emission rates were developed, short-term and long-term rates. The short-term emission rates were used 

for the following assessments, as applicable:

• Class II 1-hour NO2 SIL (NAAQS)

• Class I and II 24-hour PM2.5 SIL (NAAQS and PSD Increment)

• Class I and II visibility 

The long-term emission rates were used for the remaining assessments:
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Statoil OCS-EPA-R4012 080913

• Class I and Class II annual NO2 SIL (NAAQS and PSD Increment)

• Class I and II annual PM2.5 SIL (NAAQS and PSD Increment)

• Class I annual Nitrogen deposition rate

The Developer’s modeled maximum 1-hour emissions are based on five main generator engines 

operating at 60% load and auxiliary equipment (i.e., emergency generator engine, life boats, fast rescue 

boat and cementing unit engines) operating at 100% load. Hourly emissions for support vessels (i.e., 

crew boats and supply boats) are derived from the maximum fuel usage rates, specific engine data, and 

emission information for the respective vessels. Annual emissions for the annual NO2 modeling analysis 

are based on three main engines operating at 60% load, all auxiliary equipment at 100% load, and 

support vessels based on the maximum engine operation and fuel use for the proposed annual run time 

(i.e., crew boat at 618 hours/year resulting in 235,176 gallons of diesel fuel per year and OSV at 2,570

hours/year resulting in 621,468 gallons of diesel fuel per year for operation within 25 nautical miles of 

the drilling vessel). 

The Discoverer Americas modeled maximum 1-hour emissions are based on four Main Generator 

engines operating at 80% load and the emergency generator engine operating at 70% load (testing 

scenario). Auxiliary equipment (i.e., emergency air compressor engine, forklift engine, life boats and 

fast rescue boat) operate at 100% load. Hourly emissions for support vessels are derived from the 

specific engine data and emission information for the respective vessels. Annual emissions are based on 

three Main Generator engines operating at 35% load and the emergency generator engine operating at 70% load

(testing scenario). Annual emissions also include all auxiliary equipment at 100% load and support 

vessels based on the adjusted fuel usage and maximum engine operation for the proposed annual run 

time. The basis for the support vessel emissions (i.e., crew boats and supply boats) for both the hourly 

and annual periods is the same for both drilling vessels.

Statoil is requesting authorization for either the Developer or the Discoverer Americas drilling vessel, 

and its associated support fleet, to operate in any of Statoil’s lease blocks located within the eastern Gulf 

of Mexico as listed in Section 2.2 of this document. To ensure the modeled worst-case impact conditions 

include the worst-case project location, all impact modeling estimates were performed with the drilling 

vessel located at the northwest corner of the closest lease block to the shoreline and to the nearest PSD 

Class I area (Breton National Wildlife Refuge (NWR)). 

The modeling locations of the associated support vessels (i.e., crew boats and OSVs) for each drilling 

vessel can also affect the modeled impacts. The modeled worst-case impact location for the crew boats

and OSVs is 25 nautical miles from the main drilling vessel in the direction of the closest receptor (i.e., 

toward the Breton NWR). 

The Developer and Discoverer Americas drilling vessels require no support vessels during deployment 

so there is no distinction between the maximum 1-hour and maximum 24-hour emission rates used for 

the Class I visibility assessment. 

In addition to emission rates, the modeling analysis requires information regarding stack heights and 

other exit parameters that characterize exhaust flow from emission points. These release characteristics 

have an important influence on the results of the analysis. Exhaust stack parameters for the Developer 

and Discoverer Americas drilling vessels, as well as the crew boats and OSVs, are provided in the 

September 2012 Outer Continental Shelf Title V and PSD Permit Application DeSoto Canyon Drilling 

Exploration Project and June 2013 Revised Section 6 - Air Quality Impact Assessment documents 
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contained in the Administrative Record (see Section 9.3). Maximum short-term and long-term emission

rates are provided in this document.

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 II and Class I impact 

assessments. This 4-km VISTAS Domain 2 dataset was developed by the Federal Land Managers using 

the approved 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, nine overwater stations and 92 

to 103 precipitation stations, depending on the meteorological year. This sub-domain includes a 50 km 

buffer past the Breton Class I area, far enough east for receptors along western Florida, and far enough 

south to include a 100km buffer around the drilling location to allow re-circulation of puffs.

