Statoil OCS-EPA-R4012-M1 070914

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

Region 4 

Atlanta, Georgia 

Preliminary Determination & Statement of Basis

Outer Continental Shelf Air Permit Modification OCS-EPA-R4012-M1

For

Statoil Gulf Services, LLC

DeSoto Canyon Lease Blocks

July 9, 2014
Statoil OCS-EPA-R4012-M1 070914

Table of Contents

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

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

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

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

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

3.0 Proposed Project ................................................................................................................................... 4

3.1 Operating Scenario 1 (Maersk Developer) ....................................................................................... 4

3.2 Operating Scenario 2 (Transocean Discoverer Americas)................................................................ 6

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............................................................................................................................................... 8

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

4.6 National Emission Standards for Hazardous Air Pollutants (NESHAP)........................................ 10

5.0 Project Emissions................................................................................................................................ 10

5.1 Potential to Emit ............................................................................................................................. 10

5.2 Operating Scenario 1 (Developer) Emissions Source Analysis................................................. 11

5.3 Support Vessel Analysis................................................................................................................. 14

5.4 Compliance Methodology............................................................................................................... 14

6.0 Best Available Control Technology (BACT) and Recordkeeping Requirements.............................. 15

6.1 BACT Analysis Procedure.............................................................................................................. 16

6.2 NOX BACT Analysis for Internal Combustion Engines................................................................. 17

6.3 VOC BACT Analysis for Internal Combustion Engines................................................................ 18

6.3.1 Step 1: Identify all Available Control Technologies ............................................................... 18

6.3.2 Step 2: Eliminate Technically Infeasible Control Options...................................................... 19

6.3.3 Step 3: Rank the Remaining Control Technologies by Effectiveness..................................... 20

6.3.4 Step 4: Evaluate the Energy, Environmental and Economic Impacts ..................................... 21

6.3.5 Step 5: Select BACT................................................................................................................ 21

6.4 PM10/PM2.5 BACT Analysis for Internal Combustion Engines...................................................... 22

6.4.1 Step 1: Identify all Available Control Technologies ............................................................... 23

6.4.2 Step 2: Eliminate Technically Infeasible Control Options...................................................... 23

6.4.3 Step 3: Rank the Remaining Control Technologies by Effectiveness..................................... 25

6.4.4 Step 4: Evaluate the Energy, Environmental and Economic Impacts ..................................... 26

6.4.5 Step 5: Select BACT................................................................................................................ 27

6.5 BACT Analysis for Storage Tanks................................................................................................. 29

6.6 BACT Analysis for Cement and Barite Handling Operations........................................................ 30

6.7 BACT Analysis for Mud Degassing............................................................................................... 30

6.8 BACT Analysis for Painting Operations ........................................................................................ 31

6.9 BACT Analysis for Welding Operations........................................................................................ 31

6.10 BACT Analysis for Piping Fugitive Emissions............................................................................ 32

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.................................................................................................... 34

7.2.2 Characteristics of Modeled Operational Scenarios.................................................................. 35
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7.2.3 Meteorological Data................................................................................................................. 37

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............................................................................................... 40

7.3 PSD Class I Areas Analyses........................................................................................................... 42

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............................................................................................................................. 46

9.1 Opportunity for Public Comment ................................................................................................... 46

9.2 Public Hearing ................................................................................................................................ 47

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

9.4 Final Determination ........................................................................................................................ 48
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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, Drilling Vessel, or the Rig

CAA Clean Air Act 

CCV Closed Crankshaft Ventilation System

CEMS Continuous Emissions Monitoring System

CDPF Catalytic Diesel Particulate Filter

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 Drillship or the Ship

DPF Diesel Particulate Filter

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

FTF Flow through Filter

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

m3 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 
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NMHC Non Methane Hydrocarbons

NSPS New Source Performance Standards 

NSR New Source Review 

OCS Outer Continental Shelf 

OCSLA Outer Continental Shelf Lands Act

OCV Open Crankshaft Ventilation System

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 

THC Total Hydrocarbon

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 
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1.0 Introduction

On October 28, 2013, the U.S. Environmental Protection Agency (EPA) Region 4 issued an Outer 

Continental Shelf (OCS) permit (Permit No. OCS-EPA-R4012) to Statoil Gulf Services, LLC (The 

Applicant or Statoil) in accordance with the provisions of section 328 of the Clean Air Act (CAA), 42 

U.S.C. § 7627, and the implementing Outer Continental Shelf Air Regulations at title 40 Code of 

Federal Regulations (CFR) part 55. The existing permit, which regulates air emissions from the 

mobilization and operation of deepwater drilling vessels and associated support fleets at multiple lease 

blocks on the OCS in the eastern Gulf of Mexico, became effective on November 27, 2013.

As stated in the existing permit, Statoil plans to drill using one of two operating scenarios and, 

dependent on the scenario, will use one of two dynamically positioned deepwater drilling vessels. The 

Maersk Developer drilling vessel, also referred to as Operating Scenario 1, or the Transocean 

Discoverer Americas drillship, 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. The permitted project is for exploratory 

drilling only. If resource discoveries are made during exploration activities, subsequent facilities, 

including any necessary production platforms, would be permitted separately. 

On April 1, 2014, the EPA received an application from Statoil, dated March 27, 2014, requesting 

modification of the existing OCS permit to include Best Available Control Technology (BACT) limits

for volatile organic compounds (VOC), particulate matter with an aerodynamic diameter less than or 

equal to 2.5 microns (PM2.5), and particulate matter with an aerodynamic diameter less than or equal to 

10 microns (PM10) and revised BACT limits for oxides of nitrogen (NOX) for engines on the Developer

based on recent source test data for these pollutants that was not available at the time of permitting. 

Statoil has also requested that the modification decrease the total fuel consumption limit for the 

Developer and change the possible drilling locations for the Developer to include additional lease blocks 

in the same general area. Statoil is not requesting any change in the underlying project plans, which are

summarized below. However, the applicant has provided revised air quality modeling which contains 

changes to operating parameters for the main generating engines and support vessel engines. Statoil 

believes that the revised modeling is based on more accurate data and is a better representation of the 

impact of the actual drilling operations. The updated air quality modeling is discussed in Section 7.0 of 

this document. 

Following careful consideration and analysis of the data provided by Statoil, the EPA is proposing to

modify the permit to include BACT limits for VOC, PM2.5, and PM10 and revised BACT limits for NOX

for engines on the Developer, decrease the total fuel consumption limit for the Developer, and change 

the possible drilling locations for the Developer to include additional lease blocks in the same general 

area. 

This modification does not constitute a change in the source nor a change in the proposed drilling 

operations. While Statoil has made preparations to drill, including source testing, Statoil has not yet 

begun drilling operations on the lease blocks covered by the permit. This action is a proposed 

modification to permitted emissions limits to reflect data that is more representative of actual drilling 

operations, and to allow the operations to be conducted in additional lease blocks subject to specific 

criteria as defined in Section 2.2 below. Permit conditions unrelated to the Developer’s emissions of 

NOX, VOC, PM2.5, and PM10 and operating location have not been modified in this draft permit except 

where necessary for clarification or to correct typographic errors.
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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 to modify the permit, in addition to all supplemental materials provided, and is proposing to 

issue Permit Number OCS-EPA-R4012-M1 to Statoil for a multi-year exploratory drilling program

subject to the terms and conditions included in this revised permit. The draft modifications to the permit 

incorporate applicable requirements from the federal Prevention of Significant Deterioration (PSD) and 

title V operating permit programs. The permit continues to include applicable 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 modification and addresses changes made to the original preliminary determination/statement of 

basis for this project as a result of the permit revisions. It provides an overview of the project, a 

summary of applicable requirements, the legal and factual basis for modified draft permit conditions, 

and the EPA’s analysis of key aspects of the modification application and draft permit conditions such 

as the BACT analysis and Class II/Class I area impact analysis. Further description of the project and the 

EPA’s analysis of key aspects of the existing permit and application can be found in the original 

permit’s application materials submitted to the EPA by Statoil dated September 5, 2012, December 7, 

2012, January 28, 2013, and June 27, 2013, and in the original statement of basis for the existing permit

(Permit No. OCS-EPA-R4012), which are available in the administrative record for this project, as 

discussed in Section 9 of this document. 

2.0 Applicant Information

2.1 Applicant Name and Address

Statoil Gulf Services, LLC

2103 CityWest Boulevard, Suite 800

Houston, Texas 77042

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 in Figure 2-1. Each lease block is approximately 

five kilometers by five kilometers. 

Statoil is requesting that the permit be modified to include additional lease blocks in the same eastern 

Gulf of Mexico area, which meet the following location criteria:

 Located east of 87°30’ west longitude in the eastern Gulf of Mexico;

 

1 See CAA section 328. The Department of the Interior has jurisdiction for CAA implementation west of 87°30’.
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 Farther from the closest lease block modeled as part of the project defined in Permit No. OCSEPA-R4012 and this draft permit relative to the closest shoreline, the Breton Wilderness Class I 

area, or any Class I or Class II area;

 West of the Military Mission Line (86°41’ west longitude); 

 Outside of the current Congressional moratoria area as specified by the Gulf of Mexico Energy 

Security Act of 2006; and

 Outside 75 nautical miles of the state seaward boundary of Florida.

After a review of the information provided by Statoil, the EPA concurs that inclusion of this flexibility

while operating under Operating Scenario 1 with the Developer would be protective of air quality if any

additional lease block location that meets the criteria listed above and is subject to the same conditions

used to judge the worst-case location in the application. The worst-case location with respect to modeled 

air pollutant emissions is considered to be the northwest corner of lease block 143, which is closest to 

shore and to the Breton Wilderness Class I area. Proposed language has been added to the permit to 

allow this flexibility. Written notification to the EPA of all drilling locations prior to the commencement 

of operations remains a condition of the modified permit.

Figure 2-1 Site Location

Image reproduced from Outer Continental Shelf Title V Permit Significant Modification and PSD Permit Major Modification 

Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services LLC dated March 2012, prepared by 

ENVIRON International Corporation Baton Rouge, Louisiana.
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3.0 Proposed Project

The proposed modification does not constitute a change in the source nor a change in the proposed 

drilling operations. Statoil is still proposing 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 or, if using the 

Developer, in any future lease block held that meets the criteria listed in Section 2.2 above. It is 

expected that drilling operations will occur for approximately five to ten years. 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.

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

carbon monoxide (CO), particulate matter (PM), PM2.5, PM10, and sulfur dioxide (SO2), as well as other 

regulated air pollutants including VOC, NOX, and greenhouse gases (GHGs).2 VOC and NOX are the 

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

PM2.5. 

