UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
REGION 10
SEATTLE, WASHINGTON
STATEMENT OF BASIS
FOR PROPOSED
OUTER CONTINENTAL SHELF
PREVENTION OF SIGNIFICANT DETERIORATION
PERMIT NO. R100CS/PSD-AK-09-01
SHELL GULF OF MEXICO INC.
FRONTIER DISCOVERER DRILLSHIP
CHUKCHI SEA EXPLORATION DRILLING PROGRAM
Date of Proposed Permit: January 8, 2010
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
TABLE OF CONTENTS
ABBREVIATIONS AND ACRONYMS
1. INTRODUCTION, PROJECT DESCRIPTION AND PUBLIC PARTICIPATION ... .3
2. REGULATORY APPLICABILITY 14
3. PROJECT EMISSIONS AND PERMIT TERMS AND CONDITIONS 28
4. BEST AVAILABLE CONTROL TECHNOLOGY 50
5. AIR QUALITY IMPACT ANALYSIS 87
6. OTHER REQUIREMENTS 117
7. ABBREVIATED REFERENCES 122
APPENDIX A: CRITERIA POLLUTANT EMISSION INVENTORY
APPENDIX B: ORIGINAL MODELING RESULTS FOR SECONDARY OPERATING
SCENARIOS
l
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
ABBREVIATIONS AND ACRONYMS
ASTM American Society of Testing and Materials
BACT Best available control technology
CAA Clean Air Act
CCV Closed Crankcase Ventilation
CDPF Catalytic Diesel Particulate Filter
C.F.R Code of Federal Regulations
CO Carbon monoxide
EPA United States Environmental Protection Agency
Discoverer Frontier Discoverer drillship
HAP Hazardous Air Pollutants
H2S Hydrogen Sulfide
hp Horsepower
HPU Hydraulic Power Units
IC Internal Combustion
kW KiloWatts
kW-e KiloWatts electric
lbs Pounds
MLC Mud line cellars
MMBtu Million British thermal units
NA Not applicable
NESHAP National Emission Standards for Hazardous Air Pollutants
NOx Oxides of nitrogen
NSPS New Source Performance Standards
NSR New Source Review
OCS Outer continental shelf
OSR Oil spill response
Part 55 40 C.F.R. Part 55
PM2.5 Particulate matter with an aerodynamic diameter less than 2.5 microns
PMio Particulate matter with an aerodynamic diameter less than 10 microns
ppm Parts per million
ppmv Parts per million by volume
PSD Prevention of Significant Deterioration
PTE Potential to Emit
Rpm Revolutions per minute
SCAC Separate circuit aftercooled
SER Significant emission rate
SO2 Sulfur dioxide
Shell Shell Gulf of Mexico Inc.
SSBOP Subsea blowout preventer
tpy Tons per year
VOC Volatile organic compound
wt% Weight percent
2
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
1. INTRODUCTION, PROJECT DESCRIPTION AND
PUBLIC PARTICIPATION
1.1 Introduction
Pursuant to Section 328 of the Clean Air Act (CAA), 42 U.S.C. § 7627, the United States
Environmental Protection Agency (EPA) promulgated air quality regulations applicable to Outer
Continental Shelf (OCS) sources, which regulations are set forth in Title 40, Code of Federal
Regulations (C.F.R.), Part 55. Under these regulations, an OCS source that is a major stationary
source and which proposes to locate on the OCS is required to obtain a Prevention of Significant
Deterioration (PSD) permit before beginning construction. The requirements of the PSD
program were established under Part C of Title I of the CAA, 42 U.S.C. § 7470-7492, and are
found at 40 C.F.R. § 52.21.
Under these programs, Shell Gulf of Mexico Inc (Shell)1 has applied for a major source permit to
authorize mobilization and operation of the Frontier Discoverer drillship (Discoverer) and its
associated fleet at various drill sites in the Chukchi Sea outer continental shelf (OCS) off the
North Slope of Alaska in connection with an exploratory oil and gas drilling program
(exploration drilling program).
EPA initially proposed a draft OCS/PSD permit for Shell's exploration drilling program in the
Chukchi Sea for public comment on August 20, 2009 (August 2009 proposed permit), with an
extended public comment period running through October 20, 2009. EPA conducted
government-to-government consultation as requested by affected Native Villages, informational
meetings, and public hearings in Barrow and Anchorage, Alaska during the week of September
21, 2009. After reviewing the comments received on the August 2009 proposed permit, EPA has
decided to issue a new modified proposed permit and is initiating a new public comment period
to ensure the public has an opportunity to review and comment on the new modified permit.2
As with the August 2009 proposed permit, this new modified proposed permit will allow Shell to
operate the Frontier Discoverer drillship and associated fleet for a multi-year exploration drilling
program within Shell's current lease blocks in lease sale 193 on the Chukchi Sea OCS, beyond
1 Although the permit application was initially submitted by Shell Offshore Inc., the applicant has since clarified that
Shell Gulf of Mexico Inc. is the only entity with rights to conduct activities under the leases and is responsible for
compliance with all regulations and orders for activities on the leases. Shell Gulf of Mexico Inc. has confirmed that
it stands by all statements made in the permit application. As a result, EPA is issuing the permit to Shell Gulf of
Mexico Inc.
2 As discussed in Section 1.3.1, because EPA is reproposing the permit in its entirety and will not be taking any
further action on the August 20, 2009 initial proposed permit, EPA will not be responding to comments on the
August 20, 2009 proposed permit. To the extent a commenters believes that comments provided during the
comment period for the August 20, 2009 proposed permit have not been addressed by the new modified proposed
permit or new modified Statement of Basis, the commenter should resubmit those specific un-addressed comments
during the current comment period for this new modified proposed permit.
3
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
25 miles from Alaska's seaward boundary. Because the drillship operations would be a "major"
source of air pollutants, the permit requires that the operations meet PSD program requirements.
Major changes made to the new modified proposed permit since the August 2009 proposed
permit include:
• Overall, emissions of all PSD pollutants allowed under the new modified proposed permit are
lower, with substantial reductions of particulate matter emissions (from 184 tons per year
(tpy) to 52 tpy for fine particulate matter) and sulfur dioxide (from 181 tpy to less than 2 tpy)
as compared to the August 2009 proposed permit.
Table 1.1 - Permitted Air Pollutant Emissions from Discoverer and
Associated Fleet as OCS Source at all Locations
Air Polliiliinl
Inilinl Proposed
Emissions
)
Kc\iscd Emissions
(lp>)
Carbon Monoxide (CO)
762
449
Nitrogen Oxides (NOx)
1965
1188
Particulate Matter Less than 2.5 (PM2 5)
184
52
Particulate Matter Less than 10 (PMi0)
210
58
Sulfur Dioxide (S02)
181
2
Volatile Organic Compounds (VOC)
166
87
• The permit proposes two alternatives for when the Discoverer is considered an "OCS source"
under the permit and when the emission limitations and other operating restrictions apply. In
the August 2009 proposed permit and in this proposal, EPA seeks comment on considering
the Discoverer to be an OCS source when it is attached by a single anchor to the seabed.
EPA is also soliciting comment on an alternative proposal to consider the Discoverer to be an
OCS source when it is sufficiently secure and stable to commence exploratory activity at a
drill site.
• The proposed permit requires the use ultra-low sulfur diesel fuel in all vessels in the
associated fleet when such a vessel is within 25 miles of the Discoverer and the Discoverer is
operating as an OCS source. This change results in a decrease in emissions of SO2 from 181
tpy to less than 3 tpy.
• The proposed permit requires the use of an anchor handler/icebreaker equipped with selective
catalytic reduction controls on the main diesel engines, resulting in much lower emissions of
NOx.
• For the oil spill response vessel, the daily fuel limit for the two propulsion engines is
increased. For the two generator engines on the vessel, the daily fuel limit is decreased. The
proposed permit requires catalytic diesel particulate filters on the propulsion and generator
engines. The net result is a small increase in emissions of NOx from the vessel, but
substantial decreases in particulate matter emissions and SO2 emissions, and moderate
decreases in CO and VOC emissions from this vessel.
• The logging winch engines on the Discoverer have been replaced with newer engines, one of
which is a newer Tier 3 engine that is larger in horsepower than the engine it replaced.
4
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
• The permit requires oxidation catalysts on the compressor diesel engines on the Discoverer
(all new Tier 3 engines), which reduces emissions of particulate matter, VOC, and CO.
• The hours of operation of the emergency generator on the Discoverer are increased from 20
minutes to two hours a month to be consistent with U.S. Coast Guard requirements.
• The fuel limits for the cementing units and logging winch engines on the Discoverer are
decreased to offset the small increase in the emissions from the emergency generator.
• The proposed permit requires tighter restrictions on the waste throughput limit for the
incinerator on the Discoverer, which are tied to the use of the Discoverer's HPU engines,
resulting in an overall reduction of emissions from the incinerator and the HPU engines as
compared to the August 2009 proposed permit. The permit also requires development and
implementation of a waste segregation plan.
• For the main generator engines on the Discoverer and for the icebreaker engines, the permit
requires a compliance assurance regime based on the monitoring of engine loads instead of
monitoring of fuel usage.
• Certain restrictions on the locations of the icebreakers in relation to the Discoverer while
traveling on non-icebreaking activities are eliminated and replaced with requirements to
record the duration, purpose and operating loads at such locations.
• The number of operating loads required for the stack testing of the newer and smaller engines
and the boilers on the Discoverer and the non-propulsion engines on the icebreakers is
reduced.
• Monitoring of the ammonia emissions from controls on the Discoverer's main generator
engines is changed from continuous monitoring to stack testing.
Again, the net result of the changes in this new modified proposed permit as compared to the
August 2009 proposed permit is a reduction of all PSD pollutants emitted by Shell's exploration
drilling program, with a substantial reduction of particulate matter emissions and SO2.
Application Chronology-
November 2008-August 2008
Dale
Document Description
11/12/2008
Modeling Protocol for Chukchi and Beaufort Sea Exploration Drilling
Program
12/11/2008
Letter from Susan Childs, Shell Offshore, Inc. to Richard Albright, EPA
regarding Preconstruction Permit Application for Frontier Discoverer
Drill Vessel in Chukchi Sea, beyond the 25-mile Alaska Seaward
Boundary
01/15/2009
E-mail from Tim Martin, Air Sciences, Inc. to Herman Wong, EPA
regarding the Discoverer Chukchi Source Contribution
01/16/2009
Letter from EPA to Shell Regarding the Incompleteness Determination
for the Chukchi PSD Permit Application
01/26/2009
E-mail from Tim Martin, Air Sciences, Inc. to Herman Wong, EPA
regarding the Shell Chukchi Icebreaker Characterization
3 The Administrative Record also contains numerous emails and correspondence between Shell and its consultants
and EPA clarifying various aspects of Shell's application.
5
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
02/23/2009
Shell Offshore Inc. Outer Continental Shelf Pre-construction Air Permit
Revised Application, Frontier Discover Chukchi Sea - Cover Letter
02/23/2009
Shell Offshore Inc. Outer Continental Shelf Pre-construction Air Permit
Revised Application, Frontier Discover Chukchi Sea - Revised
Application
02/23/2009
Shell Offshore Inc. Outer Continental Shelf Pre-construction Air Permit
Revised Application, Frontier Discover Chukchi Sea - Appendices A-G
03/12/2009
Letter from Richard Albright, EPA to Susan Childs, Shell regarding
Incompleteness Determination for the Chukchi PSD Permit Application
Received on February 24, 2009
03/20/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair and Herman
Wong, EPA regarding Chukchi Sea Leases
04/14/2009
E-mail from Tim Martin, Air Sciences, Inc. to Herman Wong, EPA
regarding the Impact Modeling for Warehouse Emissions - Wainwright
or Barrow
04/23/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, EPA regarding
Conference Call on Icebreakers
04/27/2009
E-mail from Tim Martin, Air Sciences, Inc. to Rodger Steen regarding
Volume Sources
05/05/2009
E-mail from Rodger Steen, Air Sciences, Inc. regarding Updated
Emissions Discoverer El with 84-day well site limit removed & updated
BACT for FD20
05/11/2009
E-mail from Thomas Damiana, AECOM to Herman Wong, EPA
regarding Wainwright Audit Reports
05/14/2009
E-mail from Rodger Steen, Air Sciences to Sabrina Pryor regarding
Proposed Alternative Handling of Ice Management Fleet, Supply Ship,
Nanuq
05/18/2009
Shell Offshore Inc. - Response to March 12, 2009 2nd EPA Letter of
Incompleteness - Revised Preconstruction Permit Application for
Frontier Discoverer Drillship in Chukchi Sea, Alaska, beyond 25-mile
Alaska Seaward Boundary
05/19/2009
E-mail from Thomas Damiana, AECOM to Herman Wong, EPA
regarding Wainwright March 2009 Summary Report
05/20/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, EPA regarding
Hypothetical maximum Ice Management Vessel and joining of ICE
engine limits
05/29/2009
Letter from Susan Childs, Shell to Janis Hastings, EPA regarding Shell
Offshore Inc. - Updated Responses to March 12, 2009, 2nd EPA Letter of
Incompleteness
06/01/2009
Shell Offshore Inc. - Supplemental Response - Additional Impact
Analysis
06/05/2009
E-mail from Rodger Steen, Air Sciences regarding Updated BACT
Analysis for Volatile Organic Compounds sources
06/05/2009
E-mail from Kirk Winges, ENVIRON to Tim Martin, Air Sciences, Inc.
regarding Shell Chukchi and Beaufort Sea PSD Applications
06/09/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Ice Removal - Disco Bow
06/16/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, EPA regarding
Information on Non-Criteria Regulated Air Pollutants with Spreadsheet
titled "Discoverer Emissions Chukchi OCS 061509.xls"
6
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
06/16/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair and Herman
Wong, EPA regarding Shell Discoverer non-criteria pollutants with
attachment titled "Resp to EPA Disco Non-criteria 06162009.pdf'
06/19/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair and Paul Boys,
EPA regarding Discoverer Chukchi Sea - Criteria Emissions in your
requested format and Compliance Monitoring Proposal
06/23/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Follow-Up Regarding Anchor Handling and Bow Emissions
06/23/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
PM2.5 Discoverer Bow
06/23/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA Regarding
PM10 Discoverer Bow
06/23/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
PM2.5 Anchor Handling
06/23/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Modeling Files
06/24/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, EPA regarding
Information on Re supply Ship
06/26/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Request for Information on Discoverer +/-15 degree Re-Orientation
06/30/2009
E-mail from Kirk Winges, ENVIRON to Pat Nair, EPA regarding
Anchor Setting Emissions
07/06/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Herman Wong, EPA
regarding Associated Emissions
07/06/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, EPA regarding
Title VI Potential to Emit
07/12/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, EPA regarding
Questions on D399 Anticipated Compliance Conditions
07/13/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Ice Removal - Discoverer Bow
07/15/2009
E-mail from Kirk Winges, ENVIRON regarding Anchor Setting
Emissions for PM 2.5
07/15/2009
E-mail from Kirk Winges, ENVIRON regarding Anchor Setting
Emissions for PM 10
07/16/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Bow Washing Emissions for PM 2.5 and PM 10
07/16/2009
E-mail from Thomas Damiana, AECOM to Herman Wong, EPA
regarding Wainwright Near-Term Monitoring Program May 2009 Data
Summary
07/17/2009
E-mail from Tim Martin, Air Sciences, Inc. to Herman Wong, EPA
regarding Bow Washing Emissions for PM 2.5 and PM 10
07/17/2009
E-mail from Tim Martin, Air Sciences, Inc. to Herman Wong, EPA
regarding Background Concentrations
07/28/2009
E-mail from Thomas Damiana to Christopher Hall, EPA regarding
Wainwright Near-Term Monitoring Project PM2.5 Data
07/31/2009
Letter from Richard Albright, EPA to Susan Childs, Shell Transmitting
the Completeness Determination for the Chukchi PSD Permit
Application
08/10/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Janis Hastings, EPA
regarding Responses to draft disco/Chukchi permit - the largest issues
7
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
08/12/2009
E-mail from Susan Childs, Shell to Julie Vergeront, EPA regarding
SGOMI and signing authority
08/12/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA Regarding
Example Model Runs
08/12/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Shell Request for a Modification on the Discoverer Location Restrictions
08/13/2009
E-mail from Kirk Winges, ENVIRON to Dave Bray, EPA regarding
Geometry
08/13/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Example Model Runs
08/13/2009
E-mail from Kirk Winges, ENVIRON to Herman Wong, EPA regarding
Example Model Runs
September 2009 to December 2009
Dale
Document Description
09/17/2009
Letter from Susan Childs, Shell to, EPA re: Shell Gulf of Mexico Inc.
Comments on August 2009 Proposed Discoverer/Chukchi OCS/PSD
Permit to Construct
09/17/2009
Supplemental, BIRP Emissions Workbook, ISC-Prime Results
10/08/2009
Letter from Susan Childs, Shell, to EPA, re: Shell Gulf of Mexico Inc.
Comments on the August 2009 Proposed Discoverer/ Chukchi OCS/PSD
Permit to Construct (permit tracked to show Shell's requested changes)
10/19/2009
E-mail and attachments from Rodger Steen, Air Science, Inc. to Pat Nair,
EPA re: Clarifications Needed on Icebreaker #2
10/20/2009
Letter from Susan Childs Shell, to EPA re: Shell Gulf of Mexico, Inc.
Supplemental Comments on the August 2009 Proposed
Discoverer/Chukchi OCS/PSD Permit to Construct
10/20/2009
Letter from Susan Childs, Shell, to EPA re: Shell Gulf of Mexico, Inc.
Supplemental Comments on the August 2009 Proposed
Discoverer/Chukchi OCS/PSD Permit to Construct (correction)
11/13/2009
Document from Shell provided to EPA re: Conceptual Plan: Potential Re-
Proposal of Shell Chukchi Draft PSD Permit
11/18/2009
E-mail from Kirk Winges, ENVIRON, re: Kilabuck
11/19/2009
E-mail from Kirk Winges, ENVIRON, to Pat Nair, EPA, re: Scale Idea
11/23/2009
Letter from Susan Childs, Shell to Janis Hastings, EPA, re: Supplemental
Application Support Materials in Response to November 12, 2009 Meeting
11/25/2009
E-mail from Kirk Winges, ENVIRON, re: Supplemental BACT Analysis
and Small Engine Stack Testing with attachments,
12/02/2009
E-mail from Kirk Winges, ENVIRON, re: Revised CO Analysis with
attachments
12/07/2009
Wainwright Near-Term Ambient Air Quality Monitoring Program Fourth
Quarter Data Report August through October 2009 Final - RevO 1
12/09/2009
Letter from Susan Childs, Shell, to Rick Albright, EPA, re: Shell Gulf of
Mexico Inc. Supplement to Application for Discover/Chukchi OCS/PSD
Permit
12/10/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Pat Nair, re: Info on New
Engines
8
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
12/11/2009
E-mail from Kirk Winges, ENVIRON, to Paul Boys, EPA, regarding
Edited BACT with attachment, "Diesel Engine Best Available Control
Technology Analysis, Frontier Discoverer Drill Ship"
12/13/2009
Letter from Susan Childs, Shell, to Rick Albright, EPA, re: Shell Gulf of
Mexico Inc. Supplement to Application for Discoverer/Chukchi OCS/PSD
Permit with Attachments A-I
12/16/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Dave Bray, EPA, re:
Wainwright PM2.5 Analysis with Attachments (Wainwright Precipitation
and Wind Statistics)
12/18/2009
E-mail from Rodger Steen, Air Sciences, Inc. to Dave Bray, EPA, re:
Discoverer Incinerator Emissions
12/18/09
E-mail from Rodger Steen, Air Sciences, to Dave Bray, EPA, re: PM2.5
and PM10 Wainwright Statistics
12/22/2009
E-mail from Eric Hansen, ENVIRON to Paul Boys, EPA, re:
Supplemental BACT Analyses for CO Emissions from MLC and Logging
Winch Engines (with attachment: Memorandum from ENVIRON
regarding Shell Chukchi Sea PSD Permit and data)
1.2 Project Description
To implement their Chukchi Sea exploration drilling program, Shell proposes to operate the
Discoverer drillship and associated fleet in the Chukchi Sea. The application submitted by Shell
is for a major source permit to allow for operation of the Discoverer and its associated fleet at
any of Shell Gulf of Mexico Inc.'s current leases from lease sale 193 within the Chukchi Sea, all
of which are beyond 25 miles from Alaska's seaward boundary. Figure 1-1 shows the location
of the current Shell Gulf of Mexico Inc. leases in the Chukchi Sea. This region can be described
as lying west of Wainwright (162° west longitude) and north of Point Lay (71° north latitude).
9
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
She* OCS Lease Block
NAD83. Alaska AJbe's Equal A/««
I I Lease Sale 193 Area
~ National Petroleum Reserve - Alaska
¦ Ullage
# Potential Shorebase Location
ASPC CrwoY f
SHELL
CHUKCHI LEASE SALE 193 AREA
SHELL LEASE BLOCKS
CHUKCHI SEA
Under the terms of this proposed permit, the Shell is limited to operating the Discoverer in only
the following lease blocks from lease sale 193:
NR02-02:
NR03-01
6819
6820
6821
6822
6868
6869
6870
6871
6872
6918
6919
6920
6921
6922
6968
6969
6970
6971
6972
7018
7019
7020
7021
7022
7023
7068
7069
7072
6105
6106
6155
6156
6161
6162
6211
6212
6261
6363
6364
6413
6414
6415
6418
6419
6462
6463
6464
6465
6467
6468
6469
6512
6513
6514
6515
6516
6517
6518
6519
6562
6563
6564
6565
6567
6568
6569
6612
6613
6614
6615
6616
6617
6618
6665
6666
6667
6668
6705
6706
6712
6715
6716
6717
6753
6754
6755
6756
6761
6762
6765
6766
6767
6803
6804
6805
6810
6811
6812
6813
6814
6815
6816
6817
6853
6854
6855
6860
6861
6862
6863
6864
6865
6866
6903
6904
6905
6908
6909
6910
6911
6912
6913
6914
6915
6916
6953
6954
6955
6956
6957
6958
6959
6960
6961
6962
6963
6964
6965
7006
7007
7008
7009
7010
7011
7012
7013
7014
7056
7057
7058
7059
7060
7061
7062
7063
7106
7107
7108
7109
7110
7119
Figure 1-1 - Chukchi Sea Lease Area 193
10
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
NR03-02:
NR04-01:
NR03-03:
6114
6115
6161
6163
6164
6165
6213
6214
6215
6220
6259
6261
6263
6264
6265
6270
6271
6321
6322
6359
6360
6371
6372
6409
6410
6422
6423
6459
6508
6558
6608
6658
6671
6672
6708
6713
6714
6715
6721
6722
6757
6761
6762
6763
6764
6765
6766
6771
6807
6811
6812
6813
6814
6815
6816
6817
6856
6862
6863
6864
6865
6866
6905
6912
6913
6914
6915
6916
6962
6963
6964
6965
6352
6401
6402
6452
6453
6503
6504
6554
6604
6007
6008
6009
6010
6017
6018
6020
6056
6057
6058
6059
6067
6068
6070
6108
6219
6560
6561
6609
6610
6611
6658
6659
6660
6709
6721
6722
6723
6759
6771
6772
6773
6823
The Discoverer is a turret-moored drillship that was originally converted for drilling in 1975. It
underwent significant upgrades in 2007 so that it could operate in the arctic. The Discoverer is
equipped with generators for the drilling systems and associated self-powered equipment (such
as air compressors, hydraulic pumps, cranes, boilers and other small sources), thrusters for
positioning, and an emergency generator for the critical non-drilling loads when the main power
supply is not operating. These emission units are identified in Table 3-1 and discussed in greater
detail in Section 3 of this Statement of Basis. A photograph of the Discoverer is provided in
Figure 1-2.
Figure 1-2 - Photograph of the Frontier Discoverer Drillship
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
The Discoverer's operations are supported by an associated fleet that consists of an icebreaker,
an anchor handler/icebreaker, a supply ship, an oil spill response ship and oil spill workboats
(such support vessels to be referred to hereafter as the "Associated Fleet"). Prior to mobilizing
to the Chukchi Sea, the drillship is provisioned with sufficient supplies required to conduct the
initial drilling operations. Together with the ice breakers, the Discoverer mobilizes to the desired
location. Alternate locations are available in the event that ice conditions at the desired location
exceed the fleet's capability to manage ice or conduct operations. Anchors are run and set by the
ice breaker/anchor handler vessel; the mooring lines are tensioned; and the Discoverer is thus
positioned over the drill site.
Upon completion of the mooring operation, the process to drill the mud line cellars (MLC) is
initiated. The MLC is a 20 feet diameter hole excavated to approximately 35 feet below the mud
line. The MLC permits installation of the Discoverer's subsea blowout preventers (SSBOP)
below the mud line to avoid damage by ice keels should ice floes force the Discoverer off the
well. Utilizing compressed air, the excavated seabed material is lifted out of the MLC and settles
to the surrounding seafloor. The MLC operation is estimated to take about six days per drill site.
A 36 inch diameter hole is drilled for the next well interval and a 30 inch diameter tube (casing)
is installed and cemented. Cementing the casing anchors it in the hole and prevents annular
formation fluid migration between formations or to the surface. Atop the 30 inch casing is a
guide base with receptacles for guidelines that facilitate reentry into the well.
After drilling and installing casing in the next interval, the SSBOP's are installed in the MLC.
At this point the oil spill response fleet generally must be in position and be prepared to deploy
in the unlikely event of an oil spill. Additional intervals are drilled, cased, and cemented as
required to reach and evaluate the geologic objective.
Upon completion of the evaluation operations, the well is properly secured or plugged and then
abandoned using mechanical and/or cement plugs, or temporarily abandoned, which generally
occurs upon completion of any of the interim operations of cementing the casing. After the well
is abandoned the SSBOP's are retrieved. The anchors can then be retrieved and the Discoverer
can depart the drill site. The Discoverer may leave a drill site for a variety of reasons, including
plugging and abandoning, temporarily abandoning, adverse ice conditions, end of the drilling
season, or desire to move to another drill site to start or finish a well that was previously
temporarily abandoned.
The Discoverer crew works 12-hour shifts and lives on the drillship in accommodations located
at the stern of the ship. They work for three to four weeks and are transported to and from the
Discoverer by helicopter to Wainwright or Barrow, Alaska.
The icebreakers' role is to protect the Discoverer from ice movement. As most of the ice
movement is influenced by the wind, the icebreakers will generally be deployed upwind of the
drillship. The primary icebreaker will be located further from the Discoverer and cover a wider
operating range. The secondary anchor handler/icebreaker will operate closer in and will also
serve to deploy and retrieve the Discoverer's anchors.
The Chukchi exploration program will be replenished by a supply ship that is expected to make
no more than 8 trips each drilling season from port to the Discoverer. The Discoverer's
operations are also supported by an oil spill response ship, equipped with three workboats which
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
will be deployed in the event of a spill. In preparation for a potential spill, the oil spill response
(OSR) fleet will conduct frequent drills.
Shell anticipates a drilling season maximum of 168 drilling days (5.5 months), beginning in July
of each year. During each season, it will have the flexibility of drilling one or more wells or
parts of wells. It is likely that the environmental conditions (ice) will limit the drilling season to
less than these durations. Drilling is planned to begin no earlier than July of 2010 and continue
seasonally (i.e. July through December each year) until the resources under Shell's current leases
are adequately defined.
1.3 Public Participation
1.3.1 Opportunity for Public Comment
40 C.F.R. Part 124, Subparts A and C, contain the procedures that govern the issuance of both
OCS and PSD permits. See 40 C.F.R. §§ 55.6(a) (3) and 124.1. Accordingly, EPA has followed
the procedures of 40 C.F.R. Part 124 in issuing this proposed permit. This Statement of Basis
describes the derivation of the permit conditions and the reasons for them as provided in 40
C.F.R. § 124.7. It also serves as a Fact Sheet as provided in 40 C.F.R. § 124.8.
As provided in Part 124, EPA is seeking public comment on the new modified proposed Shell
OCS/PSD permit for the Chukchi Sea. The public comment period runs from January 8, 2010
through February 17, 2010. All written comments must be postmarked by February 17, 2010.
As discussed in Section 5, EPA is also soliciting public comment on the use of the non-guideline
ISC3-PRIME modeling system to predict air pollutant concentrations in connection with
issuance of this proposed permit. This is the same model that was relied on in the issuance of the
August 2009 proposed permit.
Because EPA is reproposing the permit in its entirety and will not be taking any further action on
the August 2009 initial proposed permit, EPA will not be responding to comments on the August
2009 proposed permit. If you believe any condition of this permit is inappropriate, you must
comment on the permit and raise all reasonably ascertainable issues and submit all reasonably
ascertainable arguments supporting your position by the end of the comment period. Any
documents supporting your comments must be included in full and may not be incorporated by
reference unless they are already part of the record for this permit or consist of state or federal
statutes or regulations, EPA documents of general applicability, or other generally available
referenced materials. To the extent you believe that comments you provided during the
comment period for the August 2009 proposed permit have not been addressed by the new
modified proposed permit or new modified Statement of Basis, you should resubmit those
specific un-addressed comments during the current comment period for this new modified
proposed permit.
Written comments may be submitted by mail or email. Oral comments may be submitted during
the public hearing in Barrow. Oral comments may also be recorded on cassette tape or CD, and
submitted by mail. EPA recommends that all comments, including those submitted by email,
cassette tape, or CD, include the commenter's contact information so that we may provide all
commenters with notice of the final permit decision. If EPA cannot read a comment due to
technical difficulties and cannot contact the commenter for clarification, EPA may not be able to
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
consider the comment. Please be aware that any personal information, including addresses or
phone numbers that are included with a public comment will be included in the public record for
the new modified proposed permit.
Send comments on the proposed permit to:
Email: R1 Oocsairpermits@epa.gov
Fax: 206-553-0110
Mail: Shell Chukchi Air Permit
EPA Region 10
1200 6th Ave, Ste. 900, AWT-107
Seattle, WA98101
All timely comments will be considered in making the final decision, included in the record, and
responded to by EPA. EPA will prepare a statement of reasons for changes made in the final
permit and a response to comments received, and will provide all commenters with notice of the
final permit decision.
1.3.2 Public Hearing and Informational Meetings
EPA is holding a public hearing on the proposed OCS/PSD permit as follows:
February 16, 2010
6:00 pm - 9:00 pm
Inupiat Heritage Center
Barrow, Alaska
The purpose of the public hearing is to receive public comments on EPA's proposed
OCS/PSD air quality permit for Shell to operate the Frontier Discoverer drillship on the
Chukchi Sea OCS. To express interest in attending the public hearing or for more
information about the hearing, contact Suzanne Skadowski, EPA community
involvement, at 206-553-6689 or skadowski.suzanne@epa.gov. EPA may cancel the
public hearing if there is no significant interest expressed in participation. EPA managers
and staff will participate in the public hearing by teleconference from EPA offices in
Seattle, Washington. The EPA hearing officer will be at the public hearing location in
Barrow. Facilities for participating in the public hearing by teleconference are available
at the teleconference centers in Wainwright, Point Lay, Point Hope and Atqasuk.
1.3.3 Administrative Record
The record for the new modified proposed permit includes Shell's application, including
addendums and supplemental information; all documents in the record for the August 2009
proposed permit; the new modified proposed permit and statement of basis; and all other
materials relied on by EPA.
The permit record for the new modified proposed permit is available at the EPA Region 10
Library, 1200 6th Ave, Seattle, Wash. Library hours: 9:00 am-12:00 pm and 1:00 pm-4:00 pm
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
Monday-Friday. To request a copy of these materials or a copy of the permit record, contact
Suzanne Skadowski as described above.
The permit application, the new modified proposed permit and statement of basis, and the
August 2009 proposed permit and statement of basis will also be available at the locations listed
below. Please call in advance for available viewing times.
Barrow City Office, 2022 Ahkovak Street, Barrow, Alaska, 907-852-4050
Wainwright City Office, 1217 Airport Road, Wainwright, Alaska, 907-763-2815
Atqasuk City Office, 5010 Ekosik Street, Atqasuk, Alaska, 907-633-6811
Kali School Library, 1029 Ugrak Ave, Point Lay, Alaska, 907-833-2312
Point Hope City Office, 530 Natchiq Street, Point Hope, Alaska, 907-368-2537
EPA Alaska Office, Federal Building, 222 West 7th Ave, Anchorage, Alaska, 907-271-
5083
EPA Region 10 web site: www.vosemite.epa.gov/R10/airpage.nsf/Permits/chukchiap
For more information about the public hearing or the proposed permit, to request a copy of the
permit documents on CD, or to be added to EPA's arctic permits mailing list, contact Suzanne
Skadowski at 206-553-6689 or skadowski.suzanne@epa.gov.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
2. REGULATORY APPLICABILITY
2.1 OCS
The OCS regulations at 40 C.F.R. Part 55 (Part 55) implement Section 328 of the CAA and
establish the air pollution control requirements for OCS sources and the procedures for
implementation and enforcement of the requirements. The regulations define "OCS source" by
incorporating and interpreting the statutory definition of OCS source:
OCS source means any equipment, activity, or facility which:
(1) Emits or has the potential to emit any air pollutant;
(2) Is regulated or authorized under the Outer Continental Shelf Lands Act
("OCSLA") (43 U.S.C. §1331 et seq.); and
(3) Is located on the OCS or in or on waters above the OCS.