7.2.4 Building Downwash

Building downwash accounts for the effect of nearby structures on the flow of emissions from their 

respective release structures. However, as noted above, building downwash effects were not included in 

the modeling as they will not significantly affect concentrations when the nearest receptors are located 

more than 100 km from the location of the emissions. Because of this, FLMs typically do not request 

downwash be included in long-range PSD Class I impact assessments.

7.2.5 Receptor Locations

The seaward boundaries and Air Quality Control Regions for Louisiana, Mississippi and Alabama 

extend for three nautical miles offshore and for nine nautical miles offshore Florida. For the Statoil 

Class II modeling analysis, discrete receptors were located 25 nautical miles from the seaward 

boundaries of Louisiana, Mississippi, Alabama, and Florida. The receptors were placed at 1-km intervals 

but controlling concentrations were resolved to 100-m, if needed. The location of these receptors is 

shown in Figure 7-1 as the dark/red line parallel to the shoreline. Because all of these receptors are over 

water, terrain elevations were assigned an elevation of 0 m (i.e., sea level) for the Class II impact 

analysis: [Note: Class I receptors for the Breton Wilderness were obtained from the National Park 

Service website (http://www.nature.nps.gov/air/Maps/Receptors/index.cfm). These FLM-specified 

receptors include elevations that range from 0.021 to 0.375 m.]

7.2.6 Project Impact Assessment

This section presents the estimated ambient concentrations associated with the emissions from the 

proposed Statoil exploration activities. If a pollutant’s estimated impact exceeds an EPA SIL for that 

pollutant, the impacts of the facility must be included with the impacts of other increment-consuming 

sources to evaluate total increment consumption. Exceeding a SIL also requires that the evaluation of 

compliance with the applicable NAAQS take into account background concentrations and the 

contributions of other regional sources. 

The SILs are screening values that have been used since 1980 to identify de minimis impacts. However, 

as discussed above, on January 22, 2013, the D.C, Circuit vacated the PM2.5 SIL and SMC provisions 

adopted in the EPA’s PSD Regulations (40 CFR 51.166 and 40 CFR 52.21). As discussed below, the 

EPA’s review of Statoil’s application is consistent with the D.C. Circuit’s decision.
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The proposed project emissions from the Developer and Discoverer Americas drilling vessels, as well as 

the associated support vessels, were modeled for comparison to the SIL for NO2 and PM2 and SMC for 

NO2.5. The maximum modeled project concentrations at the discrete 25- nautical mile receptors were 

compared to the PSD Class II SILs for NO2 and PM2.5. Similarly, the maximum modeled pollutant 

concentrations at the discrete 25- nautical mile receptors were compared to the SMC for NO2.

The impact modeling results are provided and compared to the SIL and SMC in Table 7-1. Because all 

maximum predicted NO2 concentrations are less than the SIL, the project’s estimated impacts are not 

considered to cause or contribute to a violation of the NO2 NAAQS or PSD increments. Furthermore, all 

maximum predicted NO2 concentrations are also much less than the NO2 SMC; therefore, no preconstruction ambient monitoring is required for NO2.

Table 7-1 

Maximum Modeled PSD Class II Area Concentrations

Pollutant Averaging 

Period

Developer

Max. 

Concentration 

(ug/m3)

Discoverer 

Americas Max. 

Concentration 

(ug/m3)

Significant 

Impact Levels 

(ug/m3)

Significant

Monitoring 

Concentrations 

(ug/m3)

NO2

a

1-hourb5.4 7.3 7.5 None

Annual 0.03 0.04 1.0 14

PM2.5 24-hrb0.10 0.11 1.2 vacated

Annual 0.0009 0.0008 0.3 None

Notes: a NOX was conservatively assumed to be 100 percent NO2.

b Maximum (100 percentile) values are provided not 98th percentile.

The recent vacatur and remand of the PM2.5 SIL resulted in a need for additional demonstration that use 

of the SIL is appropriate to identify insignificant impacts. Similarly, the SMC were vacated so preconstruction ambient air quality monitor is required. Applicants may submit existing ambient air quality 

data collected from existing monitoring networks in lieu of pre-construction monitoring if such data is 

demonstrated to be representative or conservative for the impact area. 

Statoil reviewed the available PM2.5 air quality monitoring data for the Eastern Gulf of Mexico 

(EGOM). Although there are no existing PM2.5 measurements in the vicinity of Statoil’s lease blocks, 

there are a number of shore-based monitors. Because of the scarcity of PM2.5 sources in the EGOM and 

the project’s large distance from land-based sources, the background ambient PM2.5 concentration in the 

EGOM OCS are expected to be lower than any onshore concentrations. Therefore, the existing onshore 

ambient monitoring data will provide conservative background ambient PM2.5 concentrations for the 

project location. The maximum PM2.5 24-hour and annual Design Values from the 18 existing shorebased monitors for the 2009-2011 period were 28 and 10.4 ug/m3

, respectively. 