In the existing OCS permit, emissions from the Developer are subject to PSD and title V requirements 

for NOX only (as a measured pollutant for criteria pollutants NO2 and ozone and as a precursor to PM2.5)

based on emissions estimates and the applicable permitting thresholds. However, Statoil conducted 

source testing in October 2013 for NOX, CO, PM, and VOC emissions indicating that emissions of VOC 

(as the measured pollutant for criteria pollutant ozone) and criteria pollutants PM10 and PM2.5 also have 

the potential to meet or exceed the respective significant emission rates for the Developer. The source 

testing also indicated that emissions of NOX from the main generating engines were higher than those 

estimated at the time of the original permit application. Therefore, Statoil has requested a permit 

modification to include BACT limits for PM10, PM2.5, and VOC and revised BACT limits for NOX for 

the main engines on the Developer. Activities conducted under this modified operating scenario 

continue to be considered an area source of hazardous air pollutants pursuant to 40 CFR 63 subpart 

ZZZZ.

Included in its application to revise the BACT limits for NOX and to include BACT limits for VOC, 

PM10, and PM2.5 for the Developer, Statoil performed a revised BACT analysis, a revised air quality 

analysis, and updated its Potential to Emit (PTE) for these pollutants with respect to Operating Scenario 

1, as discussed below.

3.1 Operating Scenario 1 (Maersk Developer)

The Developer (Figure 3-1) is a self-powered, dynamically positioned semi-submersible drilling vessel

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

achieved using a computer controlled system and its 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 

 

2 Section 4 of the modified permit clarifies which Global Warming Potential factors are applicable to the project.
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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 and barite used in casing and drilling activities is mixed in an enclosed system on the Developer

and was not thought to be a source of potential emissions in the original permit application. However, 

the modification application indicates that particulate emissions from cement and barite handling may 

contribute to particulate emissions on the vessel. Therefore, conditions related to this activity have been 

added to the modified draft permit.

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 

drillship via helicopters. Statoil will rely on a fleet of support vessels in two categories: OSVs and crew 

boats. There is no proposed change in the use and operation of the support vessels from the existing 

OCS permit. Therefore, permit conditions related to the support vessels have not been modified in the 

draft permit except where necessary for clarification or to correct typographic errors.

Engine details and emissions information are provided in Section 5.0 of this document.

Figure 3-1 Maersk Developer Drill Rig

Image reproduced from Outer Continental Shelf Title V Permit Significant Modification and PSD Permit Major Modification 

Application DeSoto Canyon Drilling Exploration Project for Statoil Gulf Services LLC dated March 2012, prepared by 

ENVIRON International Corporation Baton Rouge, Louisiana.
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3.2 Operating Scenario 2 (Transocean Discoverer Americas)

Statoil has not applied for any changes to Operating Scenario 2 using the Transocean Discoverer 

Americas and no permit requirements involving this drillship have been modified except where 

necessary for clarification or to correct typographic errors. Therefore, details regarding this drill ship are 

not included in this preliminary determination and statement of basis.

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’s exploratory drilling operations will be conducted 

exclusively beyond 25 miles of any state’s seaward boundary.
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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, 

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 Statoil’s

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 project. 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. 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 vessel 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 
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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. 

Table 4-1 lists the PTE for each regulated NSR pollutant from the Developer for which Statoil is seeking 

a new or revised BACT limit based on the October 2013 source testing, as well as the significant 

emission rate for these pollutants. The permit application materials and Section 5.0 of this document 

contain information regarding the emissions factors used to determine PTE for these pollutants under

Operating Scenario 1. 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 results of the October 

2013 source testing, the PTE for VOC (as a measured pollutant for criteria pollutants ozone, PM10, and 

PM2.5) has changed and is above the applicable significant emissions rates. A PSD review and BACT 

analysis are therefore required for these pollutants. Section 6.0 of this document contains a discussion of 

the BACT analysis.

Table 4-1 Potential to Emit for Regulated NSR Pollutants Based on Source Testing

Pollutant Scenario 1 (Developer) 

PTE (TPY)

Significant Emission 

Rate 

(TPY)

PSD Review 

Required

NOX

1

554.05 40 Yes

VOC275.65 40 Yes

PM10 17.47 15 Yes

PM2.5 16.03 10 Yes

 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.

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. Title V permit requirements were included in the OCS permit issued for this source 

on October 28, 2013. The proposed permit changes constitute a significant modification to the title V 

permit because they do not meet the criteria set out for a minor modification under 40 CFR 71.7(e)(1). 

More specifically, the revisions require a case-by-case determination of emissions limits. While the 

permit revisions constitute a “modification” pursuant to part 71, they do not constitute a modification to 

the emissions units or planned operation of the facility (i.e., this is not a physical change or a change in 

the method of operation, as defined under PSD). The permit continues to include all the permit terms 

necessary to meet the requirements of the applicable title V operating permits program. For example, the 

draft permit includes requirements for submittal of annual compliance certifications and annual fee 

payments based on actual emissions, as well as monitoring, recordkeeping, and reporting requirements.
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Statoil OCS-EPA-R4012-M1 070914

Updated part 71 forms for Operating Scenario 1 are included as Appendix A of Statoil’s March 2014 

modification application. 

4.5 New Source Performance Standards (NSPS)

An OCS source must comply with any NSPS applicable to their source category. See 40 CFR § 55.13(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. Engine specifications for diesel engines on the Developer are summarized in Table 4-2. 

NSPS requirements have not changed since the existing permit was issued on October 28, 2013 and are 

not affected by the proposed permit changes. Therefore, no modifications regarding NSPS requirements 

have been made to the permit.

Certification documentation for the main generator engines, the emergency generator engine, and the 

cementing unit engines are provided in Appendix B of the modification application.

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 4840 6651 8/2006

GEN-2 Main Generator 

Engine 2

Wärtsilä 

16V26A

17.0 4840 6651 8/2006

GEN-3 Main Generator 

Engine 3

Wärtsilä 

16V26A

17.0 4840 6651 8/2006

GEN-4 Main Generator 

Engine 4

Wärtsilä 

16V26A

17.0 4840 6651 8/2006

GEN-5 Main Generator 

Engine 5

Wärtsilä 

16V26A

17.0 4840 6651 8/2006

GEN-6 Main Generator 

Engine 6

Wärtsilä 

16V26A

17.0 4840 6651 8/2006

GEN-7 Main Generator 

Engine 7

Wärtsilä 

16V26A

17.0 4840 6651 8/2006

GEN-8 Main Generator 

Engine 8

Wärtsilä 

16V26A

17.0 4840 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 BUKH --- 22 29 8/2007
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Statoil OCS-EPA-R4012-M1 070914

Emissions

Unit ID

Engine 

Description

Manufacturer

and Model

Displacement 

(L/cylinder)

Ratinga

(kW)

Ratinga

(hp)

Manufacture 

Date

Engine

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. 

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 requirements applicable 

to the project have not changed since the existing permit was issued on October 28, 2013 and are not 

affected by the proposed permit changes. Therefore, no modifications regarding NESHAP requirements 

have been made to the permit.

5.0 Project Emissions

5.1 Potential to Emit 

This section describes the calculation basis for NOX, VOC, SO2 (as a precursor for PM2.5) and 

particulate 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, vendor-supplied emissions factors, and recent source testing. 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. Updated calculations based on the October 2013 main generator engine 

emissions testing results are included in Section 3 and Appendix B of Statoil’s March 2014 modification 

application. All documents submitted to the EPA in support of these calculations are included in the 

administrative record as discussed in Section 9.0 of this document. The table below provides the revised 

PTE of the project for NOX, VOC, SO2, and particulate emissions using Operating Scenario 1, based on 

the recent source testing results of the eight main diesel engines. 

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

Emission 

Source

Total 

VOC 

(TPY)

NOX 

(TPY)

SO2 

(TPY)

PM 

(TPY)

PM10 

(TPY)

PM2.5 

(TPY)

Wärtsilä Diesel 

Generator 

Engines

66.12 416.15 0.36 15.58 12.81 12.43

Emergency 

Diesel 

Generator 

Engine

0.04 0.76 5.47e-04 2.46e-02 2.02e-02 01.96e-2

Lifeboat 

Engines

1.75e-03 8.58e-03 7.57e-06 6.87e-04 5.64e-04 5.48e-04
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Statoil OCS-EPA-R4012-M1 070914

Emission 

Source

Total 

VOC 

(TPY)

NOX 

(TPY)

SO2 

(TPY)

PM 

(TPY)

PM10 

(TPY)

PM2.5 

(TPY)

Fast Rescue 

Boat Engines

0.00 0.01 1.06e-05 6.43e-04 5.29e-03 5.13e-04

Cement Unit 

Engines

0.19 0.89 8.15e-04 0.025 0.020 0.020

Offshore 

Support 

Vessels

4.29 108.99 0.07 2.97 2.44 2.37

Crew Boats 1.76 27.24 0.03 0.77 0.63 0.61

Storage Tanks 0.39 -- -- -- -- --

Fugitive 

Emissions

0.84 -- -- -- -- --

Mud Degassing0.48 -- -- -- -- --

Painting 1.54 -- -- 0.48 0.33 0.12

Welding -- -- -- 0.01 0.01 0.01

Cement/Barite 

Handling

-- -- -- 1.90 1.21 0.46

Total 75.65 554.05 0.45 21.75 17.47 16.03

 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.

5.2 Operating Scenario 1 (Developer) Emissions Source Analysis

The following is a description of the Developer’s emission units and how emissions of NOX, VOC, SO2, 

and particulate emissions were calculated for each permitted activity under Operating Scenario 1.

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, fugitive emissions, cement/barite handling activities, and storage tanks. 

Therefore, they are considered insignificant activities with respect to title V permit requirements per 40 

CFR 71.5(c)(11)(ii).

The current permit contains an annual fuel limitation of 2,654,931 gallons of diesel fuel on a rolling 12-

month basis. Based on Statoil’s recent study of the Developer’s operations while drilling, Statoil has 

indicated that fuel consumption will be less than estimated in their original application. Therefore, EPA 

has proposed a revised annual fuel limitation of 2,459,150 gallons of diesel fuel on a rolling 12-month 

basis. This estimate is based on fuel use estimates for a typical 180-day drilling campaign as provided in 

the modification application materials. If the two drilling vessels, the Developer and the Discoverer

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

be prorated based on daily use. Emissions calculations for each source are included in Section 3 and 

Appendix B of Statoil’s March 2014 modification application.
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Statoil OCS-EPA-R4012-M1 070914

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 are based on an anticipated 180 days of drilling operation per year (4,320 hours 

annually) and maximum emission factors based on source testing completed in October 2013. 

Estimates for the annual emissions rates for NO2 and particulate matter, representing normal operating 

conditions, were based on the eight main generator engines operating at 12 varying operational modes 

for 180 days of drilling activity. Estimates for the maximum short-term (1-hour and 24-hour) emission 

rates for NO2, PM10, and PM2.5 air quality modeling were based on five main generator engines 

operating at the highest emission rate measured for each relevant pollutant during the October 2013 

emissions testing. 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 March 2014 application. 