This definition shall include vessels only when they are:
(1) Permanently or temporarily attached to the seabed and erected thereon
and used for the purpose of exploring, developing or producing resources
therefrom, within the meaning of section 4(a)(1) of OCSLA (43 U.S.C.
§1331 et seq.); or
(2) Physically attached to an OCS facility, in which case only the
stationary sources aspects of the vessels will be regulated.
40 C.F.R. § 55.2; see also CAA § 328(a)(4)(C), 42 U.S.C. § 7627.
Section 328 and Part 55 distinguish between OCS sources located within 25 miles of a state's
seaward boundaries and those located beyond 25 miles of a state's seaward boundaries. CAA
§ 328(a)(1); 40 C.F.R. §§ 55.3(b) and (c). In this case, Shell is seeking a permit for an
exploration drilling program that will be conducted exclusively beyond 25 miles of Alaska's
seaward boundaries.
Section 55.13 generally sets forth the federal requirements that apply to OCS sources. Sources
located beyond 25 miles of a state's seaward boundaries are subject to the New Source
Performance Standards (NSPS), in 40 C.F.R Part 60; the PSD program in 40 C.F.R. § 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 operating permit program under Title V of the CAA and
40 C.F.R. Part 71. See 40 C.F.R. §§ 55.13(a), (c), (d)(2), (e), and (f)(2), respectively. The
applicability of these requirements to Shell's exploration drilling program is discussed in
Sections 2.2 to 2.7 below.
The OCS regulations also contain provisions relating to monitoring, reporting, inspections,
compliance, and enforcement. See 40 C.F.R. §§ 55.8 and 55.9. Section 55.8(a) and (b)
authorize EPA to require monitoring, reporting, and inspections for OCS sources and provide
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
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, provide authority for the monitoring, recordkeeping reporting and other compliance
assurance measures included in this proposed permit.
2.2 PSD
The PSD program, as set forth at 40 C.F.R. § 52.21, and incorporated by reference into
40 C.F.R. § 55.13(d)(2), applies to the construction of any new major stationary source or the
major modification of an existing major stationary source in an area that has been designated as
in attainment of the national ambient air quality standards (NAAQS) or as "unclassifiable."4 The
objective of the PSD program is to prevent significant adverse environmental impact from air
emissions by a proposed new or modified source. The PSD program limits degradation of air
quality to that which is not considered "significant." In addition, the PSD program includes a
requirement for evaluating the effect that the proposed emissions are expected to have on air
quality related values such as visibility, soils, and vegetation. The PSD program also requires
the utilization of the best available control technology (BACT) as determined on a on a case-by-
case basis taking into account energy, environmental and economic impacts and other costs.
Under the PSD regulations, a stationary source is "major" if, among other things, it emits or has
the potential to emit (PTE) 100 tpy or more of a "regulated NSR pollutant" as defined in 40
C.F.R. § 52.21(b)(50) and the stationary source is one of a named list of source categories. In
addition to the preceding criteria, any stationary source is also considered a major stationary
source if it emits or has the potential to emit 250 tpy or more of a regulated NSR pollutant. 40
C.F.R. § 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. "Any physical or operational limitation on
the capacity of the source to emit a pollutant, including air pollution control equipment and
restrictions on hours of operation or on the type or amount of material combusted, stored or
processed, shall be treated as part of its design if the limitation or the effect it would have on
emissions is enforceable." See 40 C.F.R. § 52.21(b)(4).
Under the PSD program, a source's potential to emit is used to determine not only when it is
required to obtain a PSD permit, but also to determine the scope of PSD review, in particular, the
pollutants that are subject to application of "best available control technology" or "BACT,"
analysis of ambient air quality impacts from the project, analysis of air quality and visibility
impact on Class I areas, and analysis of impacts on soils and vegetation. A source is required to
apply BACT for each pollutant for which the PTE exceeds the "significant emission rate" or
"SER" within the meaning of 40 C.F.R. § 52.21 (b)(23)(i). Additionally, and consistent with 40
C.F.R. §§ 52.21(k) and (m), Shell is required in its permit application to include an analysis of
4 Section 109 of the CAA requires EPA to promulgate regulations establishing national ambient air quality standards
for those air pollutants (criteria pollutants) for which air quality criteria have been issued pursuant to Section 108 of
the CAA. EPA has set NAAQS for six criteria pollutants: S02, particulate matter (PMi0 and PM2 5), nitrogen dioxide
(as NOx), CO, ozone (precursors NOx and VOC) and lead. 40 C.F.R. Part 50. An area that meets the NAAQS for a
particular pollutant is an "attainment" area. An area that does not meet the NAAQS is a "nonattainment" area. An
area that can not be classified due to insufficient data is designated "unclassifiable."
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
ambient air quality for each of these pollutants and a demonstration that it will not cause or
contribute to a violation of any NAAQS or PSD increment.5
2.3 Applicability of the NAAQS and PSD Increments on the OCS
Pursuant to Sections 108 and 109 of the CAA, EPA has promulgated primary and secondary
national ambient air quality standards to protect public health and the environment. These
national standards apply in the "ambient air," which is defined in 40 C.F.R. § 50.1(e) as ".. .that
portion of the atmosphere, external to buildings, to which the general public has access." The
atmosphere over United States territorial waters is "ambient air" and United States law, including
40 C.F.R. Part 50 in which the NAAQS are promulgated, applies within the boundaries of United
State and its territorial waters. Nothing in the CAA or EPA's implementing regulations limits
the applicability of the NAAQS to ambient air over land or to only ambient air within the
jurisdiction of states or tribes.
Pursuant to Section 328 of the CAA, EPA has promulgated regulations at 40 C. F. R. Part 55 to
control air pollution from OCS sources in order to attain and maintain federal and state ambient
air quality standards and to comply with the provisions of Part C of Title I to prevent significant
deterioration of air quality. With respect to PSD, 40 C.F.R. § 55.13(d) states that the PSD rules
at 40 C.F.R. § 52.21 shall apply to OCS sources. The PSD rules specifically include, at 40
C.F.R. § 52.21(c), the ambient air increments, and at 40 C.F.R. § 52.21(d), the ambient air
ceilings (NAAQS), that must be addressed in the source impact analysis required by 40 C.F.R.
§ 52.21(k). Further technical information on implementing the PSD increments on the OCS,
specifically, the definitions of "baseline concentration," baseline date," and "baseline area," is
contained in the EPA 7/2/09 Baseline Memo.
As discussed above, Section 328 of the CAA requires EPA to promulgate regulations to control
air pollution from OCS sources in order to attain and maintain federal and state ambient air
quality standards and to comply with the provisions of part C of title I to prevent significant
deterioration of air quality. While Congress evinced an intent that EPA's regulations ensure
protection of air quality onshore, EPA does not interpret Section 328 of the CAA to address only
the air quality impacts of offshore sources on onshore areas. Section 328 does not identify a
particular area where the requirements to control air pollution from OCS source located offshore
must "attain and maintain Federal and State ambient air quality standards" or limit that area to
only locations onshore. Furthermore, the D.C. Circuit of the Court of Appeals vacated certain
provisions of EPA's Part 55 OCS rules that would have varied the stringency of onshore
ambient-based requirements (e.g., the amount of offsets) based on the distance of the OCS
source from shore, even though the rules would have ensured protection of onshore air quality
because EPA had departed from the CAA's clear directive that the agency promulgate the same
"requirements.. .as would be applicable if the source were located in the corresponding onshore
area." Santa Barbara County Air Pollution Control District v. EPA, 31 F.3d 1179, 1183 (D.C.
Cir. 1994) (citing to Section 328(a)(1) of the CAA). The Court concluded that EPA could not
change the stringency of the onshore rules as applicable to offshore sources within 25 miles of a
state's seaward boundary. Id. Likewise, by making 40 C.F.R. § 52.21 applicable without change
5PSD increments are the "applicable maximum allowable increase over baseline concentration in any area" and are
set forth in 40 C.F.R. § 52.21(c).
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
to OCS sources located more than 25 miles beyond a state's seaward boundary, see 40 C.F.R. §
55.13(d)(2), EPA expressed an intent that the OCS permitting rules applicable to such sources
located more than 25 miles beyond a state's seaward boundary would apply in the same manner
as 40 C.F.R. § 52.21 would apply to onshore sources. This includes rules with respect to the
ambient air quality provisions, which require NAAQS and increment compliance in the ambient
air. By requiring Shell to show that its operations comply with NAAQS and increment in the
ambient air of Lease Area 193, this permit ensures that air quality is protected everywhere that
the PSD rules apply, including onshore and offshore areas.
2.4 Application of OCS and PSD Regulations to the Discoverer's Exploration Drilling
Operations
2.4.1. The "OCS Source"
The Discoverer is a turret-moored drillship that is able to move under its own power. During
transit, it is propelled by a 7,200 hp Mitsubishi engine. The drill ship uses a Sonat Offshore
Drilling turret mooring system that provides the ability for the drill rig floor to remain stationary
while the vessel itself may rotate, allowing the vessel bow to be oriented into the wind or broken
ice (Exploration Plan 2009, pp 6-7 and Attachment A; United States Patent No. 4,509,448).
When the Discoverer reaches the approximate location of the drill site, the anchor
handler/icebreaker (Icebreaker #2) is used to attach anchor lines from the Discoverer to the
seabed. The mooring system uses a set of eight mooring lines, buoys and anchors which are
radially located around the drillship. Drilling can occur when the Discoverer is secured with
fewer than eight anchors (United States Patent No. 4,509,448).
Anchor setting involves Icebreaker # 2 backing up to the Discoverer under low power,
connecting to the anchor line, reeling out the line, and setting the anchor at approximately 1,000
meters distance, then moving to another anchor opposite the first. Setting of each anchor
consumes about 30 minutes and the entire anchoring process consumes no more than 18-24
hours.
Once there are enough mooring lines out to control the position of the vessel with the mooring
lines, the vessel is put into position and mooring lines are adjusted to allow operations to be
undertaken at a drill site. Once the Discoverer is positioned and the anchor lines re-tensioned at
the drill site, the Discoverer's on-site Shell representative declares that the Discoverer is "secure
and stable in a position to commence activity at the well location," an event that is recorded in
log books on the Discoverer. The propulsion engine is not used during drilling (Shell 12/13/09
Supp. App.; 12/11/09 Anchoring Memo).
When the Discoverer prepares to depart from the drill site, the process is reversed—anchors are
de-tensioned and then the anchor lines released. Specifically, Icebreaker #2 moves to the
location of an anchor and attaches to the retrieval cable that is marked by a buoy. Icebreaker #2
then tugs on the anchor to release it and raise it, and then ferries it back to the Discoverer as the
cable is rewound. Retrieval of each anchor takes about 30 minutes and the entire process
generally lasts for less than 12 hours, although it may take as long as 18 hours. There is also a
process for a partial or quick release from the anchor lines in the event of approaching hazards
(Shell 12/13/09 Supp. App.).
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
Drill ships, drill rigs, and drilling platforms used for oil exploration and production vary
greatly in configuration. In the August 2009 proposed permit, EPA proposed that the
Discoverer be considered an "OCS source" within the meaning of 40 C.F.R. § 55.2 from
the time between the placement of the first anchor on the seabed to the removal of the last
anchor from the seabed at a drill site. The initial proposed permit also prohibited
operation of the propulsion engine while the Discoverer is an OCS source, that is, after
placement of the first anchor on the seabed.
During the public comment period on the August 2009 proposed permit, the Mineral
Management Services (MMS) expressed concern with the prohibition on operation of the
propulsion engine after anchoring and requested that the permit clarify and accommodate
the use of the propulsion engine in emergency situations. (MMS 10/20/09). Other
commenters also questioned whether the Discoverer could safely anchor without using
the propulsion engines.
Shell commented that it believed the Discoverer was not an OCS source within the
meaning of Section 328 of the CAA and 40 C.F.R. § 55.2 until the Discoverer is
stabilized and the anchoring process is complete. Shell also said it would attempt to meet
the requirements to shut down the propulsion engines during the anchoring process but
that if that proved to be unsafe, Shell would request a permit change. (Shell 10/20/09
Comments). A December 16, 2009 letter from MMS to EPA states that the Alaska
Region of MMS does not consider the Discoverer to be an OCS permanently or
temporarily attached to the seabed until all anchors have been set because until that time,
the Discoverer is operated under, controlled by, and subject to maritime laws and
practices (MMS 12/16/09).
EPA has reviewed the definition of OCS source in the CAA and the OCS implementing
regulations in light of the specific configuration of the Discoverer and its mooring and
drilling system. EPA's definition of "OCS source" provides that a vessel be considered
an OCS source "only when [it is]: (1) Permanently or temporarily attached to the seabed
and erected thereon and used for the purpose of exploring, developing or producing
resources therefrom... " 40 C.F.R. § 55.2 (emphasis added). The Discoverer could be
considered to be "attached to the seabed" when it is connected to the seabed by a single
anchor. After attachment of an anchor at the drill site, the Discoverer begins the process
of moving onto location at the drill site through the anchoring and tensioning process
discussed above. However, it is not clear that the ship is "erected" on the seabed for the
purposes of exploring, developing or producing resources at that time. The question is
whether the Discoverer is an OCS source during this anchoring and tensioning process.
In light of the regulatory definition of the OCS source, the application of that definition
for specific permitted activity as provided in the initial August 2009 proposal, and the
comments and additional information received on that issue since the August 2009
proposed permit, EPA is proposing two options for defining when the Discoverer
becomes an OCS source in this permit. EPA is specifically requesting comment on which
of the following definitions to include in the final permit:6
6 We note that the choice of either definition below does not effect any other permit conditions or analyses.
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Option 1: Apply the definition of "OCS source" as explained in the August 2009
proposal. Under this approach, the Discoverer would be considered an "OCS source"
within the meaning of 40 C.F.R. § 55.2 from the time between the placement of the first
anchor on the seabed to the removal of the last anchor from the seabed at a drill site.
Once the Discoverer is attached by an anchor to the seabed at a drill site, the Discoverer
is at that location for the purpose of exploring, developing or producing resources from
the seabed and its activities are more closely aligned with the activities of a stationary
source than of a vessel transiting the sea. Under this approach, connection of the
Discoverer to the seabed by an anchor at the drill site would be considered both
attachment to and erection on the seabed.
Option 2: Apply the definition so that the Discoverer is considered to be an "OCS
source" within the meaning of 40 C.F.R. § 55.2 from the time the Discoverer is declared
by the Discoverer's on-site company representative to be "secure and stable in a position
to commence exploratory activity at the drill site," an event which is recorded in the
Discoverer's logs). At this point, the Discoverer is clearly both attached to and erected
on the seabed "for the purpose of exploring, developing or producing resources
therefrom" within the meaning of EPA's OCS implementing regulations. EPA does not
agree with Shell that the Discoverer is not an OCS source until all eight anchors are
attached, since available information shows that the Discoverer is at that location for the
purpose of exploring, developing, or producing resources and that there are some
circumstances in which the Discoverer can safely drill when secured by fewer than eight
anchors. Accordingly, this option for defining when the Discoverer is an OCS source
does not turn on the number of anchors in place.
As discussed in Section 2.1 above, a vessel is also considered an OCS source when it is
"[p]hysically attached to an OCS facility, in which case only the stationary source aspects of the
vessels will be regulated." 40 C.F.R. § 55.2 (definition of OCS source). Shell's application
states that the Discoverer will be provisioned with additional supplies by a supply vessel every
two to four weeks during the drilling season, for a maximum of eight re-provisioning events each
season. When the supply vessel makes a delivery, it will attach to the Discoverer for less than 12
hours, during which time only one of the supply vessel's generators will be operating. During
the time the supply vessel is attached to the Discoverer while the Discoverer is an OCS source,
the supply vessel will also be considered an OCS source for purposes of this permit.
Aside from the supply vessel, none of the other vessels that comprise the Associated Fleet will
be physically attached to the Discoverer while the Discoverer is an OCS source and, therefore,
none of these other vessels are considered an OCS source for purposes of this permit.7 The
7 Even if the Discoverer is considered to be an OCS source when it is connected to the seabed at a drill site by a
single anchor, EPA does not consider Icebreaker # 2 to be "physically attached" to the Discoverer (and thus not an
"OCS source") during the time it is assisting the Discoverer in the anchor setting and retrieval process at a drill site.
Although there is an anchor line running between the Discoverer and Icebreaker # 2 during portions of this period,
Icebreaker # 2 can not be considered in any way to be physically attached to the Discoverer during this time within
the meaning of "OCS source" as set forth in 40 C.F.R. § 55.2. The activities during anchor handling are not
designed to "to fasten, secure or join" Icebreaker # 2 to the Discoverer or "to connect as an adjunct or associated
condition or part" Icebreaker # 2 to the Discoverer, the common meaning of "attached" in this context. The
American Heritage Dictionary of the English Language, 4th ed., (2006). Rather, Icebreaker # 2 is enabling the
attachment of the Discoverer to the seabed.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
OCS regulations make clear that, although the emissions from a vessel servicing an OCS source
and within 25 miles of the OCS Source are considered as direct emissions from the OCS source
for purposes of determining the requirements to which the OCS source is subject and in
considering the impact from the OCS source, such a vessel is not regulated as an OCS source
itself 57 Fed. Reg. 40792, 40794 (September 4, 1992).
2.4.2 Vessels included in the "Potential to Emit" of Shell's Exploration Drilling Program
As discussed in Section 2.2, whether a source is required to obtain a PSD permit under 40 C.F.R.
§ 52.21 depends on the source's "potential to emit" or PTE. In the case of "potential emissions"
from an OCS source, Part 55 defines the term similarly to the definition of PTE in the PSD
regulations and provides further 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 §§ 55.13 or 55.14 of this part, except that vessel emissions must be
included in the "potential to emit" as used in §§ 55.13 or 55.14 of this part.
40 C.F.R. § 55.2 (definition of "potential emissions").
Thus, emissions from vessels servicing or associated with an OCS source that are within 25
miles of the OCS source are considered in determining the "potential to emit" or "potential
emissions" of the OCS source for purposes of applying the PSD regulations. Emissions from
such associated vessels are therefore counted in determining whether the OCS source is required
to obtain a PSD permit, as well as in determining the pollutants for which BACT is required and
whether emissions from the OCS source cause or contribute to a violation of the NAAQS or
applicable increment. 57 Fed. Reg. at 40793-94 ("vessel emissions related to OCS activity will
be accounted for by including vessel emissions in the "potential to emit" of an OCS source.
Vessel emissions must be included in offset calculations and impact analyses, as required by
Section 328 and explained in the NPR."); 56 Fed. Reg. 63,774, 63,777 (Dec. 5, 1991) ("The
inclusion of vessel emissions in the total emissions of the stationary source is a statutory
requirement under section 328(a)(4)(C). In this manner vessel emissions of attainment pollutants
will be accounted for when PSD impact analyses are performed and increment consumption is
calculated. For nonattainment pollutants the OCS source will have to obtain offsets as required
by the COA, and vessel emissions will be offset").
Drill ships and other vessels contain many emission sources that otherwise meet the definition of
"nonroad engine" as defined in Section 216(10) of the Clean Air Act. However, based on the
specific requirements of CAA Section 328, emissions from these otherwise nonroad engines on
drill ships and subject support vessels are considered as "potential emissions" from the OCS
source, notwithstanding the fact that Section 302(z) of the CAA specifically excludes nonroad
engines from the definition of "stationary source." Similarly, nonroad engines that are part of
the OCS source are subject to regulation as stationary sources.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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Neither the definition of "OCS source" in Section 328 of the CAA nor the definition in 40 C.F.R.
§55.2 expressly excludes or even mentions an exclusion for emissions from nonroad engines,
although EPA makes clear that emissions from engines being used for propulsion are not
included within the definition of "OSC source" for those vessels that become an OCS source by
attaching to an existing OCS facility. See 40 C.F.R. § 55.2, (definition of OCS source). Indeed,
in describing the emission sources included in the definition of "OCS source," both the statutory
and regulatory definition broadly include "any equipment, activity, or facility which - emits or
has the potential to emit any air pollutant... " CAA Section 328(a)(4)(C); 40 C.F.R. § 55.2.
In describing how emissions from vessels that are not themselves an OCS source are to be
considered, both the statute and EPA's regulation refer broadly to "vessel" emissions, again
without exclusion. In explaining that only the stationary aspects (i.e., excluding engines when
being used for propulsion in the situation described above) of a vessel would be regulated as part
of the "OCS source," EPA stated in contrast that"All vessel emissions related to OCS source
activity will be accounted for by including vessel emissions in the "potential to emit" of an OCS
source." 57 Fed. Reg. at 40794 (emphasis added). Simply put, the exclusion of nonroad engines
from the general definition of "stationary source" in Section 302(z) of the CAA is overridden by
the more specific provisions in Section 328 of the CAA and 40 C.F.R. § 55.2.
In determining the PTE for Shell's Chukchi Sea exploration drilling program, EPA included the
potential emissions from the Discoverer while operating as an OCS source, as well as the
potential emissions from the Associated Fleet - the ice breaker, the anchor handler/icebreaker,
the supply ship, and the OSR fleet - when operating within 25 miles of the Discoverer while the
Discoverer is an OCS source.
There are other vessels that will be associated with Shell's exploratory drilling program, such as
an oil tanker, a barge, and shallow water landing craft. Based on Shell's application submittals,
none of these vessels will be operating within 25 miles of the Discoverer while the Discoverer is
an OCS source. Emissions from these other vessels are therefore not included in determining the
potential to emit of Shell's exploration drilling program in connection with applying the
requirements of the OCS or PSD program.
2.4.3 "Potential to Emit" of the "OCS Source"
Because Shell has applied for a major source permit authorizing operation of the Discoverer and
its Associated Fleet at any of Shell's current leases in Lease Sale 193 of the Chukchi Sea, the
PTE from the project is calculated based on emissions from any point within the area of
operation authorized under the permit during any consecutive 12-month period.
Table 2.1 lists the final PTE for each regulated NSR pollutant from the project, as well as the
significant emission rate for each regulated NSR pollutant. Appendix A contains detailed
emissions calculations used to determine PTE for emissions of CO, NOx, PM2.5, PMi0, S02,
VOC and lead, the regulated NSR pollutants that are NAAQS pollutants or precursors to
NAAQS pollutants and are therefore relevant to the ambient air quality impact analysis discussed
in Section 5. The PTE estimates for the remaining regulated NSR pollutants are set forth in Air
Sciences 6/16/09; Air Sciences 6/19/09; Air Sciences 6/30/09; Air Sciences 12/18/09-
Incinerator; Shell 12/9/09 Supp. App.; Shell 12/13/Supp. App.
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Table 2.1 - Potential to Emit for Regulated NSR Pollutants
Pollutant
Potential to Emit,
Significant Emission
tpy
Rate, tpy
CO
449
100
NOx
1188
40
PM
260*
25
PM2.5 (precursors NOx and SO2)
52
10 (40 for NOx or S02)
PM10
58
15
S02
2
40
VOC
87
40
Lead
0.11
0.6
Ozone (precursors VOC and NOx)
NA
40 forVOCorNOx
Fluorides
0
3
Sulfuric acid mist
0.404
7
Hydrogen sulfide
0
10
Total reduced sulfur
0
10
Reduced sulfur compounds
0
10
Municipal waste combustor organics
3.26 x 10"7
3.5 x 10"6
Municipal waste combustor metals
0.112
15
Municipal waste combustor acid gases
3.59
40
Municipal solid waste landfill
NA
50
emissions
Title VI, Class I or II substance
< 1
**
* Emissions of PM have been reduced substantially below this amount as a result of the
additional restrictions and controls in this proposed permit that have reduced PMio and PM22.5
emissions, but this estimate for PM has not been recalculated since the August 2009 proposed
permit.
** In 1996, EPA proposed a significant emission rate of 100 tpy for this category of pollutant
and received no adverse comments on this issue. EPA subsequently concluded that PSD review
is not necessary for this category of pollutants where they would be potentially emitted at
substantially less than 100 tpy (EPA 2/24/98; EPA 5/19/98).
Because exploration drilling programs are not included in the list of source categories subject to
a 100-tpy applicability threshold, the requirements of the PSD program apply if the project PTE
is at least 250 tpy. From Table 2-1, it is evident that Shell's Chukchi exploration drilling
program is a major PSD source because emissions of CO and NOx (and potentially PM) exceed
the major source applicability threshold of 250 tpy. In addition, emissions of CO, NOx, PM,
PM2, (including the precursors NOx and SO2), PM10, and ozone precursors (VOC and NOx)
exceed the significant emission rate for each such pollutant. Emissions of SO2 have been reduced
below the significant emission rate as a result of the imposition of BACT on SO2 emission
sources on the Discoverer and Shell's recent request for a limit requiring the use of ultra-low
sulfur diesel fuel in the Associated Fleet (discussed in Section 3.3 below). Absent the BACT
requirement on SO2 emission sources on Discoverer, emissions of SO2 from Shell's exploration
drilling program would exceed the significant emission rate. Consequently, pursuant to 40 C.F.R.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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§ 52.21(j)(2), Shell is required to apply BACT on the OCS source for CO, NOx, PM, PM2.5
(including the precursors NOx and S02), PM10, S02 and ozone precursors (VOC and NOx).
Section 4 contains a discussion of the BACT analysis for each of these pollutants. Additionally,
and consistent with 40 C.F.R. §§ 52.21(k) and (m), these potential to emit values are used in the
analysis of ambient air quality and demonstration that this source will not cause or contribute to a
violation of any NAAQS or PSD increment. Section 5 contains a discussion of the air quality
impact analysis.
2.5 Title V
As specified in 40 C.F.R. § 55.13(f)(2), the requirements of the Title V operating permit
program, as set forth at 40 C.F.R. Part 71 (Part 71), apply to OCS sources located beyond 25
miles of states' seaward boundaries. Because the PTE for this project is greater than 100 tons
per year for several criteria pollutants, it is a major source under Title V and Part 71 and must
apply for an operating permit as provided in 40 C.F.R. § 71.5(a)(l)(i ) within 12 months of first
becoming an OCS on Shell's current leases in the Chukchi Sea).
2.6 New Source Performance Standards (NSPS)
As discussed above, applicable NSPS apply to OCS sources. See 40 C.F.R. § 55.13(c). In
addition, the PSD regulations require each major stationary source or major modification to meet
applicable NSPS. See 40 C.F.R. § 52.21(j)(l). A specific NSPS subpart applies to a source
based on source category, equipment capacity and the date when the equipment commenced
construction or modification. The Discoverer contains emission units in four NSPS source
categories: compression-ignition, internal-combustion engines; boilers; incinerators; and fuel
tanks.
NSPS IIII, 40 C.F.R. Part 60, Subpart IIII, applies to stationary compression-ignition internal
combustion (IC) engines, with the earliest applicability date being for units that were modified,
or reconstructed after July 11, 2005 and the applicability date for newly manufactured engines
that are not fire-pump engines being April 1, 2006. All diesel engines on board the Discoverer
(FD-1 to FD-20), with the exception of the diesel MLC compressor engines (FD-9 to FD-11) and
the Caterpillar C7 Logging Winch Engine (FD-19), were manufactured before April 1, 2006 (Air
Sciences 7/16/09; Air Sciences 12/10/09), and therefore are not subject to NSPS IIII. The diesel
MLC compressor engines (FD-9 to FD-11), and the Caterpillar C7 Logging Winch Engine (FD-
19) are Tier 38 engines to which NSPS IIII applies.
NSPS Dc, 40 C.F.R. Part 60, Subpart Dc, applies to boilers with a capacity of at least 10
MMBtu/hr. Since the two Discoverer boilers (FD-21 and FD-22) are rated at less than 10
MMBtu/hr, NSPS Dc does not apply.
NSPS CCCC, 40 C.F.R. Part 60, Subpart CCCC, applies to commercial and solid waste
incinerators (CISWI) constructed after November 30, 1999. The incinerator on board the
8 As discussed in Section 4.2 below, EPA set new emission standards for nonroad diesel engines using a 3-tiered
progression to lower emission standards. Each tier involves a phase-in by horsepower rating over several years.
Tier 3 in NSPS IIII is the most stringent of the 3 tiers.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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Discoverer (FD-23) was manufactured after that date and meets the definition of a CISWI.
Therefore, it meets the general applicability criteria of NSPS CCCC unless it qualifies for one of
the exemptions in 40 C.F.R. § 60.2020. Shell submitted an initial notification and exemption
request to EPA as part of its OCS/PSD permit application on the grounds that the incinerator
burns more than 30% municipal solid waste and refuse derived fuel and has the capacity to burn
less than 35 tons per day of municipal solid waste and refuse derived fuel. See 40 C.F.R. §
60.2020(c)(2). EPA responded in a letter dated January 21, 2009, concurring with Shell's
exemption claim and confirming that Shell must maintain records as provided in the exemption
in order to continue to qualify for the exemption (EPA 1/21/09 CISWI Letter).
NSPS Subpart Ka, 40 C.F.R. Part 60, Subpart Ka, applies to petroleum liquids tanks with a
capacity of greater than 420,000 gallons. The largest tank on board the Discoverer has a capacity
of 142,140 gallons, well below the threshold for Subpart Ka to apply. NSPS Subpart Kb, 40
C.F.R. Part 60, Subpart Kb, applies to petroleum liquids tanks manufactured after July 1984.
All of the tanks on board the Discoverer were manufactured before 1984, and therefore none are
affected facilities subject to NSPS Subpart Kb.
In summary, the diesel MLC compressor engines (FD-9 to FD-11) and the Caterpillar C7
Logging Winch Engine (FD-19) are subject to NSPS IIII and the incinerator is subject to
requirements for maintaining an exemption from NSPS CCCC. As provided in 40 C.F.R. §§
52.21(j)(l) and 55.13(c), the permittee must meet each applicable standard of performance under
40 C.F.R. Part 60. The applicable provisions of the NSPS have not been included in this
proposed OCS/PSD permit, but Condition A.3, as well as 40 C.F.R. §§ 52.21(r)(3) and
55.6(a)(4)(iii), make clear that Shell is obligated to comply with all other federal requirements
not included in this proposed OCS/PSD permit, including NSPS IIII and CCCC. All applicable
standards promulgated pursuant to the NSPS program will be included in the Title V operating
permit for Shell.
2.7 National Emission Standards for Hazardous Air Pollutants (NESHAP)
As discussed above, applicable NESHAPs 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 C.F.R. §
55.13(e). In addition, the PSD regulations require each major stationary source or major
modification to meet applicable standards under 40 C.F.R. Part 61, which are NEHSAPs. See
40 C.F.R. § 52.21 (j)(l).
No source categories on board the Discoverer are currently regulated by NESHAPs promulgated
at 40 C.F.R. Part 61. Consequently, the emission units on the Discoverer are not subject to the
requirements of Part 61.
After the PSD program regulations were developed, EPA also promulgated Section 112
NESHAP regulations in 40 C.F.R. Part 63. Part 63 NESHAPs apply to a source based on the
source category listing, and the regulations generally establish different standards for new and
existing sources pursuant to Section 112. In addition, many Part 63 NESHAPs apply only if the
affected source is a "major source" as defined in Section 112 and 40 C.F.R. § 63.2. A major
source is generally defined as a source that has a PTE of 10 tons per year or more of any single
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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"hazardous air pollutant" or "HAP" or 25 tons per year or more of all HAP combined. See
Section 112(a)(1) and 40 C.F.R. § 63.2. An "area source" is any source that is not a major
source. See Section 112(a)(2) and 40 C.F.R. § 63.2.
Shell has estimated emissions of HAP from Shell's exploration drilling program of 3.50 tons per
year for all HAP combined based on requested limits and other limits assumed under the permit
application and supporting materials submitted to EPA (Shell 2/23/09 Rev. App., Attachment D,
Table 2-2, and Attachment E, pp E. 1-12 to -13). This makes the project an area source of HAP.
The only emission units potentially subject to a current Part 63 NESHAP that applies to area
sources are the compression-ignition internal combustion engines (RICE), identified as FD-1 to
FD-20, which are potentially subject to NESHAP ZZZZ, 40 C.F.R. Part 63, Subpart ZZZZ.
Under that rule, engines at area sources constructed before June 12, 2006 do not have to meet the
requirements of 40 C.F.R. Part 63, Subparts A and ZZZZ, including the initial notification, if
they fall within 40 C.F.R. § 63.6590(b)(3). See also 40 C.F.R. § 63.6590(a)(l)(iii). Engines
FD-1 to FD-8, FD-12 to FD-18, and FD-20 fall within that exemption because they are existing
compression-ignition stationary RICE constructed before June 12, 2006. The diesel MLC
compressor engines (FD-9 to FD-11) and the Caterpillar C7 Logging Winch Engine (FD-19)
were constructed after June 12, 2006, and therefore qualify as new engines. As provided in 40
C.F.R. § 63.6590(c), however, because these are compression-ignition stationary RICE located
at an area source, these emission units comply with Subpart ZZZZ by meeting the requirements
of 40 C.F.R. Part 60, Subpart IIII, for compression-ignition engines. As discussed above in
Section 2.4, FD-9 to FD-11 and FD-19 are subject to NSPS IIII.
At this time, it does not appear that emission units on the Discoverer are subject to any Section
112 standards except for the diesel MLC compressor engines (FD-9 to FD-11) and the
Caterpillar C7 Logging Winch Engine (FD-19), which comply with Subpart ZZZZ by meeting
the requirements of NSPS Subpart IIII. As discussed above, Condition A.3, as well as 40 C.F.R.