The PSD PM2.5 24-hour NAAQS is 35 ug/m3and the PSD Class II SIL is 1.2 ug/m3. The annual 

NAAQS is 12 ug/m3and the Class II SIL is 0.3 ug/m3. The difference between the PM2.5 NAAQS and 

the selected conservative ambient background concentrations are larger than the PM2.5 Class II SILs. 

The fact that the maximum impacts from project emissions are substantially less than the SILs (i.e.,

Table 7-1 Class II maximum project impacts are 9.2% of the 24-hour and 0.3% of the annual PM2.5 SIL) 

provides further support for the use of the SILs in this application. Hence, it is reasonable to conclude 

that a proposed source with a PM2.5 impact below the PM2.5 SIL values will not cause or contribute to a 

violation of the PM2.5 NAAQS.
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In terms of the PSD Class I areas where compliance with the PSD increments are of concern, the SILs 

are used as a screening tool to assess whether a full cumulative Class I increment assessment is needed. 

The PM2.5 increments became effective relatively recently (Major Source Baseline date of October 20, 

2010; trigger date of October 20, 2011). Because of different meteorological conditions, PSD increment 

consuming emissions from outside the EGOM would not affect a Class I area at the same time as 

emissions originating from the EGOM. Therefore, given the conservative project emission rates and 

release location (i.e., nearest possible distance to a Class I ambient receptor), the small number of other 

possible PM2.5 increment consuming emission sources in the EGOM and onshore areas, and the unlikely 

combined simultaneous contributions from land-based and OCS PM2.5 emission sources, the use of the 

PM2.5 Class I SILs should not jeopardize PSD Class I increments. 

7.2.7 Ozone

Both VOC and NOX are precursors to ozone formation. Although the project’s estimated VOC 

emissions are less than the significant emission rate of 100 TPY, the project’s estimated NOX emissions 

exceed the significant emission rate. Thus, assessment of the project’s ozone impacts is required. The 

estimated project emissions are provided in Table 4-1. An adequate ozone formation model has not been 

developed for this type of sole source application. Hence, EPA concurred that a qualitative or relative 

assessment could be performed.

To put the project’s NOx and VOC emissions in perspective, the applicant compared the proposed 

project emissions to Gulf of Mexico emissions reported in the 2008 Emissions Inventory from the 

Bureau of Safety and Environmental Enforcement (BSEE). This inventory indicates there are 3,027 

point sources that emit either VOC or NOX located in the Gulf of Mexico west of 87 degree 30 minute

longitude. The 2008 Gulfwide Emission Inventory Study Report (latest inventory report of the Bureau of 

Energy Management, Regulation and Enforcement) provides estimates of total emissions of NOX and 

VOC from all the sources in the Gulf of Mexico. Comparing the proposed project emissions with these 

estimates reveal project emissions are about 0.8% of total NOX and 0.04% of total VOC Gulf of Mexico 

emissions. 

For further comparison, Table 7-32 presents the statewide total NOX emissions from the 2008 National 

Emissions Inventory (NEI) for the states around the Gulf of Mexico as summarized from information 

provided in the Technical Support Document for the EPA Federal Transportation Rule (EPA-HQ-OAR2009-0491). This document shows that on-road sources contributed the most to the total NOX emissions 

in the Gulf States. Estimated project emissions are very small when compared with the total NOX

emissions of nearly 4.0 million tons from the five Gulf States.

Table 7-2

State NOX Emissions for Gulf States in the 2008 NEI

State NOX Emissions (TPY)

Alabama 421,467

Florida 895,436

Louisiana 548,439

Mississippi 278,745

Texas 1,827,200

Total 3,971,287
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Another consideration is the distance from the closest Statoil lease location to the coastline. The nearest 

coastline is at the mouth of the Mississippi Delta more than 180 km from the nearest lease location. 

Emissions of NOX and VOCs from the project need to travel more than 100 miles to reach the coastline 

to potentially contribute to on-shore ozone concentrations. In addition, the wind speeds direction in the 

eastern Gulf of Mexico changes frequently, so the project emissions will be distributed over a wide area. 

Based on the above information and considerations, project emissions are not expected to significantly 

impact ozone formation along and near the coastal areas of the Gulf of Mexico.