EGEN: Emergency Generator Engine

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

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

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

maintenance of 39 hours per year on a rolling 12-month average basis at 100% capacity was used for 

emission calculations and was included as a limit in the permit to ensure consistency with the 

assumptions used in the application and impact review. This limit was not revised.

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 schedule of 300 combined hours per 

year of operation on a rolling 12-month average basis. Operating hours for the cement unit diesel 

engines are limited to 300-hr per year in the permit to ensure consistency with the assumptions used in 

the application and impact assessment. This limit was not revised.

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 permit to ensure consistency with the 

assumptions used in the application and impact assessment and was not revised.

MOB: Fast Rescue Boat

The 163 hp engine in the fast rescue 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 permit to ensure consistency with the assumptions 

used in the application and impact assessment and remains unchanged.

WELD: Welding Activities

Maintenance and repair conducted while the vessel is operating under the terms of the OCS permit may 

require limited welding activities. Welding emissions were calculated based on the estimated number 
13

Statoil OCS-EPA-R4012-M1 070914

and type of welding electrodes used per 180-day drilling campaign. Monitoring and recordkeeping 

conditions have been included as draft permit revisions to ensure consistency with the assumptions and 

methodology used in the modification application. 

PAINT: Painting Activities

Maintenance and repair conducted while the vessel is operating under the terms of the OCS permit may 

require limited painting activities. Paint may be applied by spraying or rolling and may occur inside or 

outside the vessel. Statoil based the emissions from painting on the estimated amount of paint and 

thinner used during a 180 day drilling campaign, assuming 100% sprayer-applied outside painting for 

the most conservative estimate. Maximum potential VOC and HAPs content was obtained from material 

safety data sheets for available paints and thinners. Based on information from the South Coast Air 

Quality Management District, a transfer efficiency of 65% and a total PM overspray fractionation of

70% PM10 and 25% PM2.5 were used to estimate VOC and particulate matter emissions, respectively. 

Monitoring and recordkeeping conditions are proposed in the revised permit to ensure consistency with 

the assumptions and methodology used in the modification application. 

CEMENT-BARITE: Cement and Barite Handling Activities

Barite and cement handing occurs in a closed system equipped with dust collection. Vents from 

receiving components are routed to a common collection header and entrained particulate matter is 

routed under water via a submerged collection hose. Statoil estimates the control efficiency of the dust 

collection system to be nearly 100%. With this modification application, barite/cement particulate 

emissions are being included in the Developer emission calculations to account for potential particulate 

emissions. Particulate matter emissions were estimated based on PM emissions resulting from 1,440 

hours of cement/barite transfer activities per year and the use of AP-42 particle size distribution factors 

to determine PM10 and PM2.5 fractions. Monitoring and recordkeeping conditions are proposed in the 

revised permit to ensure consistency with the assumptions and methodology used in the modification 

application. 

MUD: Mud Degassing

Drilling mud circulating from the well to the drilling vessel 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 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. EPA document

Atmospheric Emissions from Offshore Oil and Gas Development and Production (450/3-77/026), June 

1977 was used as the basis for drilling mud emissions calculations. Monitoring and recordkeeping 

conditions are proposed in the revised permit to ensure consistency with the assumptions and 

methodology used in the modification application. 

FUG: Fugitive Emissions Sources

Fugitive emissions from each drilling scenario were based on the number of fugitive components (e.g., 

piping, valves, flanges) identified on the 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). Monitoring and recordkeeping conditions are proposed 

in the revised permit to ensure consistency with the assumptions and methodology used in the 

modification application. 

Storage Tanks
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Statoil OCS-EPA-R4012-M1 070914

VOC emissions are generated from the storage of diesel fuel, aviation fuel for the helicopters, and waste 

oil. Refueling and unloading emissions associated with the support vessels are also included in the 

storage unit emissions calculations. Statoil used the EPA TANKS 4.09d computer software program to 

calculate potential emissions. The default EPA TANKS 4.09d properties for Distillate Fuel Oil No. 2 

and Jet Naphtha were used to calculate emissions for the diesel/waste oil storage tanks and for the 

aviation fuel storage tanks, respectively.

5.3 Support Vessel Analysis 

Crew boat calculations are based on 618 operating hours per year resulting in 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 resulting in 621,468 gallons of 

diesel consumed per year when within 25 miles of the drilling vessel. Changes in the use and operation 

of the support vessels from the existing OCS permit were not proposed in the modification application. 

The planned operation times for each support vessel category were used for emission calculations and 

are included as operational limits in the permit to ensure consistency with the assumptions used in the 

application and impact review. Conditions included in the revised permit remain unchanged from the 

existing permit. However, the applicant has proposed changes to several operating parameters used in 

the revised air quality modeling to better reflect actual emissions and overall drilling operations. The 

revised air quality modeling is discussed in Section 7.0 of this document.

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

support fleet vessels. Detailed emission factors for these sources are available in Statoil’s March 2014 

modification application, which is included in the administrative record referenced at the end of this

document.

5.4 Compliance Methodology

The revised permit continues to define and allow the following three systems for monitoring of NOX, 

VOC, PM10, and PM2.5 from the main generator diesel units on the Developer (GEN-1 through GEN-8):

 An EPA-approved parametric monitoring method;

 An EPA-approved continuous emissions monitoring system; or

 A stack testing emissions monitoring system, if approved in writing by the EPA prior to stack 

testing.

A combination of these methods, as necessary for different pollutants or engines, may also be used. 

The compliance demonstration method for the emergency generator diesel unit (EGEN), the cementing 

unit engines (CMU-1 and CMU-2), and the emergency vessels (LB-1 through 4 and MOB) on the 

Developer includes 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, VOC, PM10, and PM2.5 

emitted. Monitoring and recordkeeping requirements for these engines remain unchanged from the 

existing permit.
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Statoil OCS-EPA-R4012-M1 070914

Compliance demonstration for the support vessels also remains unchanged, as specified in the existing 

permit, and includes:

 Monitoring and maintaining a contemporaneous record of operating and standby time within the 

25 mile radius of the drilling vessel;

 Determining and recording sulfur content upon receiving each fuel shipment;

 Maintaining a record of the number of gallons of diesel fuel on the support vessel entering the 

25 mile radius; and 

 Maintaining a record of the number of gallons of diesel fuel on the support vessel exiting the 25 

mile radius.

The permit continues to require Statoil to supply the EPA with all records that are required to be kept as 

a condition of the permit upon request. In addition, Statoil is required to provide a semi-annual report of 

its emissions information and calculations in accordance with all relevant permit conditions.

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 potential to emit in amounts equal 

to or greater than the pollutant’s significant emission rate. See 40 CFR § 52.21(j). Statoil is seeking a 

permit modification to include BACT limits for VOC, PM10, and PM2.5 and revised BACT limits for

NOX for main engines on the Developer based on the recent source testing data for these pollutants that 

was not available at the time of permitting. The current permit contains BACT limits for NOX; however, 

the recent source test data indicates that NOX emissions will be higher than those anticipated at the time 

that Statoil applied for the original permit and that VOC, PM10, and PM2.5 will be emitted in quantities 

exceeding significant emissions thresholds under Operating Scenario 1. Therefore, BACT must be 

determined for each emission unit on the drilling vessel that has the potential to emit NOX, VOC, PM10, 

or PM2.5 while 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, VOC, PM10, or PM2.5 emissions, as they are used for man overboard and emergency 

escape scenarios only. 

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

drilling and operational power demand. Consequently, pollutants are not emitted from these engines at a 

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

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

Source testing, conducted in October 2013, in accordance with Condition 6.5 of the existing permit, 

yielded data that was generally higher than the respective BACT limits for NOX, in the existing permit 
16

Statoil OCS-EPA-R4012-M1 070914

and established that emissions would exceed the PSD significant emissions thresholds for PM10, PM2.5, 

and VOC. The test was performed for three runs each at high, medium and low loads and included 

emissions data results for NOX, total hydrocarbons (THC), CO, and PM at engine loads of 30%, 45%, 

and 60%. Due to testing time constraints, direct PM measurements were not made at the 45% engine 

load, but were interpolated from the high and low load runs. 

The original emission estimates and BACT limits were based on AP-42 emission factors and vendor 

data due to the lack of actual emissions data for the aforementioned pollutants on this drilling vessel or 

like drilling vessels. The AP-42 factors that were relied upon by the applicant (AP-42, Section 3.4 Large 

Stationary Diesel Engines) are from a very limited sampling (i.e., the testing of one engine only) and

may not be the most favorable information in terms of accuracy or reliability. Furthermore, the AP-42 

factors and vendor data are more representative of land-based rather than marine-based applications and 

specifically do not account for the frequent variable load scenarios and operating characteristics 

associated with drilling operations. In addition, the vendor data is based on laboratory test cycles, which 

often does not reflect in-use operating conditions. Nonetheless, these factors were the best available at 

the time the existing permit was issued. 

Following careful consideration and analyses of the data provided by Statoil, the EPA is proposing to 

revise the BACT limits for NOX and establish BACT limits for PM10, PM2.5, and VOC for the main 

generating engines on the Developer as specified in the draft permit conditions. 

A single BACT limit was proposed by Statoil for each pollutant that generally correlated to the highest 

3-run average test result from a single engine, irrespective of the operating load. Upon analysis of the 

data, however, the EPA determined that separate emission limits for low load and high load operations 

are more appropriate for the particulate matter and VOC emission limits. Emission rates for these 

pollutants are significantly higher at low loads. This is expected due to the combustion characteristics of 

the diesel engines. In addition, in establishing BACT limits, the EPA considered correlation of the data 

across the test runs, as significant deviations may be an indicator of poor test results or operations 

outside of optimum performance. Therefore, the EPA has proposed high and low load limits that are 

more reflective of the variable load operations of these engines when operating under the terms of the 

permit.

6.1 BACT Analysis Procedure

A top-down BACT analysis was conducted by the applicant and a BACT determination made for each 

emissions unit of the Developer that has the potential to emit NOX, PM10, PM2.5, and/or VOC. 

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 
17

Statoil OCS-EPA-R4012-M1 070914

Administrator determines that technological or economic limitations on the application of 

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

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

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

best available control technology. 

The CAA contains a similar BACT definition, although the 1990 CAA amendments added “clean fuels” 

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

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

determining BACT. Memorandum from J. Craig Potter, Assistant Administrator for Air and Radiation, 

to EPA Regional Administrators regarding Improving New Source Review (NSR) Implementation (Dec. 

1, 1987). 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).