§§ 52.21(r)(3) and 55.6(a)(4)(iii), make clear that Shell is obligated to comply with all other
federal requirements not included in this OCS/PSD proposed permit. All applicable standards
promulgated under Section 112 will be included in the Title V operating permit for Shell.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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3. PROJECT EMISSIONS AND PERMIT TERMS AND
CONDITIONS
3.1 Overview
Shell intends to implement their Chukchi Sea exploration drilling program through the use of the
Frontier Discoverer drillship and the Associated Fleet.
As discussed above, determining a project's PTE is essential for determining the applicability of
PSD, as well as the scope of PSD review, in particular, the pollutants that are subject to
application of BACT, analysis of ambient air quality impacts from the project, analysis of air
quality and visibility impact on Class I areas, and analysis of impacts on soils and vegetation. As
discussed in Section 2, PTE reflects a source's maximum emissions of a pollutant from a source
operating at its design capacity, including consideration of any physical or operational
limitations on design capacity such as air pollution control equipment, emission limitations, and
other capacity limiting restrictions that effectively and enforceably limit emissions capacity. See
40 C.F.R. §§ 52.21(b)(4) and 55.2. In the case of OCS sources, emissions from vessels servicing
or associated with an OCS source are included in the "potential to emit" for an OCS source while
physically attached to the OCS source and while en route to or from the source when within 25
miles of the source.
The detailed emissions calculations for the Chukchi Sea exploration drilling program are
contained in Appendix A and in Air Sciences 6/16/09; Air Sciences 6/19/09; Air Sciences
6/30/09; Air Sciences 12/18/09-Incinerator; Shell 12/9/09 Supp. App.; Shell 12/13/Supp. App.
In developing the emission inventory, EPA relied extensively on emissions data that were
representative of the subject emission unit. For most emission units on board the Discoverer,
EPA used emissions data from either the manufacturer or from literature that provided equivalent
emissions data, such as data from similar emission units. In a very few instances, where
representative data were not available, EPA relied on AP-42 to calculate projected emissions
(EPA 1995 AP-42 and updates).
The emission inventory reflects application of emission limitations representing best available
control technology or "BACT." As discussed in Section 4.1, a new major stationary source is
required to apply BACT for each pollutant subject to regulation under the Clean Air Act that it
would have the potential to emit in significant amounts. 40 C.F.R. § 52.21(j). Based on the
emission inventory for the OCS source presented in Table 2-1, the emissions of NOx, PM, PM2.5,
PMio, SO2,9 VOC and CO have a PTE exceeding their respective significant emission rates.
Therefore, BACT must be determined for each emission unit on the Discoverer or that is part of
the OCS source that emits these pollutants. Section 4 contains a detailed discussion of the
BACT determination for each emission unit subject to BACT. The proposed permit contains
emission limitations that represent BACT and the emission inventory reflects these BACT-based
emission limitations.
The emission inventory also reflects emission limitations and operating restrictions requested by
Shell in its permit application as well as emission limitations and operating restrictions based on
9 See discussion of S02emissions in Section 2.4.3.
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operating conditions assumed in the air quality impact analysis. The PSD regulations require
that a source demonstrate that the allowable emissions increase from the new source, in
conjunction with all other applicable increases or reductions (including secondary emissions),
would not cause or contribute to a violation of the NAAQS or any applicable maximum
allowable increase over the baseline concentration in any area. 40 C.F.R. § 52.21(k). The
"applicable maximum allowable increase over baseline concentration in any area" are referred to
as "increments" and are set forth in 40 C.F.R. § 52.21(c). After application of emission
limitations that represent BACT, preliminary modeling indicated that additional restrictions on
Shell's emissions and mode of operation would be needed to ensure attainment of the NAAQS
and compliance with increment for some pollutants. Therefore, to ensure attainment of NAAQS
and compliance with increment, the proposed permit imposes restrictions on emission units and
Shell's mode of operation that are in addition to the application of BACT and that further limit
operation of and emissions from the project.
The air quality impact analysis is discussed in Section 5. Emission limitations and operational
restrictions are needed to demonstrate compliance with the annual increment for NOx, attainment
of the 24-hour PM2.5 NAAQS, and compliance with the 24-hour PM-10 increment. Therefore,
for most emission units, the permit contains an annual limit on NOx, and 24-hour limits on PMio
and PM2.5.
The permit contains monitoring, recordkeeping and reporting to monitor and ensure compliance
with the emission limitations. This proposed permit requires stack testing of certain sources
prior to commencement of each of the first three drilling seasons. Under this approach, not all
emission units in a source category will be tested each year, but by the end of the first three
drilling seasons, all of them will have been tested. Monitoring for the daily PM10 and PM2.5
limits and the annual NOx limit is based on emission factors derived from source tests, load
monitoring or fuel usage, and annual fuel usage limits.
The number and range of stack testing of the newer and the smaller internal combustion engines
(FD-9 to FD-20) and boilers (FD-21 to FD-22) in this proposed permit has been reduced from
the testing required in EPA's initial August 2009 proposed permit. In comments on the August
2009 proposal, Shell requested that stack testing be eliminated entirely for the newer engines, the
smaller engines, and the boilers. (Shell 9/17/09 Comments; Shell 11/23/09 Supp. App; Environ
11/25/09). EPA does not agree with Shell that testing these emission units is unnecessary, but
believes that testing at a reduced number of operating loads or operating load ranges will
continue to provide a reasonable assurance of compliance and accommodate (in part) Shell's
concerns regarding the number of required source tests under the permit generally and the
difficulty of stack testing some of these specific units due to their unique operation and function.
There are no ambient air standards for VOC and predicted impacts of CO from this project are
well below the standards. Therefore, EPA focused the monitoring regime on the BACT emission
limits for these pollutants. For VOC and CO, testing at lower loads is expected to provide a
higher emission factor than testing at full operating loads (see emissions data for various
Caterpillar D343 configurations). The same is true with respect to visible emissions. EPA
therefore believes that requiring stack testing for VOC, CO and visible emissions within the
expected operating range of each engine will provide a reasonable indication of compliance for
the VOC, CO, and visible emission limits for the newer engines, the smaller engines, and the
boilers. See Permit Conditions F.6, G.8, H.7,1.7, and J.5. Because the data for NOx and
particulate matter is less conclusive, EPA is requiring stack testing at two load ranges - a high-
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load operating range and a lower-load operating range. Shell requested a reduced testing regime
only for certain emission units on board the Discoverer, but EPA believes it is appropriate to
extend this approach to the engines on board the icebreakers for the same reasons and has done
so in this proposed permit. See Conditions N.10.2 and 0.12.2.
Shell has provided EPA with information that Shell asserts shows that testing of the deck cranes
(Units FD-14 to FD-15) is not practical because of their location on the ship and because of how
the engines are loaded. (Shell 9/17/09 Comments; Shell 11/23/09 Supp. App; Environ 11/25/09).
While EPA understands that there may be practical challenges to testing these emission units,
EPA has insufficient information at this time to eliminate testing for these units. EPA is
therefore proposing that, as with the other newer and smaller engines on the Discoverer, that
stack testing be required across a fewer number of load ranges. During the public comment
period, EPA invites public comment and additional information from Shell and other
commenters that further supports or opposes eliminating the stack testing requirement for the
deck cranes.
Except for those conditions addressing notification, reporting and testing, the permit conditions
contained in Sections B through Q of the proposed permit apply only during the time that the
Discoverer is an OCS source. Permit conditions addressing notification, reporting and testing
apply at all times as specified. When the Discoverer is an "OCS Source" for purposes of the
proposed permit is discussed in Section 2.4.1.
3.2 Generally Applicable Requirements
This section describes the permit conditions that apply generally to the Discoverer and the
Associated Fleet and generally relate to permit administration or enforcement.
Condition A.l requires the permittee to construct and operate the OCS source and the Associated
Fleet in accordance with its application and supporting materials and in accordance with the final
permit, as provided in 40 C.F.R. §§ 55.6(a)(4)(i) and 52.21(r)(l).
Condition A.2 specifies the enforcement authority for violation of OCS and PSD regulations and
this permit, as provided in 40 C.F.R. §§ 55.9(a)-(b) and 52.21. Operation in violation of a permit
term or condition is not authorized under this permit.
Condition A.3 makes clear that the permit does not relieve the permittee of the responsibility to
comply fully with all other requirements of federal law as provided in 40 C.F.R. §§
55.6(a)(4)(iii) and 52.21(r)(3). EPA is aware that Shell is required to obtain approval from other
agencies before it is authorized to begin exploratory drilling in the Chukchi Sea and that there is
pending litigation regarding the leases under which Shell proposes to conduct its exploratory
drilling. EPA believes it is nonetheless appropriate to proceed with issuance of this OCS/PSD
permit so that once Shell has all necessary approvals and authorizations to begin its exploratory
drilling program on its leases in Lease Area 193, Shell can proceed with its exploratory drilling
operations in Lease Area 193 without further delay consistent with a final OCS/PSD permit and
all other necessary federal approvals and requirements. Condition A.3 makes clear Shell's
obligation to satisfy all other federal requirements prior to commencing operation under this
CAA permit.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
Condition A.4 requires the permittee to notify all owners, operators and contractors of the source
of the requirements of the permit, as provided in 40 C.F.R. § 55.6(a)(4)(iv).
Condition A. 5 contains provisions relating to automatic expiration of PSD permits as provided in
40 C.F.R. § 52.21(r)(2) in the event of failing to timely commence or complete construction or of
a delay in construction. As provided in 40 C.F.R. § 124.5(g)(2), such permit expiration is not
subject to the procedural requirements of 40 C.F.R. Part 124.
Condition A.6 contains provisions for revision, termination, or revocation and reissuance of the
permit. Although 40 C.F.R. Part 124 does not contain such procedures for OCS or PSD permits,
see 40 C.F.R. § 124.5(g)(1), EPA believes it has inherent authority to revise, terminate, or revoke
and reissue a permit for cause, including a material mistake, inaccurate statements made during
permit issuance, failure to comply with permit requirements, or ensuring compliance with the
requirements of the Clean Air Act. Should EPA decide cause exists to revise, terminate, or
revoke and reissue the permit, EPA will follow 40 C.F.R. Part 124. EPA intends to give Shell
reasonable notice prior to initiating such action.
Condition A.7 clarifies that the specification of a reference test method does not preclude the use
of other credible evidence for the purpose of establishing whether or not the permittee is in
compliance with a particular requirement. This is consistent with EPA's interpretation of the
Clean Air Act requirements. See 40 C.F.R. §§ 52.12(c), 60.11(g), 61.12(e), and 62 Fed. Reg.
8314 (February 24, 1997).
Condition A.8 includes EPA's inspection authority under Section 114 of the CAA. As discussed
above, the permittee is a Title V source and must apply for a Title V operating permit under 40
C.F.R. Part 71 within one year of commencing operation. To facilitate incorporation of the
requirements of this permit into the permittee's Title V permit, EPA has used the inspection
language in 40 C.F.R. § 71.6(c).
Condition A.9 includes general recordkeeping requirements, including a record retention
requirement of five years. Again, because Shell is subject to the Title V operating permit
program and will be issued a Title V operating permit, EPA believes it is appropriate to make the
general recordkeeping requirements in the permit consistent with part 71. See 40 C.F.R.
§ 71.6(a)(3).
Condition A. 10 specifies the EPA address to which information under the permit must be
submitted.
Condition A. 11 requires the certification of all documents submitted under the permit. Again, to
facilitate incorporation of this requirement into Shell's Title V permit, EPA used language
consistent with 40 C.F.R. § 71.5(d).
Conditions A. 12 and A. 13 contain standard language regarding severability of permit conditions
and property rights. Again, to facilitate incorporation of these requirements into Shell's Title V
permit, EPA used language consistent with 40 C.F.R. §§ 71.6(a)(5) and 71.6(a)(6)(iv).
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
3.3 Source-Wide Requirements
Section B of the permit contains air quality-related and operational limits that generally apply on
a source-wide basis to the Discoverer and the Associated Fleet.
Condition B.l requires Shell to notify EPA at least 10 days prior to becoming an OCS source at
any drill site. This proposed permit authorizes operation of the OCS source at multiple drill site
locations on Shell's lease holdings in Lease Area 193 of the Chukchi Sea. The emissions limits
and related monitoring, recordkeeping, and reporting apply at all drill site locations. Overall
operation as an OCS source under the permit is limited to 168 days per rolling 12-month period.
Condition B.l requires the permittee to notify EPA of the proposed new location and probable
duration of a drill site operation as well as to confirm that no Class I area or any area known to
have a violation of applicable increment would be impacted by that specific operation.
Condition B.2 limits the annual duration of Shell's exploration operations in the Chukchi Sea.
Shell's drilling season will largely be limited by sea ice conditions. Some variability can be
expected from year to year. However, Shell expects to start drilling in July of each year and the
drilling season is expected to last 5.5 months and has specifically requested that the proposed
permit impose an annual limit of 168-days of operation as an OCS source. Condition A. 13 limits
the drilling season to the period between July 1 and December 31 of each year, which is referred
to as the "drilling season" in the permit, and limits the number of days of operation as an OCS
source to 168 calendar days each year. This is not a continuous 168-day period but an
aggregation of all time operating as an OCS source during a given 12-month period. In addition,
for each drill site, this condition requires Shell to document the exact location of the Discoverer
when drilling, the lease block where drilling is occurring and the duration of the Discoverer as an
OCS source at that site. This condition also clarifies that time recorded as an OCS source must
include time spent drilling relief wells.
Condition B.3 requires Shell to notify EPA of the beginning and end of each drilling season.
Condition B.4 imposes a BACT limit of 0.0015 percent sulfur by weight on the fuel used in the
Discoverer engines (except the propulsion engine), boilers, and incinerator. Shell is required to
monitor fuel sulfur content by either testing the fuel being used or obtaining supplier
certifications from the supplier. Note that Shell has committed to using only ultra-low sulfur
diesel in the propulsion engine when operating north of the Bering Strait (Shell 12/9/09 Supp.
App.). EPA's authority to impose emission limitations and other operating restrictions on the
Discoverer, however, is limited to when the Discoverer is an OCS source.
Condition B.5 limits the fuel sulfur content of fuel used in the Associated Fleet to a sulfur
content of 0.0015 percent by weight, which Shell is required to monitor by either testing the fuel
being used or obtaining supplier certifications from the supplier. This is a reduction in the
permitted fuel sulfur content of fuel used in the Associated Fleet from the initial August 2009
proposed permit of 0.19 percent by weight of sulfur and is based on Shell's commitment to using
fuel with a maximum sulfur content of 0.0015 percent sulfur by weight in all engines on vessels
in the Associate Fleet when operating north of the Bering Strait (Shell 12/9/09 Supp. App.). The
emission inventory, permit limits, and other analyses supporting the proposed permit are based
on the use of ultra-low sulfur fuel.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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Condition B.6 implements the BACT requirement to control emissions PM, PMio and PM2.5
emissions from crankhouse ventilation. It requires that that each diesel IC engine, except for the
MLC Compressor Engines (FD-9 to FD-11) and the Caterpillar C7 Logging Winch Engine (FD-
19), be equipped with a closed crankcase ventilation (CCV) system. The MLC Compressor
Engines and the Caterpillar C7 Logging Winch Engine have built-in crankcase emission
controls.
Condition B.7 contains general testing requirements related to how the stack tests must be
conducted. It also contains procedures for approval of an alternative to or a deviation from a
reference test method.
Condition B.8 prohibits Shell from flow testing wells, flaring gas, storing liquid hydrocarbons
recovered during well testing, or refueling within 25 miles of the Discoverer while the
Discoverer is an OCS source. Shell's application states that, during its planned drilling campaign
using the Discoverer, they have no plans to conduct these activities. Because EPA has therefore
not estimated or analyzed emissions from these activities, Condition B.8 prohibits them.
Condition B.9 requires Shell to calculate monthly emissions of pollutants of CO, NOx, PM2.5,
PM10, S02 and VOC. In addition, Condition B.10 requires a monthly calculation of rolling-12-
month emissions of each of these pollutants for the prior 12-month period. Condition B. 11
requires Shell to notify EPA if any of the emission or throughput limits in the permit are
exceeded.
All of the emissions estimates are based on the equipment and control equipment being operated
using good practices. Consequently, Condition B. 12 requires the use of good air pollution
control practices for minimizing emissions and is derived from language in the general
provisions of theNSPS andNESHAP. See 40 C.F.R. §§ 60.11(e) and 63.6(e).
3.4 Frontier Discoverer Drillship
Sections 3.4 through 3.7 describe each emission unit or group of emission units on the
Discoverer and the Associated Fleet in more detail. It also provides additional explanation for
the basis for the emissions calculations, explains the BACT or other emission limitations
applicable to the emission unit(s), and explains the monitoring, recordkeeping and reporting for
the emission unit(s).
The Discoverer is a turret-moored drillship that is able to move under its own power. The
propulsion unit will not be used while the drillship is an OCS source (see Section 3.4.2). While
an OCS source, the Discoverer will use a variety of pollutant-emitting equipment and/or
activities. The emission units on board the Discoverer are listed in Table 3-1. All of these
emission units are existing equipment, with the exception of the MLC air compressors, which are
new engines.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
Table 3-1 - Frontier Discoverer Emission Units
ID
Description
Make and Model
Rating
FD-1 - 6
Generator Engines
Caterpillar D3 99 SCAC 1200 rpm
1,325 hp
FD-7a
Propulsion Engine
Mitsubishi 6UEC65
7,200 hp
FD-8
Emergency Generator
Caterpillar 3304
131 hp
FD-9 - 11
MLC Compressor Engines
Caterpillar C-15
540 hp
FD-12- 13
HPU Engines
Detroit 8V-71
250 hp
FD-14
Port Deck Crane Engine
Caterpillar D343
365 hp
FD-15
Starboard Deck Crane Engine
Caterpillar D343
365 hp
FD-16 - 17
Cementing Unit Engines
Detroit 8V-71N
335 hp
FD-18
Cementing Unit Engine
GM 3-71
147 hp
FD-19
Logging Winch Engineb
Caterpillar C7
250 hp
FD-20
Logging Winch Engineb
lohn Deere PE4020TF270D
35 hp
FD-21 -22
Heat Boilers
Clayton 200
7.97 MMBtu/hr
FD-23
Incinerator
TeamTec GS500C
276 lb/hr
FD-24 -30
Fuel Tanks
NA
Various
FD-31
Supply Ship Generator
Engine (s)
Generic
584 hp
FD-32
Drilling Mud System
NA
NA
FD-33
Shallow Gas Diverter System
NA
NA
a. The propulsion engine will not be used when the Discoverer is an OCS source.
b The engines used to power the logging winch functions are different from the initial August 2009
proposed permit - - the engines were changed at Shell's request, and the necessary changes have
been reflected in the emission inventory, the proposed permit, and the other analyses supporting
this proposed permit (Air Sciences 12/10/09).
As noted in Table 3-1, most of the emission units on board the Discoverer are internal
combustion engines. The Discoverer is also equipped with two boilers. Both the engines and the
boilers are fired on a light-distillate, liquid fuel equivalent to No. 1 or 2 grade diesel. As
discussed previously, Condition B.4 requires Shell to use only fuels with very low sulfur content
in the Discoverer emission units (0.0015% sulfur by weight). This fuel must also be used in the
Discoverer incinerator burner.
3.4.1 Generator Engines (FD-1 to FD-6)
Six Caterpillar D399 generator sets provide the primary systems power for the drilling as well as
the ship utilities. The Discoverer D399 units are each rated at 1325 horsepower (hp), and are
separate circuit aftercooled (SCAC). These D399 engines are specified to produce peak power at
1200 revolutions per minute (rpm). Each engine can be operated at varying load levels
throughout the drilling process. Shell expects that no more than five engines will operate at one
time, leaving one as a spare. The normal ramping procedure is to operate the fewest number of
engines needed to power the load and as load increases, to add on engines so that the operating
engines are at 50 percent capacity or greater. In recognition of the excess capacity and to limit
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
maximum emissions, Shell has requested that the engines be limited to operate at no more than
71% of rated capacity, in aggregate.
As discussed in Section 4, EPA is proposing that selective catalytic reduction (SCR) and
oxidation catalyst control devices represent BACT for the D399. These controls are to be
retrofitted by D.E.C. Marine AB, a Swedish company with extensive experience in installing
ship emission control systems for NOx. The analyses in support of this permit action were based
on the SCR units and the oxidation catalysts being fully operational at any time that the engine
they serve are running. Conditions C.l and C.2 reflect these requirements.
The D.E.C. Marine AB control guarantees for NOx and CO are based on the engines running at
between 50 and 100% load. Based on Shell's discussions with the vendor, Shell is confident that
the SCR and oxidation catalyst are able to meet the proposed emission rates, even at lower loads.
As a result, the emission inventory and modeling analyses are based on these emission rates at all
loads. Therefore, the BACT permit conditions contained in Condition C.3 are based on these
limits applying at all operating conditions. Condition C.4 contains emission limits for PM2.5
(daily), PMio (daily) and NOx (annual) that arise out of emission limits requested by Shell.
Again, these limits apply at all operating conditions.
D.E.C. Marine AB does not guarantee an emission rate for emissions of VOC. Instead, they
indicate that emissions reduction can be expected between 70 and 90%. Shell has used the lower
range as part of their representation of PTE. Shell has indicated that the oxidation catalyst will
result in a 50% reduction in emissions of particulate matter of all sizes. EPA's emission
inventory reflects these assumptions and requires stack testing (Condition C.6) to assure that
actual emission rates comply with the BACT emission limits.
In comments on the initial August 2009 proposed permit, Shell requested that the permit be
revised so that compliance with the emission limits applicable to the main generators would be
monitored by the electrical power output produced by the generators instead of by monitoring
fuel usage as in the initial proposal. (Shell 9/17/09 Comments). Based on supplemental
information submitted by Shell (Shell 11/23/09 Supp. App.), EPA believes that monitoring
electrical power output produced by the generators will provide a reasonable means of assuring
compliance with the applicable emission limits. The main generators comprise six Caterpillar
D399 engines rated at 1325 hp each, with an aggregate rating of 7950 hp. Shell has requested a
limit to operate at no greater than 71% of this rating, or 5,645 hp. This is equivalent to 4209 kW
(mechanical). In Shell's November 23, 2009 submittal, Shell presented generator efficiencies
for a variety of gensets, with efficiencies ranging from 92% to 96% (Shell 11/23/09 Supp. App.).
Given the apparent age of the Discoverer's gensets and the lack of specific information regarding
the efficiencies of the Discoverer's gensets, EPA believes it is appropriate to use the most
conservative value (i.e. 92%) to represent generator efficiency for these emission units. This
would result in an hourly limit of 3,872 kWe-hr.
Condition C.5 limits the power output in aggregate for these gensets to 3,872 kWe and, in
conjunction with the emission factors derived from the stack testing required in Condition C.6, is
used to monitor compliance with emission limits for these engines. Condition C.6 requires Shell
to conduct stack testing for CO, NOx, PM2.5, PM10, VOC, ammonia and visible emissions and to
monitor certain parameters in addition to determining the efficiency for each engine. In addition
to monitoring power output (Condition C.7), Shell is required to monitor and record parameters
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
related to good operation of the SCR. Condition C.7.5 requires Shell to monitor and record
hourly NOx emissions.
3.4.2 Propulsion Engine (FD-7)
Section 2.4.1 discusses two alternative approaches for when the Discoverer will be considered an
OCS source under the proposed permit. Under both approaches, the propulsion engine will have
no emissions during the time the Discoverer drillship is an OCS source.
Based on Shell's application and EPA review, the permit will feature two permit conditions
regarding use of this emission unit. Condition D. 1 prohibits the use of the propulsion engine
while the Discoverer is an OCS source. Condition D.2 requires Shell to report to EPA any use of
this engine while the Discoverer is an OCS source.
3.4.3 Emergency Generator (FD-8)
The Discoverer will have one emergency generator, powered by a 131 hp Caterpillar 3304
engine, for use in powering the basic drillship utilities, which include domestic and worker safety
devices. This generator will not be used for powering drilling equipment. There are no planned
uses of the emergency generator except for weekly exercising which involves operation for
approximately 120 minutes (two hours) at loads up to capacity.
In estimating emissions from this generator, EPA relied upon Caterpillar emissions data from an
EPA Health Assessment Document (EPA 2002). Because this document did not feature data
specific to the 3304 model engine, EPA used the maximum emissions rate for each pollutant
from all Caterpillar engines as a conservative assessment of emissions from the Caterpillar 3304
engine. In estimating PM2.5 emissions, EPA conservatively assumed that all PMio emissions
were also PM2.5
Based on Shell's application and EPA review, Condition E.l prohibits operations of the
emergency engine in excess of 120 minutes during any single day and 48 hours during any
rolling 12-month period. This is an increase in anticipated use and emissions from the August
2009 permit. (Shell 9/17/09 Comments). Fuel limits for the Cementing Units and Logging
Winch Engines (FD-16 to FD19) have been decreased to offset the small increase in emissions
from the emergency generator. Condition E.2 requires Shell to record all usage of this engine
while the Discoverer is an OCS source and, per Condition E.3, to report any deviation from the
operational restrictions.
3.4.4 Mud Line Cellar (MLC) Compressor Engines (FD-9 to FD-11)
The MLC air compressors are used for drilling the MLCs, which is the initial drilling activity.
Shell expects to use these compressors for about one week per well. The compressors will be
powered by three 540-hp Caterpillar C-15 engines, and will be used at between 50 and 100
percent capacity during the week needed to evacuate the MLC. Shell has requested an annual
fuel limit of 81,346 gallons for all three engines combined. Hourly and daily emissions are based
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
on operation of all three engines at maximum capacity. The C-15 engines are new and are
required to meet EPA's Tier 3 emission standards for nonroad engines (40 C.F.R. § 89.112).10
The Tier 3 standards have a single limit for NOx and VOC combined. In the emission inventory,
the conservative maximum emission rate of 4.0 g/kW-h was used for each pollutant (i.e. NOx and
VOC). These engines are also subject to a PM limit of .20 g/kW-h under the Tier 3 standards.
In the emission inventory, this emission rate of .20 g/kW-h was also used to estimate emissions
of PMio and PM2.5, a conservative assumption. Particulate matter emissions are expected to be
even lower as a result of the addition of an oxidation catalyst and the passage of the exhaust
gases through that system.
Conditions F.l and 2 contain the BACT emission limits and requirements for these engines.
Condition F.3 of the permit contains the annual NOx emissions limit that results from the fuel
limit requested by Shell, 81,346 gallons for all three engines combined during any rolling 12-
month period, which is contained in Condition F.5. The annual NOx limit and fuel limit each
apply to all three engines in aggregate. In contrast, Condition F.4 imposes emissions limits for
PM2.5 and PMio on a per-unit base. To monitor fuel usage, Condition F.7 requires the permittee
to install, properly maintain and operate totalizing, nonresettable diesel fuel flow meters on each
engine and to monitor and record the daily use of fuel in each engine. Condition F.6 requires
Shell to stack test one engine in each of the first three drilling seasons for CO, VOC and visible
emissions within one load range, and NOx, PM2.5 and PMio within two different load ranges.
3.4.5 Hydraulic Power Units (FD-12 to FD-13)
The hydraulic power units (HPU) are also used for drilling the MLCs. The HPU units are
powered by a pair of 250-hp Detroit Diesel 8V-71 engines. These units will be used very
similarly to the MLC compressors. Shell has requested an annual fuel limit of 44,338 gallons for
both engines combined. Hourly and daily emissions are based on operation of both engines at
maximum capacity.
EPA relied on the EPA Health Assessment Document for engine-specific data (EPA 5/02 Diesel
Health Assessment). This source had several data points for this engine, and EPA used the
maximum of the data values for each pollutant as a conservative assessment of emissions. This
document only listed emissions data for PM, not PMio or PM25. Consequently, the values for
PM were assumed to be representative of PMio and PM2.5 emission rates, again, a conservative
assumption.
The proposed permit requires Shell to use a catalytic diesel particulate filter (CDPF) on each
engine in this group for control of oxidizable emissions (volatile organics, carbon monoxide, and
hydrocarbon particulate matter). The filter vendor Shell is using, CleanAIR Systems, has
indicated that with the correct filter on each engine, and with adequate regeneration, the filters
are capable of 85% reduction in PM emissions, 90% reduction in CO emissions, and 90%
reduction in VOC emissions. (Air Sciences 4/27/09). CleanAIR Systems has also indicated that
the exhaust temperature will need to be above 300 degrees Celsius (°C), or 572 degrees
10 As discussed in Section 4.2 below, EPA set new emission standards for nonroad diesel engines using a 3-tiered
progression to lower emission standards. Each tier involves a phase-in by horsepower rating over several years.
Tier 3 in 40 C.F.R. Part 60, Subpart IIII, is the most stringent of the 3 tiers.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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Fahrenheit (°F), for at least 30% of the engine operating time for proper filter regeneration using
ultra low sulfur fuel (i.e. 0.0015 percent sulfur by weight). (Shell 2/23/09 Rev. App., Appendix
F, pp. 173-183).
Condition G. 1 requires use of the CDPF whenever the engine being served by that CDPF is in
operation. The CDPFs are equipped with a HiBACK monitor and alarm system that monitors
exhaust pressure and temperature. Condition G. 1.1 requires that each CDPF be equipped with a
fully operational HiBACK system and, in order to assure adequate regeneration, Condition G.1.2
requires temperature over the course of a day of operation to be at least 300 °C for at least 30%
of operational time. Conditions G.2 and G.3 reflect the BACT emission limits, including a
requirement to use good combustion practices to control NOx emissions.
Condition G.4 of the permit contains the annual NOx emissions limit that resulted from the fuel
limit requested by Shell, 44,338 gallons for both engines combined during any 12-month period,
which is contained in Condition G.6. The annual NOx limit and the fuel limit apply to both
engines in aggregate. In contrast, Condition G.5 contains emissions limits for PM2.5 and PMi0
that apply on a per-unit base. To monitor fuel usage, Condition G.9 requires the permittee to
install, properly maintain and operate totalizing, nonresettable diesel fuel flow meters on each
engine and to monitor the daily use of fuel in each engine as well as other parameters necessary
to assure compliance with the limitations in this section of the permit. Condition G.8 requires
Shell to stack test one engine each of the first two drilling seasons for CO, VOC and visible
emissions at one load, and NOx, PM2.5 andPMio at two different loads.
Shell intends to operate the HPU engines under one of three operating scenarios: Base Operating
Scenario, Alternative Operating Scenario #1 and Alternative Operating Scenario #2. Under each
of these scenarios, Shell will operate under different daily fuel limits and coordinate operation of
these engines with operation of the incinerator (FD-23). Under the Base Operating Scenario, the
HPU engines shall not be operated while the incinerator is allowed to incinerate no greater than
1300 lbs of waste in any calendar day. With Alternative Operating Scenario #1, the HPU
engines are allowed to combust up to 352 gallons of fuel per calendar day in both engines in
aggregate, while the incinerator is limited to 800 lbs of waste during the same day. Under
Alternative Operating Scenario #2, the HPU engines' fuel limit rises to 704 gallons per calendar
day in both engines in aggregate, and the incinerator limit is reduced to 300 lbs of waste during
the same day. The conditions establishing the alternative operating scenarios for the HPU
engines are contained in Condition G.7.
3.4.6 Deck Cranes (FD-14 to FD-15)
The Discoverer is equipped with two deck cranes that are mounted on and rotate on pedestals.
One crane is located on the port side of the drillship and the other crane is located on the
starboard side. Each crane is powered by a Caterpillar D343 engine rated at 365 hp. The engines
are mounted on the pedestal with the rotating crane. The cranes are used intermittently to move
materials around the deck and to on-load supplies from the supply ship. Shell has requested both
daily and annual limits on the amount of fuel combusted in these two emission units. As with
the HPU engines, the crane engines will have CDPFs for control of particulate matter, CO, and
VOC.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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Emissions from the Caterpillar D343 engines were estimated from the manufacturer's emissions
data. Permit conditions for these emission units parallel those for the HPU engines. Specifically,
Condition H. 1 contains the requirement to use the CDPF, HiBACK system and exhaust
temperature limits. Conditions H.2 and H.3 contain the BACT limitations, while Condition H.4
specifies the annual emission limit for NOx, and Condition H.5 contains the daily emission limits
for PM2.5 and PMi0. Condition H.6 specifies the annual fuel limit, while Conditions H.7 and H.8
contain the stack testing, monitoring, recordkeeping and reporting requirements.
3.4.7 Cementing Units and Logging Winch Engines (FD-16 to FD-20)
The three cementing units are used intermittently when drilling is interrupted for forcing a liquid
slurry of cement and additives down the casing and into the annular space between the casing
and the wall of the borehole when the drill pipe is pulled out of the hole, or for plugging and
abandoning wells. The cementing units are also used intermittently as high pressure pumps for
hydrostatically testing various well equipment and drilling components, such as the wellhead
connections, the blowout preventer, and other connections. The two logging winches are used to
gather information from each well when the drill stem is removed.
The cementing unit and logging winch engines will all be equipped with CDPFs. FD-19 is a
Caterpillar C7 engine that meets EPA's Tier 3 emission standards. Although the logging winches
will operate only when the cementing units are not used and the prime movers are operating at a
low load, Shell is not requesting these as operating restrictions and has instead modeled all
described units operating concurrently. The logging winches operate at variable and
unpredictable loads.
