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
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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 (MaerskDeveloper) 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
ii
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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
C02
Carbon Dioxide
C02e
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
3
m
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
N02
Nitrogen Dioxide
NO A A
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
S02
Sulfur Dioxide
Support Vessels
Crew Boats and Offshore Support Vessels
THC
Total Hydrocarbon
TP Y 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'
2
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• Farther from the closest lease block modeled as part of the project defined in Permit No. OCS-
EPA-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
88ww www
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
/•.'.VI 'IROS 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
few*
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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
ENllRONInternational 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)(1) 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)(1).
"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
NOx1
554.05
40
Yes
VOC2
75.65
40
Yes
PM10
17.47
15
Yes
PM2.5
16.03
10
Yes
'NOx is a measured pollutant for the criteria pollutants ozone and NO2 and a precursor for ozone and PM25.
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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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)(l), 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)
Rating"
(kW)
Rating"
(hp)
Manufacture
Date
GEN-1
Main Generator
Engine 1
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-2
Main Generator
Engine 2
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-3
Main Generator
Engine 3
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-4
Main Generator
Engine 4
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-5
Main Generator
Engine 5
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-6
Main Generator
Engine 6
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-7
Main Generator
Engine 7
Wartsila
16V26A
17.0
4840
6651
8/2006
GEN-8
Main Generator
Engine 8
Wartsila
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
9
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Emissions
Unit ID
Engine
Description
Manufacturer
and Model
Displacement
(L/cylinder)
Rating"
(kW)
Rating"
(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
Total
NOx
S02
PM
PM10
PM2.5
Source
VOC
(TPY)
(TPY)
(TPY)
(TPY)
(TPY)
(TPY)
Wartsila Diesel
66.12
416.15
0.36
15.58
12.81
12.43
Generator
Engines
Emergency
0.04
0.76
5.47e-04
2.46e-02
2.02e-02
01.96e-2
Diesel
Generator
Engine
Lifeboat
1.75e-03
8.58e-03
7.57e-06
6.87e-04
5.64e-04
5.48e-04
Engines
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Emission
Source
Total
VOC
(TPY)
NOx
(TPY)
S02
(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 Degassing
0.48
--
--
--
—
--
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
1 NOx 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)(l l)(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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GEN-1 through GEN-8: Main Diesel Generator Engines
The Developer's electrical power is provided by eight identical Wartsila 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 forNCh 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 CI5 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
Statoil OCS-EPA-R4012-M1 070914
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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%) PMio 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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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, PMio, 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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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, PMio, 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
15
Statoil OCS-EPA-R4012-M1 070914
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and established that emissions would exceed the PSD significant emissions thresholds for PMio, 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 emittedfrom any
proposed major stationary source or major modification which the Administrator, on a case-by-
case basis, taking into account energy, environmental, and economic impacts and other costs,
determines is achievable for such source or modification through application of production
processes or available methods, systems, and techniques, including fuel cleaning or treatment or
innovative fuel combustion techniques for control of such pollutant. In no event, shall
application of best available control technology result in emissions of any pollutant which would
exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the
Statoil OCS-EPA-R4012-M1 070914
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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
Statoil OCS-EPA-R4012-M1 070914
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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:
Statoil OCS-EPA-R4012-M1 070914
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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 top-
down 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.
Statoil OCS-EPA-R4012-M1 070914
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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 overtime and damage the catalyst. Furthermore, based on information from Wartsila, 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
20
Statoil OCS-EPA-R4012-M1 070914
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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 $l,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
21
Statoil OCS-EPA-R4012-M1 070914
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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)
66.12 TPY
combined
eight
engines
(12-month
rolling total)
1.73 g/kW-hr
at> 55%o
loads for each
engine (rolling
24-hour
average)
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 Repl acement
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 top-
down 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 two-
stroke engines. Therefore, the EPA does not consider this technology to be feasible for these engines.
Statoil OCS-EPA-R4012-M1 070914
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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 overtime and damage the catalyst. Furthermore, based on information from Wartsila, 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
PMio 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.
Statoil OCS-EPA-R4012-M1 070914
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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
PMio 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
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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, after-
cooler, and high injection
pressure) and ULSD with
good combustion practices
based on current
manufacturer
recomm endati ons.