6.2 NOX BACT Analysis for Internal Combustion Engines

A revised BACT determination for the main generator engines on the Developer, which have the 

potential to emit NOX above the BACT limits established in the existing permit, was included in the 

modification application. However, the EPA has determined that the BACT analysis conducted in 

conjunction with this latest revision did not result in any significant changes to the respective control 

technology determinations for the NOX emitting units of the Developer. This is as expected, since the 

applicant has not proposed to change any emissions units from those included in the existing permit 

issued on October 28, 2013 or to change the use or operation of these emission units. The detailed 

BACT analysis including NOX control technologies and feasibility determinations can be found in the 

March 2014 modification application and in the original statement of basis for the existing permit 

(Permit No. OCS-EPA-R4012), which are available in the administrative record for this project, as 

discussed in Section 9.0 of this document.

As discussed above, results from the October 2013 source tests on the Developer’s main generating 

engines demonstrated that the emissions of NOX would exceed the BACT limit of 8.6 g/kW-hr 

established in the existing permit. Statoil proposed a revised BACT emission limit for NOX of 12.30 

g/kW-hr for the main generator engines on the Developer based on a 5% margin of compliance above 
18

Statoil OCS-EPA-R4012-M1 070914

the highest emission rate obtained during the source test. Based on our analysis of all test results, the 

EPA is proposing a BACT emission rate for each of the engines of 12.0 g/kW-hr, which is 

approximately two standard deviations above the average of the high load testing results. Given that 

there is a 24-hour averaging time and the units will be operating at variable load, the EPA believes well 

maintained engines will be able to achieve this emission rate. This BACT emission rate is within the 

range of the EPA’s recent BACT determinations for engines of similar size and model year.

In addition to the short-term BACT emissions limit, annual emissions rate limits in tons per year have 

been added to the draft permit for the main generator engines which reflect calculations presented in the 

modification application.

The EPA refers interested parties to the administrative record for Permit No. OCS-EPA-R4012 for the 

EPA’s original statement of basis/preliminary determination for this project and the comprehensive NOX

BACT analysis. These materials are available in the project’s administrative record, as discussed in 

Section 9.0 of this document. The revised NOX BACT emissions limits that were incorporated in this 

modified draft permit are given in the table below. 

Table 6-1: Revised NOX BACT Conclusions (Operating Scenario 1)

Emission Units Control Option Short Term 

Emission Limit 

Annual 

Emission Limit

(8) Main Generator 

Engines

(GEN-1 through

GEN-8)

40 CFR part 94 Tier 2 

Compliant Design 

(Turbocharger, Aftercooler,

High Injection Pressure Fuel 

System, and Low NOX

Tuning)

12.0 g/kW-hr

each engine

(24-hour rolling 

average)

416.15 TPY 

combined eight 

engines

(12-month 

rolling total)

6.3 VOC BACT Analysis for Internal Combustion Engines

Most VOCs found in diesel exhaust are the result of unburned fuel, although some are formed as 

combustion products. VOC compounds participate in atmospheric photochemical reactions which can 

result in the formation of ozone. For the purpose of PSD applicability, VOCs do not include methane, 

ethane, and other compounds that have negligible photochemical reactivity.

6.3.1 Step 1: Identify all Available Control Technologies

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

modification application submitted in March 2014: 

1. Diesel Oxidation Catalyst (DOC)

2. Catalyzed Diesel Particulate Filter (CDPF)

3. Flow Through Filter (FTF)

4. Engine Replacement

5. Tier 1 or 2 Certification

6. Good Combustion Practices

7. Ultra-Low Sulfur Diesel (USLD)

From other OCS projects, the EPA is aware of the following additional technology options:
19

Statoil OCS-EPA-R4012-M1 070914

8. 4-Way Catalyst Converter with Exhaust Gas Recirculation System

9. E-POD 

6.3.2 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.

Diesel Oxidation Catalyst (DOC), Catalytic Diesel Particulate Filter (CDPF), and Flow through 

Filter (FTF): These control technologies require sufficient exhaust temperatures to perform. The main 

generating engines operate under fluctuating, typically low, loads and the emergency generator and 

cementing unit engines operate intermittently by design. Therefore, none of the diesel engines onboard 

the Developer are able to sustain the constant steady state loads or temperatures necessary for control 

technology performance. These control technologies are also flow-through units that can cause pressure 

drops across the exhaust flow resulting in back pressure and plugging of the engine, which can create 

safety concerns. In addition, for internal combustion engines, these technologies have not been designed 

or tested on a scale comparable to the large main and emergency diesel engines. Although the applicant 

provided a cost analysis for installing DOC, CDPF, and FTF on the emergency generator engine, these 

analyses were not relied upon in EPA’s decision. The EPA agrees with the applicant that these control 

technologies are not technically feasible for the main generating engines, the emergency generator, and 

the cementing unit engines. 

Engine Replacement (40 CFR part 1042 Tier 4 Compliant Engines): Based on engine specifications, 

the main generator engines on the Developer are classified as Category 2 marine engines under 40 CFR 

part 1042 Tier 3 and Tier 4 requirements. 40 CFR part 1042 does not require Tier 3 certification for 

Category 2 engines rated at or above 3,700 kW. Tier 4 certification requirements for similarly rated 

engines go into effect beginning with model years 2014-2015. After an independent search by the EPA, 

no comparable Tier 3 or Tier 4 certified marine engines that satisfy size, space, and weight restrictions 

on the vessel were identified. It has been established in previous Region 4 OCS permitting actions that 

the referenced restrictions must be met for engine replacements to avoid any possible safety risk from a 

loss of power. With no comparable engine on the market able to meet the lower Tier 3 or Tier 4 

emission standards without the use of add-on control technology, the EPA agrees that this option is not 

considered to be technically feasible for the main generator engines.

Replacement of the emergency generator engine with a comparable 40 CFR 1042 Tier 3 or Tier 4 

certified engine is considered technically feasible and is carried through the next step of the BACT 

analysis. Likewise, replacement of the cementing unit engines is considered technically feasible and is 

carried through the next step of the BACT analysis.

40 CFR 94 Tier 1 or 2 Certification: The main generator engines on the Developer are Category 2 

marine engines subject to Tier 1 certification requirements under 40 CFR part 94. However, the 

certification documentation provided by the applicant indicates that the main generator engines meet the 

more stringent 40 CFR part 94 Tier 2 THC+NOX emission standard that is applicable to comparable 

2007-2013 model year engines. Therefore, meeting this tier standard is considered technically feasible

for control of VOC and is carried through the next step of the BACT analysis for the main generator 

engines.
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Statoil OCS-EPA-R4012-M1 070914

The emergency generator engine located on the Developer is a Category 1 marine engine certified by the 

manufacturer to meet relevant 40 CFR part 89 Tier 1 nonroad compression ignition engine requirements 

for hydrocarbon emissions. Meeting this tier standard is considered technically feasible for control of 

VOC and is carried through the next step of the BACT analysis for the emergency generator engine.

The cement unit engines located on the Developer are certified to meet the 40 CFR part 94 Tier 2 marine

engine standard for THC+NOx emissions of 7.2 g/kW-hr. Therefore, meeting this tier standard is 

considered technically feasible for control of VOC and is carried through the next step of the BACT 

analysis for the cementing unit engines.

4-Way Catalyst Converter with Exhaust Gas Recirculation System: The engines onboard the 

Developer will not sustain constant steady state loads or temperatures for a sufficient time necessary for 

high catalyst performance. Non-combustible chemical elements present in engine lube oils may also 

collect over time and damage the catalyst. Furthermore, based on information from Wärtsilä, this 

technology is in the developmental stage and is not available for this project. For these reasons, the EPA 

has determined that this technology is not technically feasible.

E-POD: This technology integrates selective catalytic reduction with a DOC or a CDPF. The EPA has 

determined that this technology is technically infeasible based on the rationale for elimination of DOC 

and CDPF technologies. 

6.3.3 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 6-2 lists the control technologies that have not been ruled out 

as technically infeasible options. These options are then ranked by effectiveness.

Table 6-2: Step 3 Control Technologies Ranked by Effectiveness

Engine Rank Control Description VOC

Control 

Effectiveness

(8) Main Generator Engines

(GEN-1 thru GEN-8)

1 40 CFR 94 Tier 2 compliant 

engines, use of ULSD, turbocharger, 

aftercooler, high injection pressure 

fuel system, and good combustion 

practices

Baseline

Emergency Generator Engine

(EGEN)

1 Engine replacement and 40 CFR 

1042 Tier 3 or 4 certification

56%

2 40 CFR 89 Tier 1 compliant engine, 

use of ULSD, turbocharger, 

aftercooler, electronic fuel injection 

system, and good combustion 

practices

Baseline

(2) Cementing Unit Engines

(CMU-1 and CMU-2)

1 Engine replacement and 40 CFR 

1042 Tier 3 or 4 certification

22%

2 40 CFR 94 Tier 2 certification, use 

of ULSD, turbocharger, aftercooler, 

and good combustion practices

Baseline
21

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6.3.4 Step 4: Evaluate the Energy, Environmental and Economic Impacts

Engine Replacement and 40 CFR 1042 Tier 3 or 4 Certification for Emergency Generator Engine: 

In their March 2014 modification application, Statoil examined the cost effectiveness of replacing the 

emergency generator engine on the Developer with a comparable 40 CFR part 1042 Tier 4 certified 

engine. A comparable 2014 or 2015 model year replacement would ordinarily be required to meet the 

Tier 3 certification requirements. However, to remain conservative in the cost analysis, the applicant 

assumed that an appropriate Tier 4 compliant engine comparable in size to the emergency generator 

engine would be available and technically feasible. A VOC emissions control efficiency of 

approximately 56% was determined by comparing the annual average VOC emission factor for the 

existing emergency generator engine (0.43 g/kW-hr) to the Tier 4 non-methane hydrocarbons (NMHC) 

emission standard (0.19 g/kW-hr) that would apply to a comparable engine. The total capital cost for 

replacement of the emergency generator engine is estimated to be $5,644,136. Based on a 10-year 

engine lifespan and a 7% annual interest rate, the cost is estimated to be $808,441 on an annualized 

basis. 

Statoil estimated that 10 days would be necessary to replace the engine and included the daily lease rate 

for the vessel in the cost analysis. Based on the emissions reduction potential (56%), Statoil estimates a 

VOC reduction of 0.020 tpy. As a result, the cost effectiveness was calculated to be $40,693,133 per ton 

of VOC emissions removed. The EPA concurs with the applicant that this is not cost effective.

Cost analysis calculations and supporting documentation are included in Appendix D of the March 2014 

modification application.