To estimate emissions from these emission units, EPA relied on the EPA Diesel Health
Assessment Document for engine-specific data. (EPA 5/02 Diesel Health Assessment). As
noted earlier, this document had several data points for the Detroit 8V-71. All of the "-71" series
are from the same family of engines, with a different number of cylinders. In addition, the GM 3-
71 engine (FD-18) is manufactured by Detroit Diesel. Accordingly, for the GM 3-71 engine,
EPA used the maximum of the data values for each pollutant from any -71 series engine as a
conservative assessment of emissions. As also noted before, this document only listed emissions
data for PM, not PMio or PM2.5 Consequently, the values for PM were assumed to be
representative of PMio and PM25 emission rates, a conservative assumption. Because the
logging unit engines are Tier 2 and Tier 3 engines, EPA used the corresponding limits in 40
C.F.R. Part 89 to estimate the PTE from these engines.
Permit conditions for these emission units parallel those for the HPU engines. Specifically,
Condition 1.1 contains the requirement to use the CDPF, HiBACK system and exhaust
temperature limits. Conditions 1.2 and 1.3 contain the BACT limitations for each of the engines,
while Condition 1.4 specifies the annual emission limit for NOx, and Condition 1.5 contains the
daily emission limits for PM2.5 and PMi0. For this group of engines, Shell requested and EPA is
imposing a daily fuel limit in addition to an annual fuel usage limit. Condition 1.6 specifies the
annual and daily fuel limits while Conditions 1.7 and 1.8 contain the stack testing and monitoring
requirements.
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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3.4.8 Heaters/Boilers (FD-21 and 22)
The Discoverer has two Clayton 200 diesel-fueled boilers for providing heat for domestic and
work space heating purposes. Shell's intent is to use one boiler for normal operation and the
second as a backup although there could be times when both would operate. For this permit,
Shell is not requesting any operational limits, and so, the PTE for the boilers has been
determined based on continuous operation for 168 days at full load. Because emissions are
based on operation as described above, limitations on fuel usage or hours of operation are
unnecessary. Emissions were estimated based on emissions data from the manufacturer. EPA
conservatively assumed that all PMio was PM25.
In addition to the B ACT limits in Condition J. 1 and J.2, Section J of the permit contains
conditions that are very similar to those imposed on the engines in previous conditions of the
permit. Condition J.3 contains an annual emission limit for NOx and Condition J.4 contains daily
emission limits for PM10 and PM25. Condition J.5 contains stack testing requirements and
Condition J.6 specifies the monitoring, recordkeeping and reporting required of Shell.
3.4.9 Waste Incinerator (FD-23)
Shell intends to dispose of domestic and other non-hazardous materials in a small two-stage,
batch-charged unit capable of burning 276 lbs/hr (125 kg/hr) of solid trash or 1,000 lb of liquid
sewage per day. In developing the emissions estimate, EPA relied on AP-42 (EPA1995 AP-42
and updates) emissions data for a larger class of incinerators because the manufacturer's
emissions data is oriented to satisfying European emission standards, and was not in a format
that could be converted into a throughput-based emission factor. For emissions of CO, NOx,
VOC and lead, EPA used the worst case emission factor for combustion of domestic waste or
sewage. In using this approach, the monitoring regime can be simplified and does not need to
require maintaining separate logs for the types of material incinerated.
For emissions of PM2.5, PM10 and SO2, Shell requested throughput-based limits. These values are
used in the emission inventory, and are reflected in emission limits in the permit (Condition K.5).
These limits, expressed in lbs/ton of waste incinerated, do not require additional monitoring
because they are the same as the BACT emission limits in the permit (Condition K. 1). Shell also
requested throughput limits that are below rated capacity in order to demonstrate that they meet
NAAQS and increment. These throughput limits and their related PTE limits for NOx, PM2.5 and
PM10 are contained in Conditions K.6, K.3 and K.4 respectively. In addition to these conditions,
the permit also requires stack testing (Condition K.8) and monitoring, recordkeeping and
reporting (Condition K.9)
Shell intends to operate the incinerator in coordination with operation of the HPU engines (FD-
12 to FD-13) under one of three operating scenarios: Base Operating Scenario, Alternative
Operating Scenario #1 and Alternative Operating Scenario #2. Under each of these scenarios,
Shell will operate under different daily incineration and fuel limits. Under the Base Operating
Scenario, the HPU engines shall not be operated while the incinerator is allowed to incinerate up
to 1300 lbs of waste in any calendar day. With Alternative Operating Scenario #1, the HPU
engines are allowed to combust up to 352 gallons of fuel per calendar day in both engines in
aggregate, while the incinerator is limited to 800 lbs of waste during the same day. Under
Alternative Operating Scenario #2, the HPU engines' fuel limit rises to 704 gallons per calendar
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
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day in both engines in aggregate, and the incinerator limit is reduced to 300 lbs of waste during
the same day. The conditions that establish the alternative operating scenarios for the incinerator
are contained in Condition K.7.
3.4.10 Diesel Fuel Tanks
The Discoverer is equipped with a number of fuel tanks that are used to store the fuel used in the
various emission units on board the drillship. Table 3-2 lists the tanks on board the Discoverer
as well as their respective capacities.
Table 3-2 - Discoverer Diesel Fuel Tanks
ID
Tank Capacity
(m3)
Tank Capacity
(gallons)
FD-24
538
142,140
FD-25
267
70,542
FD-26
267
70,542
FD-27
179
47,292
FD-28
150
39,630
FD-29
150
39,630
FD-30
135
35,667
The fuel stored in the tanks is the diesel used to fuel the emission units on board the Discoverer.
Diesel fuel has a very low vapor pressure, and so the tanks will have very low emissions - about
23 lbs of VOC per year (Air Sciences 4/13/09). Consequently, the proposed permit contains no
conditions regarding operation of these tanks.
3.4.11 Supply Ship Generator Engine (FD-31)
Although the Discoverer is provisioned and supplied at the beginning of a drilling season,
additional supplies are expected to be brought out to the drillship during the course of the drilling
season. Shell is expecting to re-provision the Discoverer at intervals of two to four weeks, for a
maximum of eight re-provisionings per season.
Shell will use a leased vessel to conduct these resupply operations. The most recent plans call
for a foreign-flagged vessel named Jim Kilabuk. The Jim Kilabuk will provision out of Canada,
and a different vessel would be used if supplied out of Alaska. There will be no need for the
supply ship to be within 25 miles of the Discoverer except for the time needed to approach,
deliver, and leave the area. If the supply ship makes a delivery, it will attach to the Discoverer
for less than 12 hours, during which time only one of its 292-hp generators will be operating. To
simplify the monitoring regime for this very occasional source, stack testing has been scaled
back to testing at only one load. This will require Shell to assume that the generator engine is
operated at full load while the supply ship is attached to the Discoverer. The permit does not
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specify a particular vessel, but does require that the rated capacity of the generator be no greater
than included in the modeling analysis.
The supply ship requirements are contained in Conditions L.l through L.5. Condition L.l
contains operational limits on the duration and frequency of supply ship visits. Conditions L.2
and L.3 contain PTE annual emission limits and PTE daily emission limits, respectively.
Condition L.4 contains the stack testing requirements and Condition L.5 specifies the
monitoring, recordkeeping and reporting required of Shell.
3.4.12 Mud Drilling System (FD-32)
The wells Shell proposes to drill in the Chukchi Sea will use the conventional rotary drilling and
fluids circulating systems. The fluids circulating system is comprised of drilling fluid, which is
pumped down the drill string, through orifices in the bit, and back to the surface where it is
directed into storage pits on the rig. After solids removal and mud conditioning, the drilling fluid
is directed from the pits back down the drill string. The drilling fluid cools and lubricates the
drill bit, carries cutting out of the hole and exerts hydrostatic pressure which prevents an influx
of formation fluids into the well bore. Shell estimates the maximum amount of hydrocarbons
that could be released from an entire drilling season to be 128 lbs of VOC (Air Sciences 5/4/09;
12/13/09 Supp. App.). Because of the low level of emissions, the proposed permit contains no
conditions regarding this emission unit.
3.4.13 Shallow Gas Diverter System (FC-33)
The shallow gas diverter is an emergency protection device for the protection of the drill rig and
personnel, and is not expected to be used except in the event of an influx to the well. The
purpose of a diverter is to direct any formation fluids away from the rig in the event of an influx
into the borehole. The diverter is used while drilling the shallow interval of the well before the
blow out preventers are installed (the interval from the 30 inch casing shoe at approximately 500
feet, down to 20 inch casing shoe at approximately 1000 feet. The diverter does not shut the well
in, but merely diverts the flow for discharge away from the rig, until the gas dissipates or the
hole bridges over. The diverter is used because at the shallow depths, the formation strength is
insufficient to withstand the potential pressure of a shut-in gas or gas/mud column in the
annulus. The blow out preventers are installed after running the 20 inch casing, because below
the 20 inch casing, the formation strength is sufficient to permit the well to be physically shut in
using the blow out preventers.
According to Shell, these types of diverters have been in use for decades. For example, the
model KFDS diverter, the type used on the Discoverer, has been in use for 25 years. MMS
requires all rigs operating in OCS waters to use a diverter. Most offshore rigs have diverters
whether or not they operate in OCS waters. Some land-based rigs use a diverter, or a similar
device called a rotating head, if the geologic environment suggests the possibility of shallow gas.
The diverter is located in a housing located under the rig floor. The drilling riser is attached to
the bottom of the diverter housing and maintains a continuous conduit for the return of the
drilling fluids from the sea bottom back to the rig. The drill string is run through the rig floor
and through the diverter housing and riser and down to the bottom of the well. The diverter
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housing has two large 16-20 inch diameter outlets oriented at 180 degrees to each other to which
are attached large pneumatic fast acting valves. The control logic for these valves is such that
only one can be closed at any given time. The diverter is a donut-shaped rubber element that is
located in the diverter housing above the two outlets. A hydraulically activated piston
compresses the element to seal around the drill string (or upon itself if the drill pipe is out of the
hole) and direct the flow through the outlet whose valve is in the open position in the event of a
shallow fluids (gas, water or air) flow. The opposing outlets permit the rig to divert the flow to
the downwind side of the rig. Attached to the valves are large diameter flowlines that direct the
flow from the diverter to the edge of the rig. The flowlines are generally horizontal, so that
the elevation is approximately 5-15 feet below the rig floor.
Shell anticipates that the likelihood of encountering shallow gas in the planned drill sites is quite
low, for the following reasons:
1. Shell has drilled wells nearby that have penetrated the same shallow formations and did
not see shallow gas;
2. Shell has conducted shallow hazards seismic surveys to delineate possible shallow gas
intervals and have selected locations to avoid any likely potential shallow gas sites;
3. Shell drills with a drilling fluid density that exceeds the anticipated formation fluid
pressure;
4. Shell drills a smaller (12 V^-Xl V2") pilot hole and uses formation evaluation tools to
interpret in real time the possibility of a shallow gas flow environment because drilling
the smaller hole limits the amount of gas that can enter the well bore and permits the use
of the dynamic kill procedure to shut off the flow; and
5. Shell will have a volume of heavy weight kill mud on hand immediately available to
pump in the event of a formation fluid influx so that the appropriate hydrostatic head can
be reestablished and influx can be shut off.
Based on the information above, EPA has determined that the very low probability of use of a
diverter requires no permit conditions beyond requirements to record and report to EPA if a
diversion event occurs. See Condition M. 1.
3.5 Ice Management and Anchor Handling Fleet
Since EPA proposed the initial permit for public comment on August 2009, Shell has revised its
approach to the use of icebreaking vessels (Shell 9/17/09 Comments). Icebreakers #1 and #2 no
longer have linked operational/emissions limits, and they are no longer interchangeable vessels.
Shell's ice management and anchor handling fleet is still expected to consist of two leased ships:
an icebreaker (referred to in the permit as Icebreaker #1) and an anchor handler/icebreaker
(referred to in the permit as Icebreaker #2). The purpose of this fleet is to manage the ice in the
area of the Discoverer, which involves deflecting or in extreme cases breaking up any ice floes
that could impact the ship when it is drilling, and to handle the ship's anchors during connection
to and disconnection from the seabed.
The ice floe frequency and intensity is unpredictable and could range from no ice to ice
sufficiently dense that the fleet has insufficient capacity and the Discoverer would need to
disconnect from its anchors and move off site. Based on statistics on ice at the Sivulliq drill site
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in the Beaufort Sea, Shell estimates that ice breaking capability in its lease holdings in Lease
Area 193 in the Chukchi Sea would only be required 38 percent of the time. For the remainder
of the time the ice management and anchor handling fleet would be beyond the 25-mile radius
from the Discoverer in a warm stack mode (anchored and occupied).
The primary driver of the ice fl oe is the wind, so the ice management ships are typi cally upwind
of the Discoverer when managing the ice. Figure 3-1 depicts the approximate locations of the
primary icebreaker and the anchor handler/ice management vessel when used to break one-year
ice.
Figure 3-1 - Ice management and anchor handling ships locations for breaking of one-
year ice
For addressing one-year ice, Icebreaker #1 will typically be positioned from 4,800 meters to
19,000 meters upwind on the drift line and Icebreaker #2 will be located from 1,000 meters to
9,600 meters upwind from the Discoverer. In the case of thick ice, the width of the Icebreaker
#1 swath will be about 3 miles (4.8 km) to either side of the drift line and Icebreaker #2 will be
moving laterally 1.5 miles (2.4 km) to either side of the drift line. The actual vessel distances
will be determined by the ice floe speed, size, thickness, and character, and wind forecast.
Although 2-meter-thick first-year ice is not expected, it might occur and the ice management
fleet would be moving at near full speed to fragment this ice. Occasionally there may be multi-
year ice ridges which are expected to be broken at a much slower speed than used for first-year
ice. Multi-year ice may be broken by riding up onto the ice so that the weight of the icebreaker
on top of the ice breaks it.
Shell will be leasing Icebreaker #1 from year to year. Consequently, the vessel used as
Icebreaker #1 may change from year to year. In order to accommodate this uncertainty, Shell
has requested that the permit allow for a generic Icebreaker #1. Furthermore, the fleet could
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consist of either two vessels or only one vessel, depending on availability of ships and ice
conditions. At present, there are only a limited number of eligible ships. Murmansk Shipping of
Russia operates two vessels - the Vladimir Ignatjuk and the Kapitan Dranitsyn. Viking leases
four vessels - the Odin, the Tor, the Balder and the Vidor. The Talagy is available from Smit,
and lastly, the Nordica and Fennica are operated by Finstaship. Shell has dropped the Kapitan
Dranitsyn from consideration for this project.
The emission sources from all of these icebreaker class vessels consist of diesel engines for
propulsion power, general purpose generators, boilers and incinerators. To accommodate the
requested flexibility, Shell has developed a single generic equipment list for Icebreaker #1 that
cannot be exceeded for any vessel. Table 3-3 shows the maximum aggregate ratings for each
category of equipment for Icebreaker #1.
Table 3-3 - Maximum Aggregate Rating of Emission Sources for Icebreaker #1
Description
Make and Model
Maximum Aggregate
Rating
Propulsion Engines
Various
28,400 hp
Generator Engine(s)
Various
2,800 hp
Heat Boiler(s)
Various
10 MMBtu/hr
Incinerator
Various
154 lbs/hr
To execute Icebreaker #2 duties, Shell will use one of two vessels - either the Tor Viking or a
new icebreaker being built to their specifications by Edison Chouest. Each of these vessels will
be equipped with SCR on the main engines, which will result in a substantial reduction of NOx.
(Shell 9/17/09 Comments). The latter vessel has not been named yet but is referred to by the
shipbuilder as Hull 247. Throughout this permit documentation, this vessel is also referred to as
Hull 247, with the intent that all permit conditions for Icebreaker #2 continue to apply to the
vessel, even once it has had its name changed from Hull 247 to its permanent name. Table 3-4
shows the maximum aggregate ratings for each category of equipment for Icebreaker #2.
Table 3-4 - Maximum Aggregate Rating of Emission Sources for Icebreaker #2
Description
Make and Model
Maximum Aggregate
Rating
Tor Viking
Propulsion Engines
Various
17,660 hp
Generator Engine(s)
Various
2,336 hp
Heat Boiler(s)
Various
1.37 MMBtu/hr
Incinerator
Various
151 lbs/hr
Hull 247
Propulsion Engines
Various
24,000 kW
Heat Boiler(s)
Various
4.00 MMBtu/hr
Incinerator
Various
151 lbs/hr
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Marine propulsion engines, such as those used on the icebreakers, have a different emission
profile than the more common engines found on board the Discoverer. The most cited reference
on emissions from marine engines is a document published by Lloyds Register. However, a more
recent publication compares emission factors from Lloyds with more recent emissions data from
the Swedish Environmental Research Institute (Corbett 11/23/04). To ensure that the emissions
factors used in the emission inventory for this project were adequately conservative, EPA
compared these data with emissions data from AP-42 (see Reference Table 3 in Appendix A)
and used the highest value for each pollutant.
In addition, Shell has requested limits on PM2.5 of 42.2 lbs/hr and on PMio of 48.0 lbs/hr (Air
Sciences 2009b) on Icebreaker #1, and 11.4 lbs/hr and 11.7 lbs/hr, respectively, for Icebreaker
#2. The permit requires candidate icebreakers to have their emission units tested prior to each
drilling season. If a candidate vessel's uncontrolled emissions of PM2.5 or PMi0 are above these
values, then the vessel cannot be used as either Icebreaker #1 or Icebreaker #2. Conditions N. 1
and 0.1 contain these equipment capacity and emission limits for the two icebreakers.
In calculating emissions from the emission sources on board the icebreakers, all sources, except
the propulsion engines, were assumed to operate at 100% of rated capacity. The propulsion
engines were represented at operating at no more than 80% of rated capacity. Consequently,
these restrictions are imposed in Conditions N.2 and O.2.
Based on the emissions calculations and resultant modeling, Shell has determined a maximum
usage for the icebreakers. The emissions, fuel and power output limits associated with this
scenario are contained in Conditions N.3, N.4, N.5, N.6, 0.3, 0.4, 0.5 and 0.6. The fuel and
power output limits in Condition N.5, N.6, 0.5 and 0.6 will also serve to limit emissions of the
other pollutants, such as CO. The fuel limits on the icebreakers are based on Shell's estimate of
its need for icebreaking capacity and ensure that emissions from the icebreakers will not exceed
the modeled emissions scenarios.
Based on Shell's application, there is no scenario where either of the icebreakers is attached to
the drillship, thereby becoming part of the OCS source.11 Consequently, the permit contains
Conditions N.8 and 0.10 that prohibit such attachment. The permit does allow each icebreaker
to approach near the Discoverer for purposes of transferring equipment and crew to and from the
Discoverer. Otherwise, Condition N.7 requires Icebreaker #1 to, consistent with the modeling
analysis, operate outside of a 4800 meter long cone centered on the centerline of the Discoverer.
Similarly, Condition 0.7 requires Icebreaker #2 to operate outside of a 1000 meter long cone
centered on the centerline of the Discoverer, except during anchor handling operations
(Condition 0.8) and bow washing (Condition 0.9). The air quality impact analysis was based on
these operating scenarios and therefore the permit contains emission limits to impose these
restrictions. The icebreakers are allowed to transit through their respective cones as these transit
events will be of short duration and at low loads as they will not be conducting icebreaking
activities within the cones. This is a change from the August 2009 proposed permit. Modeled
11 As discussed in Section 2.4.1 above, EPA does not consider Icebreaker #2 to be physicially attached to the
Discoverer within the meaning of the definition of "OCS source" in 40 C.F.R. § 55.2 during the time it is assisting
the Discoverer in the anchor setting and retrieval process.
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impacts from transit events in the area would therefore be expected to be lower than the worst
case scenario.
In order to assure compliance with the emission limits, both icebreakers are required to test their
emission sources each drilling season as provided in Conditions N.10 and 0.12. Conditions
N. 11 and 0.13 require Shell to conduct monitoring, recordkeeping and reporting to assure
compliance with the substantive conditions of Sections N and O of the permit.
3.5.1 Anchor Setting and Retrieval
As discussed above, the anchor-handling operation involves placing the Discoverer anchors on
the seabed in preparation for drilling, and retrieving the anchors when the Discoverer is being
moved off the well. Anchor handler propulsion power during anchor handing operations is
either low or at idle since it is precision work setting anchors, spooling-out lines, and tensioning
lines. The emissions from Icebreaker #2 during anchor retrieval are included in those allowed
for Icebreaker #2 in Conditions 0.3 and 0.4.
3.5.2 Bow Washing of Discoverer
Occasionally, ice can build up at the bow of the Discoverer. Periodically, to remedy this
situation, Icebreaker #2 will pass close to the Discoverer bow and dislodge this ice with its
propeller wash. During these "bow washing" events, which would last no more than one hour,
Icebreaker #2 operates at low power, and operates from either side of the bow (rather than in
front of the bow).
3.6 Supply Ship
As described in Section 3.4.11, although the Discoverer is expected to be provisioned at the
beginning of the season, additional supplies will be needed. These supplies will be brought out
on a supply ship. Section 3.4.11 addressed operations and emissions while the supply ship is
attached to the Discoverer. This section addresses operations of the supply ship as it transits to
and from the Discoverer. Table 3-5 lists the emission units associated with the supply ship.
Table 3-5 - Supply Ship
Description
Make and Model
Maximum Aggregate Rating
Propulsion Engines
Various
7,200 hp
Generator Engine(s)
Various
584 hp
While the supply ship is in transit, Shell's application describes operations as consisting of the
two propulsion engines operating at no more than 80% of rated capacity, and both generators
operating at full load. Condition P.l prohibits operation of these engines at loads above 80%, and
Condition P.3.1 requires Shell to confirm operations of these engines.
3.7 Oil Spill Response (OSR) Ships
The OSR fleet in the Chukchi is expected to consist of one offshore management ship, the
Nanuq, and three 34-foot work boats, the Kvichak No. 1, No. 2 and No. 3. Two of the 34-foot
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work boats will be used to tow containment booms while the third will act as a backup, for crew
changes and re-fueling. The Nanuq is expected to be used only in the unplanned event of an oil
discharge to the water. It will remain within about 5,000 meters of the drillship and downwind,
but at least 2,000 meters away for safety purposes. The work boats will remain on the deck of
the management vessel and will only be in the water for training, drills, and response events.
The OSR fleet will have on-water drills at a maximum frequency of once per day, which will
consist of an 8-hour exercise. The exercise will normally consist of two 34-foot boats towing an
open apex boom diverting a water stream back to the Nanuq. The Nanuq will have skimmers
deployed and be simulating the recovery of oil downstream of the open apex. During this
exercise, the small craft as well as the Nanuq will be moving at approximately 0.5 nautical miles
per hour.
Table 3-6 presents the emission units on board the Nanuq and each of the Kvichak work boats.
Table 3-6 - Oil Spill Response Fleet
ID
Description
Make and Model
Rating
Oil Spill Response Main Ship - Nanuc
N-l -2
Propulsion Engines
Caterpillar 3608
2,710 kW
N-3 - 4
Non-propulsion Electrical
Generators
Caterpillar 3508
1,285 hp
N-5
Emergency Generator
John Deere
166 kW
N-6
Incinerator
ASC/CP100
125 lbs/hr
Oil Spill Response Work Boat - Kvichak 34-foot No. 1
K-l - 2
Propulsion Engines
Cummins QSB
300 hp
K-3
Generator Engines
Various
12 hp
Oil Spill Response Work Boat - Kvichak 34-foot No. 2
K-4-5
Propulsion Engines
Cummins QSB
300 hp
K-6
Generator Engines
Various
12 hp
Oil Spill Response Work Boat - Kvichak 34-foot No. 3
K-7 - 8
Propulsion Engines
Cummins QSB
300 hp
K-9
Generator Engines
Various
12 hp
In determining the PTE from the OSR fleet, EPA relied on manufacturer's data for the two
Caterpillar 3608 propulsion engines. Emissions from the two Caterpillar 3508 generator engines
and the incinerator were estimated using EPA's AP-42 document. The emergency generator will
not be used as part of normal operations and will only be used during a true emergency situation.
Each of the three Kvichak work boats is equipped with two Cummins QSB engines for
propulsion power and a small 12 hp generator engine. Emissions for the former were based on
manufacturer's data, while generator engine emissions were determined using AP-42.
Since EPA proposed the initial permit for public comment on August 2009, Shell has committed
to use of CDPF units from CleanAIR Systems on both the propulsion and non-propulsion
generator engines on the Nanuq. Condition Q. 1 therefore requires use of the CDPF whenever
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these engines are operated. The main ambient air impacts from this fleet are annual NOx.
Accordingly, Condition Q.2 imposes an annual NOx emission limit that results from fuel usage
limits requested by Shell. These fuel limits are contained in Condition Q.3. Shell has analyzed
operation of the OSR based on certain operational parameters for the fleet. Where these
assumptions affect the outcome of the air quality impact analysis, adherence to these parameters
is required in Conditions Q.4, Q.5 and Q.6. These conditions require the OSR fleet to operate
downwind of the Discoverer and at a minimum distance of 2,000 meters from the Discoverer
except in the case of an emergency or to transfer equipment and crew to and from the
Discoverer. In addition, the OSR fleet is prohibited from attaching to the Discoverer.
Condition Q.7 requires Shell to stack test the propulsion engines and the generator engines for
emissions of NOx. Condition Q.8 requires the use of fuel flow meters to track fuel usage for
these emission units, and has other monitoring requirements to assure compliance with the other
permit conditions in Section Q of the permit.
3.8 Associated Growth
The indirect activities associated with the Discoverer exploration activities are likely to include
support facilities in Wainwright or Barrow. The facilities could include storage facilities and
aircraft hangers. Shell has estimated emissions from operation of the warehouse as well as from
helicopter access to the Discoverer (Air Sciences 4/12/09). EPA has determined that permit
conditions are not necessary to address these types of activities.
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4. BEST AVAILABLE CONTROL TECHNOLOGY
4.1 BACT Applicability and Introduction
Pursuant to 40 C.F.R. § 52.21(j), a new stationary source shall apply BACT for each pollutant
subject to regulation under the Clean Air Act that it would have the potential to emit in
significant amounts. Based on the emission inventory for the project presented in Table 2-1,
NOx, PM, PM2.5, PMio, SO2, VOC and CO will be emitted in quantities exceeding their
respective significant emission rates. Therefore, BACT must be determined for each emission
unit on the Discoverer which emits NOx, PM, PM2.5,PMi0, SO2, VOC and CO while the drillship
is operating as an OCS source.
BACT is defined in 40 C.F.R. §52.21 (b)(12) in part as
an emissions limitation (including a visible emission standard) based on the maximum
degree of reduction for each pollutant subject to regulation under the Act which would be
emitted from any proposed major stationary source or major modification which the
Administrator, on a case-by-case basis, taking into account energy, environmental, and
economic impacts and other costs, determines is achievable for such source or
modification through application of production processes or available methods, systems,
and techniques, including fuel cleaning or treatment or innovative fuel combustion
techniques for control of such pollutant. In no event shall application of best available
control technology result in emissions of any pollutant which would exceed the emissions
allowed by any applicable standard under 40 C.F.R. parts 60 and 61. If the Administrator
determines that technological or economic limitations on the application of measurement
technology to a particular emissions unit would make the imposition of an emissions
standard infeasible, a design, equipment, work practice, operational standard, or
combination thereof, may be prescribed instead to satisfy the requirement for the
application of best available control technology.
The Clean Air Act contains a similar BACT definition, although the 1990 Clean Air Act
amendments added "clean fuels" after "fuel cleaning or treatment" in the above definition. 42
USC § 7479(c).
On December 1, 1987, EPA issued a memorandum describing the top-down approach for
determining BACT. 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, for each pollutant to which BACT applies:
Step 1: Identify all 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.
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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).
In the permit application, Shell applied the EPA top-down BACT methodology to groups of
similar emission units on the Discoverer. For example, there are six large diesel generators (FD-
1 to FD-6) that are identical and three diesel engine driven compressors that are identical (FD-9
to FD-11), so the BACT analysis was performed for each group of identical engines. Likewise,
there are a number of smaller diesel engines [<500 horsepower (hp)] which are similar so that the
BACT analysis can be performed for each similar group of emission units. EPA agrees that
grouping identical or similar emission units for the BACT analysis is reasonable. EPA's BACT
evaluation uses the top-down format and follows a pattern of grouping identical or similar
emission units as was done in the Shell permit application.
Throughout the BACT section PM, PM2.5 and PMi0 emissions will be addressed together for all
emission units except the incinerator since it is assumed that essentially all of the PM and PMio
emissions are also PM2.5 emissions, and the control technologies available for PM2.5 emissions
on the types of equipment aboard the Discoverer will also effectively control PM and PMi0. In
addition, the BACT analyses for VOC and CO are grouped together because the same control
technology is generally used to control both pollutants for the specific types of emission units on
the Discoverer.
4.2 S02 BACT Analysis for the Diesel IC engines, Boilers and Incinerator
Step 1 - Identify all available control technologies
Most of the SO2 emissions for this project result from combustion of diesel fuel which contains
some amount of sulfur. Sulfur contained in the material burned in the incinerator also
contributes to the SO2 emissions. The available SO2 control technologies can be grouped into
one of two categories: use of low sulfur fuels and post-combustion treatment of the exhaust gases
from the emission units. Shell searched the EPA RACT, BACT, LEAR Clearinghouse (RBLC)
and the California BACT Clearinghouse (CA-BACT) for determinations made for S02 from the
type of emission units on the Discoverer (diesel IC engines, small boilers and the incinerator).
The search results are shown in Table 4-4 of the permit application (Shell 2/23/09 Rev. App).
The most common control technologies found were "no control" or use of "low sulfur fuel." The
only post-combustion S02 control technology found was a semi-dry scrubber for an incinerator
which was much larger than the incinerator on the Discoverer. The RBLC and CA-BACT did
not have any post-combustion control technology applications for diesel IC engines, small
boilers, or small incinerators. Several other SO2 flue gas desulfurization control technologies
exist and are used on larger S02 sources, such as power plants, petroleum refineries, pulp mills
and incinerators, but are not found in practice on smaller emission units such as the boilers and
incinerator on the Discoverer.
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Step 2 - Eliminate technically infeasible control options
For technical reasons, EPA believes that post-combustion S02 control technologies are not
feasible for any of the emission units on the Discoverer, all of which are relatively small
emission units. The fact that no post-combustion controls were found in the RBLC search for
diesel IC engines, small boilers, and small incinerators indicates that such controls they have not
been found to be technically feasible or cost effective for small emission units in past
determinations. Moreover, in this case, the emission units are located on a ship with limited
space, and the ship will be located in an Arctic environment (low temperatures and limited fresh
water availability). Use of ultra-low sulfur diesel fuel (discussed below) results in very low SO2
emission rates (the table titled "Summary of Annual Emissions" for the Frontier Discoverer
Sources in Appendix A, page A-l shows less than 0.4 ton per year of SO2 for the sum of all
emission units on the Frontier Discoverer). Even if post-combustion S02 controls could be
engineered to overcome the factors described above, they could not achieve the same degree of
S02 emissions reduction as the use of ultra-low sulfur diesel fuel when compared to the use of a
higher sulfur baseline fuel. Therefore, the BACT analysis for SO2 is focused on evaluating
diesel fuels with various levels of sulfur content.
Step 3 - Rank the remaining technologies by control effectiveness
Shell identified diesel fuels with three different sulfur contents, including ultra-low sulfur diesel
with <0.0015 weight percent sulfur (<15 ppm), low sulfur diesel <0.05 weight percent sulfur
(<500 ppm) and higher sulfur diesel fuel (>500 ppm). Since the S02 emissions are directly
proportional to the sulfur content of the fuel, the fuels are rank ordered in SO2 reduction
effectiveness from the fuel with the lowest amount of sulfur to the fuel with the highest amount
of sulfur.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Shell proposed to use the lowest available sulfur content diesel fuel with a sulfur content of <15
ppm. Ultra-low sulfur diesel fuel is required by other EPA regulations for both on-road diesel
vehicles and for non-road diesel engines. Therefore, ultra-low sulfur diesel fuel is available as a
control technology for the emissions units on the Discover. Not only does ultra-low sulfur diesel
result in the lowest S02 emissions, it is necessary to allow the use of various catalytic control
devices for other pollutants such as selective catalytic reduction for NOx control, oxidation
catalysts and catalytic diesel particulate filters for particulate matter, VOC and CO control
(discussed in the sections below).
Use of <15 ppm ultra-low sulfur diesel for the emission units on the Discoverer provides a
greater than 97% reduction in S02 emissions compared to low sulfur diesel (<500 ppm). As
mentioned above, using ultra low sulfur diesel fuel, the total annual emissions of S02 from all
the emission units on the Discoverer are less than one ton per year. Because Shell proposed the
most effective control option as BACT and there is no evidence that the most effective control
option would have adverse environmental impacts, no additional evaluation is required.
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Step 5 - Select SO? BACT for the Diesel Engines. Boilers and Incinerator
Since use of ultra-low sulfur diesel fuel is the most effective control option, EPA is proposing
that BACT for S02 is the use of ultra-low sulfur diesel fuel with <0.0015 weight percent sulfur
(<15 ppm) for the emission units located on the Discoverer. The fuel sampling and test methods
for determining the sulfur content of the diesel fuel are presented in Section 4.7
4.3 NOx BACT Analysis
Step 1 - Identify all available control technologies
In general, NOx emissions are generated in the combustion process as a result of the reaction of
oxygen with nitrogen contained in the fuel or with nitrogen present in the combustion air. As
described in Section 4.2, we have determined that BACT for SO2 is the use of ultra low sulfur
diesel fuel in all combustion sources on the Discoverer. The processes used by the petroleum
refining industry to produce ultra-low sulfur diesel fuel, such as hydrotreating and
hydrocracking, remove nitrogen as well as sulfur. Since ultra-low sulfur diesel fuel contains
very little nitrogen, most of the NOx emissions from the emissions units on the Discoverer are
attributable to the reaction of oxygen with nitrogen in the combustion air, known as thermal
NOx. The concentration of thermal NOx formed is a function of the combustion temperature
with higher temperatures resulting in higher concentrations of NOx in the exhaust gas.