7.2.8 Additional Impact Assessments

An additional impacts analysis was performed in accordance with PSD requirements in 40 CFR § 

52.21(o). The analysis evaluates the potential impacts that the emissions from the proposed exploration 

activities could have on growth, soils, vegetation, and visibility in the OCS impact area of concern.

7.2.8.1 Growth

The potential growth of industrial, commercial, and residential sources as a result of the proposed 

DeSoto Canyon exploration activities is expected to be minimal. The current infrastructure that supports 

the well developed oil and gas activities in the area just west of the proposed drilling activities is 

adequate to support the proposed drilling activities and no additional growth is expected.

7.2.8.2 Soil and Vegetation

The potential impacts of the proposed project on the soils and vegetation in the project’s impact area 

must be considered. Assessment of impacts to vegetation having no significant commercial or 

recreational values is not required. Due to the location of the proposed exploration activities in the 

eastern Gulf of Mexico more than 150 km from any coastline and the modeled project impacts of less 

than significant levels, no significant impact from the proposed project to soils or vegetation is expected.

7.2.8.3 Visibility

The estimate of project impact on visibility in the project’s impact area was assessed using the EPA 

plume impact screening model VISCREEN. The VISCREEN model estimates the potential visual 

impact of a plume caused by a proposed project’s emissions. A VISCREEN Level I analysis was 

conducted to estimate if the emissions from the proposed exploration activities could result in an adverse 

impact on visibility at the closest visibility sensitive Class II area receptor. The project’s particulate 

matter and NOX emissions were provided as inputs, while the default values were used for background 

ozone, stability class, and wind speed (default background ozone concentration of 0.04 parts per million, 

and default stability and wind speed are 6 and 1 meter per second, respectively). VISCREEN 

conservatively evaluated whether a plume from the Developer or Discoverer Americas drilling vessels, 

and associated support vessels, will produce a plume perceptible to an observer under worst-case 

meteorological conditions at a specific location. Several angles between the observer’s line of sight and 

the sun’s radiation (θ) are considered. 

The application of VISCREEN is limited to distance less than or equal to 50 km. Therefore, to 

conservatively estimate the potential visual impact in the impact area that is more than 150 km from the 

drilling location, the much smaller 50 km distance was used in the VISCREEN analysis. Tables 7-3 and 

7-4 provide the results of the VISCREEN modeling for the two drilling vessels. These tables show that 

the default threshold for Delta E and contrast (Cp) were not exceeded for sky or terrain backgrounds by 
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either drilling vessel at 50 km distance. Therefore, the proposed exploration activities are not expected 

to impair the local visibility at the closest areas of concern, 25 nautical miles from each state’s seaward 

boundary. 

Table 7-3

VISCREEN Level 1 Developer Results

Background Θ Distance

(Source-Observer)

Delta E Contrast

Critical Plume Critical Plume

Sky 10 50 2.00 1.088 0.05 -0.006

Sky 140 50 2.00 0.337 0.05 -0.007

Terrain 10 50 2.00 0.087 0.05 0.001

Terrain 140 50 2.00 0.026 0.05 0.001

Table 7-54

VISCREEN Level 1 Discoverer Americas Results

Background Θ Distance

(Source-Observer)

Delta E Contrast

Critical Plume Critical Plume

Sky 10 50 2.00 1.449 0.05 -0.008

Sky 140 50 2.00 0.449 0.05 -0.010

Terrain 10 50 2.00 0.118 0.05 0.002

Terrain 140 50 2.00 0.036 0.05 0.002

7.3 PSD Class I Areas Analyses

The four closest PSD Class I areas to the project location are Breton National Wildlife Refuge (175 km), 

Bradwell Bay Wilderness Area (307 km), Saint Marks Wilderness Area (313 km ) and Chassahowitzka 

Wilderness Area (641 km). The FLM for Breton, Chassahowitzka, and Saint Marks Wilderness Areas is 

the Fish & Wildlife Service (FWS). The FLM for the Bradwell Bay Wilderness Area is the National 

Forest Service. Discussions with the FWS concerning the proposed project resulted in a request for an 

Air Quality Related Values (AQRV) assessment for the nearest PSD Class I area. Visibility and nitrogen 

and sulfate deposition are the AQRV of concern at the Breton National Wildlife Refuge. In addition to 

AQRV of concern to the FLM, the EPA requires the assessment of PSD Class I increments. The PSD 

increment at the Breton NWR was assessed using the same model and modeling procedures as used for 

the PSD Class II impact assessment. 