Engine Replacement and 40 CFR 1042 Tier 3 or 4 Certification for Cement Unit Engines: In their 

March 2014 modification application, Statoil examined the cost effectiveness of replacing the cementing 

unit engines on the Developer with comparable 40 CFR part 1042 Tier 3 certified engines. A 

comparable 2014 or 2015 model year replacement would ordinarily be required to meet the current Tier 

3 certification requirements. However, to remain conservative in the cost analysis, the applicant assumed 

that an appropriate Tier 3 engine meeting the more stringent part 1042 requirements for a 2018 model 

year engine would be available. A VOC emissions control efficiency of approximately 22% was 

determined by comparing the Tier 2 THC+NOx emission standard applicable to each of the existing 

cement unit engines (7.2 g/kW-hr) to the Tier 3 THC+NOx emission standard (5.6 g/kW-hr) that would 

apply to a Category 1 marine engine of a comparable engine. The total capital cost for replacement of 

the two cementing unit engines is estimated to be $309,185. Based on a 10-year engine lifespan and a 

7% annual interest rate, the cost is estimated to be $44,021 on an annualized basis. 

Statoil did not include a daily lease rate for the vessel in the cost analysis. Based on the emissions 

reduction potential (22%), Statoil estimates a VOC reduction of 0.042 tpy. As a result, the cost 

effectiveness was calculated to be $1,061,191/ton of VOC emissions. The EPA concurs with the 

applicant that this is not cost effective.

Cost analysis calculations and supporting documentation are included in Appendix D of the March 2014 

modification application.

6.3.5 Step 5: Select BACT

After taking into account the energy, environmental, and economic impacts discussed above in Step 4 of 

the BACT analysis, the EPA determined that the control options summarized in Table 6-3 are BACT for 
22

Statoil OCS-EPA-R4012-M1 070914

diesel engines on the Developer. The BACT limits for VOC emissions from the main generator engines 

were established for low and high engine load scenarios (i.e., less than 55 percent and greater than or 

equal to 55 percent loads). In addition to the short-term BACT emissions limit, annual emissions rate 

limits in tons per year have been added to the draft permit for the main generator engines which reflect 

calculations presented in the modification application.

Table 6-3: VOC BACT Conclusions for Internal Combustion Engines

Emission Units Control Option Short Term 

Emission 

Limit

Annual 

Emission 

Limit

Operating Limit

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, 

after- cooler, and high 

injection pressure) and 

ULSD with good 

combustion practices 

based on current 

manufacturer 

recommendations.

2.15 g/kW-hr 

at < 55% 

loads for each 

engine (24-

hour rolling 

average)

-----------------

1.73 g/kW-hr 

at ≥ 55% 

loads for each 

engine (rolling 

24-hour 

average) 

66.12 TPY 

combined 

eight 

engines 

(12-month 

rolling total)

_________

Emergency 

Generator 

Engine

(EGEN)

Use of engine with 40 

CFR 89 Tier 1 compliant 

design (including 

turbocharger, after cooler 

and electronic fuel 

injection) and ULSD 

with good combustion 

practices based on 

current manufacturer 

recommendations.

__________ ________ 39 hours per year of 

planned operation time 

for routine testing and 

maintenance on a 

rolling 12-month 

average basis

Cementing Unit 

Engines

(CMU-1 and

CMU-2)

Use of engine with 40 

CFR 94 Tier 2 compliant 

design and ULSD with 

good combustion 

practices. 

__________ ________ 300 combined hours 

per year on a rolling 

12-month average 

basis

6.4 PM10/PM2.5 BACT Analysis for Internal Combustion Engines

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

lubrication oil in the combustion chamber. BACT for PM10 and PM2.5 is addressed concurrently since 

any control technology available for the control of PM2.5 will also effectively control PM10. The PM10

and PM2.5 emissions represent 82.2% and 79.8% of total PM emissions, respectively, based on AP-42 

factors.
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6.4.1 Step 1: Identify all Available Control Technologies

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

application submitted in March 2014 which is contained in the administrative record described in 

Section 9.0 of this document:

1. Diesel Particulate Filter/Catalyzed Diesel Particulate Filter (DPF/CDPF)

2. Diesel Oxidation Catalyst (DOC)

3. Flow Through Filter (FTF)

4. Open/Closed Crankshaft Ventilation (OCV/CCV)

5. Engine Replacement

6. Engine Retooling (Engine Rebuild Kits)

7. Engine Derate

8. Alternative Lube Oils

9. Tier 1 or 2 Certification

10. LNE design including (turbocharger with after-cooler/high injection pressure/electronic fuel 

injection)

11. Good Combustion Practices

12. Ultra-low Sulfur Diesel

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

13. E-POD Technology (on Large Combustion Engines and Third Party Engines)

14. 4-Way Catalyst Converter with Exhaust Gas Recirculation System

6.4.2 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.

Diesel Oxidation Catalyst (DOC), Catalytic Diesel Particulate Filter (CDPF), and Flow through 

Filter (FTF): These control technologies require sufficient exhaust temperatures to perform. The main 

generating engines operate under fluctuating, typically low, loads and the emergency generator and 

cementing unit engines operate intermittently by design. Therefore, none of the diesel engines onboard 

the Developer are able to sustain the constant steady state loads or temperatures necessary for control 

technology performance. These control technologies are also flow-through units that can cause pressure 

drops across the exhaust flow resulting in back pressure and plugging of the engine, which can create 

safety concerns. In addition, for internal combustion engines, these technologies have not been designed 

or tested on a scale comparable to the large main generator and emergency diesel engines.

The smaller cement unit engines operate in a hazardous area that requires specially certified equipment 

to meet safety standards. CDPF, DOC or FTF systems that meet the hazardous zone requirements were 

not identified by the applicant or by the EPA after an independent search. Although the applicant 

provided a cost analysis for installing DOC, CDPF, and FTF on the emergency generator engine, these 

analyses were not relied upon in the EPA’s decision. The EPA agrees with the applicant that these 

control technologies are not technically feasible for the main generating engines, the emergency 

generator, and the cementing unit engines. 
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Engine Replacement (40 CFR part 1042 Tier 3 or 4 Compliant Engines): Based on engine 

specifications, the main generator engines on the Developer are classified as Category 2 marine engines 

under 40 CFR part 1042 Tier 3 and Tier 4 requirements. 40 CFR part 1042 does not require Tier 3 

certification for Category 2 engines rated at or above 3,700 kW. Tier 4 certification requirements for 

similarly rated engines go into effect beginning with model years 2014-2015. After an independent 

search by the EPA, no comparable marine engines that satisfy size, space, and weight restrictions on the 

vessel were identified that are certified to Tier 3 or Tier 4 standards. It has been established in previous 

Region 4 OCS permitting actions that the referenced restrictions must be met for engine replacements to 

avoid any possible safety risk from a loss of power. With no comparable engine on the market able to 

meet the lower Tier 3 or Tier 4 emission standards without the use of add-on control technology, the 

EPA agrees that this option is not considered to be technically feasible for the main generator engines. 

Replacement of the emergency generator engine with a comparable 40 CFR 1042 Tier 3 or Tier 4 

certified engine is considered technically feasible and is carried through the next step of the BACT 

analysis. Likewise, replacement of the cementing unit engines is considered technically feasible and is 

carried through the next step of the BACT analysis.

40 CFR 94 Tier 1 or 2 Certification: The main generator engines on the Developer are Category 2 

marine engines certified by the manufacturer to meet Tier 1 requirements under 40 CFR part 94. Tier 1 

certification requirements do not include a PM emissions limitation. PM emissions were measured in the 

October 2013 source testing from the main generator engines. The results indicate that emissions from 

the main generator engines would likely meet the applicable Tier 2 PM emission standard. However, 

there was not sufficient data to definitively establish compliance. Therefore, replacement of these 

engines with Tier 2 certified engines is considered technically feasible and is carried through the next 

step of the BACT analysis.

The emergency generator engine is a Category 1 marine engine certified by the manufacturer to meet 

relevant 40 CFR part 89 Tier 1 nonroad compression ignition engine requirements for PM emissions. 

Since 40 CFR part 1042 Tier 3 certification requirements apply for engine model years between 2012 

and 2015, Statoil opted to examine replacement of this engine with a new unit meeting this requirement 

as opposed to a Tier 2 compliant model. This is considered technically feasible for control of 

PM10/PM2.5 and is carried through the next step of the BACT analysis for the emergency generator 

engine.

The cement unit engines are certified to meet the 40 CFR part 94 Tier 2 marine engine standard for PM

emissions. Therefore, meeting this tier standard is considered technically feasible for control of 

PM10/PM2.5 and is carried through the next step of the BACT analysis for the cementing unit engines.

Open Crankcase/Closed Crankcase Ventilation: Crankcase ventilation systems are intrinsic to an 

engine’s design. The main generator, emergency generator, and cement unit engines on the Developer

are constructed with OCV systems that use centrifugal force or knockout-type equipment for PM 

control. Therefore, use of this control technology is carried forward in the BACT analysis for these 

engines.

Engine Rebuild Kits: According to the manufacturer of the engine rebuild kits, Clean Cam Technology 

Systems, LLC, these kits are only available for two-stroke Detroit Diesel engines, model series 71 and 

92. None of the main generator, emergency generator, or cement unit engines on the Developer are twostroke engines. Therefore, the EPA does not consider this technology to be feasible for these engines.
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Engine Derate: While derating the engines can potentially reduce NOX emissions, it would likely result 

in higher particulate emissions due to decreased combustion temperatures and more incomplete 

combustion within the engine. Furthermore, derating an engine can decrease available power to the 

engines reducing the vessel’s ability to maintain correct positioning during storms and loop current 

events and impairing the performance of the auxiliary engines during drilling activities. This would 

cause an unacceptable safety risk on the drilling vessels. Therefore, the EPA does not consider this 

control technology technically feasible.

Alternative Lube Oils: Statoil conducted a review of the available literature regarding use of alternative 

lube oils in diesel engines, which is included in the March 2014 modification application. Currently, 

there is a lack of information available to definitively assess the use of alternative lube oils or quantify 

emissions reductions with respect to PM emissions control. Therefore, the EPA does not consider the 

use of alternative lube oils to be a technically feasible demonstrated control for these engines at this 

time.

4-Way Catalyst Converter with Exhaust Gas Recirculation System: The engines onboard the 

Developer will not sustain constant steady state loads or temperatures for a sufficient time necessary for 

high catalyst performance. Non-combustible chemical elements present in engine lube oils may also 

collect over time and damage the catalyst. Furthermore, based on information from Wärtsilä, this 

technology is in the developmental stage and is not available. For these reasons, the EPA has determined 

that this technology is not technically feasible.

E-POD: This technology integrates selective catalytic reduction with a DOC or a CDPF. The EPA has 

determined that this technology is technically infeasible based on the rationale for elimination of DOC 

and CDPF technologies. 

6.4.3 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 6-4 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, the emergency generator engines, and the cementing unit engines.