Shell searched the EPA RBLC and the CA-BACT for thermal NOx determinations made for
diesel IC engines >500 hp, diesel IC engines <500 hp, small boilers and the incinerator. Their
findings are summarized in Table 4-2 of the permit application. For diesel IC engines, the
control technologies include combustion modifications designed to lower the combustion
temperature and thereby lower the generation rate of NOx. These combustion modification
technologies include injection timing retard (ITR), intake air cooling (AC), high injection
pressure for the fuel (HIP) and water injection (WI). Although not listed in the RBLC or CA-
BACT, Shell also identified exhaust gas recirculation (EGR) as another diesel IC engine control
technology for NOx that has become commercially available. The RBLC also lists low NOx
design (LND) for several engines, but does not describe the actual NOx combustion control
technology. Presumably the determinations labeled LND are referring to specific combustion
chamber designs or other engine modifications that reduce NOx formation and, thus, these
designs are intrinsic to the particular model of engine associated with each RBLC determination
for LND.
Shell submitted additional information to supplement the permit application in a document by
Environ International Corp. titled "Diesel Engine Best Available control Technology Analysis"
as an attachment to an e-mail dated December 11, 2009 (Environ 12/11/09). One of the engine
modification control alternatives included in this document was a cam shaft cylinder
reengineering kit, which is available for certain engines.
Some of the combustion modification technologies for NOx control have associated negative
impacts. For example, ITR results in increased emissions of particulate matter, VOC and CO,
decreased fuel efficiency and higher soot contamination of the engine lube oil. The use of
combustion modification technologies can result in NOx emission reductions ranging from 10%
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to 50% from baseline emissions depending on the specific technology or combination of
technologies (Shell 2/23/09 Rev. App.; EPA 9/28/07 Retrofit Strategies; EPA 1995 AP-42 and
updates; MassDEP 6/08).
In 1998 EPA set new emission standards for nonroad diesel engines. The rulemaking was part of
a 3-tiered progression to lower emission standards. Each tier involves a phase in by horsepower
rating over several years. Tier 1 standards for engines over 50 horsepower were phased in from
1996 to 2000. More stringent Tier 2 standards for all engine sizes were phased in from 2001 to
2006, and yet more stringent Tier 3 standards for engines rated over 50 horsepower were phased
in from 2006 to 2008 (EPA 8/98 Nonroad Diesel). Depending on the year of manufacture, new
diesel IC engines are available that meet the EPA Tier 2 or Tier 3 emission standards. The
resulting lower NOx emission rates for diesel IC engines designed to meet the Tier 2 or Tier 3
standards are the result of the intrinsic engine design features built into them by the
manufacturer.
The only post-combustion exhaust gas treatment for NOx emissions found by the search of the
RBLC and CA-BACT for diesel IC engines was selective catalytic reduction (SCR). SCR
involves reaction of a reagent such as urea or ammonia with NOx in the presence of a catalyst to
yield elemental nitrogen. SCR systems have the capability of reducing NOx emissions by 90% or
more. Use of selective non-catalytic reduction (SNCR) has been investigated for controlling
NOx from diesel IC engines. However, because the NOx reduction reactions are highly
dependent on temperature, the NOx reduction potential of SNCR is much lower than for SCR,
and SNCR is not suited for diesel engine applications with low exhaust temperatures (Nam
2/13/02; WRAP 11/28/05).
In the December 11, 2009 supplement to the BACT analysis, Shell included two additional post-
combustion control options for NOx: Lean NOx Catalyst (LNC) also know as Hydrocarbon SCR
(HC SCR) and NOx Adsorber technology (Environ 12/11/09). LNC or HC SCR utilize a NOx
reduction catalyst and uses unburned hydrocarbons in the exhaust stream or additional diesel fuel
that is injected into the LNC device as the reducing agent to react NOx to elemental nitrogen.
LNC is usually integrated with a catalytic diesel particulate filter (discussed further in Section
4.4) to remove excess hydrocarbons by catalytic reaction to carbon dioxide and water. One
manufacture of a LNC system is Cleaire whose LONESTAR™ system for off-road applications
is designed to achieve at least 40% NOx reduction (Cleaire 2009). The California Air Resources
Board has verified the Cleaire LONESTAR™ system for certain turbo charged diesel engines
but excludes 2-stroke engines, engines with original equipment manufacturers diesel particulate
filters and engines with external EGR. NOx Adsorbers adsorb NOx by catalytically reacting NO
to N02 and reacting the N02 with a chemical coating on the catalyst matrix to form a nitrate salt.
Before the chemical coating becomes saturated, it must be regenerated using a chemical such as
hydrogen.
The search of the EPA RBLC and the CA-BACT for boilers and incinerators found
determinations based on the use of low NOx burners (LNB), EGR and SNCR.
Good combustion practice of operating and maintaining the emission units according to the
manufacturer's recommendations to maximize fuel efficiency and minimize emissions is also an
available work practice for all emission units on the Discoverer.
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As discussed above, the control option must result in an emission rate no less stringent than an
applicable NSPS emission rate, if any NSPS standard for that pollutant is applicable to the
source. 40 C.F.R. § 52.21(b)(12)(definition of BACT).
4.3.1 NOx BACT for the Generator Diesel IC Engines (FD-1 to FD-6)
Step 2 - Eliminate technically infeasible control options
Six Caterpillar D399 generator sets provide the electrical power for drilling and ship utilities on
the Discoverer (FD-1 to FD-6). Each of these generator diesel IC engines is rated at 1325 hp,
and the normal procedure is to operate the minimum number of engines needed to power the load
while keeping each operating engine at 50% capacity or greater. Since the generator diesel IC
engines are the largest engines on the Discoverer and will operate for the most hours, thereby
resulting in the largest potential uncontrolled emissions, BACT for the generator diesel IC
engines was evaluated separately from BACT for the other diesel IC engines.
The available controls for the generator diesel IC engines include ITR, AC, HIP, LND, Tier 2 or
3 controls, WI, EGR, and SCR. EPA's view is that LND, Tier 2 or 3 controls, EGR, and WI are
technically infeasible. LND and Tier 2 or 3 level controls are intrinsic to the original engine
design and are not part of the Caterpillar D399 design. EGR is not available for older model
engines such as the Caterpillar D399. WI is considered technically infeasible for a number of
reasons, the most significant being the large amount of extremely pure water required. In
general, reduction of NOx emissions by one percent requires one percent of water in the water-
fuel system. In other words, achieving a 50 percent NOx reduction requires running the engine
using a 1:1 mix of water and diesel fuel. A WI system would require water purification
equipment and storage capacity on a ship with limited space availability. Another issue with the
introduction of water in the combustion chamber is the potential for liquid water droplets to
contact the cylinder surface, which would cause an immediate disintegration of the lubrication
oil film and damage to the engine. Cold temperature environments (such as the Arctic Ocean)
are also problematic for WI systems due to the potential for freezing. For these reasons and
because of the potential engine retrofit incompatibility for the Caterpillar D399 engines, EPA
believes that WI is technically infeasible for these engines.
ITR, AC, and HIP and good combustion practice are technically feasible for this generator
engine model. SCR is technically feasible because the engines are stationary on the vessel deck
and there is adequate room to install the SCR devices.
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible control technologies for the Discoverer's generator diesel IC engines
(FD-1 to FD-6) are ranked by control effectiveness as follows:
1. SCR - 90% control (0.5 g/kW-hrNOx)
2. ITR, AC, and/or HIP - 10% to 50% control
3. Good combustion practices
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In the permit application, Shell provided several uncontrolled NOx emission rates for the
Caterpillar D399 generator engines, including actual stack test information for one of the
Caterpillar D399 generator engines (FD-1) (TRC 6/3/07). Testing was performed by TRC
Environmental Corporation on May 18 and 19, 2007 for three engine load conditions (100%,
75% and 50%). The measured NOx emission rate ranged from 5.62 g/kW-hr to 6.99 g/kW-hr,
with the lowest emission rate at 100% load. Using the lowest measured uncontrolled emission
rate of 5.62 g/kW-hr and applying the proposed and guaranteed emission rate of 0.5 g/kW-hr, the
percentage reduction in NOx emissions from applying SCR is >91%. The percentage reduction
from the higher uncontrolled emission rates would be even greater.
EPA has promulgated emission standards for non-road diesel IC engines in 40 C.F.R. § 89.112.
For engines >750 hp, the Tier 2 emission limit for NOx + non-methane hydrocarbons (NMHC) is
6.4 g/kW-hr. EPA also promulgated emission standards for new and in-use non-road
compression-ignition engines in 40 C.F.R. § 1039. Although these standards for engines >750
hp do not apply until model year 2011, the NOx emission standard for generator sets is 0.67
g/kW-hr. By comparison with these standards, the NOx emission limit of 0.5 g/kW-hr that EPA
is proposing in this permit for the generator diesel IC engines is significantly lower.
Recent permitting actions for IC engines by the Alaska Department of Environmental
Conservation have not required NOx emission limits nearly as low as the 0.5 g/kW-hr emission
limit proposed for the Discoverer generator IC engines. For example, the permit for the Nixon
Fork Mine issued August 13, 2009 included a generator engine operating at 11.1 g/kW-hr; the
permit for the Naknek Power Plant issued March 31, 2009 included a generator engine with an
emission rate of 26.0 g/kW-hr; and the Liberty Oil Project (BP) permit issued December 12,
2008 included a generator engine with an emission rate of 6.3 g/kW-hr.
Based on achieving the proposed NOx emissions limit 0.5 g/kW-hr, the maximum NOx emissions
from each Caterpillar D399 generator engine on the Discoverer would be 1.55 tons per year as
shown in Appendix A. The maximum total NOx emissions from all six generator engines would
be 9.30 tons per year.
EPA asked Shell to evaluate the use of diesel IC engine modifications such as ITR, AC or HIP in
combination with the SCR control system, since theoretically a lower inlet NOx concentration to
the SCR control system would result in a lower outlet value (EPA 4/8/09). In an email to EPA
dated April 20, 2009, Shell's environmental consultant provided a response from D.E.C. Marine
(Air Sciences 4/20/09). D.E.C. Marine stated that, although the use of engine modifications in
addition to the SCR control system would, in theory, result in a lower NOx emission rate, the
engine modifications would have collateral adverse impacts, including increased fuel
consumption, lower exhaust gas temperature and increased levels of particulate and hydrocarbon
emissions. The surface of the catalyst in the SCR (and the oxidation catalyst) systems would be
adversely affected by the higher loading of particulate matter and hydrocarbon emissions and the
lower exhaust temperature would reduce the effectiveness of the catalytic reactions in the SCR
system. D.E.C. Marine stated that "It is therefore best to optimize the engine for good
combustion and keeping the temperatures high." D.E.C. Marine also stated that use of the
SCR system is a much more effective way to reduce NOx emissions than using retrofit engine
modifications, and that the SCR system is designed with "plenty of margin to make sure we will
stay below the guaranteed level of 0.5 g/kW-hr...." EPA agrees that optimizing the engine
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combustion performance in combination with the SCR control system is a preferred strategy for
controlling NOx from the generator engines.
The use of SCR results in low concentrations of ammonia emissions that are not completely
reacted in the SCR system. The unreacted ammonia emissions are also known as ammonia slip.
In order to ensure that the ammonia slip is maintained at the minimum level commensurate with
achieving the NOx emission limit of 0.5 g/kW-hr, EPA is proposing an emission limit for
ammonia as part of the BACT emission limit for NOx from the generator engines. D.E.C.
Marine stated that the SCR system is designed so that ammonia slip is less than 10 ppm;
however, they expect that the ammonia slip will actually be less than 3 ppm because the
oxidation catalyst that follows the SCR catalyst will oxidize most of the ammonia that passes
through the SCR catalyst (Shell 2/23/09 Rev. App., Appendix F, Footnote 3, page 8). Based on
these facts, EPA believes that an ammonia emission limit representative of good performance for
the SCR and oxidation catalyst system is 5 ppm at the actual stack gas conditions.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Shell proposed that SCR represents BACT for the generator diesel IC engines because it offers
the highest NOx emissions reduction of >90%. Shell requested a technical proposal for an SCR
control system from D.E.C. Marine, a Swedish company that has been installing such control
systems on marine vessels since 1991. According to a letter from D.E.C. Marine to Shell dated
2008-10-09 (Shell 2/23/09 Rev. App., Application, Appendix F, Footnote 1, page 6), D.E.C.
Marine has installed SCR control systems on more than 70 vessels since 1991. The SCR system
D.E.C. Marine described in their technical content and offer (Shell 2/23/09 Rev. App., Appendix
F, page 195 - 209) is capable of reducing NOx emissions to as low as 0.1 g/kW-hr under ideal
steady state conditions; however, the D.E.C. Marine guarantee is 0.5 g/kW-hr because of the
continually varying operating level of the engines and the severe environmental conditions in the
Arctic Ocean.
As discussed in more detail in Step 3 above, EPA believes that an emission limit of 0.5 g/kW-hr,
in conjunction with good combustion practice and a limit on ammonia slip, represent BACT for
the generator diesel IC engines. The D.E.C. Marine SCR system uses a tuned urea injection
system where the rate of urea injection is a function of engine operating load. In addition, the
system includes a NOx exhaust analyzer that sequences through the six generator engines to
provide a direct measurement of NOx emissions once per hour for each engine. The information
from the NOx analyzer provides a means for the urea injection algorithm to be optimized over
time. Since the NOx analyzer is not used for instantaneous continuous control of the urea
injection system, periodic monitoring of NOx is appropriate. Use of a continuous NOx analyzer
on each engine would not provide any significant benefit, but would increase the analyzer
maintenance requirements and monitoring costs by a factor of six.
Step 5 - Select NOx BACT for the generator diesel IC engines
Based on the facts presented above, EPA is proposing a NOx emission limit of 0.50 g/kW-hr, in
conjunction with an ammonia emission limit of 5 ppm at actual stack gas conditions, as BACT
for the Caterpillar D399 generator diesel IC engines based on the use of SCR technology. The
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averaging time and compliance test methods for these emission limits (and the emission limits
discussed below) are presented in Section 4.8.
4.3.2 NOx BACT for the Compressor Diesel IC Engines (FD-9 to FD-11)
Step 2 - Eliminate technically infeasible control options
As discussed in Section 4.3, the available control technologies for the Discoverer's three MLC
compressor diesel IC engines (FD-9 to FD-11, 540 hp Caterpillar C-15 engines) are ITR, AC,
HIP, LND, Tier 2 or Tier 3 controls, WI, EGR, NOx adsorbers, LNC and SCR. The Caterpillar
C-15 diesel engines for the air compressors are new Tier 3 engines which incorporate the
technologies of EGR and AC into the intrinsic design of the engines to meet the Tier 3 emission
standard of 4.0 g/kW-hr for NOx + NMHC. Because these engines are designed and tuned to
meet Tier 3 standards, they are incompatible with incorporating combustion control technologies
such as ITR, AC, HIP, LND, and EGR in addition to the Tier 3 controls. EPA believes that WI
is technically infeasible due to the cold climate in which these generators will be operated, the
potential engine retrofit incompatibility, the excessive pure water requirements, limited available
space on the ship for storing the water, and the potential risk of engine damage associated with
this technology.
NOx adsorbers have been used on light duty vehicles; however, Shell stated that they are not
aware of any marine applications of this technology. Shell cites one manufacturer, Johnson
Matthey, as stating that they are just starting to look at this technology for stationary applications
and the technology is not commercially available for stationary applications (Environ 12/11/09).
EPA's Office of Transportation and Air Quality has published a summary of potential retrofit
technologies for diesel engines which includes NOx adsorbers (EPA 12/14/09 Potential Retrofit
Technologies). However, NOx adsorbers are not listed on EPA Verified Retrofit Technologies
list nor are they listed on the EPA Verified Nonroad Engine Retrofit Technologies List (EPA
12/14/09 Verified Retrofit Technologies; EPA 12/14/09 Nonroad Retrofit Technologies). Since
NOx adsorber technology is not commercially available, EPA considers this technology to be
technically infeasible for this application.
LNC has been used in retrofit applications for both on-road and nonroad diesel engines.
Example applications include backhoes, graders, loaders and back-up generators; however,
neither Shell nor EPA is aware of any marine applications of LNC. A representative of Cleaire,
a vendor of LNC technology, stated that there have been few stationary applications of their
LNC systems; and although there are no technical reasons the LNC systems would not work, the
Cleaire representative stated that their LNC technology would be more of a demonstration
project for this application and technical support during the demonstration of this technology
would be needed. Therefore, the Cleaire representative would not recommend their LNC
technology as commercial for this application (Environ 12/11/09). EPA considers this
technology to be technically infeasible for this application.
The compressor diesel IC engines are portable due to critically limited deck space on the
Discoverer. The compressor units are designed to be portable so they can be removed from the
drill ship at any time should deck space be required for other equipment or materials. However,
for operational reasons the preference is to have the compressor units on board the drill ship to
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minimize the time required to set up the units for a second MLC operation if so required. The
physical location of the compressor units on the Discoverer is shown in the photograph labeled
Figure 3-1 of the December 11, 2009 supplement to the BACT analysis (Environ 12/11/09). As
can be seen in the photograph, there is very limited space around the compressor units. Shell
provided drawings of the SCR and SCR injection control unit sized for the compressor IC
engine. The SCR catalyst unit is approximately 30 inches square and 52 inches flange to flange.
Additional space would be required for the piping to connect the SCR catalyst unit to the exhaust
pipe from the engine. In addition, the SCR injection control unit has a footprint of about 40
inches by 18 inches and a height of approximately 66 inches. The supply of urea for an SCR
system for the compressor engines would require a 1000 gallon storage tank with a deck space
requirement of approximately 6.5 by 4 feet and would need to be maintained at a temperature
above the "salt out temperature" when urea begins to precipitate from solution. Shell contends
that there is not adequate space to install the SCR equipment at the location of the compressor
units on the Discoverer and that SCR should therefore be considered technically infeasible for
this application.
The State of California typically imposes emission controls that are more stringent than the
Federal standards. The California Air Resources Board has created a voluntary Portable Engine
Registration Program (PERP), which allows owners and operators to register their portable
engines/equipment and operate them throughout the state without obtaining permits from local
air districts. The current registration requirements for 2009 and 2010 for engines between 75 and
750 bhp are that these engines must meet the Tier 3 standards. Local air districts in California
use the PERP when permitting portable engines including skid mounted engines used on
offshore platforms and drilling operations. For example, the Santa Barbara County Air Pollution
Control District, which has offshore platforms in its jurisdiction, considers engines meeting the
PERP requirements to also meet BACT requirements and does not require additional controls for
these engines (Environ 12/11/09). Portable engines such as the compressor IC engines which
meet the Tier 3 standards would meet BACT requirement without additional controls under the
PERP.
For the reasons discussed above, EPA believes that SCR is not technically feasible for portable
deck engines and has excluded SCR from further consideration in the BACT analysis for the
compressor diesel IC engines.12
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible control technologies for compressor diesel IC engines (FD-9 to FD-11)
are ranked by control effectiveness as follows:
1. Tier 3 Emission Standards of 4.0 g/kWh of NOx + NMHC
12 Although we have determinated this technology is not technically feasible, even if it were feasible and remained
in the analysis, it would be excluded from consideration in step 4 due to unreasonable control costs. Shell submitted
for a cost effectiveness analysis for SCR based on cost quotation data from Johnson Matthey, a SCR vendor, in the
December 2009 supplement to the BACT analysis (Environ 12/11/09). The cost effectiveness value calculated for
the compressor engines was greater than $34,000/ton of NOx removed, which is greater than what EPA considers
reasonable for a BACT determination.
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2. Tier 2 Emission Standards of 6.4 g/kWh of NOx + NMHC
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Since Shell proposed the most effective control option (the Tier 3 emission standards) as BACT
and there is no evidence that the most effective control option would have adverse environmental
impacts as compared to other control options, no additional evaluation is required.
Step 5 - Select NOY BACT for the compressor diesel IC engines
Based on the facts presented above, EPA is proposing that BACT for NOx from the compressor
diesel IC engines is 4.0 g/kW-hr NOx + NMHC, the Tier 3 engine standard.
4.3.3 NOx BACT for the Smaller Diesel IC Engines (FD-12 to FD-20)
Step 2 - Eliminate technically infeasible control options
The smaller diesel engines on the Discoverer include:
1. FD-12 and FD-13, HPU Engines - 250 hp Detroit 8V-71
2. FD-14 and FD-15, Cranes - 365 hp Caterpillar D343
3. FD-16 and FD-17, Cementing Units - 335 hp Detroit 8V-71N
4. FD-18, Cementing Unit - 147 hp GM 3-71
5. FD-19, Logging Unit Winch - 250 hp Caterpillar C7
6. FD-20, Logging Unit Generator - 35 hp John Deere PE4020TF270D
The available control technologies for engines under 500 hp are ITR, AC, LND, WI, cam shaft
reengineering kit, LNC, NOx adsorbers, SCR and good combustion practices. The Logging Unit
Winch engine (FD-19) has been up-graded from the engine proposed in the original permit
application to an engine (Caterpillar C7) that meets the Tier 3 engine standards. The logging
unit generator engine was also changed to a John Deere engine that meets the Tier 2 engine
standards.
As explained in Section 4.3.1, WI is considered technically infeasible due to the cold climate in
which these generators will be operated, the potential engine retrofit incompatibility, the
excessive pure water requirements, limited available space on the ship for storing the water, and
the potential risk of engine damage associated with this technology.
ITR and AC decrease the peak combustion temperature, which lowers the NOx generation rate
but can increase the exhaust gas temperature, which may in turn adversely impact exhaust valve
life and turbocharger performance. The Tier 2 and Tier 3 engines are not amenable to ITR or
AC because these engines have been optimized as part of the low NOx design of the engines.
ITR is not as effective on engines which lack electronic fuel injection such as the HPU units, the
cementing units, and the cranes. ITR and AC result in an increase in emissions of PM, CO and
VOC emissions which puts an additional load on the downstream control equipment for those
pollutants which is detrimental to the performance of the downstream control equipment. For
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these reasons EPA considers ITR and AC to be infeasible technology for any of the smaller
diesel IC engines on the Discoverer.
EGR is not feasible for retrofit on the HPU units and the cementing units because these engines
are older two-stroke engines which are not amenable to EGR. The crane engines are older
Caterpillar engines for which EGR is not available. The logging unit engines are newer Tier 2
and Tier 3 engines which incorporate EGR in the low NOx design of the engines. Therefore,
EGR is considered technically infeasible for any of the smaller IC diesel engines on the
Discoverer.
Cam shaft cylinder reengineering kits are available from Clean Cam Technology Systems
(CCTS) for older Detroit Diesel Corporation two-stroke engines such as the HPU engines and
the two larger Cementing unit engines. The CCTS retrofit kits are not available for the older
Caterpillar engines or the newer Logging unit engines. The CCTS retrofit kits are considered
technically feasible only for the HPU engines (FD-12 and FD-13) and the two larger Cementing
unit engines (FD-16 and FD-17).
NOx adsorbers have been used on light duty vehicles; however, Shell stated that they are not
aware of any marine applications of this technology. Shell cites one manufacturer, Johnson
Matthey as stating that they are just starting to look at this technology for stationary applications
and the technology is not commercially available for stationary applications (Environ 12/11/09).
EPA's Office of Transportation and Air Quality has published a summary of potential retrofit
technologies for diesel engines which includes NOx adsorbers (EPA 12/14/09 Potential Retrofit
Technologies). However, NOx adsorbers are not listed on EPA Verified Retrofit Technologies
list nor are they listed on the EPA Verified Nonroad Engine Retrofit Technologies List (EPA
12/14/09 Verified Retrofit Technologies; EPA 12/14/09 Nonroad Retrofit Technologies). Since
NOx adsorber technology is not commercially available, EPA considers this technology to be
technically infeasible for this application.
LNC has been used in retrofit applications for both on-road and nonroad diesel engines.
Example applications include backhoes, graders, loaders and back-up generators; however,
neither Shell nor EPA is aware of any marine applications of LNC. A representative of Cleaire,
a vendor of LNC technology, stated that there have been few stationary applications of their
LNC systems; and although there are no technical reasons the LNC systems would not work, the
Cleaire representative stated that their LNC technology would be more of a demonstration
project for this application and technical support during the demonstration of this technology
would be needed. Therefore, the Cleaire representative would not recommend their LNC
technology as commercial for this application (Environ 12/11/09).
There are no determinations for installing SCR on diesel engines under 500 hp in the EPA RBLC
or CA-BACT, indicating that SCR has not previously been deemed BACT for this diesel engine
category due to technical infeasibility and/or energy, environmental, and/or economic impacts.
Although SCR is proposed for the main generator sets, several issues have been identified with
applying SCR to the smaller IC engines. Whereas the generator engines will be operated in a
manner and in a location where the exhaust temperature going to the SCR can be maintained in
the appropriate range and the urea temperature will be above the "salt out temperature," the
smaller engines will operate on a more intermittent basis over a wide range of loads in locations
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more exposed to ambient temperature conditions. The following considerations have an impact
on the technical feasibility of SCR for the smaller IC engines.
1. The dynamic loading of the smaller engines with short term load swings up to 50 percent
can be expected when these engines are operated. The changing load will result in times
when the engine load is not sufficient to achieve the exhaust temperatures necessary for
optimal performance of the SCR system. Below about 400°F the NOx reduction may be
as low as 20%. Excessive ammonia slip can occur when the catalyst temperature is not in
the optimum range for the reaction between NOx and ammonia.
2. The smaller engines are located on the topside deck of the ship and exposed to the
ambient climatic conditions in the Arctic which will contribute to the difficulty of
maintaining proper temperature in the SCR catalyst. The photos in the December 11,
2009 supplement to the BACT analysis shows several of the smaller engine units in
Figures 3-1 through 3-6 (Environ 12/11/09).
3. Urea will "salt out" or precipitate from solution at lower temperatures depending on the
concentration of urea in the solution. Whether the urea is stored in local tanks at each
engine or transferred from a central storage tank, special precautions would be required to
ensure that urea did not precipitate.
4. Space on the ship is limited as shown in Figures 3-1 to 3-3 in the December 11, 2009
supplement to the BACT analysis. Several of the smaller engines are "packaged" into
enclosed skids which have little or no additional space to accommodate SCR equipment
and urea storage tanks without a total redesign of the units.
5. Shell has expressed concern that taking additional deck space for SCR equipment or for
urea storage tanks would compromise the maneuverability of equipment needed during
drilling.
For these reasons, EPA believes SCR is technically infeasible for implementation on the smaller
diesel IC engines on the Discoverer.
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible control technologies for the smaller diesel IC engines (FD-12 to FD-20)
are ranked by control effectiveness as follows:
1. Cam shaft cylinder reengineering kits
2. Good combustion practice
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
The cost of the CCTS engine retrofit cam kits varies by size of the engine, but is relatively low.
However, the cost of the kits is not the major cost of the engine rebuild. The major costs are
associated with providing the technicians and mechanics to the site to extract the engine and
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shipping the engine to and from the Discoverer and the engine shop where the retrofit kit is
installed. The cost of the kit ranges from $4000 to $7500 depending on engine size. The
additional cost for logistics and shipping was estimated by Shell to be $50,000 per engine. In the
December 11, 2009 supplement to the BACT analysis, Shell estimated the cost effectiveness for
the reengineered HPU engines to be $16,202/ton of NOx reduced and $12, 206/ton of NOx
reduced for the reengineered Cementing units (Environ 12/11/09). EPA believes that these cost
effectiveness values exceed what is reasonable to be representative of BACT for these engines.
The remaining technically feasible control option is the use of good combustion practice. Good
combustion practice for NOx control essentially consists of operating and maintaining the
engines according to the manufacturer's recommendations to maximize fuel efficiency and
minimize emissions.
Step 5 - Select NOv BACT for the smaller combustion engines
EPA proposes that BACT for NOx for all of the smaller diesel IC engines is the good combustion
practice of operating and maintaining the engines according to the manufacturer's
recommendations to maximize fuel efficiency and minimize emissions. More specifically, EPA
proposes the following good combustion practices, in addition to the emission limits set forth
below, as BACT for the engines:
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended operations and scheduled maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
EPA proposes the following NOx emission limits as representative of BACT for the smaller
diesel IC engines, as shown in Table 4-1. The emission limits shown in Table 4-1 are derived
from the emission factors or the emission rates and the engine ratings identified in Appendix A.
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Table 4-1 - NOY Emission Limits for the Smaller Diesel IC Engines
Emission Unit Number and
Engine Name
NOx Emission Limit
(g/kW-hr)
FD-12& 13, HPU Engines
13.155
FD-14 & 15, Deck Crane Engines
10.327
FD-16 & 17 Cementing Unit Engines
13.155
FD-18 Cementing Unit Engine
15.717
FD - 19 Logging Unit Winch Engine
4.0
FD-20, Logging Unit Generator Engine
7.50
4.3.4 NOx BACT for the Diesel-Fired Boilers (FD-21to FD- 22)
Step 2 - Eliminate technically infeasible control options
The Discoverer has two small diesel fueled boilers (FD-21 and FD-22) to provide heat for
domestic and work spaces. According to Shell's application, under typical operations, one boiler
will be operating and the second will be on standby, although there may be times when both
boilers operate simultaneously. The maximum heat input for each of the existing Clayton Model
200 boilers is approximately 8 million Btu per hour (MMBtu/hr). As shown in Appendix A, the
total estimated emissions of NOx from the two boilers are 6.46 tons per year.
A search of the EPA RBLC and CA-B ACT found that previous determinations for NOx control
of small boilers included no controls, lowNOx burners (LNB) and flue gas recirculation (FGR).
Literature from Clayton Industries, the manufacturer of the two boilers, states that LNB are
available only for natural gas or propane fired boilers (Shell 2/23/09 Rev. App., Appendix F,
Footnote 37, page 101), and are not available for the diesel fired boilers on the Discoverer. The
Clayton literature also states that FGR is an available option for new boilers, but that they are not
aware of any FGR retrofits to any of their existing boilers (Shell 2/23/09 Rev. App., Appendix F,
Footnote 38, page 104). There are no determinations for installing SCR on small boilers (<100
MMBtu/hr), nor is EPA aware of any instance where SCR has been installed on small boilers on
exploration vessels. The boilers on the Discoverer are located next to the engine room, which is
being expanded to accommodate the SCR systems for the generator engines. Shell states that
after installation of the SCR for the generator engines, there will be no deck space for additional
SCR units. For these reasons, EPA believes that LNB, FGR and SCR are technically infeasible
for the small boilers at issue in this specific application.
Step 3 - Rank the remaining technologies by control effectiveness
The only technically feasible NOx control option for the two boilers (FD-21 and FD-22) is good
combustion practices.
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Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Since the top control option from Step 3 (good combustion practices) is the only technically
feasible control option, this step is not required.
Step 5 - Select NOx BACT for the diesel-fired boilers
EPA proposes that BACT for NOx for the diesel-fired boilers be the good combustion practice of
operating and maintaining the engines according to the manufacturer's recommendations to
maximize fuel efficiency and minimize emissions. More specifically, EPA proposes the
following good combustion practices, in addition to the emission limits set forth below, as BACT
for the engines:
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended operation and scheduled maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
The emission limit representative of NOx BACT for the boilers is 0.20 pounds per million Btu
(lb/MMBtu). This emission limit was derived from the emission rate and boiler size information
provided in Appendix A.
4.3.5 NOx BACT for the Incinerator (FD-23)
Step 2 - Eliminate technically infeasible control options
The Discoverer has a two-stage, batch charged incinerator capable of incinerating 276 pounds
per hour of solid trash, or 6624 pounds per day; however, Shell has requested an operating
restriction to limit the maximum amount of trash burned to no more than 1300 pounds per day.
The maximum incineration capacity is rated at 3 MMBtu/hr. The use rate and batch size will be
variable depending on the waste generation rate on board the Discoverer. The only
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determination for post-combustion controls for NOx found in the EPA RBLC and CA-BACT
searches was for selective non-catalytic reduction (SNCR), although that determination was for a
much larger incinerator. Team Tec, the manufacturer of the incinerator on the Discoverer, was
not aware of any control technologies that have been installed on this model of incinerator for
control of NOx (Shell 2/23/09 Rev. App., Appendix F, Footnote 39, pages 105 to 112). Since the
heat content and the batch size charged to the incinerator will be quite variable, design of an
SNCR control system would be infeasible. Therefore, EPA believes that SNCR is technically
infeasible for this small incinerator.
Step 3 - Rank the remaining technologies by control effectiveness
The only technically feasible NOx control option for the incinerator (FD-23) is good combustion
practices.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Since the top control option from Step 3 (good combustion practices) is the only technically
feasible control option, this step is not required.
Step 5 - Select NOx BACT for the incinerator
EPA proposes that BACT for NOx for the incinerator be the good combustion practice of
operating and maintaining the engines according to the manufacturer's recommendations to
maximize fuel efficiency and minimize emissions. More specifically, EPA proposes the
following good combustion practices, in addition to the emission limits set forth below, as BACT
for the engines:
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended operation and scheduled maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
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The NOx emission limit representative of BACT for the incinerator is 5.0 pounds of NOx per ton
of waste burned which is the same as the NOx emission factor presented in the emission
inventory in Appendix A.