7.3.1 Air Quality Model Selection

The EPA’s preferred model for long-range transport assessments is also recommended by the FLM. 

Therefore, the same model used in the PSD Class II area impact assessment - CALPUFF Version 5.8 

(release 070623) – was used to evaluate potential AQRV and PSD increment impacts at the Breton 

NWR (PSD Class I areas). 

7.3.2 Modeling Procedures

The modeling procedures used for the Class I area impact analyses followed the recommendations of the 

Interagency Workgroup on Air Quality Modeling and the FLM Air Quality Related Values Workgroup 

(FLAG), outlined in the FLAG Phase I Report - Revised (2010). The selected options for the CALPUFF 

modeling system followed the procedures and defaults approved by the FLM and/or the EPA. 
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The CALPUFF-estimated hourly PM2.5 and NO2 concentrations were averaged for the annual and 24-

hour periods. Visibility extinction coefficients and total deposition fluxes were calculated for 24-hour 

and annual averages, respectively. Comparisons to the regulatory standards and/or FLM target values 

were based on the maximum modeled values from the modeled three-year meteorological dataset.

The CALPUFF chemistry transformations depend on the ambient ammonia and ozone concentrations. 

Because of the low ammonia background concentration expected over the Gulf of Mexico, the FLM 

requested value of 3 ppb was used. The ozone background concentrations for the 2001-2003 modeled 

years were those included with the meteorological dataset. A conservative background value of 65 ppb 

was used for any missing values. 

The Class I area modeling assessment used the maximum short-term (i.e., 24-hour emission rate) and 

long-term emission scenarios for both the Developer and Discoverer Americas drilling vessels (see 

Section 7.2.2). The operational scenarios that produce the maximum hourly emission for the vessels 

were used to obtain the maximum 24-hour impact values. 

To provide the worst-case impact conditions the drilling vessels were located at their closest location –

the NW corner of the lease block nearest Breton. Crew boats and OSVs were modeled as point sources 

located 25 nautical miles from the drilling vessel in the direction of the nearest shore receptor and 

Breton NWR. 

7.3.4 Meteorological Data

The three-year meteorological dataset (2001-2003) developed by the Visibility Improvement State and 

Tribal Association of the Southeast (VISTAS) was used for the PSD Class I impact assessment. This 

dataset, the same as used for the PSD Class II impact assessment, covers the Gulf of Mexico region of 

interest. This analysis used a 4-km grid size to better resolve the impacts.

7.3.5 Modeling Results

The maximum Class I area estimated annual NO2 impacts from the proposed exploratory drilling 

emissions are provided in Table 7-5. The accepted PSD Class I annual SIL and the PSD increment are 

also provided in this table. The maximum modeled annual concentration associated with the proposed 

project emissions for the Developer and Discoverer Americas drilling vessels are much less than the 

SIL. Therefore, the project is considered to have no significant impact on the PSD Class I NO2 

increment.

Table 7-5

Maximum Modeled Class 1 NO2 Concentrations

Class I Area Developer Discoverer Americas

Annual Average (ug/m3) Annual Average (ug/m3)

Breton NWR 

Max. Concentrations

0.02 0.02

EPA Proposed SIL 0.1 0.1

Class I PSD Increment 2.5 2.5

Note: NOx was assumed to be 75 percent converted to NO2.

The maximum Class I area estimated annual and 24-hour PM2.5 impacts from the proposed project 

emissions are provided in Table 7-6. The PSD Class I SIL and the PSD increments are also provided in 
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Statoil OCS-EPA-R4012 080913

this table. The maximum modeled annual concentrations associated with the proposed project emissions 

for the Developer and Discoverer Americas drilling vessels are much less than the SIL. The estimated 

project maximum PM2.5 24-hour concentration for the Developer and Discoverer Americas are also less 

than the SIL. 

Table 7-6

Maximum Modeled Class I PM2.5 Concentrations

Class I Area Developer Discoverer Americas

24-hour Average

(ug/m3)

Annual Average 

(ug/m3)

24-hour Average

(ug/m3)

Annual Average 

(ug/m3)

Breton NWR Max. 