Table 6-4: Step 3 Control Technologies Ranked by Effectiveness

Engine Rank Control Description PM10/PM2.5 

Control 

Effectiveness

(8) Main Generator Engines

(GEN-1 thru GEN-8)

1 Engine replacement and 40 CFR 94 

Tier 2 certification for PM

4%

2 40 CFR 94 Tier 2 compliant

engines, use of ULSD, OCV, 

turbocharger, aftercooler, high 

injection pressure fuel system, and 

good combustion practices

Baseline

Emergency Generator Engine

(EGEN)

1 Engine replacement and 40 CFR 

1042 Tier 3 or 4 certification

87%
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2 40 CFR 89 Tier 1 compliant engine, 

use of ULSD, OCV, turbocharger, 

aftercooler, electronic fuel injection 

system, and good combustion 

practices

Baseline

(2) Cementing Unit Engines

(CMU-1 and CMU-2)

1 Engine replacement and 40 CFR 

1042 Tier 3 or 4 certification

50%

2 40 CFR 94 Tier 2 certification, use 

of ULSD, OCV, turbocharger, 

aftercooler, and good combustion 

practices

Baseline

6.4.4 Step 4: Evaluate the Energy, Environmental and Economic Impacts

Engine Replacement and 40 CFR 94 Tier 2 Certification for Main Generator Engines: In their 

March 2014 modification application, Statoil examined the cost effectiveness of replacing all eight of 

the main generator engines on the Developer with comparable 40 CFR part 94 Tier 2 certified engines. 

A PM emissions control efficiency of approximately 4% was determined by comparing the maximum 

annual average PM emission factor for the existing engines (0.52 g/kW-hr) to the Tier 2 emission 

standard (0.50 g/kW-hr) that would apply to comparable engines. The total capital cost for replacement 

of the main generator engines is estimated to be $25,231,200. Based on a 10-year engine lifespan and a 

7% annual interest rate, the cost is estimated to be $3,592,355 on an annualized basis. 

Statoil estimated that 30 days would be necessary to replace the engines and included the daily lease rate 

for the vessel in the cost analysis. Based on the emissions reduction potential (4%), Statoil estimates a 

PM10 reduction of 0.512 tpy and a PM2.5 reduction of 0.497 tpy. As a result, the cost effectiveness was 

calculated to be $7,013,456 per ton of PM10 emissions and $7,227,983 per ton of PM2.5 emissions 

removed. Although the EPA calculated slightly different costs based on information in the analysis 

($7,016,318 tpy and $7,228,078, respectively), the EPA concurs with the applicant that this option is not 

cost effective for the main generator engines.

Cost analysis calculations and supporting documentation are included in Appendix D of the March 2014 

modification application.

Engine Replacement and 40 CFR 1042 Tier 3 or 4 Certification for Emergency Generator Engine: 

In their March 2014 modification application, Statoil examined the cost effectiveness of replacing the 

emergency generator engine on the Developer with a comparable 2012 through 2015 model year 40 

CFR part 1042 Tier 3 certified engine. Tier 4 certification is not required prior to 2016 engine model 

years. To remain conservative in their cost estimate, Statoil assumed that an engine comparable in size 

and specifications to the emergency generator engine would be available and technically feasible. A PM

emissions control efficiency of approximately 87% was determined by comparing the annual average 

PM emission factor for the existing emergency generator engine (0.30 g/kW-hr) to the Tier 4 emission 

standard (0.04 g/kW-hr) that would apply to a comparable engine. The total capital cost for replacement 

of the emergency generator engine is estimated to be $5,644,136. Based on a 10-year engine lifespan 

and a 7% annual interest rate, the cost is estimated to be $808,441 on an annualized basis. 
27

Statoil OCS-EPA-R4012-M1 070914

Statoil estimated that 10 days would be necessary to replace the engine and included the daily lease rate 

for the vessel in the cost analysis. Based on the emissions reduction potential (87%), Statoil estimates a 

PM10 reduction of 0.0176 tpy and a PM2.5 reduction of 0.017 tpy. As a result, the cost effectiveness was 

calculated to be $46,039,050 per ton of PM10 emissions and $47,446,719 per ton of PM2.5 emissions 

removed. Although the EPA calculated slightly different costs based on information in the analysis 

($45,934,147 tpy and $47,555,352, respectively), the EPA concurs with the applicant that this option is 

not cost effective for the emergency generator engine.

Cost analysis calculations and supporting documentation are included in Appendix D of the March 2014 

modification application.

Engine Replacement and 40 CFR 1042 Tier 3 or 4 Certification for Cement Unit Engines: In their 

March 2014 modification application, Statoil examined the cost effectiveness of replacing the cementing 

unit engines on the Developer with comparable 40 CFR part 1042 Tier 3 certified engines. A 

comparable 2014 through 2017 model year replacement would ordinarily be required to meet the current 

Tier 3 certification requirements. However, to remain conservative in the cost analysis, the applicant 

assumed that an appropriate Tier 3 engine meeting the more stringent part 1042 requirements for a 2018 

model year engine would be available. A PM emissions control efficiency of approximately 50% was 

determined by comparing the Tier 2 emission standard applicable to each of the existing cement unit 

engines (0.20 g/kW-hr) to the Tier 3 emission standard (0.10 g/kW-hr) that would apply to a Category 1 

marine engine of a comparable 2018 model year engine. The total capital cost for replacement of the two 

cementing unit engines is estimated to be $309,185. Based on a 10-year engine lifespan and a 7% annual 

interest rate, the cost is estimated to be $44,021 on an annualized basis. 

Statoil did not include a daily lease rate for the vessel in the cost analysis. Based on the emissions 

reduction potential (50%), Statoil estimates a PM10 reduction of 0.0101 tpy and a PM2.5 reduction of 

0.0098 tpy. As a result, the cost effectiveness was calculated to be $4,342,888 per ton of PM10 emissions 

and $4,475,674 per ton of PM2.5 emissions removed. Although the EPA calculated slightly different 

costs based on information in the analysis ($4,358,514 tpy and $4,491,938, respectively), the EPA 

concurs with the applicant that this option is not cost effective for the cementing unit engines.

Cost analysis calculations and supporting documentation are included in Appendix D of the March 2014 

modification application.

6.4.5 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 summarized in Table 6-5 are BACT for 

diesel engines on the Developer. The BACT limits for PM10 and PM2.5 were established for low and 

high engine load scenarios (i.e., less than 55 percent and greater than or equal to 55 percent loads). In 

addition to the short-term BACT emissions limit, annual emissions rate limits in tons per year have been 

added to the draft permit for the main generator engines which reflect calculations presented in the 

modification application.

Table 6-5: BACT Conclusions
28

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Emission Units Control Option Short Term 

Emission Limit

Annual Emission 

Limit

Operating 

Limit 

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) and ULSD with 

good combustion practices 

based on current 

manufacturer 

recommendations.

PM10: 0.50 

g/kW-hr at 

< 55% loads for 

each engine (24-

hour rolling 

average) 

PM2.5: 0.49 

g/kW-hr at 

< 55% loads for 

each engine (24-

hour rolling 

average) 

-----------------

PM10: 0.26 

g/kW-hr at ≥ 

55% loads for 

each engine (24-

hour rolling 

average) 

PM2.5: 0.26 

g/kW-hr at ≥ 

55% loads for 

each engine (24-

hour rolling 

average) 

PM10: 12.81 TPY 

combined eight 

engines (12-

month rolling 

total)

PM2.5: 12.43

TPY combined 

eight engines (12-

month rolling 

total)

___________

Emergency 

Generator 

Engine

(EGEN)

Use of engine with 40 

CFR 94 Tier 1 compliant 

design (including 

turbocharger, after cooler 

and electronic fuel 

injection) with good 

combustion practices 

based on current 

manufacturer 

recommendations.

____________ _____________ 39 hours per 

year of planned 

operation time 

for routine 

testing and 

maintenance 

on a rolling 12-

month average 

basis

Cementing 

Unit Engines

(CMU-1 

and CMU-2)

Use of engine with 40 

CFR 94 Tier 2 compliant 

design and good 

combustion practices. 

____________ _____________ 300 combined 

hours per year 

on a rolling 12-

month average 

basis
29

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6.5 BACT Analysis for Storage Tanks

The Developer has various storage tanks subject to BACT review for emissions of VOC. These tanks 

provide storage for diesel fuel, helicopter fuel, and waste oil. The following tanks are included in this 

analysis: FO CMV ST, FO MOB ST, FO SER ST 1 and 2, FO SET ST 3 and 4, FO ST 1 through 4, FO 

LB ST 1 through 4, FO EGEN ST, AV ST 1 through 3, and WO ST 1 and 2. The fuel in these tanks will 

generate VOC emissions resulting from both breathing and working (i.e., loading) losses.

Step 1: Identify all available control technologies

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

submitted in March 2014:

1. Vapor Collection System and Control Device

2. Internal Floating Roof or External Floating Roof 

3. Adsorption System

4. Fixed Roof with Submerged Fill Pipe

The EPA did not identify any additional control technologies that are appropriate for use on storage 

tanks on the Developer.

Step 2: Eliminate technically infeasible control options

After analyzing the above control technologies, all of the options were eliminated as technically 

infeasible for control of VOC emissions from the tanks. Below is a summary of the reasons for 

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

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

March 2014.

Vapor Recovery Units, Adsorption Systems, and Internal or External Floating Roofs: Installation 

of vapor recovery units, adsorption systems and internal or external floating roofs are all considered 

technically infeasible due to space constraints on the vessel. Furthermore, adsorption systems are 

generally not effective for controlling low concentrations of VOC generated by diesel storage tanks. 

Floating roofs are not effective for controlling VOC emissions from stored liquids of low vapor 

pressures, such as diesel. 

Submerged Fill Systems: The Pontoon Fuel Oil Tanks 1 through 4 (FO ST 1 through 4) and the Upper 

Hull Fuel Oil Tanks 1 and 2 (FO SER ST 1 and 2) are equipped with this technology. However, it is not 

technically feasible to install submerged fill systems on existing Developer storage tanks that were not 

initially designed with this technology due to space constraints and the potential for overloading the 

existing mechanical pump feed system with increased pressure. In general, these systems are not 

installed on storage tanks of low vapor pressure and low capacity as is the case with the remaining 

storage tanks. 

Steps 3/4/5: Rank/Evaluate/Determine BACT

Based on a review of the available control technologies, the EPA has determined that BACT is use of 

good maintenance practices in accordance with the most recent manufacturer’s specifications for all 

storage tanks on the drilling vessel at the time that project activities are conducted under this permit and 
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Statoil OCS-EPA-R4012-M1 070914

the use of a submerged fill system for tanks FO ST 1 through 4 and FO SER ST 1 and 2. This will limit 

tank leakage and excessive VOC emissions. The amount of VOC emissions emitted from the tanks is 

also contingent upon both the fuel type and the amount of fuel. Therefore, the applicant will maintain 

records of the tank identification, volume, and fuel type stored. The applicant will calculate emissions 

from the storage tanks using EPA’s TANKS 4.0.9d program.