4.4 PM/PM10/PM2 5 BACT Analysis
Step 1 - Identify all available control technologies
PM/PM10/PM2.5 emissions (hereafter referred to as particulate matter or PM13) from diesel
engines are a complex mixture of compounds which are formed through a number of different
mechanisms. Diesel PM emissions are comprised of the soluble organic fraction (SOF), the
insoluble fraction, and the sulfate fraction. Fuel and lube oil contribute to the SOF fraction. The
insoluble fraction is primarily dry carbonaceous soot from incomplete fuel combustion. The
sulfate fraction is produced from the sulfur in diesel fuel. The available PM control technologies
for the Discoverer's engines, boilers, and incinerator were determined from searches performed
on the RBLC and the CA-BACT. The search conditions and a summary of the resulting control
technologies are provided in Table 4-5 of the Shell permit application.
The available PM combustion control technologies for diesel IC engines identified in the RBLC
and CA-BACT searches include low sulfur fuel (LSF), oxidation catalyst (OxyCat), diesel
particulate filter (DPF), Tier 2 or Tier 3 level controls, and closed crankcase ventilation (CCV),
which is sometimes referred to as positive crankcase ventilation (PCV). Although not listed in
the RBLC or CA-BACT, the combination of OxyCat and DPF, referred to as a catalytic diesel
particulate filter (CDPF), is also an available control technology for PM reduction. This list of
available control technology is consistent with the list of diesel retrofit technologies that EPA has
approved for use in engine retrofit programs (EPA 12/14/09 Verified Retrofit Technologies), and
with the control technologies discussed in the Western Regional Air Partnership "Offroad Diesel
Retrofit Guidance Document" (WRAP 11/28/05) and the Massachusetts Department of
Environmental Protection "Diesel Engine Retrofits in the Construction Industry: A How To
Guide" (MassDEP 6/08).
LSF reduces the sulfate PM fraction by limiting the amount of sulfur in the fuel that is available
for sulfate formation. As described in Section 4.2, use of ultra-low sulfur was determined to
represent BACT for S02 and has the added benefit of reducing the sulfate portion of PM
emissions from emission units burning diesel fuel. An OxyCat removes the SOF of PM through
catalytic oxidation of the combustible organic matter resulting in an overall PM control
efficiency of about 50 percent. A DPF removes the insoluble fraction of PM (soot) by filtration
with an overall PM control efficiency of 40 to 50 percent. CDPF technology removes both the
SOF and the insoluble fraction of PM with an overall PM control efficiency of about 85 percent.
According to information from CleanAIR Systems, a CDPF vendor, the CDPF must be operated
at temperatures greater than 300°C (572°F) for a certain percentage of the operating time for
proper filter regeneration when using low sulfur fuel (Shell 2/23/09 Rev. App., Appendix F,
13 As discussed above, except with respect to the incinterator, all PM and PMi0from all emission units on the
Discoverer are assumed to be PM2 5>, a conservative assumption.
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Footnote 51, page 179). Therefore, the capability to monitor temperature of the engine exhaust
gas at the inlet of the CDPF should be required for those emission units for which CDPF
technology is determined to represent BACT.
The crankcase of a combustion engine accumulates gases and oil mist called blow-by gases that
leak into the crankcase from the combustion chamber and other sources. The blow-by gases must
be vented from the crankcase to prevent damage to engine components such as seals. The blow-
by gases contains PM, which is primarily SOF, and will contribute to PM emissions if not
controlled. CCV systems were developed to remove blow-by gases from the engine and to
prevent those vapors from being expelled into the atmosphere. The CCV system does this by
directing the blow-by gases back to the intake manifold, so they can be combusted. Shell stated
that all of the diesel IC engines on the Discoverer except for the MLC Compressor engines (FD -
9 to FD-11) will be equipped with a CCV system. The MLC Compressor engines have built-in
crankcase emission control.
Regardless of the technology applied to achieve BACT, the control option must result in an
emission rate no less stringent than an applicable NSPS emission rate, if any NSPS standard for
that pollutant is applicable to the source. 40 C.F.R. § 52.21(b)(12)(definition of BACT). EPA
has promulgated exhaust emission standards for stationary IC engines under the NSPS Subpart
IIII which specifies that engine manufacturers must certify their 2007 and later engines to the
applicable emission standard for new nonroad engines in 40 C.F.R. § 89.112 (and several other
sections). 40 C.F.R. § 60.4201(a). Engines designed to meet Tier 2 or Tier 3 PM emission
standards typically employ a combination of low PM emitting engine designs and DPF or CDPF.
For diesel IC engines manufactured to meet the Tier 3 emission standards such as the three 540
hp MLC compressor engines (FD-9 to FD-11) and the 250 hp Logging Unit Winch engine (FD-
19), the applicable PM emission standard is 0.2 grams per kilowatt hour (g/kW-hr). 40 C.F.R. §
89.112(a) Table 1.
No PM control technologies were found from the search of the RBLC and CA-BACT for diesel
fired boilers less than or equal to 100 MMBtu/hr. Although not found in the previous
determinations listed in the RBLC and CA-BACT, PM control technologies such as an
electrostatic precipitator (ESP) or a fabric filter could theoretically be designed for the small
boilers on the Discoverer.
The only PM control technology for the incinerator found in the RBLC and CA-BACT search
was an ESP although it was for a much larger incinerator than the one on the Discoverer. Other
control devices such as a ceramic fabric filter, a venturi scrubber or a wet ESP could
theoretically be designed for the small incinerator on the Discoverer and were evaluated as
control options.
Good combustion practice of operating and maintaining the emission units according to the
manufacturer's recommendations to maximize fuel efficiency and minimize emissions is also an
available work practice for all emission units on the Discoverer.
4.4.1 PM BACT for the Generator Diesel IC Engines (FD-1 to FD- 6)
Step 2 - Eliminate technically infeasible control options
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The available control technologies for the Discoverer's diesel IC engines are LSF, OxyCat, DPF,
CDPF, Tier 2 or 3 level controls, and CCV. Tier 2 or Tier 3 level controls are intrinsic to the
original engine design; and, therefore, are not considered technically feasible in this case since
they are not part of the design of the existing Caterpillar D399 diesel engines.
The primary difference between an OxyCat system and a CDPF is that the OxyCat system is
constructed with an open flow catalyst matrix. In contrast, the CDPF is constructed with a
catalyst matrix where the inlet channels of the catalyst matrix are plugged at the downstream
end, forcing the exhaust gases to flow through the pores of the catalyst matrix and out the
adjacent channels, which are plugged at the inlet end of the matrix. Because of this design
difference, a CDPF achieves a higher percentage reduction of PM emissions but approximately
the same percentage reduction for VOC and CO as compared to an OxyCat system, although at
the expense of a higher pressure drop across the catalyst matrix.
The higher pressure drop of the CDPF is of concern because, as described in Section 4.3.1, the
generator diesel IC engines will be equipped with the SCR system for NOx control. The SCR
catalyst imposes a backpressure on the engines due to the pressure drop required to move the
exhaust gases through the SCR catalyst matrix. Adding the additional pressure drop associated
with a CDPF could result in an excessive backpressure on the engines. D.E.C. Marine addressed
the possibility of designing a CDPF to be used with the SCR system (Shell 2/23/09 Rev. App.,
Appendix F, Footnote 41, page 113). Since a CDPF has not been included with the vendor's
SCR systems in the past, a feasibility study would have to be conducted before final design.
Several considerations would have to be addressed including the additional cross-sectional area
needed for the CDPF catalyst matrix (perhaps as much as 50% larger than for an OxyCat
matrix), the temperature profiles to determine how well the captured soot would be oxidized in
the CDPF, the increased backpressure imposed and the manual cleaning frequency (or filter
element exchange) required to keep the backpressure within specifications. D.E.C. Marine stated
that they are not aware of any applications of CDPF systems on older heavy duty marine engines
without modern electronic controlled fuel injection. Since CDPF systems are not commercially
available in combination with SCR systems for diesel engines such as the Discoverer's generator
diesel IC engines, EPA believes CDPF systems are technically infeasible for this specific
application.14
Step 3 - Rank the remaining technologies by control effectiveness
The remaining technically feasible controls for the generator diesel engines include OxyCat, LSF
and good combustion practices for control of exhaust gas emissions. CCV or coalescing filters
are available for control of crankcase emissions.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
14 Even if a CDPF was technically feasible in this specific application, Shell estimated the cost effectiveness of a
CDPF for the generator engines and found the cost effectiveness values to be in the range of $20,000 to $30,000 per
ton of PM removed (see Appendix C of the permit application for the detailed cost calculations). This cost
effectivness value exceeds what EPA believes to be representaitve of BAC for these engines.
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The most efficient available technology is an OxyCat system with estimated removal efficiency
of 50% for PM. As discussed in Section 4.2, EPA's view is that ultra-low sulfur fuel represents
BACT for S02 control and will have the added benefit of reducing the sulfate fraction of the PM
emissions. Therefore, ultra-low sulfur fuel can be considered, in conjunction with OxyCat, as a
combination of PM control techniques. The proposed D.E.C. Marine design incorporates
oxidation catalyst downstream of the SCR catalyst in the same converter shell, which results in a
more compact and economical system than having separate devices. The OxyCat system is
expected to reduce PM emissions to <0.127 g/kW-hr.
In addition to the exhaust gases from the engine, the generator diesel IC engines produce
emissions from the crankcase, which must be ventilated to prevent pressure buildup from
combustion gases that escape around the piston rings during the combustion stroke. Installation
of CCV as a retrofit technology will eliminate crankcase PM emissions by recycling them back
to the intake manifold of the engine. (Shell 2/23/09 Rev. App., Appendix F, Footnote 47, pages
151 to 166 of the permit application.
Step 5 - Select PM BACT for the Generator Diesel IC Engines
EPA is proposing that BACT for PM from the generator diesel IC engines is 0.127 g/kW-hr
based on the use of OxyCat in combination with use of ultra-low sulfur fuel (<15 ppm).
The definition of BACT provides that if EPA 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 BACT. 40 C.F.R. § 52.21(b)(12). Since quantifying PM
emissions from crankcase ventilation is difficult and makes the imposition of an emission
standard for the crankcase ventilation infeasible, EPA proposes that BACT for crankcase
ventilation be a work practice of installing CCV systems which will eliminate any venting of
crankcase emissions to the atmosphere.
In order to detect a major failure of the oxidation catalyst, EPA is also proposing a visible
emissions (opacity) limit in addition to the particulate emission limit described above. EPA
proposes that visible emissions from the engines, excluding condensed water vapor, shall not
reduce visibility through the exhaust effluent more than 20 percent averaged over any six
consecutive minutes.
4.4.2 PM BACT for the Compressor Diesel IC Engines (FD-9 to FD-11) and the Logging
Unit Winch Engine (FD-19) (all Tier 3 Engines)
Step 2 - Eliminate technically infeasible control options
The compressor diesel IC engines and the Logging Unit Winch engine are newer and meet the
EPA Tier 3 emission standards. According to the literature describing the Caterpillar C-15
engines, part of the control technology used on the C-15 engine includes clean gas induction
which consists of a DPF and EGR (Shell 2/23/09 Rev. App, Appendix F, footnote 36, pages 94
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to 99). Therefore, the C-15 engines include the same type of diesel particulate filtration as
achieved with a CDPF. The Tier 3 standard for PM is 0.2 g/kW-hr. Additional add-on PM
control devices could be used, such as a CDPF, an OxyCat system or a DPF in series with the
integral controls on the Tier 3 engines.
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible control technologies for the compressor diesel IC engines (FD-9 to FD-
11) and the Logging Unit Winch engine (FD-19) are ranked by PM control effectiveness as
follows:
1. CDPF - 85 percent control
2. OxyCat - 50 percent control
3. DPF - 40 - 50 percent control
4. Good combustion practices
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
In the December 11, 2009 supplement to the BACT analysis, Shell included a cost effectiveness
calculation for a CDPF for the Compressor engines and the Logging Unit Winch engine (Environ
12/11/09). The calculated cost effectiveness value was $41,883/ton of PM removed for a CDPF
on a compressor engine and $90,467/ton of PM removed for a CDPF on the Logging Unit Winch
engine. Since the cost effectiveness values estimated for the CDPF on the Tier 3 engines are
much greater than $10,000/ton commonly considered high for stationary source BACT
determinations, EPA proposes that use of a CDPF does not represent BACT for the Tier 3
engines.
In the December 11, 2009 supplement to the BACT analysis, Shell included a cost effectiveness
calculation for an OxyCat system for the compressor engines and the Logging Unit Winch
engine (Environ 12/11/09). The calculated cost effectiveness value was $32,139/ton of PM
removed for an OxyCat system on a compressor engine and $55,233/ton of PM removed for an
OxyCat system on the Logging Unit Winch engine. As in the case of the CDPF discussed above,
the cost effectiveness values for an OxyCat system are higher than EPA considers reasonable for
a BACT determination.
Since the cost of a DPF is not significantly lower than for an OxyCat and the PM removal
efficiency is no greater than an OxyCat system, the cost effectiveness of a DPF on either of the
Tier 3 engines is also greater than EPA considers reasonable for a BACT determination.
The remaining technically feasible control option is the use of good combustion practices.
Step 5 - Select PM BACT for the Compressor and Logging Unit Winch IC Engines
The CDPF, OxyCat and the DPF have been eliminated from consideration for use on Tier 3
engines based on unreasonably high cost effectiveness values. EPA proposes that BACT for PM
for the compressor diesel IC engines and the Logging Unit Winch engine is that the engines meet
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the Tier 3 engine PM standard of 0.20 g/kW-hr and the use of good combustion practice for
operating and maintaining the engines according to the manufacturer's recommendations to
maximize fuel efficiency and minimize emissions. More specifically, EPA proposes the
following good combustion practices, in addition to the emission limit set forth above, as BACT
for the compressor engines and the Logging Unit Winch engine:
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended operations and scheduled maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
In order to detect a significant degradation in the performance of the PM control system inherent
to the compressor engines and the Logging Unit Winch engine, EPA is proposing a visible
emissions (opacity) limit in addition to the PM emission limit described above. EPA proposes
that visible emissions from the engines, excluding condensed water vapor, shall not reduce
visibility through the exhaust effluent more than 20 percent averaged over any six consecutive
minutes.
4.4.3 PM BACT for the Smaller Diesel IC Engines (FD-12 to FD-18 and FD-20)
Step 2 - Eliminate technically infeasible control options
The available control technologies for the Discoverer's smaller diesel IC engines are LSF,
OxyCat, DPF, CDPF, Tier 2 or 3 level controls, and CCV. Tier 2 or Tier 3 level controls are
intrinsic to the original engine design. These control technologies are not technically feasible
because they are not part of the design of the Discoverer's smaller diesel IC engines. LSF,
OxyCat, DPF, and CDPF are all considered technically feasible for the smaller diesel IC engines.
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible PM control technologies for the exhaust gases from the smaller diesel IC
engines are ranked by control effectiveness as follows:
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1. CDPF - 85 percent control
2. OxyCat - 50 percent control
3. DPF - 40 to 50 percent control
4. Good combustion practices
Ultra-low sulfur fuel is included in combination with all the above technologies in determining
the above control effectiveness.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Since Shell proposed to install CDPF, which EPA agrees is the most effective control option, on
each of the smaller diesel IC engines and there is no evidence that the most effective control
option would have adverse environmental impacts as compared to other control options, no
further analysis is required.
Step 5 - Select PM BACT for the Smaller Diesel Engines
EPA proposes that BACT for PM from the smaller diesel IC engines be an emission rate based
on the use of CDPF technology in combination with use of ultra-low sulfur fuel. The BACT
emission rate for each of the smaller diesel IC engines is shown in Table 4-2.
Table 4-2 - PM Emission Limits for the Smaller Diesel IC Engines
Emission Unit Number and Engine Name
PM Emission Limit
(g/kW-hr)
FD-12& 13, HPU Engines
0.253
FD-14 & 15, Deck Crane Engines
0.0715
FD-16 & 17, Cementing Unit Engines
0.253
FD-18 Cementing Unit
0.386
FD-20, Logging Winch Engine
0.090
As discussed in Section 4.4.1 above, since quantifying PM emissions from crankcase ventilation
is difficult and makes the imposition of an emission standard for the crankcase ventilation
infeasible, EPA proposes that BACT for crankcase ventilation be a work practice consisting of
installation of CCV for all smaller diesel IC engines except for the MLC Compressor engines
(FD 9 to FD-11) and the Logging Unit Winch Engine (FD-19), which have built-in crankcase
emission control.
According to the information from CleanAIR Systems, a CDPF vendor, the CDPF must be
operated at temperatures greater than 300°C (572°F) for a certain percentage of the operating
time for proper filter regeneration when using low sulfur fuel. Therefore, EPA proposes that the
permit include a condition requiring the permittee to monitor temperature of the engine exhaust
gas at the inlet of the CDPF.
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In order to detect a major failure of the CDPF control devices, EPA is also proposing a visible
emissions (opacity) limit in addition to the PM emission limit described above. EPA proposes
that visible emissions from the engines, excluding condensed water vapor, shall not reduce
visibility through the exhaust effluent more than 20 percent averaged over any six consecutive
minutes.
4.4.4 PM BACT for the Diesel-Fired Boilers (FD-21 to FD-22)
Step 2 - Eliminate technically infeasible control options
No PM controls were found in the RBLC or CA-BACT search for small boilers.15 Although it
may be theoretically possible to design an ESP or a fabric filter for the small boilers on the
Discoverer, one factor limiting the application of a fabric filter or an ESP on these boilers is that
more than 50 percent of the PM from diesel fired boilers is condensable PM which would not be
collected in a fabric filter or ESP at normal exhaust gas temperatures. As shown in Appendix A,
the PM emissions for each boiler are 0.38 ton per year. Based on these factors, EPA considers a
fabric filter or an ESP to be technically infeasible for control of PM from the boilers on the
Discoverer. The use of ultra-low sulfur fuel for combustion will minimize the sulfate fraction of
the PM emissions.
Step 3 - Rank the remaining technologies by control effectiveness
The only technically feasible PM control option for the two boilers (FD-21 and FD-22) is good
combustion practices.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Since the top control option from Step 3 (good combustion practices) is proposed as BACT, this
step is not required.
Step 5 - Select PM BACT for the Diesel-Fired Boilers
EPA is proposing that good combustion practices represent BACT for PM for the diesel-fired
boilers on the Discoverer. Good combustion practice for PM control essentially consists of
operating and maintaining the boilers according to the manufacturer's recommendations to
maximize fuel efficiency and minimize emissions. More specifically, EPA proposes the
following good combustion practices, in addition to the emission limit set forth below, as BACT
for the diesel-fired boilers on the Discoverer:.
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
15 These control technologies are not found in practice because of the high cost of such control technology and the
very small potential reduction in PM emissions.
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• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended operation and scheduled maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
EPA proposes that an emission limit representative of PM BACT for the boilers is 0.0235
pounds per million Btu (lb/MMBtu). This emission limit was derived from the emission rate and
boiler size information provided in Appendix A.
In order to detect a major operating problem with the boilers, EPA is also proposing a visible
emissions (opacity) limit in addition to the PM limit described above. EPA proposes that visible
emissions from the boilers, excluding condensed water vapor, shall not reduce visibility through
the exhaust effluent more than 20 percent averaged over any six consecutive minutes.
4.4.5 PM BACT for the Incinerator (FD-23)
Step 2 - Eliminate technically infeasible control options
Based on review of the RBLC and CA-BACT, the available control technologies for the
Discoverer's incinerator (FD-23) are an ESP and good combustion practices. The incinerator
listed in the RBLC with an ESP was rated at 350 tons per day (29,167 lb/hr), which is over 100
times the size of the incinerator on the Discoverer. Communication with TeamTec, the
manufacturer of the incinerator on the Discoverer, indicated that they were not aware of any
control technologies that have been installed on this model of incinerator for control of any of the
pollutants including PM (Shell 2/23/09 Rev. App., Appendix F, Footnote 39, pages 105 to 112).
By letter to EPA dated December 13, 2009, Shell provided a study conducted by GI
Development LLC to evaluate PM control options for the incinerator (Shell 12/13/09 Supp.
App.). The GI Development LLC study evaluated a dry ESP, a wet ESP, a venturi scrubber and
a ceramic fiber baghouse.
Step 3 - Rank the remaining technologies by control effectiveness
1. Ceramic fabric baghouse - 99 percent control
2. Venturi scrubber - 90 percent control
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3. Dry ESP - 75 percent control at the quoted size
4. Wet ESP - 75 percent control at the quoted size
5. Good combustion practices.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
The cost effectiveness value for the ceramic fiber baghouse based on a capital equipment cost of
$230,000 was calculated to be $65,986/ton of PM removed. The high cost effectiveness value
was due to both the high capital cost and the relatively low amount of potential PM removed
(about 0.5 ton/year). This cost effectiveness value is higher than EPA considers reasonable for a
BACT determination. Therefore, the ceramic fabric baghouse control device was eliminated
from consideration in the BACT process.
The cost effectiveness value for the venturi scrubber based on a capital equipment cost of
$150,000 was calculated to be $49,490/ton of PM removed. The high cost effectiveness value
was due to both the high capital cost and the relatively low amount of potential PM removed
(about 0.5 ton/year). This cost effectiveness value is higher than EPA considers reasonable for a
BACT determination. Therefore, the venturi scrubber control device was eliminated from
consideration in the BACT process.
Since both the dry and the wet ESP control devices have a higher capital cost ($420,000 and
$175,000 respectively) and a lower PM control percentage than the venturi scrubber, the cost
effectiveness values for either ESP is greater than for the venturi scrubber. Therefore, the dry
and wet ESP control devices were eliminated from consideration in the BACT process.
The remaining control option is good combustion practices.
Step 5 - Select PM BACT for the Incinerator
Good combustion practices are determined to represent BACT for PM for the incinerator. Good
combustion practice for PM control essentially consists of operating and maintaining the
incinerator according to the manufacturer's recommendations to maximize fuel efficiency and
minimize emissions. More specifically, good combustion practices for the incinerator consist of
the following:
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
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• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended scheduled operation and maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
In order to minimize emissions of PM, EPA proposes that the permit require that Shell develop
and implement a written waste segregation work practice plan to ensure that non-combustible
items containing heavy metals that could be volatilized and emitted from the incinerator as PM
are not introduced into the incinerator.
The PM emission limit representative of BACT for the incinerator is 8.20 pounds of PMio per
ton of waste burned and 7.00 pounds of PM2.5 per ton of waste burned. These emission limits are
identical to the emission factors presented in the emission inventory in Appendix A.
4.5 CO and VOC BACT Analysis
Technology used to control CO emissions from combustion sources, including internal
combustion engines, also provides control of volatile organic compound (VOC) emissions.
Therefore, the following BACT analysis addresses CO and VOC control in combination.
Step 1 - Identify all available control technologies
The available CO and VOC control technologies for the Discoverer's engines, boilers, and
incinerator were determined from searches performed on the RBLC and the CA-BACT. The
search conditions and a summary of the resulting control technologies are provided in Table 4-7
of the permit application. Crankcase ventilation gases from the diesel engines contain some
VOC. CCV eliminates emissions from crankcase blow-by by directing these gases back to the
intake manifold of the engine so they can be combusted.
The available CO and VOC combustion control technologies for diesel IC engines identified in
the RBLC and CA-BACT are OxyCat and Tier 2 or Tier 3 diesel engine standards. OxyCat
reduces CO/VOC emission through catalytic oxidation of these combustible gases. The OxyCat
control system proposed for the generator diesel IC engines (and discussed in the Section 4.4.1
above) will provide an overall control efficiency of 80 percent for CO and approximately 70
percent for VOC according to D.E.C. Marine, the OxyCat vendor for the Discoverer's generator
diesel IC engines (Shell 2/23/09 Rev. App., Appendix F, Footnote 1, pages 6 & 7). Diesel
engines designed to meet Tier 2 or Tier 3 emission standards typically employ a combination of
advanced combustion technology and catalytic oxidation. Although not listed in the RBLC or
CA-BACT, a CDPF reduces CO and VOC emissions through catalytic oxidation with an overall
control efficiency of 90% for both pollutants (Air Sciences 4/27/09).
Regardless of the technology applied to achieve BACT, the control option must result in an
emission rate no less stringent than an applicable NSPS emission rate, if any NSPS standard for
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that pollutant is applicable to the source. 40 C.F.R. § 52.21(b)(12)(definition of BACT). EPA
has promulgated exhaust emission standards for stationary IC engines under the NSPS Subpart
IIII which specifies that engine manufacturers must certify their 2007 and later engines to the
applicable emission standard for new nonroad engines in 40 C.F.R. § 89.112 (and several other
sections). 40C.F.R. § 60.4201(a). Engines designed to meet Tier 2 or Tier 3 PM emission
standards typically employ a combination of low PM emitting engine designs and DPF or CDPF.
For diesel IC engines manufactured to meet the Tier 3 emission standards such as the three 540
hp MLC compressor engines (FD-9 to FD-11) and the 250 hp Logging Unit Winch engine (FD-
19), the applicable CO emission standard is 3.5 grams per kilowatt hour (g/kW-hr). 40 C.F.R. §
89.112(a) Table 1. The VOC emission limit for Tier 3 engines is expressed as a combined value
with NOx (4.0 g/kW-hr).
No CO or VOC control technologies were found in the RBLC and CA-BACT searches for
diesel-fired boilers less than or equal to 100 MMBtu/hr or for incinerators, nor are any CO or
VOC control technologies found in practice for existing small boilers or incinerators. Therefore,
good combustion practice is the only available control technology for consideration in this
analysis for the diesel-fired boilers and the incinerator.
4.5.1 CO and VOC BACT for the Generator Diesel IC Engines (FD-1 to FD-6)
Step 2 - Eliminate technically infeasible control options
The available control technologies for the generator diesel IC engines are OxyCat, CDPF, Tier 2
or Tier 3 level controls, and CCV. Tier 2 or Tier 3 level controls are intrinsic to the original
engine design; and, therefore, are not considered technically feasibility since they are not part of
the design of the Discoverer's existing Caterpillar D399 diesel engines.
As discussed above in Section 4.4.1, the primary difference between an OxyCat system and a
CDPF is that the OxyCat system is constructed with an open flow catalyst matrix. In contrast,
the CDPF is constructed with a catalyst matrix where the inlet channels of the catalyst matrix are
plugged at the downstream end, forcing the exhaust gases to flow through the pores of the
catalyst matrix and out the adjacent channels, which are plugged at the inlet end of the matrix.
Because of this design difference, a CDPF achieves a higher percentage reduction of PM
emissions but approximately the same percentage reduction for VOC and CO as compared to an
OxyCat system, although at the expense of a higher pressure drop across the catalyst matrix.
As also discussed above, the higher pressure drop of the CDPF is of concern because, as
described in Section 4.3.1, the generator diesel IC engines will be equipped with the SCR system
for NOx control. The SCR catalyst imposes a backpressure on the engines due to the pressure
drop required to move the exhaust gases through the SCR catalyst matrix. Adding the additional
pressure drop associated with a CDPF could result in an excessive backpressure on the engines.
D.E.C. Marine addressed the possibility of designing a CDPF to be used with the SCR system
(Shell 2/23/09 Rev. App., Appendix F, Footnote 41, page 113). Since a CDPF has not been
included with their SCR systems in the past, a feasibility study would have to be conducted
before final design. Several considerations would have to be addressed including the additional
cross-sectional area needed for the CDPF catalyst matrix (perhaps as much as 50% larger than
for an OxyCat matrix), the temperature profiles to determine how well the captured soot would
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be oxidized in the CDPF, the increased backpressure imposed and the manual cleaning frequency
(or filter element exchange) required to keep the backpressure within specifications. D.E.C.
Marine states that they are not aware of any applications of CDPF systems on older heavy duty
marine engines without modern electronic controlled fuel injection. Since CDPF systems are not
commercially available in combination with SCR systems for diesel engines such as the
Discoverer's generator diesel IC engines, EPA believes that CDPF systems are technically
infeasible for this specific application.16
Step 3 - Rank the remaining technologies by control effectiveness
The remaining technically feasible controls for the generator diesel IC engines include OxyCat
and good combustion practices for control of exhaust gas emissions.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
The most efficient available technology is an OxyCat system with estimated control efficiency of
80% for CO and 70% for VOC. The design proposed by D.E.C. Marine incorporates oxidation
catalyst downstream of the SCR catalyst in the same converter shell, which results in a more
compact and economical system than having separate devices. The OxyCat system is expected
to reduce CO emissions to <0.179 g/kW-hr and VOC emissions to <0.0229 g/kW-hr.
In addition to the exhaust gases from the engine, the diesel generator engines produce emissions
from the crankcase, which must be vented to prevent pressure buildup from combustion gases
that escape around the piston rings during the combustion stroke. As discussed above in Section
4.4.1, EPA is proposing that CCV represents BACT for PM. Installation of CCV will also
control CO and VOC emissions by recycling them back to the intake manifold so that they can
be combusted.
Step 5 - Select CO and VOC BACT for the Generator Diesel IC Engines
EPA proposes that BACT for CO and VOC for the generator diesel IC engines is an emission
limit of 0.1790 g/kW-hr for CO and 0.0230 g/kW-hr for VOC based on the use of OxyCat
technology.
16 Even if a CDPF was technologically feasible in this specific application, Shell estimated the cost effectiveness of
a CDPF for the generator engines and found the cost effectiveness values to be in the $20,000 to $30,000 per ton of
PM removed (see Appendix C of Shell 2/23/09 Rev. App. for the detailed cost calculations). Using a similar cost
effectiveness calculation procedure, EPA estimated that the cost effectiveness value for a CDPF to control CO and
VOC was approximately $40,000 per ton of CO and VOC removed. These cost effectiveness values exceed what
EPA believes is representative of BACT for these engines.
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4.5.2 CO and VOC BACT for the Compressor Diesel IC Engines (FD- 9 to FD-11) and
the Logging Unit Winch Engine (FD-19) (all Tier 3 Engines)
Step 2 - Eliminate technically infeasible control options
Shell proposed that engines meeting the Tier 3 emission standards represent BACT. However,
there is no technical reason why add-on controls can not be considered for Tier 3 engines. The
available control technologies for the Tier 3 diesel IC engines include CDPF, OxyCat, and good
combustion practices. CCV is included as an inherent feature of the Tier 3 engines.
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible control technologies for the smaller diesel engines are ranked by control
effectiveness:
1. CDPF - 80% control for CO and VOC
2. OxyCat - 47% control for CO and VOC
3. Good combustion practices
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
On December 22, 2009, Shell submitted CO cost effectiveness calculations for CDPF and Oxy
Cat controls for the compressor engines and the Logging Unit Winch engine (Environ
212/22/09). The cost effectiveness value for a CDPF for each of the compressor engines was
calculated to be $9,848/ton of CO removed. The cost effectiveness value for an OxyCat for each
of the compressor engines was calculated to be $4,323/ton of CO removed. The cost
effectiveness values were calculated assuming the baseline emission rate was equal to the Tier 3
CO engine standard of 3.5 g/kW-hr. Since the cost effectiveness value for the CDPF was near
the high end of the range that EPA considers reasonable, the incremental cost effectiveness value
between an OxyCat and a CDPF was evaluated to determine whether the additional cost to move
from an OxyCat to a CDPF for the compressor engines was justified. The incremental cost
effectiveness value was calculated to be $17,700/ton of CO removed. Because the incremental
cost effectiveness value between an OxyCat and a CDPF is so large, EPA proposes that an
OxyCat is representative of BACT for the compressor engines.
In the December 22, 2009 analysis, the cost effectiveness values for a CDPF and an OxyCat for
the Logging Unit Winch engine were calculated (Environ 12/22/09). The cost effectiveness
value for a CDPF for the Logging Unit Winch engine was calculated to be $3,329/ton of CO
removed, a cost effectiveness value that EPA considers reasonable. Therefore, EPA proposes
that a CDPF is representative of BACT for the Logging Unit Winch engine.
Step 5 - Select CO/VOC BACT for the Compressor and Logging Unit Winch Diesel IC Engines
EPA proposes that BACT for CO from the compressor diesel IC engines is an emission limit of
1.86 g/kW-hr based on the use of an OxyCat. EPA proposes that BACT for CO from the
Logging Unit Winch diesel IC engine is an emission limit of 0.70 g/kW-hr based on the use of a
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CDPF. For these Tier 3 engines, the VOC emissions are included in determining compliance
with the NOx emission limit described in Section 4.3.2.
The use of an OxyCat on the compressor engines and a CDPF on the Logging Unit Winch
engine will concurrently reduce PM emissions by 50 percent and 85 percent, respectively.
Therefore, EPA proposes to reduce the PM emission limits for the Tier 3 engines to 0.10 g/kW-
hr for the compressor engines and 0.03 g/kW-hr for the Logging Unit Winch engine.
According to the information from CleanAIR Systems, a CDPF vendor, the CDPF must be
operated at temperatures greater than 300°C (572°F) for a certain percentage of the operating
time for proper filter regeneration using low sulfur fuel. Therefore, EPA proposes to include in
the permit a condition requiring monitoring of the temperature of the engine exhaust gas at the
inlet of the CDPF.
4.5.3 CO and VOC BACT for the Smaller Diesel IC Engines (FD-12 to FD-18 and FD-20)
Step 2 - Eliminate technically infeasible control options
The available control technologies for the smaller diesel IC engines include CDPF, OxyCat, Tier
2 or Tier 3 engine standards, CCV and good combustion practices. Tier 2 or Tier 3 engine
standards are intrinsic to the original engine design and are not technically feasible for the
smaller, existing diesel IC engines on the Discoverer.