Concentrations

0.04 0.0004 0.04 0.0004

EPA SIL 0.07 0.06 0.07 0.06

Class I PSD 

Increment

2 1 2 1

Given the conservative emission rates and release location (i.e., nearest possible distance to Class I 

ambient receptor), and small number of other possible increment consuming PM2.5 emission sources in 

the eastern Gulf of Mexico, the use of the PM2.5 SIL should not jeopardize PSD Class I increment at this 

area. The fact that the maximum modeled project emissions are substantially lower than the SIL (i.e., the 

Table 7-6 maximum project impacts are 57.1% of the 24-hour and 0.7% of the annual PM2.5 SIL) adds 

support for the use of the SIL as an indicator of insignificant project impacts in this application.

The CALPUFF estimates of deposition of acid-forming compounds from the project’s emissions are 

provided in Table 7-7. This table also contains the FLM accepted Deposition Analysis Thresholds 

(DAT) established for areas east of the Mississippi. The DAT is defined as the additional amount of 

nitrogen or sulfur deposition within a PSD Class I area below which estimated project impacts are 

considered negligible [Federal Land Manager’s Air Quality Related Values Workgroup, Phase I Report 

– Revised June 2008]. The estimated project deposition rates are much less than the DAT. Therefore, the 

project associated Class I area deposition should be negligible. 

Table 7-7

Estimated Class I Area Deposition Fluxes (kg/ha/yr)

Class I Area Developer Discoverer Americas

Nitrogen Deposition Nitrogen Deposition

Breton NWR 0.0013 0.0014

Deposition Analysis 

Threshold

0.010 0.010

The visibility concern at Breton NWR is regional haze. The project’s contribution to regional haze is 

addressed as the 24-hour change in extinction. The FLM considers a five percent change in extinction to 

be just perceptible. The FLM accepted procedures known as Method 8 was used. Method 8 employs the 

IMPROVE extinction equation using monthly relative humidity adjustment factors, annual background 

aerosol concentrations, and 98th percentile modeled values at each receptor to provide estimates of the 

change in extinction associated with project emissions. 
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The Method 8 estimated project associated changes in visibility extinction for both the Developer and 

Discoverer Americas vessels resulted in a number of days with more than five percent change in 

extinction. The Developer assessment resulted in 15 days exceeding five percent change in extinction 

with a maximum of 15.51 percent. Fourteen of the 15 days had changes of less than 10 percent. The 

Discoverer Americas vessel emissions resulted in 27 days exceeding five percent change in extinction 

and a maximum of 21.88 percent. Nineteen of the 27 days had changes of less than 10 percent. Table 7-8

provides a summary of the results of the Method 8 modeling analysis. This table reveals that the three

year average Method 8 98th percentile values for the drilling vessels are less than the target five percent 

change in extinction for Developer but just greater than the target five percent for the Discoverer 

Americas.

Table 7-98

Summary of Method 8

Maximum Estimated Change in Extinction for Breton Wilderness

Criteria Developer (%) Discoverer Americas (%)

Highest Value 15.51 21.88

Number Days > 5% Change 15 27

Number Days >10% Change 1 8

98th Percentile Change 2001 5.01 7.19

98th Percentile Change 2002 3.51 5.06

98th Percentile Change 2003 3.69 5.07

98th Percentile Change 3 year average 4.07 5.77

The estimated impacts of the proposed project’s emissions on the nearest PSD Class I area shows 

visibility impacts for one of the drilling vessels (i.e., Discoverer Americas) just greater than the FLM 

target value. Both drilling vessels’ deposition levels are less than the FLM’s target or threshold values. 

The Breton NWR FLM reviewed this PSD Class I area impact assessment and indicated that because of 

the conservative assumptions contained in the emission estimates and analyses, and the temporary nature 

of the activity, they expected no significant project-related impacts. 

8.0 Additional Requirements

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

Section 7(a)(2) of the Endangered Species Act (ESA) requires federal agencies, in consultation with the 

National Oceanic and Atmospheric Administration (NOAA) Fisheries Service and/or the U.S. Fish and 

Wildlife Service (collectively, “the Services”), to ensure that any action authorized, funded, or carried 

out by the agency is not likely to jeopardize the continued existence of a species listed as threatened or 

endangered, or result in the destruction or adverse modification of designated critical habitat of such 

species. See 16 U.S.C. §1536(a)(2); see also 50 CFR §§ 402.13 and 402.14. The federal agency is also 

required to confer with the Services on any action which is likely to jeopardize the continued existence 

of a species proposed for listing as threatened or endangered or which will result in the destruction or 

adverse modification of critical habitat proposed to be designated for such species. See 16 U.S.C. §