6.6 BACT Analysis for Cement and Barite Handling Operations

The Developer has cement and barite mixing and transfer operations (CEMENT-BARITE) subject to 

BACT review for emissions of PM10 and PM2.5.

Step 1: Identify all available control technologies

Statoil identified dust collectors with or without the use of an enclosed conveyance system as the only

available control technology in their OCS permit application submitted in March 2014. The EPA did not 

identify any additional control technologies that are appropriate for use with the cement/barite 

operations on the Developer.

Step 2: Eliminate technically infeasible control options

The applicant determined that the use of a cyclone dust collector in an enclosed pneumatic conveyance 

system with the exhaust routed underwater is technically feasible.

Steps 3/4/5: Rank/Evaluate/Determine BACT

Based on a review of the available control technologies, the EPA has determined that BACT is use of 

the existing enclosed conveyance system with cyclonic dust collector and underwater exhaust. The 

permittee shall also use best management practices such as proper maintenance and operation of the 

enclosed pneumatic conveyance dust collector system based on the most recent manufacturer’s 

specifications for the system issued at the time that project activities are conducted under this permit,

performance of a daily visual check of the dust collector system, and maintenance of a daily inspections 

and system maintenance record.

6.7 BACT Analysis for Mud Degassing

The Developer has mud degassing operations (MUD) subject to BACT review for emissions of VOCs. 

Step 1: Identify all available control technologies

The application states that a review of the RBLC database did not reveal any potential control 

technologies to capture and control fugitive emissions from the mud degassing operations and no VOC 

control technologies are applicable. The EPA did not identify any additional control technologies that 

are appropriate for use with the mud degassing operations on the Developer.

Step 2: Eliminate technically infeasible control options

There were no control technologies identified in Step 1.

Steps 3/4/5: Rank/Evaluate/Determine BACT
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Statoil OCS-EPA-R4012-M1 070914

Based on a review of the available control technologies, the EPA has determined that BACT for VOC 

emissions from mud degassing is proper maintenance and operation of all units associated with this 

process based on the most recent manufacturer’s specifications for the equipment issued at the time that 

project activities are conducted under this permit. 

6.8 BACT Analysis for Painting Operations

The Developer has painting operations (PAINT) subject to BACT review for emissions of VOC and 

PM10/PM2.5.

Step 1: Identify all available control technologies

The application states that a review of the RBLC database did not reveal any potential control 

technologies for emissions from the painting operations aboard the Developer. However, Statoil 

acknowledges that transfer efficiency is key in minimizing emissions from painting activities. 

Information included in the application indicates that a high transfer efficiency (> 65%) is possible using 

the paint spraying equipment currently in use on the Developer. Additional information supplied to the 

EPA by Statoil via email on June 23, 2014 indicates that the model of paint sprayer in use on the 

Developer is a high volume low pressure unit designed to attain high transfer efficiencies. Attainment of 

actual transfer efficiencies approaching the potential efficiency is highly dependent on equipment 

operators following manufacturer recommended practices and procedures. The paint sprayer model 

currently in use on the drilling vessel or sprayers of similar efficiency ratings will be used while 

conducting any spray coating under this permit. 

The EPA is also aware of a number of best management practices that can reduce painting related 

emissions, including but not limited to limiting the amount of painting that is performed on the vessel 

while conducting exploratory drilling activities under this permit; use of paint rollers instead of sprayers 

where practical; down spraying of paint where possible; use of a containment system such as a shroud or 

a barrier around the section of the drillship being painted whenever practical to reduce airborne 

particulate matter; proper storage of coatings and thinners in appropriately labeled, non-leaking 

containers; and maintenance of material safety data sheet information for all paints and thinners used 

while conducting painting activities under this permit.

Step 2: Eliminate technically infeasible control options

Use of the identified strategies in step 1 is considered to be technically feasible.

Steps 3/4/5: Rank/Evaluate/Determine BACT

Based on a review of the available control technologies, the EPA has determined that BACT for VOC 

and PM10/PM2 emissions from painting are paint sprayer transfer efficiency requirements, limitation of 

paint spraying, and best management practices as described in step 1.

6.9 BACT Analysis for Welding Operations

The Developer has welding operations (WELD) subject to BACT review for emissions of PM10 and 

PM2.5.
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Statoil OCS-EPA-R4012-M1 070914

Step 1: Identify all available control technologies

The applicant identified the limitation of electrode usage as the only available control technology in the 

modification application submitted in March 2014. The EPA also considers the use of best management 

practices a control technology. This would include, but not be limited to, following the most recent 

manufacturer’s specifications for all equipment used in welding operations at the time that project 

activities are conducted under this permit.

Step 2: Eliminate technically infeasible control options

Of the available control technologies identified in step 1, both are considered technically feasible.

Steps 3/4/5: Rank/Evaluate/Determine BACT

Based on a review of the available control technologies, the EPA has determined that BACT is best 

management practices including following the most recent manufacturer’s specifications for all 

equipment used in welding operations issued at the time that project activities are conducted under this 

permit. The permittee shall maintain an accurate record of the types and quantity (in pounds) of welding 

rods used on a rolling 12-month basis for the purpose of calculating actual emissions

6.10 BACT Analysis for Piping Fugitive Emissions

Statoil identified potential piping fugitive VOC emissions in the BACT analysis portion of their permit 

application. However, based on similar permit applications, the EPA has determined that BACT is 

limited to good maintenance practices to minimize fugitive emissions, including minimizing the release 

of emissions from valves, pump seals, and connectors; daily visual inspections of the components; and 

prompt repair of leaking components. The applicant will report any leaks and corrective action taken. 

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 or major modification, 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).3 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 4.0 above, Statoil requested revised BACT limits for NOX and new BACT 

limits for PM10, PM2.5, and VOC based on October 2013 source testing which indicates that potential 

emissions from the Developer are above the PSD significant emission rates for PM10, PM2.5, and VOC 

and that emissions of NOX are greater than those anticipated at the time that Statoil submitted its original 

 

3

The maximum allowable PSD increments are listed in 40 CFR § 52.21(c).
33

Statoil OCS-EPA-R4012-M1 070914

permit application. NOX is a measured pollutant for NO2 and ozone. Therefore, the PM10, PM2.5, NO2

and ozone NAAQS; and the PM10, PM2.5, 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. 

Therefore, Statoil must address compliance with the 24-hour and annual PM2.5 NAAQS considering 

both direct emissions and secondary contributions. 

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

4

. 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 project, or that would 

occur as a result of any commercial, residential, industrial and other growth associated with the source. 

Analysis for vegetation having no significant commercial or recreational value is not required.

For sources impacting Federal Class I areas,540 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. 

Since the modifications associated with this revised permit do not change the current permitted 

Operating Scenario 2 for the drillship Transocean Discoverer Americas, the required air quality impact 

analyses only addresses the revised Operating Scenario 1 for the Maersk Developer drilling vessel and 

associated support vessels. 

7.2 PSD Class II Air Quality Impact Assessment

An air quality impact assessment was performed for the revised operation of the Maersk Developer

deepwater drilling vessel and associated support vessels. The modeled operating scenario was that which 

produced the worst-case impact. 

 

4

Due to the recent vacatur of the its significant monitoring concentration for PM2.5 (see Section 7.2), this exemption is not aplicable for PM2.5.

5

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

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As discussed in Section 4.0, the estimates of maximum annual emissions of all pollutants from the 

Developer drilling vessel and associated supporting vessels resulted in estimated emissions of PM10, 

PM2.5, VOC, and NOX greater than the PSD significant emissions rate. Hence, PM10, PM2.5, and NOX

are subject to ambient impact assessment. The VOC and NOX pollutants are measured pollutants for 

ozone and precursors for PM2.5. Therefore, impact assessments are also provided for ozone and 

secondary PM2.5.

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, the worst case emissions were assumed to be 

located at the drilling site where the greatest onshore and nearshore impacts could occur [Note: Same 

location as used for both the Discoverer Americas and Developer drilling vessels in the original permit 

application.]. 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. 

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).
35

Statoil OCS-EPA-R4012-M1 070914

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 PM10, PM2.5, and NOX emission sources associated with the proposed exploration drilling 

activities are the diesel-fired engines on the drilling vessel. Additionally, the OCS air regulations define 

the OCS source to include emissions from vessels servicing the OCS sources while en route to and from 

the source when within 25 nautical miles of the drilling operation. Therefore, the impacts from the 

associated fleet of vessels that support the primary drilling activity were included. 

The Developer and support vessel emission sources include the following:

• Main Diesel Generator Engines (8),

• Emergency Generator Engine (1),

• 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), 

• Cement and Barite Handling Activities, and

• Painting 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.

Modeling Domain – Dark Blue

25-nautical mile Receptors – Red

Class I Receptors – Purple

Radii – Light Blue
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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 drilling vessel uses a computer 

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

and thrusters. The Developer drilling vessel requires no 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 the 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 the Developer operational scenarios, 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 PM10 and PM2.5 SIL (NAAQS and PSD Increment), and

• Class I and II visibility.

The long-term emission rates were used for the remaining assessments:

• Class I and Class II annual NO2 SIL (NAAQS and PSD Increment),

• Class I and II annual PM10 and PM2.5 SIL (NAAQS and PSD Increment), and

• Class I annual Nitrogen deposition rate.

The Developer’s modeled maximum short-term (1-hour to 24-hour) emissions are based on:

• Five main generator engines operating at 60% load and auxiliary equipment (i.e., 1 

emergency generator engine, 4 life boat engines, 1 fast rescue boat and 2 cementing unit 

engines) operating at 100% load. 

• Three Offshore Support Vessels (OSV) with 2 main engines on each at 75% load.

• One crew boat with 4 engines each at 75% load.

• These vessel/boat operations also have daily fuel usage limits: All OSV operations are 

limited to 13,058 gallons diesel fuel per day while the crew boat diesel fuel usage is limited 

to 6,620 gallons when operating within 25 nautical miles of the drilling vessel.

The Developer’s annual modeled emissions are based on:

• Eight main generator engines operating at 12 varying operational modes for 180 days;

• All auxiliary equipment operating at 100% load [1 emergency (39 hours), 4 life boat engines 

(12 hours), 1 fast rescue (12 hours), and 2 cement units (300 hours total)] for the indicated 

permitted time periods in the 180-day campaign;. 