Step 3 - Rank the remaining technologies by control effectiveness
The technically feasible control technologies for the smaller diesel engines are ranked by control
effectiveness:
1. CDPF - 90 percent control for CO and VOC
2. OxyCat - 80 percent control for CO and 70 percent control for VOC
3. Good combustion practices
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Shell proposed to use CDPF, the top control option, for all of the smaller diesel IC engines that
are not Tier 3 engines. Therefore, no further analysis is required.
Step 5 - Select CO/VOC BACT for the Smaller Diesel Engines
EPA proposes that BACT for CO and VOC is the emission limits shown in Table 4-3 below
based on the use of CDPF. The CO and VOC emissions limits are based on a 90% reduction of
uncontrolled emissions from the engines.
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Table 4-3 - CO and VOC Emission Limits for the Smaller Diesel IC Engines
Emission Unit Number and
Engine Name
VOC Emission Limit
(g/kW-hr)
CO Emission Limit
(g/kW-hr)
FD-12& 13, HPU Engines
0.20
0.40
FD-14 & 15, Deck Crane Engines
0.0640
0.220
FD-16 & 17, Cementing Unit
Engines
0.20
0.40
FD-18 Cementing Unit Engine
0.270
0.880
FD-20, Logging Unit Generator
Engine
0.750
0.550
According to the information from CleanAIR Systems, a CDPF vendor, the CDPF must be
operated at temperatures greater than 300°C (572°F) for a certain percentage of the operating
time for proper filter regeneration using low sulfur fuel. Therefore, EPA proposes to include in
the permit a condition requiring monitoring of the temperature of the engine exhaust gas at the
inlet of the CDPF.
In addition to the exhaust gases from the engine, the smaller diesel IC engines produce emissions
from the crankcase, which must be ventilated to prevent pressure buildup from combustion gases
that escape around the piston rings during the combustion stroke. EPA believes that CCV
represents BACT for PM. Installation of CCV will also control CO and VOC emissions by
recycling them back to the intake manifold so that they can be combusted.
4.5.4 CO and VOC BACT for the Diesel-Fired Boilers (FD-21 to FD-22) and the
Incinerator (FD 23)
Step 2 - Eliminate technically infeasible control options
No CO or VOC controls were found in the RBLC or CA-BACT searches for small boilers and
incinerators. As shown in Appendix A, the CO and VOC emissions for each boiler are 1.25 tons
per year and 0.02 tons per year, respectively. Similarly, the CO and VOC emissions for the
incinerator are 1.69 tons per year and 0.16 tons per year, respectively.
Step 3 - Rank the remaining technologies by control effectiveness
The only technically feasible CO and VOC control option for the two boilers (FD-21 and FD-22)
and the incinerator (FD-23) is good combustion practices.
Step 4 - Evaluate the most effective control based on a case-bv-case consideration of energy,
environmental and economic impacts
Since the only control option from Step 3 (good combustion practices) is proposed as BACT, this
step is not required.
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Step 5 - Select CO and VOC BACT for the Diesel-Fired Boilers and the Incinerator
EPA proposes that good combustion practices represent BACT for CO and VOC for the diesel-
fired boilers and the incinerator. Good combustion practice for CO and VOC control essentially
consists of operating and maintaining the boilers and the incinerator according to the
manufacturer's recommendations to maximize fuel efficiency and minimize emissions. More
specifically, good combustion practices for the boilers and the incinerator consist of the
following:
• Operating personnel must be trained to identify signs of improper operation and
maintenance, including visible plumes, and instructed to report these to the maintenance
specialist,
• At least one full-time equipment maintenance specialist must be on board at all times
during drilling activities,
• Each emission unit must be inspected by the maintenance specialist at least once a week
for proper operation and maintenance consistent with the manufacturer's
recommendations,
• The operation and maintenance manual provided by the manufacturer for each emission
unit must be maintained on board the Discoverer at all times,
• The manufacturer's recommended operation and scheduled maintenance procedures
must be followed for each emission unit.
EPA proposes that the permit include a condition requiring the permittee to follow the good
combustion practices listed above.
EPA proposes that the emission limits shown in Table 4-4 below are representative of CO and
VOC BACT for the boilers and the incinerator. The emission limits for the boilers are derived
from the emission rate and boiler capacity information in the emission inventory in Appendix A.
The emission limits for the incinerator are identical to the emission factors for the incinerator
from the emission inventory in Appendix A.
Table 4-4 - CO and VOC Emission Limits for the Boilers and the Incinerator
Emission Unit
VOC Emission Limit
CO Emission Limit
Boilers (FD-21 & 22)
0.00140 lb/MMBtu
0.0770 lb/MMBtu
Incinerator (FD-23
3.0 lb/ton of waste burned
31.0 lb/ton of waste burned
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4.6 BACT for the Drilling Mud De-gassing Operation (FD-32)
In the letter to EPA dated December 13, 2009, Shell provided additional explanation for the
VOC estimate from de-gassing of drilling mud that was originally provided in its May 4, 2009
submission to EPA (Shell 12/13/09 Supp. App.). The VOC emission estimate based on the
possibility of drilling a maximum of four wells per year was 128 pounds of VOC per year.
Drilling mud is used to lubricate and carry away heat from the drill bit and to transport drill
cuttings to the surface. When the drill passes through a hydrocarbon zone, hydrocarbons in the
drill cuttings are carried to the surface (the deck of the Discoverer) with the mud. The mud is
directed to the "ditch", then the shakers and then to the mud pit. These pieces of equipment are
exposed to the atmosphere and any trapped gases such as hydrocarbons, water vapor or carbon
dioxide flash out of the mud. If high concentrations of hydrocarbons from the mud are detected,
the mud it diverted to a mud separator where gases flashed from the mud are directed through a
10 inch diameter pipe and vented at the top of the drilling derrick as a safety precaution to
prevent exposure to workers and to keep the potentially explosive gases away from ignition
sources.
To control all VOC emissions from mud degassing, the mud-handling system would need to be
redesigned to collect gas from both the open mud processing areas and from the mud gas
separator. The gas collection system would need to be designed to handle a gas volumetric flow
rate up to 500 cubic feet per minute associated with emergency and unexpected releases, but
normally would process very small gas flows. With such a variable flow rate, condensers,
carbon adsorption or routing the gases to the air intake of an on-board combustion device would
not be technically feasible. A flare is the only VOC control device that is capable of handling
this type of gas service.
In Attachment D of the December 13, 2009 letter to EPA, Shell provided cost information for a
flare based on information from the EPA Air Pollution Cost Control Manual (Shell 12/13/09
Supp. App). The annualized cost for a small flare (2 inch diameter nozzle) from Table 2.13 of the
EPA Air Pollution Cost Control Manual was $61,800. This annualized cost value is likely an
underestimate of the cost as applied to Shell's operation since it was for an on-land flare which is
less expensive to construct compared to an on-ship flare system and was based on 2002 dollars.
However, using the annualized cost of $61,800, the cost effectiveness value for controlling 128
pounds of VOC per year was calculated to be $965,625/ton of VOC removed (assuming 100
percent destruction of the VOC in the flare). A cost effectiveness value of this magnitude is
much higher than EPA considers reasonable for a BACT determination. Therefore, EPA
proposes that BACT for the mud de-gassing operation on the Discoverer is the use of the existing
equipment.
4.7 BACT for the Supply Vessel at Discoverer (FD-31)
Aside from the supply vessel, the vessels in the Associated Fleet will not be physically attached
to the Discover, and therefore will not be part of the OCS source and not subject to the BACT
requirement. The supply vessel will be part of the OCS source and thus subject to BACT only
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for the relatively short period of time it will be tied to the Discoverer. Shell estimated a
maximum of eight resupply events per year. When the supplies are delivered to the Discoverer,
the supply vessel would be attached to the Discoverer for a maximum of 12 hours with one
generator diesel engine of less than 300 horsepower operating. The maximum time a supply
vessel would be attached to the Discoverer and thus considered part of the "OCS source" would
be 96 hours for the drilling season. The estimated emissions from the supply vessel while tied to
the Discoverer based on the maximum time of 96 hours are shown in Appendix A. The largest
value is 0.43 tons per year for NOx. The estimated emissions in units of tons per year for all
other pollutants are smaller: 0.09 for CO; 0.03 for PM; 0.03 for VOC; and 0.0002 for SO2.
Because of the very small emission reduction potential and the short time period over which any
control technology would be amortized, EPA believes that installation of any additional control
technology on the supply vessels would not be cost effective. In the December 11, 2009
supplement to the BACT analysis, Shell provided cost effectiveness calculations for several
control alternatives that could be applied to the generator engine on the supply vessel (Environ
12/11/09). In all cases the calculated cost effectiveness values were much greater than EPA
considers reasonable for BACT determinations. For example, the calculated cost effectiveness
values for the supply vessel generator engine were approximately: $187,000/ton of PM for a
CDPF; $114,000/ton of PM for an OxyCat; and $228,000/ton of PM for a DPF. These cost
effectiveness values are much greater that EPA considers reasonable within the context of a
BACT determination. Thus, EPA proposes that BACT for the supply vessel is no additional
add-on controls. Shell has agreed, and the permit proposes, that Shell use ultra-low sulfur diesel
fuel in all vessels in the Associated Fleet, including the supply vessel to assure attainment of the
NAAQS and compliance with increment.
4.8 Reference Test Methods
This section describes the reference test methods EPA is proposing for the emission limits
discussed above.
EPA is proposing that BACT for SO2 is the use of ultra-low sulfur diesel fuel (<0.0015% by
weight). A representative fuel sample for sulfur analysis must be collected by one of the
methods identified in 40 C.F.R. § 80.330(b). Any test method for determining the sulfur content
of diesel fuel must satisfy the EPA approval process contained in 40 C.F.R. § 80.585(a) and the
precision and accuracy requirements of 40 C.F.R. § 80.584. As an alternative, the sulfur content
of the diesel fuel may be determined using ASTM D 5453-09. The permit specifies the frequency
of the required testing, which is discussed in Section 3. The testing requirement can also be met
by obtaining a certification from the fuel supplier that the fuel meets the sulfur specification
based on testing using the methods described above.
EPA proposes that all other emission limits be based on the average of three one hour test runs,
with the arithmetic average of the three runs compared to the applicable emission limit.
NOx emissions shall be measured using EPA Method 7E. EPA Method 7E is the performance
test method required by a number of EPA NSPS for sources similar to those on the Discoverer
such as steam generating units, gas turbines and large stationary IC engines.
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CO shall be measured using EPA Method 10. EPA Method 10 is the performance test method
required by the EPA NSPS for petroleum refinery fluid catalytic cracking units which typically
include a boiler fueled by off-gas containing CO.
Ammonia emissions shall be measured using Conditional Test Method 027 (CTM-027) or CTM-
038.
Except for the incinerator, PM2.5. PMi0 and PM2.5 emissions shall be measured using EPA
Method 201/201A and Other Test Method 28 (OTM 28). Once proposed revisions to EPA
Method 202 are finalized, see 56 Fed. Reg. 12970 (March 25, 2009), the permit requires the use
of EPA Method 202 in place of OTM 28 to measure condensable particulate matter.
For the incinerator only, PM25 emissions shall be measured using OTM 27 and OTM 28 until
EPA finalizes the pending revisions proposed in 56 Fed. Reg. 12970 (March 25, 2009), at which
time PM2 5 emissions from the incinerator will be measured using the revised EPA Methods
201/201A and 202.
For opacity standards, EPA is proposing EPA Method 9 (40 C.F.R. Part 60, Appendix A) as the
reference test method for opacity standards with numerical limits for point sources, with an
averaging period of six minutes and an observation interval of 15 seconds.
EPA Methods 1, 2, 3 A, 3B, 4 and 19 shall be used as needed to convert the measured NOx, PM,
PMio, PM2.5 and CO emissions into units of the emission limits in the permit. The EPA Methods
identified in this section can be found in 40 C.F.R. Part 60, Appendix A, in 40 C.F.R. Part 51,
Appendix M or on the EPA Emission Measurement Center webpage
http://www.epa.gov/ttn/emc/. Permit Condition B.7.11 contains procedures for Shell to request
and for EPA to approve alternatives to or deviations from the referenced test methods.
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5. AIR QUALITY IMPACT ANALYSIS
5.1 Required Analyses
The PSD rules and implementing guidance require the permit applicant to demonstrate that, for
all criteria air pollutants that would be emitted in excess of the significance thresholds at 40
C.F.R. § 52.21(b)(23)(i), the allowable emission increases (including secondary emissions) from
a proposed new major stationary source, in conjunction with all other applicable emission
increases or reductions at the source, would not cause or contribute to a violation of any NAAQS
nor cause or contribute to a violation of any applicable "maximum allowable increase" over the
baseline concentration in any area. The analysis must be based on air quality models, data bases,
and other requirements specified in 40 C.F.R. 51, Appendix W, Guideline on Air Quality
Models. The ambient air quality impact analyses for Shell's exploration drilling program are
different from most that are received and reviewed by EPA in that (1) exploratory drilling
operations will occur on the outer continental shelf (OCS) in the Chukchi Sea, (2) drilling will
occur at different lease blocks in Lease Sale Area 193, and (3) combustion units are on board
stationary and moving vessels.
As discussed in Section 2.2 above, the PSD requirements apply to emissions of CO, NOx, PM,
PM25, PMio, SO2 and VOC from Shell's exploratory drilling program. Of these pollutants,
NAAQS have been promulgated for CO, NO2 (for NOX), PM2.5 (including precursors SO2 and
NOx), PM10, SO2 and ozone (represented by precursors VOC and NOx).
The "maximum allowable increases," also known as PSD increments, are listed in 40 C.F.R. §
52.21(c). There are PSD Class I, II and III increments applicable to areas designated Class I, II
and III. Class I areas are defined in 40 C.F.R. § 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.
Class II areas are defined in 40 C.F.R. § 52.21(g). These are defined as all areas not designated
Class I, except for any areas redesignated from Class II to Class I or Class III. As discussed
below, the area covered by Shell's leases in Lease Sale 193 is a Class II area. See CAA Section
162(b). No areas have been redesignated to Class III that might be impacted by this project. The
NAAQS and PSD Class I and II increments are listed in the Table 5-1.
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Table 5-1 - Ambient Air Quality Standards, Air Quality Increments, and Impact Area and
Monitoring Thresholds
Air Pollutant
Averaging
Period
Air Quality Standards a
Air Quality
Increments b
Significant
Impactc
(Hg/m3)
Ambient
Monitoring
b
(Hg/m3)
Primary
(Hg/m3)
Secondary
(Hg/m3)
Class I
Area
(Hg/m3)
Class II
Area
(Hg/m3)
Sulfur Dioxide (S02)
3-Hour
1300
25
512
25
24-Hour
365
5
91
5
13
Annual
80
2
20
1
Nitrogen Dioxide
(N02)
Annual
100
100
2.5
25
1
14
Carbon Monoxide
(CO)
1-Hour
40000
2000
8-Hour
10000
500
575
Particulate Matter
equal to or less than 10
microns (PMi0)
24-Hour
150
150
8
30
5
10
Annual
4
17
1
Particulate matter
equal to or less than
2.5 microns (PM25)
24-Hour
35
35
Annual
15
15
Lead (Pb)
Rolling 3-
Month
0.15
0.15
Quarterly
Average
1.5
1.5
0.1
Ozone (03)
1-Hour
0.12 d
0.12 d
e
8-Hourf
0.75 d
0.75 d
8-Hour8
0.80 d
0.80 d
Fluorides
24-Hour
0.25
Total Reduced Sulfur
1-Hour
10
Hydrogen Sulfide
(H2S)
1-Hour
0.2
Reduced Sulfur
Compounds
1-Hour
10
a. Reference: 40 C.F.R. Part 50
b. Reference: 40 C.F.R. Part 52.21(c)
c. Reference: EPA 5/87 Ambient Monitoring Guidelines; EPA 10/90 Draft NSR Manual
d. Units in parts per million (ppm)
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e. No monitoring threshold level. However, if the net emissions increase of N02 or VOC is 100
tons per year or more, the PSD regulation requires an ambient air quality impact analysis
including an ozone data collection program. 40 C.F.R. § 52.21(i)(5).
f. 2008 standard
g. 1997 standard
40 C.F.R. § 52.21(m) requires a PSD permit application to include an air quality analysis in
connection with the demonstration required by 40 C.F.R. § 52.21(k). For each pollutant for
which aNAAQS or PSD increment exists, 40 C.F.R. § 52.21(m)(l)(iv) requires the analysis to
include at least one year of pre-construction ambient air quality monitoring data, unless EPA
approves a shorter monitoring period (not less than four months). 40 C.F.R. § 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 impact less than the ambient monitoring thresholds listed in 40 C.F.R. § 52.21 (i)(5)(i),
which are also listed in Table 5-1. For each pollutant for which no NAAQS has been
established, 40 C.F.R. § 52.21(m)(l)(ii) allows EPA to require monitoring as determined to be
necessary to assess ambient air quality for that pollutant in the area. In addition, 40 C.F.R. §
52.21(m)(2) authorizes EPA to require post-construction ambient air quality monitoring if EPA
determines it is necessary to determine the effect that emissions from the source or modification
may have on air quality.
40 C.F.R. § 52.21(o) requires additional impact analyses, which must include an analysis of the
impairment to visibility, soils and vegetation that would occur as a result of the proposed source
or modification, or that would occur as a result of any commercial, residential, industrial and
other growth associated with the source or modification. Analysis for vegetation having no
significant commercial or recreational value is not required.
For sources impacting Federal Class I areas, 40 C.F.R.§ 52.21(p) requires EPA to consider any
demonstration by the Federal Land Manager that emissions from the proposed source
modification would have an adverse impact on air quality related values, including visibility
impairment. If EPA concurs with the demonstration, the rules require that EPA shall not issue
the PSD permit.
5.2 NAAQS and Increment Analysis
The air quality analysis for NAAQS and increment compliance for Shell's exploratory drilling
program was conducted in two basic stages. First, Shell conducted a screening analysis to
determine the pollutants for which the project exceeded the significant impact levels and for
which a more robust air quality demonstration would be required. EPA guidance calls for a
more detailed air quality analysis if the emission rate is significant, and the predicted maximum
concentration of the specific air pollutant is greater than the applicable significant impact level,
which are set forth in Table 5-1 (EPA 5/87 Ambient Monitoring Guidelines; EPA 10/90 Draft
NSR Manual). As shown in Table 5-2, the highest concentration impact from the Discoverer and
the Associated Fleet predicted by the screening analysis for the applicable averaging time
exceeded the significant impact levels for SO2, NO2, and PMi0. As a result, a detailed ambient
air quality impact analysis is required for these three air pollutants. An air quality analysis is
also required for ozone because NO2 and VOC emissions exceed 100 tons per year. See 40
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C.F.R. § 52.21(i)(5). In addition, because EPA has not promulgated a PM2.5 significant impact
level, a NAAQS analysis is required for this air pollutant.
5.2.1 Significant Impact Radii
The significant impact levels are also used to determine the significant impact area radii. The
radius is the farthest distance from a stationary source or major modification in which the
concentration predicted by an EPA-accepted model exceeds its significant impact level. EPA
guidance limits the radius to 50-kilometers. 40 C.F.R. Part 51, Appendix W. In this case, the 24-
hour S02 and PM10, and annual N02 significant impact area radius was set to 50-kilometers
because the model predictions had not fallen below the threshold for these three air pollutants at
this distance. Figure 5-1 shows the significant impact areas for the Shell Chukchi Sea OCS
leases.
Table 5-2 - Class II Area Significant Impact Levels and Radius
Air Pollutant
Averaging
Time
Predicted
(|ig/m3)
Level
(|ig/m3)
Percent
SIA Radius a
(km)
Sulfur Dioxide (S02)
3-Hour
74.00
25.00
296.00
18.80
24-Hour
28.00
5
560.00
50.00
Annual
2.10
1
210.00
8.70
Nitrogen Dioxide (N02)
Annual
20.80
1
2080.00
50.00
Carbon Monoxide (CO)
1-Hour
391.20
2000
19.56
NA
8-Hour
352.00
500
70.40
NA
Particulate Matter equal to or
less than 10 microns (PMi0)
24-Hour
28.20
5
564.00
50.00
Annual
1.90
1
190.00
14.40
Particulate Matter equal to or
less than 2.5 microns (PM2 5)
24-Hour
b
Annual
b
Ozone (03)
c
Reference: Shell 5/29/09 Supp. App.
NA e= Not Applicable.
a. The significant impact area radius is the furthest modeled distance in which there is a significant impact, or
a maximum radius of 50-kilometers.
b. Because EPA has not promulgated PM2.5 significant impact levels, a NAAQS analysis is required for this
air pollutant.
c. The net emissions increase of NOx and VOC emissions exceed 100 tons per year. As a result, Shell is
required to conduct an ozone analysis, including data collection. See Section 3 and Appendix A for
emission calculations.
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Figure 5-1 - Chukchi Sea PCS Leases and Significant Impact Areas
8g Boundary
Aaska Seaward Bounda-y
Lakes and Risers
IBCAO EMiymstryCm)
j OCS Protractbn D'agrams
| Shell OCS Lease
| Aiministraive Boundaries
| /laska Coastline
0 25 SO
Shell Chukchi Sea OCS Leases with 50Km Buffer
Datum: NAD27
Projection: /&Jaska Albers
Soirees:
MapMakers Alaska
OMIA.Q
Atqasuk
5.2.2 Baseline Area, Baseline Date, and Trigger Date
For sources locating on the OCS more than 25 miles from the State's seaward boundary, EPA
considers the "baseline area" for purposes of 40 C.F.R. § 52.21 to be the area bounded on the
shoreward side by a parallel line 25 miles from the State's seaward boundary; on the seaward
side by the boundary of U.S. territorial waters; and on the other two sides by the seaward
extension of the onshore Air Quality Control Region (AQCR) boundaries (EPA 7/2/09 Baseline
Memo).
Hence, that portion of the Chukchi Sea and Beaufort Sea meeting the above definition is one
single baseline area. The "major stationary source baseline date," as defined in 40 C.F.R.
§ 52.21 (b)(14)(i), and the trigger dates for SO2, NO2, and PM10 for this baseline area are shown
in Table 5.3 below.
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Table 5.3 - Major Source Baseline Dates
Air Pollutant
Major Stationary Source
Trigger Date
Sulfur Dioxide
June 5, 1975
August 7, 1977
Nitrogen Dioxide
February 8, 1988
February 8, 2008
Particulate Matter
June 5, 1975
August 7, 1977
The minor source baseline date is established in an area when the first complete PSD application
is submitted to EPA after the trigger date. See 40 C.F.R. § 52.21(b)(14)(i). EPA deemed the
Shell OCS/PSD application for exploratory drilling in the Chukchi Sea complete on July 31,
2009 (EPA 7/31/09 Completeness Letter), which effectively establishes July 31, 2009 as the
minor source baseline date for S02, N02, and PMi0 in the Chukchi Sea/Beaufort Sea baseline
area. As a result, Shell is required to consider increment consuming emissions increases and
decreases after July 31, 2009 from other sources in the area in its analysis of compliance with air
quality increments. In this case, however, there are no existing major or minor stationary sources
in any of the applicable air pollutant significant impact areas impacted by this permitting action.
Because this is the first complete PSD permit application that has been submitted in the baseline
area and there are no existing sources, Shell only needs to address its own emissions in
conducting the air quality impact analysis. See 40 C.F.R. § 52.21(b)(13), 40 C.F.R. §
52.21(k)(l) and EPA 10/90 Draft NSR Manual.
As discussed in section 5.2.4 below, Shell anticipates constructing a warehouse which would
have an oil fired heater in the existing Northern Alaska Intrastate AQCR. The permitting of this
source is the responsibility of the Alaska Department of Environmental Conservation since it is
not an OCS source. Nevertheless, the minor source baseline dates have been triggered in this
AQCR as shown in Table 5.4 below (Schuler 7/2/09).
Table 5.4 - Minor Source Baseline Date
Air Pollutant
Minor Source Baseline Date
Sulfur Dioxide
June 1, 1979
Nitrogen Dioxide
February 8, 1988
Particulate Matter
November 13, 1978
5.2.3 Air Quality Model
In its air quality analysis, Shell used a non-guideline model called ISC3-Prime (EPA 2004 ISC3-
Prime) in order to better predict the maximum concentration immediately downwind of the hulls
of the vessels. The ISC3-Prime model has been evaluated under Arctic conditions (EPA 6/03
AERMOD). In the absence of the site-specific, over-ocean meteorological data necessary to run
other models, EPA believes ISC3-Prime is an appropriate model for determining the air quality
impacts from the Discoverer and the Associated Fleet in Arctic conditions and approved the use
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of ISC3-Prime pursuant to Section 3.2 in 40 C.F.R. Part 51, Appendix W for use in evaluating
Shell's permit application and air impact analysis. As provided in 40 C.F.R. § 52.21(1)(2), EPA
is requesting public comment on the suitability of use of the ISC3-Prime model in the ambient
air quality impact analysis for this permitting action.
5.2.4 Modeled Operating Scenarios
Working with Shell, EPA identified two primary operating scenarios (with two alternatives to
one of the primary operating scenarios) and eleven secondary operating scenarios to analyze in
determining air quality impacts (summarized in Table 5-5).17 EPA believes these scenarios are
representative of the drilling operations Shell will be conducting in the Chukchi Sea during the
July to December drill season (Shell 12/18/08 App; Shell 2/23/09 Rev. App.; Shell 5/29/09 Supp.
App; Shell 9/17/09 Comments). The two primary operating scenarios are the continuous over
water operation of the Discoverer and the Associated Fleet at lease blocks in Lease Sale 193
(POS #1) and the continuous over land operation of an oil fired heater located in a warehouse at
an undermined site on-shore (POS #2). The two alternatives to the first primary operating
scenario involve different levels of usage of the Discoverer incinerator and HPU units.
Secondary operating scenarios (SOS #1 to #11) basically consist of intermittent, concurrent
operations of the Associated Fleet with the Discoverer or operations independent from the
Discoverer. The inventory of emissions allowed under the permit from the emission units on the
Discoverer and the Associated Fleet were used as inputs in modeling the various scenarios.
Since these operations occur over water and in an area lacking any significant industrial and
commercial activities or development, the areas are considered rural for dispersion modeling
purposes. Auer 1978. The modeling analysis used actual dimensions of the structures that cause
wake effects, which is a more conservative modeling approach.
17 Shell submitted modeling analyses in support of the August 2009 proposed permit, and provided a supplemental
analysis of POS# 1 and two alterantives to POS#l on September 17, 2009 (Shell 9/17/09 Comments).
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Table 5-5 - Primary and Secondary Operating Scenarios
Operating Scenario
No.
Description
Primary
1
Drilling by the Discoverer, and deployment of the ice breaker and oil spill
response fleets (including two alternatives)
2
Associated Growth (land based combustion source).
Secondary
1
Discoverer bow ice removal by Ice Breaker #2 concurrent with POS # 1.
2
Supply ship transit concurrent with POS # 1.
3
Discoverer replenishment by supply ship concurrent with POS # 1.
4
Discoverer emergency generator testing concurrent with POS # 1.
5
Anchor deployment by Ice Breaker #2 and no drilling activities.
6
Anchor retrieval by Ice Breaker #2 and no drilling activities.
7
Discoverer alignment concurrent with POS # 1.
8
Helicopter support concurrent with POS # 1.
9
Multi year ice breaking concurrent with POS # 1.
10
No ice breaking concurrent with POS # 1.
11
No replenishment concurrent with POS # 1.
Reference: (Shell 12/18/08 App; Shell 2/23/09 Rev. App.; Shell 5/29/09 Supp. App; Shell 9/17/09 Comments).
POS = Primary Operating Scenario
The operating scenarios have been evaluated either quantitatively or qualitatively. POS #1 and
#2 have been evaluated quantitatively. Since SOS #1 to #4 will operate during drilling
operations, the scenarios have also been evaluated quantitatively. SOS #5 and #6 will operate
independent of POS #1 and have been quantitatively analyzed to confirm that their operations
would not exceed 24-hour PM2.5 NAAQS. The remaining five SOS's have been evaluated
qualitatively as described below.
SOS #7. Power to realign the Discoverer bow into the prevailing wind direction
will come from generators that are already operating as a result of drilling
operations. The occurrence of realignment should not increase the drill ship
generator emission rates under POS #1. (Environ 6/26/09).
SOS #8. Besides providing lift, the helicopter horizontal rotor(s) also provide a
mechanism to immediately disperse emissions generated by its engine. Emissions
from the helicopters are not expected to have a significant impact in its area of
operation.
SOS #9. The ice breaker fleet will operate under the same mode as first year ice
to crush multi year ice. Hence, the crushing of multi year ice should not increase
vessel emission rates under POS #1.
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SOS #10. When the ice breaker fleet services are not needed, it will locate at least
25 miles away from the Discoverer. At this distance, the ice breaker vessel
emissions are not considered to be emissions from an OCS source (See 40 C.F.R.
§ 55.2).
SOS #11. Like SOS #10, the supply ship will locate at least 25 miles away from
the drilling operations when it is not replenishing the Discoverer. At this
distance, the emissions from the supply ship are not considered to be emissions
from an OCS source (40 C.F.R. § 55.2).
To determine compliance quantitatively, the calculated significant emission rates associated with
eight operating scenarios were modeled and the predicted concentration impacts of the air
pollutants are compared to the NAAQS, PSD air quality increments, significant impact levels
and/or ambient monitoring thresholds as shown in Table 5-1.
Importantly, only the POS #1 and its two alternatives have been re-modeled to reflect the
significant emission reductions and other changes made to the proposed project since the August
2009 proposed permit (Shell 9/17/09 Comments). As discussed above S02 emissions have been
reduced by 99%, PMio and PM2.5 emissions have been reduced by more than 70%, NOx
emissions have been reduced by 40%, VOC emissions have been reduced by 47%, and CO
emissions have been reduced by 41%. POS #2 has not been remodeled since it has not changed,
nor have SOS #1 through #6 been remodeled to reflect the emission reductions and changes to
the project. Since the original modeling of POS #2 and SOS # 1 through #6 showed that
NAAQS and increments would be met, and with the 40% reduction in NOx emissions and over
70%) reduction in PM10 and PM2.5 emissions, EPA expects that remodeling these scenarios with
the new lower emission rates would continue to confirm that NAAQS and increments would be
met. Tables 5-15 and 5-16 show the original modeling results for POS #2 with the most recent
background levels, and Appendix B shows the original modeling results for SOS #1 through #6,
adjusted for the changes to the impact of POS #1, with the most recent background levels. These
adjustments produce reasonable estimates of the predicted concentrations that re-modeling these
scenarios would produce.
5.2.5 Modeling Methodology
To quantitatively evaluate the operating scenarios detailed in Section A, Shell employed the non-
guideline ISC3-Prime model (EPA 8/26/04 ISC3-Prime). The assumptions, procedures,
emission rates, source types, and stack parameters associated with each modeled operating
scenario are discussed in the below subsections. Furthermore, to model the majority of the
scenarios by air pollutant in a single model run, Shell modified the ISC3-Prime source code to
accept at least 1318 emission sources, 20000 receptors points, and 30 source groups (Air
Sciences 7/7/09).
EPA requires verification that the predicted concentrations are not affected by code changes. To
accomplish the verification, Shell downloaded the test case files that are available from the EPA
SCRAM web site. Shell then ran its modified version of ISC3-Prime using the test case input
file. When the EPA test case output file predicted concentrations are compared to the Shell
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modified model output file predicted concentrations, the results are equivalent out to the third
decimal point (Shell 5/29/09 Supp. App.). Thus, the verification is sufficient.
In its review of Shell's previous modeling, EPA independently verified the maximum predicted
model concentration impacts contained in the Shell supplemental revisions (Shell 5/29/09 Supp.
App.) and emails (Environ 6/23/09-Emissions; Environ 6/23/090-Modeling). EPA downloaded
the ISC3-Prime model from the SCRAM web site as well and modified the number of emission
sources from 300 to 1500; the number of receptor points from 1200 to 25000; and the number of
source groups from six to ten. This EPA version of the model was run for ten cases to obtain
final concentration impacts for POS #1, ten cases to obtain final concentration impacts for the ice
breaker fleet, one case for PMio maximum predicted concentration impact during Discoverer
bow ice removal, and two cases for PM2.5 maximum predicted concentration impacts during bow
ice removal and anchor handling. The EPA and Shell modeled SO2, NO2, CO, PM10 and/or
PM2.5 concentration impacts differ by at most 0.02 percent. Thus, EPA has independently
confirmed that the Shell code changes to ISC3-Prime had no significant effect on the predicted
concentration impacts from Shell's exploration drilling program.
5.2.5.1 Urban/Rural Area Determination
The exploratory drilling operations will occur at 275 lease blocks contained in Lease Sale Area
193 (Air Sciences 3/20/09). These lease blocks are located approximately 110 kilometers
northwest of the city of Wainwright, Alaska. In addition, Shell will operate a combustion source
in a warehouse at a coastal location. Since these operations occur over water and/or in areas
lacking any significant industrial and commercial activities or development, the two areas are
considered rural for dispersion modeling purposes (Auer 1978).