1536(a)(4); see also 50 CFR §§ 402.10. Further, the ESA regulations provide that where more than one 

federal agency is involved in an action, the consultation requirements may be fulfilled by a designated 

lead agency on behalf of itself and the other involved agencies. See 50 CFR §§ 402.07. 
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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 DOI is the lead federal agency for authorizing oil and gas 

exploration activities on the OCS. Therefore, BOEM served as the Lead Agency for ESA section 7 and 

MSA compliance for Statoil’s exploration activities. In accordance with section 7 of the ESA, BOEM

consults prior to a lease sale with NOAA Fisheries and FWS to ensure that a sale proposal will not cause 

any protected species to be jeopardized by oil and gas activities on a lease. In addition, BOEM requests 

annual concurrence from the Services to ensure current activities remain consistent with the terms and 

conditions of the Biological Opinion issued for the lease sale activities.

Since the BOEM consultations address the same exploratory drilling activities authorized by the air 

permit that the EPA is issuing to Statoil, the EPA relied in part on those conclusions for our preliminary

determination. In addition, NOAA Fisheries considered the scope of the proposed action and did not 

identify any routes of effects for air quality. Based upon the best available data and technical assistance

from the Services, the EPA determined that the issuance of this OCS permit to Statoil for exploratory 

drilling is not likely to cause any adverse effects on listed species and essential fish habitats beyond 

those already identified, considered and addressed in the prior consultations. The proposed OCS permit 

includes a condition requiring Statoil to comply with all other applicable federal regulations, which 

includes the results of any current and future biological opinions. 

8.2 National Historic Preservation Act

Section 106 of the National Historic Preservation Act requires federal agencies to take into account the 

effects of their undertakings on historic properties. Section 106 requires the lead agency official to 

ensure that any federally funded, permitted, or licensed undertaking will have no effect on historic 

properties that are on or may be eligible for the National Register of Historic Places. The BOEM is the 

lead agency permitting Statoil's activity in the DeSoto Canyon lease blocks, which were included in 

BOEM Lease Sales 213 and 222. The environmental effects of Sales 213 and 222 were analyzed in a 

multi-sale Environmental Impact Statement, covering sales in 2007 through 2012 accessible on the web 

at http://www.gomr.boemre.gov/PDFs/2007/2007-018-Vol1.pdf.

BOEM typically conducts section 106 consultation at the pre-lease stage by prior agreement with the 

Advisory Counsel for Historic Preservation rather than at the individual post-lease permit level. In order 

to reach a Finding of No Significant Impact, mitigation is carried out at the post-lease plan level by 

requiring remote sensing survey of the seafloor in areas considered to have a high probability for 

archaeological resources. At the time these leases were sold, the area was not considered to have a high 

probability for containing archaeological remains such as a shipwreck. Any cultural resources 

discovered during that inspection are required by regulation to be reported to BOEM with 72 hours. No 

significant archaeological properties are anticipated in this location, but should anything be discovered 

there as a result of the operator's investigations, BOEM would enter into consultation with the State 

Historic Preservation Office and the Advisory Counsel for Historic Preservation.

8.3 Executive Order 12898 – Environmental Justice

Executive Order 12898, entitled “Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations,” directs federal agencies, including the EPA, to the extent 

practicable and permitted by law, to identify and address, as appropriate, disproportionately high and 

adverse human health or environmental effects of regulatory programs, policies, and activities on 
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Statoil OCS-EPA-R4012 080913

minority populations or low-income populations. See Executive Order 12898, 59 Fed. Reg. 7629 

(February 11, 1994). Consistent with Executive Order 12898 and the EPA’s environmental justice 

policy (OEJ 7/24/09), in making decisions regarding permits, such as OCS permits, the EPA gives 

appropriate consideration to environmental justice issues on a case-by-case basis, focusing on whether 

its action would have disproportionately high and adverse human health or environmental effects on 

minority or low-income populations. 

The EPA has concluded that this proposed OCS air permitting action for Statoil’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 drilling area is located approximately 

160 miles southeast of the mouth of the Mississippi River and 200 miles southwest of Panama City, 

Florida in the Gulf of Mexico. The project is located more than 150 miles offshore in ultra deepwater

and the EPA is not aware of any minority or low-income population that may frequently use the area for 

recreational or commercial reasons. In addition, since the project is located well away from land, the 

project’s emissions impacts will be dispersed over a wide area with no elevated concentration levels 

affecting any onshore populated area. 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 § 124. 

As provided in part 124, the EPA is seeking comments on the Statoil OCS air permit OCS-EPA-R4012

during the public comment period as specified in the public notice. 