• One OSV with two main engines on each at 100 % load for 2,570 hours per 180-day 

campaign;

• One crew boat with 4 engines and 2 generator engines at 100% load each for 618 hours per 

180-day campaign; and 
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• Although a 180-day drilling campaign is the planned annual operations, the length of the 

campaign will be fuel limited. These limits are: based on 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 Developer

exploratory drilling operations will be limited to 2,459,150 gallons diesel fuel per year.

Statoil is requesting authorization for the Developer drilling vessel, and its associated support fleet, to 

operate in any of Statoil’s lease blocks located within the eastern Gulf of Mexico (EGOM) as listed in 

Section 2.2 of this document and any additional lease block in the EGOM whose nearest drilling 

location is at least 176 km (95 nautical miles) from the three PSD Class I area if concern in this 

application, more than 300 km (162 nautical miles) from any other PSD Class I area, and more than 93 

km (50 nautical miles) from the nearest PSD Class II modeled receptor. To ensure the modeled worstcase 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 the Developer

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). This location was used for all impact assessment except PSD Class I area 

visibility. The mobile support vessels were modeled as 100 volume sources distributed along the 25 

nautical mile path. The initial plume dimensions (i.e., sigma-y and sigma-z) were based on the width and 

height of a representative support vessel. The Developer 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 

drilling vessel, 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 contained in the 

Administrative Record (see Section 9). 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 100 km buffer around the drilling location to allow re-circulation of puffs.
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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 Developer 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.

The proposed project emissions from the Developer drilling vessel, as well as the associated support 

vessels, were modeled for comparison to the SMC and SIL for NO2, PM10, and PM2.5. The maximum 

modeled project concentrations at the discrete 25- nautical mile receptors were compared to the PSD 

Class II SILs for NO2, PM10, and PM2.5. Similarly, the maximum modeled pollutant concentrations at 

the discrete 25-nautical mile receptors were compared to the SMC for these pollutants.

The impact modeling results are provided and compared to the SIL and SMC in Table 7-1. Because all 

maximum predicted NO2, PM10, and PM2.5 concentrations are less than the SIL, the project’s estimated 

impacts are not considered to cause or contribute to a violation of the associated NAAQS or PSD 

increments. Furthermore, all maximum predicted concentrations are also much less than the SMC; 

therefore, no pre-construction ambient monitoring is required.

Table 7-1 

Maximum Modeled PSD Class II Area Concentrations
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Pollutant Averaging Period Developer 

Max. 

Concentration 

(ug/m3)

Significant 

Impact Levels 

(ug/m3)

Significant

Monitoring 

Concentrations 

(ug/m3)

NO2

a

1-hourb6.5 7.5 None

Annual 0.042 1.0 14

PM2.5 24-hrb0.09 1.2cvacated

Annual 0.0015 0.3c None

PM10 24-hr 0.107 5 10

Annual 0.0017 1 None

a Annual NOX was conservatively assumed to be 75 percent NO2. One-hour NOX modeled value provided is three year average of the maximum daily 1-hour 

NOX concentration at each receptor with 80 percent NO2 conversion.

b Maximum (100 percentile) values are provided not 98th percentile.

c The PM2.5, SIL, and SMC were vacated in January 2013.

The 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 pre-construction 

ambient air quality monitoring 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 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 shore-based 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 PM2.5 

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 7.5% of the 24-hour and 0.5% 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.

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. 
40

Statoil OCS-EPA-R4012-M1 070914

7.2.7 Ozone

Both VOC and NOX are precursors to ozone formation and the project’s estimated VOC and 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, the 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 0.75% of total NOX and 0.12% of total VOC Gulf of 

Mexico emissions. 

For further comparison, Table 7-2 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

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. 

Therefore, 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.
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7.2.8.1 Growth

The potential growth of industrial, commercial, and residential sources as a result of the proposed 

exploration activities is expected to be minimal. The current infrastructure that supports the welldeveloped 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 drilling vessel, 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. Two criteria are 

assessed in the analysis, delta E and contrast. Delta E, also called plume perceptibility, refers to the color 

difference between the plume and background (i.e., brightness, color hue, and color saturation). The 

default threshold or “critical” value for delta E is 2.0. Contrast, also referred to as green contrast value or 

Cp, represents the contrast of a plume against a background such as the sky or a terrain feature. Change 

in contrast is measured in terms of green color wavelength. The default threshold or “critical” value for 

contrast is 0.05.

Tables 7-3 provides the results of the VISCREEN modeling for the Developer drilling vessel. This table 

shows that the default threshold for Delta E and contrast (Cp) were not exceeded for sky or terrain 

backgrounds by the drilling vessel at 50 km distance. Therefore, the proposed Developer 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 Delta E Contrast
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(Source-Observer) Critical Plume Critical Plume

Sky 10 50 km 2.00 1.254 0.05 -0.007

Sky 140 50 km 2.00 0.387 0.05 -0.009

Terrain 10 50 km 2.00 0.079 0.05 0.001

Terrain 140 50 km 2.00 0.023 0.05 0.001

7.3 PSD Class I Areas Analyses

The PSD Class I areas nearest 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 Breton NWR, 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-preferred model for long-range transport assessments, CALPUFF Version 5.8, was used to 

evaluate potential AQRV and PSD increment impacts at Breton NWR. This model is also recommended 

by the FLM for Breton NWR. 

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. 

The CALPUFF-estimated hourly PM10, 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 the Developer drilling vessel (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 condition the drilling vessel was located at their closest location – the 

NW corner of the lease block nearest Breton. For all impact analyses except PSD Class I area visibility, 
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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. For the PSD Class I visibility assessment, 

the mobile support vessels were modeled as 100 volume sources distributed along the 25 nautical mile 

path. The initial plume dimensions (i.e., sigma-y and sigma-z) were based on the width and height of a 

representative support vessel. 

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 impacts from the proposed exploratory drilling emissions are 

provided in Table 7-4. The accepted PSD Class I annual SIL is also provided in this table. The 

maximum modeled concentrations associated with the proposed project emissions for the Developer

drilling vessel are much less than the SIL. Therefore, the project is considered to have no significant 

impact on the PSD Class I increments.

Table 7-4

Maximum Modeled Class 1 Concentrations

Criteria Pollutant Averaging Period Developer Max. 

Concentration 

(ug/m3)

EPA SIL

(ug/m3)

NO2

a Annual 0.018 0.1

PM2.5b24-hr 0.047 0.07c

Annual 0.0007 0.06c

PM10 24-hr 0.052 0.3

Annual 0.0008 0.2

a NOX was assumed to be 75 percent converted to NO2.

b 100 percent (maximum) values are provided using direct PM2.5 emissions only.

c The Class I PM2.5 SIL was vacated in January2013.

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 7-4 maximum project impacts are 67.1% of the 24-hour and 1.2% 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 7-5. 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 
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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 7-5

Estimated Class I Area Deposition Fluxes (kg/ha/yr)

Class I Area Developer

Nitrogen Deposition

Breton NWR 0.0014

Deposition Analysis 

Threshold

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. 

Visibility extinction coefficients were calculated for 24-hour averages. Comparison with FLMrecommended criteria for regional visibility impacts is shown by calculating the change in 24-hour 

extinction for each Class I receptor. The CALPUFF modeling system was used to predict both the 

extinction coefficient attributable to emissions from the project as well as the background extinction 

coefficients for that day’s meteorology. 

The Method 8 estimated project associated changes in visibility extinction for the Developer vessel 

resulted in a number of days with more than five percent change in extinction. The Developer

assessment resulted in 19 days over a three year period from 2001 through 2003 exceeding five percent 

change in extinction with a maximum of 18.95 percent. Fourteen of the 19 days had changes of less than 

10 percent. Table 7-6 provides a summary of the results of the Method 8 modeling analysis. This table 

reveals that the three year average Method 8 98th percentile value for the drilling vessel is less than the 

five percent change in extinction that the FLM considers to be the perceptible level.

Table 7-6 

Summary of Method 8

Maximum Estimated Change in Extinction for Breton Wilderness

Criteria Developer (%)

Highest Value 18.95

Number Days > 5% Change 19

Number Days >10% Change 5

98th Percentile Change 2001 5.03

98th Percentile Change 2002 4.32

98th Percentile Change 2003 4.73

98th Percentile Change 3 year average 4.69
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The estimated impacts of the proposed project’s emissions on the nearest PSD Class I area shows 

visibility impacts for the Developer just greater than the FLM perceptibility level. The drilling vessel’s 

deposition levels are less than the FLM’s DAT 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. 

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. BOEM serves 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 proposing to revise, 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. This determination 

remains unchanged from the original permit action.
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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 Gulf of Mexico. 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. 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 

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 permit revision 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. 

This determination remains unchanged from the original permit action.

9.0 Public Participation

9.1 Opportunity for Public Comment

While neither the OCS nor PSD regulations address the administrative procedures for permit revisions, 

given that the revisions change the BACT emission limits previously offered for public comment and 

include new BACT limits and work practice standards, the EPA is following the procedures of 40 CFR 
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part 124 and 40 CFR part 71 in processing this permit revision. As required by these provisions, the 

EPA is seeking public comment on the revisions incorporated into the Statoil OCS air permit OCS-EPAR4012-M1.

Any interested person may submit written comments on the draft revisions to the permit during the 

public comment period. If you believe that any revision to 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 administrative 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 revisions to the air quality permit, EPA’s analysis of the 

modification, and the revised air quality impacts of the project. If you have 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 the EPA. The EPA may summarize the 

comments and group similar comments together in our response instead of responding to each individual 

commenter.

All comments on the draft permit revisions must be received by email at R4OCS permits@epa.gov, 

submitted electronically via www.regulations.gov (docket # EPA-R04-OAR-2014-0510), or 

postmarked by August 8, 2014. Comments sent by mail should be addressed to: USEPA Region 4, Air 

Permits Section APTMD, 61 Forsyth Street, SW, Atlanta, GA 30303; Attn: Rosa Yarbrough. An 

extension of the 30-day comment period may be granted if the request for an extension is filed within 

the 30-day comment period and it 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 must 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 revisions. Public Hearing requests must be in writing and received by EPA by

July 31, 2014. 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 
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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 in the draft permit revisions, EPA will hold a public hearing on August 14, 

2014, 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 404-562-9643 to verify if the public hearing will be held.

9.3 Administrative Record

The administrative record contains the application, supplemental information submitted by Statoil, 

correspondence (including e-mails) clarifying various aspects of Statoil’s application, other material 

used in the EPA’s decision and rationale process, and correspondence with other agencies. The 

administrative record and draft permit are available on www.regulations.gov (docket# EPA-R04-OAR2014-0510) and through the EPA’s website at: 

http://www.epa.gov/region4/air/permits/ocspermits/ocspermits.html. 

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 

The EPA will make a decision to issue a final revised permit, or to deny the application for the permit

modification, after the Agency has considered all timely comments on the proposed determination. 
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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.