PMio: 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: 12.81 TPY
combined eight
engines (12-
month rolling
total)
PM2.5: 12.43
TPY combined
eight engines (12-
month rolling
total)
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%o loads for
each engine (24-
hour rolling
average)
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
recomm endati ons.
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
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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
Statoil OCS-EPA-R4012-M1 070914
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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 PMio 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
30
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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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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 § 52.2l(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 PMio, 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).
32
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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 § 52.2l(m), a PSD permit application must include an air quality analysis in connection
with the demonstration required by 40 CFR §52.2 l(k). For each pollutant for which a NAAQS or PSD
increment exists, 40 CFR § 52.21(m)(l)(iv) requires the analysis to include at least one year of pre-
construction 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 pre-
construction 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-
l4. 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 § 52.2 l(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,5 40 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 PM25 (see Section 7.2), this exemption is not aplicable for PM25.
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.
Statoil OCS-EPA-R4012-M1 070914
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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 PMio,
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).
Statoil OCS-EPA-R4012-M1 070914
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Figure 7-1 CALPUFF Modeling Domain
LCC (RPO Projection) Easting, km
Image reproduced from the Revised Air Quality Impact Assessment dated June 20 IS from ENVIRON.
7.2.2 Characteristics of Modeled Operational Scenarios
The primary PMio, 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.
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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 long-
term 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 N02 SIL (NAAQS),
Class I and II 24-hour PMio 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 worst-
case impact conditions include the worst-case project location, all impact modeling estimates were
performed with the drilling vessel located at the northwest corner of the closest lease block to the
shoreline and to the nearest PSD Class I area (Breton National Wildlife Refuge (NWR)).
The modeling locations of the associated support vessels {i.e., crew boats and OSVs) for 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 A 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
Significant
Significant
Max.
Impact Levels
Monitoring
Concentration
(ug/m3)
Concentrations
(ug/m3)
(ug/m3)
N02 a
l-hourb
6.5
7.5
None
Annual
0.042
1.0
14
PM2.5
24-hrb
0.09
1.2°
vacated
Annual
0.0015
0.3°
None
PM10
24-hr
0.107
5
10
Annual
0.0017
1
None
" Annual NOx was conservatively assumed to be 75 percent N02. One-hour NOx modeled value provided is three year average of the maximum daily 1-hour
NOx concentration at each receptor with 80 percent N02 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/m3 and the PSD Class II SIL is 1.2 ug/m3. The annual PM2.5
NAAQS is 12 ug/m3 and 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.
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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-OAR-
2009-0491). 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 §
52.2l(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.
Statoil OCS-EPA-R4012-M1 070914
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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 well-
developed oil and gas activities in the area just west of the proposed drilling activities is adequate to
support the proposed drilling activities and no additional growth is expected.
7.2.8.2 Soil and Vegetation
The potential impacts of the proposed project on the soils and vegetation in the project's impact area
must be considered. Assessment of impacts to vegetation having no significant commercial or
recreational values is not required. Due to the location of the proposed exploration activities in the
eastern Gulf of Mexico more than 150 km from any coastline and the modeled project impacts of less
than significant levels, no significant impact from the proposed project to soils or vegetation is expected.
7.2.8.3 Visibility
The estimate of project impact on visibility in the project's impact area was assessed using the EPA
plume impact screening model VISCREEN. The VISCREEN model estimates the potential visual
impact of a plume caused by a proposed project's emissions. A VISCREEN Level I analysis was
conducted to estimate if the emissions from the proposed exploration activities could result in an adverse
impact on visibility at the closest visibility sensitive Class II area receptor. The project's particulate
matter and NOx emissions were provided as inputs, while the default values were used for background
ozone, stability class, and wind speed (default background ozone concentration of 0.04 parts per million,
and default stability and wind speed are 6 and 1 meter per second, respectively). VISCREEN
conservatively evaluated whether a plume from the Developer 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 (9) 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
0
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 PMio, 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,
42
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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)
N02a
Annual
0.018
0.1
PM2.5b
24-hr
0.047
0.07'
Annual
0.0007
0.06=
PM10
24-hr
0.052
0.3
Annual
0.0008
0.2
a NOx was assumed to be 75 percent converted to NCh
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
Statoil OCS-EPA-R4012-M1 070914
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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 FLM-
recommended 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
Statoil OCS-EPA-R4012-M1 070914
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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-EPA-
R4012-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 R40CS 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 R40CSpermits@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-OAR-
2014-0510) 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
varbrough.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.
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