Any interested person may submit written comments on the draft permit during the public comment 

period. If you believe that any condition of the permit is inappropriate, you must raise all reasonably 

ascertainable issues and submit all reasonably available arguments supporting your position by the end 

of the comment period. Any documents supporting your comments must be included in full and may not 

be incorporated by reference unless they are already part of the record for this permit or consist of state 

or federal statutes or regulations, EPA documents of general applicability, or other generally available 

referenced materials. 

Comments should focus on the proposed air quality permit, the permit terms, and the air quality aspects 

of the project. If you have general comments regarding non-air quality impacts, leasing, drilling safety, 

discharge, or other similar issues not subject to this public comment period, you should submit them

during the leasing and plan approval proceedings of the BOEM, which is the lead agency for offshore 

drilling.

All timely comments related to the proposed action will be considered in making the final decision and 

will be included in the administrative record and responded to by EPA. The EPA may summarize the 

comments and 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 at R4OCS permits@epa.gov, submitted 

electronically via www.regulations.gov (docket # EPA-R04-OAR-2013-0577), or postmarked by 

September 9, 2013. Comments sent by mail should be addressed to: USEPA Region 4, Air Permits 

Section APTMD, 61 Forsyth Street, SW, Atlanta, GA 30303. An extension of the 30-day comment 
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Statoil OCS-EPA-R4012 080913

period may be granted if the request for an extension adequately demonstrates why additional time is 

required to prepare comments. All comments will be included in the public docket without change and 

will be made available to the public, including any personal information provided, unless the comment 

includes Confidential Business Information or other information in which disclosure is restricted by 

statute. Information that you consider Confidential Business Information or otherwise protected should 

be clearly identified as such and should not be submitted through e-mail. 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 notification of the EPA’s final decision regarding the permit and the EPA’s response to comments 

submitted during the public comment period. 

For general questions on the draft permit, contact: Ms. Lori Shepherd at 404-562-8435 or 

shepherd.lorinda@epa.gov.

9.2 Public Hearing 

The EPA will hold a public hearing if the Agency determines that there is a significant degree of public 

interest in the draft permit. Public Hearing requests must be in writing and received by EPA by

August 30, 2013. Requests should be sent by email to R4OCSpermits@epa.gov or by mail addressed

to: USEPA Region 4, Air Permits Section, 61 Forsyth Street, SW, Atlanta, GA 30303. Requests for a 

public hearing must state the nature of the issues proposed to be raised in the hearing. If a public hearing 

is held, you may submit oral and/or written comments on the draft permit at the hearing. You do not 

need to attend the public hearing to submit written comments. If EPA determines that there is a 

significant degree of public interest, EPA will hold a public hearing on September 16, 2013, at:

Bay County Public Library 

Northwest Regional Library System

898 W 11th Street

Panama City, FL 32412-0625

(850) 522-2119

If a public hearing is held, the public comment period will automatically be extended to the close of the 

public hearing. If no timely request for a public hearing is received, or if EPA determines that there is 

not a significant degree of public interest, a hearing will not be held. Such an announcement will be 

posted on EPA’s website at: 

http://www.epa.gov/region4/air/permits/ocspermits/ocspermits.html,

or, you may call the EPA at the contact number above to verify if the public hearing will be held.

9.3 Administrative Record

The administrative record contains the application, supplemental information submitted by Statoil, and 

correspondence (including e-mails) clarifying various aspects of Statoil’s application. The 

administrative record and draft permit are available on www.regulations.gov (docket# EPA-R04-OAR2013-0577) and through the EPA’s website at: 

http://www.epa.gov/region4/air/permits/ocspermits/ocspermits.html. 
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These web sites can be accessed through free internet services available at local libraries.

The draft permit and the administrative record are also available for public review at the EPA Region 4 

office at the address listed below. Please call in advance for available viewing times.

EPA Region 4 Office

61 Forsyth Street, SW

Atlanta, GA 30303

Phone: (404) 562-9043

To request a copy of the draft permit, preliminary determination or notice of the final permit action, 

please contact: Ms. Rosa Yarbrough, Permit Support Specialist at: 404-562-9643, or 

yarbrough.rosa@epa.gov. 

9.4 Final Determination 

A decision to issue a final permit, or to deny the application for the permit, shall be made after all timely 

comments on the proposed determination have been considered. Notice of the final decision shall be sent 

to each person who has submitted written comments or requested notice of the final permit decision, 

provided the EPA has adequate contact information.