5.2.5.2 Ambient Air Definition
Ambient air is defined as . .that portion of the atmosphere, external to buildings, to which the
general public has access" 40 C.F.R. § 50.1(e). Consistent with this definition, ambient air
begins at, and extends outward from the edge of the Discoverer and each vessel in the Associated
Fleet. Similarly, ambient air begins at the exterior walls of warehouse that houses the oil fired
heater.
5.2.5.3 Good Engineering Practice Stack Height
The Building Profile Input Program for PRIME (BPIPPRM) (EPA 4/21/09 User's Guide) is used
to determine if an exhaust plume from each emission unit will be affected by a nearby structure.
Specifically, the stack location and height for each of the ten exhaust stacks above the water
surface, and structure height above the water surface, number of tiers, and corner locations for
each of the seven structures were input into BPIPPRM to make this determination for the
Discoverer. The results from running this EPA program indicate that all proposed stack heights
were of insufficient height to prevent wake effects. Hence, Shell included the dimensions
associated with the applicable structures that cause wake effects for each stack in its modeling
analysis. (Shell 5/29/09 Supp. App.).
Similarly, the warehouse structure and heater stack information were input into BPIPPRM. It
was determined that the warehouse structure would cause wake effects as well (Air Sciences
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6/9/09). Therefore, Shell included building dimensions in the modeling of this combustion
source (Shell 5/29/09 Supp. App.).
5.2.5.4 Meteorology
Because site-specific meteorology was not available, Shell used screening meteorology to predict
the ambient air impact concentrations from its exploratory drilling program. The use of
screening meteorology results in a more conservative approach to modeling because it assumes
more persistent conditions conducive to high ambient pollution impacts than would be expected
to actually occur.
Meteorological data from the SCREEN3 model is used in ISC3-PRIME to predict the highest
concentration impact for over water and over land modeling cases. In the SCREEN3 model,
meteorology consists of 54 hours of wind speed, stability, temperature and mixing height
combinations and a single downwind wind direction (EPA 10/92 Screening Procedures). For use
in ISC3-PRIME, an external file was generated with the SCREEN3 meteorology and specific
wind directions. Essentially, the file contained the SCREEN3 meteorological data combinations
with wind directions incremented every five degrees from five degrees to 360 degrees around the
compass. This resulted in 3888 hours of meteorology.
Because the emission units are modeled at their exact location on the Discoverer relative to a
common origin, it was necessary to increment the wind direction every five degrees and use a
Cartesian receptor grid as detailed below to predict concentration impacts. If all the emissions
units are co-located or forced on a line parallel to a single wind direction, unrealistic high
concentrations would be predicted.
The SCREEN3 model employs a default ambient temperature of 293 Kelvin (K) (i.e., 19.85
degrees centigrade or 67.73 degrees Fahrenheit) to predict ambient air quality concentration
impacts. Shell modified the screening meteorology by using a lower, more representative
ambient temperature of 261.1 K (i.e., -12.1 degrees centigrade or 10.31 degrees Fahrenheit)
measured at Barrow, Alaska (Shell 5/29/09 Supp. App.).
5.2.5.5 Receptor Locations and Elevations
A Cartesian coordinate system was used by Shell to define its primary rectangular modeling
domain and engulf all its over water drilling operations (see Figure 5-2). The center of the 13
kilometer by 10 kilometer domain is the exploratory drill hole location below an anchored
Discoverer. As shown in Figure 5-3, the drill hole location is at (93, 55) meters. Receptors in
this domain are spaced every 100-meters for a total of 12576 points.
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Figure 5-2 - Modeling Domain and Receptor Points
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Figure 5-3 - Discoverer and Onboard Emission Units
20
40
60
80
100
120
140
160
180
V)
l_
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located at 0-meters and ±15-meters from the centerline of the vessel. Total
receptor points: 2232.
During replenishment, the supply ship is tied to the Discoverer. As a result, a
fifth domain consists of receptor points placed around the supply ship hull at
about 10-meter intervals. Total receptor points: 18.
A discrete receptor point is used to predict concentration impacts at two over land locations.
They are Point Lay and Wainwright which are 100 kilometers and 110 kilometers, respectively,
from the Shell drilling operations. (Shell 2/23/09 Rev. App.).
The over water domains plus the two over land discrete receptors result in a total of 16534
receptor points, all with a surface elevation set to 0.0-meters. Except for POS #2, these receptor
points and elevations are input into ISC3-Prime to quantify the maximum concentration impacts
for POS #1 and SOS's #1 to #6.
For the over land combustion source, Shell also uses a Cartesian coordinate system. Receptor
points are spaced at 10-meter intervals and located at the exterior walls of the building housing
the combustion unit. Extending outward from the building to 1000-meters, receptor points are
spaced at 25-meter increments. All receptor point elevations are set to 0.0-meters. Total
receptor points: 6592.
5.2.5.6 Volume Source Representation for Vessels
Because there are no established procedures to model underway ship emissions, the vessels were
modeled as volume sources with the release height based on the lowest final plume rise in each
fleet. EPA believes this approach will result in conservative concentration predictions.
To obtain the lowest final plume rise, EPA requested Shell to model each known possible vessel
of the ice breaker and oil spill response fleets, and the supply ship as point sources taking into
account building wake effects. EPA also recommended that D stability and a wind speed of 20
meters per second meteorology be used in the SCREEN3 model to reduce the plume rise. The
lowest plume rise calculated by SCREEN3 within the ice breaker fleet and oil spill response
fleet, and the supply vessel would establish the release height of each representative volume
source.
Initial lateral and vertical dispersion characteristics are also required when modeling volume
sources. Following the guidance contained in the ISC3 model user's guide (EPA 9/95 ISC3), the
initial lateral and vertical dispersion characteristics are based on the length of the vessel (sigma-
y0) and the height dimension of the source (sigma-z0), respectively.
The calculated volume source parameters representing the ice breaker fleet, oil spill response
fleet and supply ship were subsequently modeled concurrently with the Discoverer on board
emission units as they operate in the Chukchi Sea (Shell 2/23/09 Supp. App.).
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5.2.5.7 Source Emission Rates and Stack Parameters and Locations
The following two subsections detail the calculated emission rates of each air pollutant and the
source parameters of each combustion unit or source that were input into ISC3-Prime to
determine compliance with NAAQS and air quality increments.
5.2.5.7.1 Emission Rates
Shell's exploratory drilling program consists principally of a drill ship, two fleets, and a supply
ship. A list of the emission units or sources and the modeled air pollutant emission rates are
presented in Appendix A. The vessels that are modeled as volume sources include the supply
ship, the oil spill response vessel, the oil spill response work boats (3), Ice breaker #1, and Ice
breaker #2. To derive the individual volume source emission rate, the vessel travel distance (i.e.,
line of adjacent volume sources) is divided by the separation distance between the sources to
obtain the number of volume sources. The total air pollutant emission rates for the vessels are
then divided by the number of volume sources to derive a common air pollutant emission rate for
each individual volume source. For example, suppose the travel distance of Ice Breaker #2 is
4800-meters and the separation distance is 100-meters. Dividing the travel distance by the
separation distance results in 48 volume sources on the line. Using the SO2 emission rate (41.6
pounds per hour) for Ice Breaker #2 and dividing it by 48 volume sources, an individual volume
source emission rate of 0.8666 pounds per hour is calculated.
In addition, Ice Breaker #2 is used in SOS #1, #5 and #6 to remove ice that has accumulated on
the bow of the Discoverer and for anchor deployment and retrieval. For these three other uses of
Ice Breaker #2, the emission rates have been partitioned according to the vessel's primary and
secondary uses during a day, specifically, one hour for bow ice removal and 18 hours to deploy
and retrieve the anchors. When Ice Breaker #2 is not performing these tasks, it is assumed to be
breaking or crushing ice in the Chukchi Sea.
Detailed discussions of the assumptions and methodologies used to derive these modeled
emission rates can be found in Section 3 and Appendix A. As discussed above, these emission
rates have been substantially reduced as compared to the emission rates in the August 2009
proposed permit.
5.2.5.7.2 Source Locations and Source Parameters
The location and source parameters of the emission units and sources appear in Table 5-6 and
Table 5-7 for the POS's and SOS's, respectively. The X-coordinate and Y-coordinates are based
on an origin at (93, 55) meters as depicted in Figure 5-3. In general, Ice Breaker #1 and Ice
Breaker #2 will operate no closer than 4800-meters and 1000-meters upwind of the Discoverer
respectively, during drilling operations. During the removal of ice that has accumulated on the
bow of the Discoverer, Ice Breaker #2, can approach no closer than 100-meter from the drill
ship. In general, the oil spill response fleet will operate downwind of the Discoverer at a
distance of 2000-meters.
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Parameters for modeling point sources include stack height, stack gas exit temperature, stack gas
exit velocity and inside stack diameters. Modeling volume sources requires release height, initial
sigma-y and initial sigma-z.
Table 5-6 - Primary Operating Scenario - Location and Stack Parameters
Emission Units
or Sources
Source
Type
Locationa
Stack Parameters
X
(m)
y
(m)
Height
(m)
Temperature
(K)
Velocity
(m/sec)
Diameter
(m)
Generator Eng a'b'°
Point
154.10
55.20
17.40
710.00
32.89
0.32
MLC Comp Enga b c
Point
102.00
63.00
13.10
699.80
40.00
0.21
HPU Enga b c
Point
79.00
65.00
10.70
699.80
40.00
0.18
Cementing Eng
Point
95.00
67.00
10.70
800.00
46.60
0.18
Port Crane Eng a'b'°
Point
114.00
66.00
18.29
672.00
20.10
0.25
Stbd Crane Eng a'b'°
Point
70.10
43.70
18.29
672.00
20.10
0.25
Heat Boilera b c
Point
154.30
52.20
17.40
478.00
7.34
0.46
Log Winch Eng a'b'°
Point
120.70
55.20
13.11
710.90
52.97
0.10
Incineratorabc
Point
61.00
65.00
7.01
623.00
10.00
0.46
Over Land Heater d
Point
0.00
0.00
7.62
478.00
6.60
0.46
Height
(m)
Sigma-y o
(m)
Sigma-z0
(m)
Ice Breaker #1a c e
Volume
d
d
25.22
46.51
9.21
Ice Breaker #2 a c f
Volume
e
e
25.22
46.51
9.21
Oil Spill ResponseK
a,c,g,h
Volume
f
f
3.38
23.26
1.42
Oil Spill ResponseN
a,c,h,i
Volume
g
g
17.55
23.26
6.38
Reference: Shell 5/29/09 Supp. App.; Shell 9/17/09 Comments
a. Origin of coordinate system (93, 55) meters or the drill hole location below the Discoverer.
b. Discoverer emission units. A single location is used to represent similar emission units (i.e., six generator
engines, three MLC compressor engines, two HPU engines, two cementing engine units, two heat boilers
and two logging winch engines.
c. Stack height or release is meters above the surface or water line.
d. The coordinate system used to model the over land located heater is different from that used by the over
water emission sources. The origin is at (0, 0) m, or the stack location.
e. Ice Breaker #1 is located approximately 5000-meters upwind of the drill hole location. Ice Breaker #1 is
represented by 96 volume sources.
f. Ice Breaker #2 is located approximately 1000-meters upwind of the drill hole location. Ice Breaker #2 is
represented by 48 volume sources.
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g. Oil Spill ResponseK is located about 2000-meters downwind of the drill hole location. There are three
work boats.
h. Oil Spill ResponseK and Oil Spill ResponseN are divided into 40 volume sources each.
i. Oil Spill ResponseN is located about 2000-meters downwind of the drill hole location. The vessel is the
Nanuq.
Table 5-7 - Secondary Operating Scenario - Location and Stack Parameters
Emission Units
or Sources
Operating
Scenario
Location
Stack Parameters
X
(m)
y
(m)
Height
(m)
Temperature
(K)
Velocity
(m/sec)
Diameter
(m)
Resupply a'b
SOS #3
70.00
-12.00
15.24
700.00
4.00
0.18
Emergency
Generatorac
SOS #4
Height
(m)
Sigma-y0
(m)
Sigma-Zo
(m)
Bow Ice Removal
a,d
SOS#l
e
e
24.43
23.26
9.21
Supply Ship
Transita
SOS #2
f
f
15.24
29.07
6.38
Anchor
Deployment8
SOS #5
h
h
24.43
23.26
9.43
Anchor Retrieval
g
SOS#6
h
h
24.43
23.26
9.43
Reference: Shell 2/23/09 Rev. App.; Environ 7/15/09-PM10;
invi ron 7/15/09-P
VI2.5; Environ 7/16/09
Bow Washingl; Environ 7/16/09-Bow Washing2.
a. Occurs during Discoverer drilling operations or POS # 1.
b. Supply ship Kilabuk is tied to the Discoverer.
c. The emergency generator emissions were modeled with FD 1-6 emissions.
d. Bow ice removal is performed by Ice Breaker #2and using six volume sources to represent the
activity.
e. Minimum separation distance between Frontier Discover and Ice Breaker #2 is 100-meters during
this bow ice removal.
f. The supply ship is modeled during the last 5-kilometers to the Discoverer using 80 volume
sources to represent the transit.
g. Occurs when there is no drilling operation. This activity is represented by 1004 volume sources.
h. Minimum separation distance between Frontier Discover and Ice Breaker #2 is 900-meters during
anchor setting and retrieval.
5.2.5.8 Scaling Factors
Scaling factors, as recommended by EPA, are used to calculate the concentrations for longer
averaging periods from the hourly concentrations predicted by ISC3-Prime (EPA10//92
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Screening Procedures). The scaling factors are the upper range numbers and are shown below.
In this analysis, EPA recommended that Shell use the upper end scaling factors because of the
expected wind persistence over the Chukchi Sea and the wake effects caused by vessel
structures.
Table 5-8 - Scaling Factors
I Averaging Period
Scaling Factor
3-Hour
1.0
8-Hour
0.9
24-Hour
0.6
Annual Average
0.1
5.2.6 Background Monitoring Data and Preconstruction Monitoring
Background monitoring data is used in conjunction with modeled predictions to determine if
emissions from the project would cause or contribute to violations of NAAQS. For background
air monitoring data in its permit application, Shell relies on data collected at a monitoring station
in Wainwright, Alaska, one of the few locations on the coast of the Chukchi Sea that has even
limited infrastructure (see Figure 5-4 for the location of North Slope air monitoring stations).
Shell is also relying on data from the Wainwright monitoring station to fulfill the preconstruction
monitoring requirement of 40 C.F.R. § 52.21(m). As shown in Table 5-9, preconstruction
monitoring is required for SO2, NO2, and PM10 because the predicted highest concentration for
these three air pollutants emitted by the Discoverer and the Associated Fleet exceed the
respective significant monitoring thresholds for these pollutants. Preconstruction monitoring is
also required for ozone because emissions of N02 and VOC exceed 100 tons per year.
Table 5-9 - Preconstruction Significant Monitoring Levels
Air Pollutant
Averaging Time
Predicted
(|ig/m3)
Level
(|ig/m3)
Percent
Sulfur Dioxide (S02)
24-Hour
28.00
13
215.38
Nitrogen Dioxide (N02)
Annual
20.80
14
148.57
Carbon Monoxide (CO)
8-Hour
352.00
575
61.22
Particulate Matter equal to or less
than 10 microns (PMi0)
24-Hour
28.20
10
282.00
Particulate Matter equal to or less
than 2.5 microns (PM2 5)
a
Ozone (03)
b
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a. EPA has not promulgated a PM2.5 monitoring threshold.
b. The net emissions increase NO2 and VOC emissions exceed 100 tons per year. As a result, Shell is
required to conduct an ozone analysis including data collection. See Section 3 and Appendix A for
emission calculations.
There are no islands, platforms or infrastructure in the Chukchi Sea on which to install, operate
and maintain ambient air quality monitoring equipment. Wainwright is a rural community on the
shores of the Chukchi Sea with a population of around 500. There are a number of air pollution
sources in Wainwright, such as a diesel-fired utility electric power plant, a fuel storage facility,
airport, residential heating, vehicle exhaust, and unpaved roads. Importantly, Wainwright
experiences arctic weather conditions similar to those of the Chukchi Sea. While the
Wainwright monitoring station will be somewhat influenced by local sources, EPA believes that
it provides a conservative representation of air quality in the area covered by Shell's leases in
Lease Area 193 because of the relative closeness of Wainwright to the Shell leases, the relative
lack of air pollution sources in Wainwright and the area covered by Shell's leases, and the
similarity of the meteorology in Wainwright and the area covered by Shell's leases.
The Wainwright monitoring station began collecting data on November 8, 2008. Data
measurements include SO2, NO2, NOx, NO, CO, PM10, PM2.5 and ozone with meteorological
data being collected at the Wainwright airport. EPA approved the monitoring plan for the
Wainwright monitoring station on January 5, 2009. EPA has reviewed the quarterly reports,
including instrument operating parameters, and analyzed the measured air pollutant data during
the collection period from November 8, 2008 to October 31, 2009 for consistency with 40 C.F.R.
§ 52.21 and the approved monitoring plan. (AECOM 2008 QAPP; AECOM 11/08-1/09;
AECOM 2/09-4/09; AECOM 5/09; AECOM 6/09;AECOM 8/09-10/09; EPA 7/31/09
Wainwright QA Memo; EPA 1/7/10 Wainwright QA Memo EPA; 1/7/10 Deadhorse QA
Memo). EPA has concluded that the SO2, NO2, NOx, NO, CO, ozone and PM10 data collected
from November 8, 2008 to October 31, 2009 and the PM2.5 data collected from March 6, 2009
to October 31, 2009 are appropriate for use as representative background air quality levels for
this permitting action. With respect to PM2.5, a problem with the instrumentation rendered the
data collected from November 8, 2008 through March 5, 2009 invalid. The problem has since
been addressed. (EPA 7/31/09 QA/QC Memo).
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Figure 5-4 - North Slope Monitoring Stations
Version: 02/02/2009 Project No. 180-15
Norili Slope Ambient Background
Monitoring Stations
AIHSCIfNCtt INC.
- Piudho« B«>
Based on information provided by Shell and other available information, EPA believes that the
monitoring data collected at the Wainwright monitoring site is, in general, conservatively
representative of air quality in the Chukchi Sea where Shell will be conducting its exploratory
drilling program and that a complete and adequate air quality analysis as required by 40 C.F.R.
§ 51.21 (m)< 1 )(iv) can be accomplished with monitoring data from the Wainwright monitoring
site. Measurements of the three gaseous air pollutants (S02, N02, and CO) generally track with
seasonal fluctuations at monitoring stations at other locations on the North Slope. Measurements
of the two particulate matter air pollutants (PM2.5 and PMi0) also follow expectations, with
higher levels during the summer and fall when the ground is not frozen or covered with snow.
There are nearby sources of fugitive dust, including unpaved roads and other unpaved areas such
as airport runways, that would be expected to contribute to particulate matter concentrations at
the Wainwright monitoring site. Shell has submitted an analysis of the particulate matter data to
show that levels on days with high winds and dry soils are much higher than other days. (Shell
12/9/09; Environ 12/18/09-PM). For example, the average and 24-hour maximum PM2.5
concentrations were more than twice as high on days with high winds and no precipitation than
on other days. Shell contends that this analysis, along with the fact that there are sources of dust
in the vicinity of the Wainwright monitor, establishes that the highest recorded particulate matter
levels at the Wainwright are associated with local windblown dust and are not reflective of
conditions on the OCS source where Shell is conducting drilling operations more than 50 miles
from shore. Based on the information provided by Shell, EPA agrees that the PM2.5 and PMio
values recorded at the Wainwright monitoring station on high wind days with no precipitation
106
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are not representative of air quality in the vicinity of the Shell's exploratory drilling operations in
the Chukchi Sea and are appropriately excluded from consideration in determining the
background levels on the OCS near the drilling sites. Accordingly, EPA has determined an
average and a maximum concentration for both PM2.5 and PMi0 that are used as background
concentrations for both onshore and offshore impact analyses. The offshore background
concentrations exclude the high wind/non-precipitation days, while the onshore background
concentrations include all days. Table 5-10 summarizes the analysis of PM2.5 and PM10 data and
the final background levels that are used for the offshore (in the vicinity of Shell's operations)
and onshore NAAQS demonstrations (the nearest on-shore locations to Shell's operations).
Table 5-10 Determination of Background PM10 and PM2.5 Concentrations for Use with
Offshore and Onshore Impact Analyses
24-hour PM2.5 Concentration
(ug/m3)
24-hour PM10 Concentration
(ug/m3)
# Days
Average
Maximu
m
# Days
Averag
e
Maximu
m
Precipitation Days a
Non-High Wind Days b
52
2.8
7.0
54
13.4
54.0
High Wind Days c
6
3.8
7.0
4
13.8
28.0
Non-Precipitation Days d
Non-High Wind Days b
133
2.7
11.0
126
15.7
91.0
High Wind Days c
36
6.1
23.0
35
20.3
114.0
Offshore Background Concentrations (Excluding Non-Precipitation Days/High Wind Days)
Offshore Background
191
2.8
11.0
184
15.0
91.0
Onshore Background Concentrations (All Days)
Onshore Background 227
3.3
23.0 219
15.8
114.0
Reference: Shell 12/9/09; Environ 12/18/09-PM
a. These days fall within a two day period (on that day or on the previous day) where there is total
precipitation greater than 0.01 inches.
b. Days with less than 4 hours of winds greater than 10 meters/second.
c. Days with at least 4 hours of winds greater than 10 meters/second.
d. These days fall within a two day period (on that day or on the previous day) where there is total
precipitation equal to or less than 0.01 inches.
EPA expects that the background levels of pollution, and especially PM2.5 and PM10, more than
50 miles offshore in the vicinity of Shell's planned exploratory drilling operations are likely to
be lower than the levels recorded at Wainwright. Table 5-11 summarizes the background
concentrations that are used in the analysis of NAAQS compliance for both the offshore areas
near the Discoverer and in the onshore communities of Wainwright and Point Lay.
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Table 5-11 Background Ambient Concentrations for Use with Offshore and Onshore
Impact Analyses
Pollutant
Averaging
Period
Onshore
Background
Offshore
Background
no2
Annual b
2.0
2.0
pm2 5 c
24-Houra
23
11
Annual b
3.3
2.8
PM10
24-Houra
114
91
Annual b
15.8
15.0
3-Houra
17
17
so2
24-Houra
10
10
Annual b
0.5
0.5
CO
1-Houra
1050
1050
8-Houra
941
941
Ozone
1-Houra
114
114
8-Houra
93
93
Reference: AECOM 11/08-1/09; AECOM 2/09-4/09; AECOM 5/09; AECOM 6/09; AECOM 8/09-
10/09); Reference: Shell 12/9/09; Environ 12/18/09-PM.
a. The period of record for the data collection at Wainwright is November 8, 2008 to October 31, 2009.
Except for the Offshore Background values for PMio and PM2.5, the maximum short-term concentrations
(24 hours and less) are given here.
b. Except for the Offshore Background values for PM10 and PM2.5, the value is an average over the entire
dataset.
c. The period of record for PM2 5 data collection at Wainwright is March 6, 2009 to October 31, 2009.
5.2.7 Ozone
Because NOx and VOC net emissions exceed 100 tons per year, Shell is required under the PSD
regulation to perform an ozone ambient air quality impact analysis including gathering ambient
air measurements. Ozone is inherently a regional pollutant, the result of chemical reactions
between emissions from many sources over a period of hours or days, and over a large area.
Ozone is formed in the atmosphere through a chemical reaction that includes NOx, VOC and CO
in the presence of sunlight. The sources of these air pollutants are mainly combustion sources
such as power plants, refineries and automobiles.
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Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
EPA does not have a recommended modeling approach for assessing the impact of an individual
source on ozone. Individual source impacts are generally within the range of "noise" of regional
ozone models (i.e., imprecision in predicted concentration due to uncertainty in model inputs for
emissions, chemistry, and meteorology). EPA's Guideline on Air Quality Models (40 CFR 51,
App. W), which is applicable to PSD permit modeling, reflects this understanding. Guideline §
5.2.1(a) notes that "Simulation of ozone formation and transport is a highly complex and
resource intensive exercise," and paragraph (c) states: "Choice of methods used to assess the
impact of an individual source depends on the nature of the source and its emissions. Thus,
model users should consult with the Regional Office to determine the most suitable approach on
a case-by-case basis." Under the Guideline, EPA has considerable discretion in methods for
assessing the ozone impact of individual sources. See In re: Prairie State Generating Company,
13 E.A.D. , PSD Appeal No. 05-05, slip op. at 133 (EAB 2006). In practice, it is very rare for
EPA to require ozone modeling for individual sources.
The land area closest to Shell's exploration operations in the Chukchi Sea is part of the State of
Alaska's Northern Interstate Air Quality Control Region. See 40 C.F.R. § 81.246. This region is
designated as either attainment or unclassifiable for all criteria pollutants, including ozone. See
40 C.F.R. § 81.301. Actual emissions of ozone precursors from point and area sources in the
North Slope Borough were approximately 42,500 tons per year of NOx and 1,600 tons per year
of VOC, with the vast majority (41,000 and 1,100 tons per year, respectively) from point sources
in the North Slope oil and gas fields near Deadhorse. In contrast, potential emissions from
Shell's exploration operations are expected to be approximately 1181 tons per year of NOx and
108 tons per year of VOC, and there are no other stationary source operations near Shell's
exploration operations in the Chukchi Sea. The contribution from these precursor emissions to
the formation of ozone is expected to be small downwind of Lease Sale Area 193.
Over the past ten years, there have been monitoring programs that measured ozone and ozone
precursors (i.e., NOx and VOC) in the North Slope where oil and gas operations are currently
located. The ozone measurement programs include Barrow (2003 - 2005), BPX-Badami (1999),
BPX-Prudhoe Bay (2006 - 2007), CPAI-Alpine (Nov 2004 - Dec 2005) and CPAI-Kuparuk
River (Jun 2001 - June 2002). Measurements from these six sites indicate that the highest 1-hour
concentration was 73 parts per billion while the highest 8-hour measurement was 50 parts per
billion. The hourly concentration represents 61 percent of the 120 parts per billion hourly
NAAQS. The 8-hour concentration represents 67 percent of the 75 parts per billion of the 2008
8-hour NAAQS. (Shell 11/23/09 Supp. App.).
As discussed above, CPAI and Shell began an ambient air quality data collection program at
Wainwright, Alaska to represent background air quality levels in the Chukchi Sea. Table 5-11
shows the maximum hourly and 8-hour ozone concentrations measured during the first twelve
months of data collection at Wainwright. The 1-hour and 8-hour measured concentrations
represent 49 percent and 63 percent of their NAAQS, respectively.
Given the low level of ozone precursor emissions from Shell's exploration operations in
comparison to regional emissions of ozone precursors, the fact that there are no other stationary
sources in the more immediate regional vicinity of Shell's operations in the Chukchi Sea that
contribute ozone precursors to the airshed, and the moderate levels of the maximum 1-hour and
8-hour measured on the North Slope and at Wainwright, the contribution of the ozone precursor
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emissions from Shell's exploration operations to the formation of ozone in the region is expected
to be small. For these reasons, EPA believes that emissions from Shell's exploration operations
will not cause or contribute to a violation of the NAAQS for ozone.
5.2.8 Results of NAAQS Demonstration
All of the modeled operating scenarios for the Discoverer and its Associated Fleet resulted in
predicted total concentration impacts, including existing background data, below the level of the
NAAQS. Table 5-12 summarizes the highest predicted and total impacts for the POS #1 and its
alternatives. The levels range from a low of 3.1% of the annual S02 NAAQS to a high of 84.0%
of the 24-hour PM2.5 NAAQS. In addition, Table 5-13 shows the predicted total concentration
impacts at Point Lay and Wainwright, the two nearest villages to Shell's leases in Lease Sale
193. In these villages, the total predicted impacts for SO2, NOx, and CO are less than 10% of
their respective NAAQS and the total predicted impacts for PMi0 and PM2.5 are less than 78% of
their respective NAAQS. Thus, the modeling demonstrates that emissions associated with the
proposed permit are not expected to cause or contribute to a violation of the applicable NAAQS.
Table 5-12 - Maximum Predicted Impacts on NAAQS and PSD Class II Increments from
POS #1 and Alternatives
Concentration (ug/m3)
PSD Class
Percent
Increment
Percent
NAAQS
Pollutant
Averaging
Period
Total
No
Background
Back
ground
Total
th Background
II
Increment
(ug/m3)
NAAQS
(ug/m3)
N02 2
Annual
18.2
2.0
20.2
25
72.8%
100
20.2%
pm25
24-Hour
18.4
11
29.4
*
35
84.0%
Annual
1.3
2.8
4.1
*
15
27.3%
PM10
24-Hour
19.4
91
110.4
30
64.7%
150
73.6%
Annual
1.4
15.0
16.4
17
8.2%
...
S02
3-Hour
68.8
17
85.8
512
13.4%
1,300
6.6%
24-Hour
26.8
10
36.8
91
29.5%
365
10.1%
Annual
2.0
0.5
2.5
20
10%
80
3.1%
CO
1-Hour
396.6
1050
1446.6
*
40,000
3.6%
8-Hour
356.9
941
1297.9
*
10,000
13.0%
Re
?erence: Shel
9/17/09 Supp. App.; Environ 12/2/09)
*EPA has not promulgated increments for PM2.5 or CO
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Table 5-13 - Predicted Impacts on NAAQS from POS #1 and Alternatives at Wainwright
and Point Lay
Pollutant
Averaging
Period
Max. Modeled 1
Wainwright ^nt
Concentration (ug/m3)
Wainwright
Background Total with
Background
Point Lay
Total with
Background
NAAQS
Percent
NAAQS
Wainwright
Percent
NAAQ
Point
Lay
no2
Annual
1.7
1.8
2.0
3.7
3.8
100
3.7%
3.8%
pm25
24-Hour
2.6
2.7
23
25.6
25.7
35
73.1%
73.4%
Annual
0.2
0.2
3.3
3.5
3.5
15
23.3%
23.3%
PM10
24-Hour
2.8
3.0
114
116.8
117.0
150
77.9%
78.0%
Annual
0.2
0.2
15.8
16.0
16.0
—
—
—
3-Hour
7.3
7.8
17
24.3
24.8
1,300
1.9%
1.9%
so2
24-Hour
4.1
4.4
10
14.1
14.4
365
3.9%
3.9%
Annual
0.3
0.3
0.5
0.8
0.8
80
1.0%
1.0%
CO
1-Hour
34.1
36.4
1050
1084.1
1086.4
40,000
2.7%
2.7%
8-Hour
30.6
32.7
941
971.6
973.7
10,000
9.7%
9.7%
Reference: Shell 9/17/09 Supp. App.
1 The nearest villages to Shell's Chukchi leases are Wainwright (-110 km away) and Point Lay (-100 km away)
5.2.9 Results of Increment Demonstration
All of the modeled operating scenarios for the Discoverer and its Associated Fleet resulted in
predicted concentration impacts below the Class II increments. Table 5-12 above also shows the
predicted maximum concentrations for POS #1 and its alternatives as compared to the PSD
increments for Class II areas.
As also shown in Table 5-14 below, predicted impacts for the Class II increments in Point Lay
and Wainwright are significantly lower, less than 5% for all SO2, increments and the 24-hour
PM10 increment and less than 10% for the annual NOx increment and the 24-hour PM10
increment.
ill
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Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
Table 5-14 - Predicted Impacts on PSD Class II Increments from POS #1 and Alternatives
at Wainwright and Point Lay
Concentration ( g/m3)
Pollutant
Averaging
Period
Max. Modeled 1
Wainwright
Class II
Increment
Wainwright
Percent
Increment
Point Lay
Percent
Increment
no2
Annual
1.7
1.8
25
6.8%
7.2%
PM10
24-Hour
2.8
3.0
30
9.3%
10.0%
Annual
0.2
0.2
17
1.2%
1.2%
so2
3-Hour
7.3
7.8
512
1.4%
1.5%
24-Hour
4.1
4.4
91
4.5%
4.8%
Annual
0.3
0.3
20
1.5%
1.5%
Reference: Shell 9/17/09 Supp. App
1 The nearest villages to Shell's Chukchi leases are Wainwright (-110 km away) and Point Lay (-100 km away)
The nearest Class I area is Denali National Park located about 950-kilometers from the Shell
lease blocks in Lease Sale 193. Based on the distance and the amount of emissions, the National
Park Service did not request Class I area quality increment analysis for Denali National Park
(Notar 8/5/09).
5.2.10 Conclusions
An ambient air quality impact analysis was performed using conservative modeling assumptions
to demonstrate compliance with NAAQS and air quality increments at over water and over land
locations. These assumptions include the use of screening meteorology and the upper end
scaling factors to derive other averaging period concentrations from the 1-hour model prediction,
and the use of a volume source height based on a D stability and 20 meter per second wind
speed. From an engineering perspective, the modeling analysis also took into consideration the
application of emission limits and the requirements reflecting Best Available Control
Technology, and other limits in the permit that restrict operation and location of the Discoverer,
ice breaker fleet, oil spill response fleet and/or supply vessel.
Based on the conservative modeling assumptions and the predicted SO2, NO2, CO, PM10, and
PM2.5 concentration impacts for the primary and secondary operating scenarios, EPA has
concluded that Shell's exploratory drilling project is expected to comply with the applicable
NAAQS and Class II area air quality increments.
5.3 Additional Impacts Analysis
As discussed above, 40 C.F.R. § 52.21(o) requires additional impact analyses, which must
include an analysis of the impairment to visibility, soils and vegetation that would occur as a
result of the proposed source modification, or that would occur as a result of any commercial,
residential, industrial and other growth associated with the source modification. 40 C.F.R. §
52.2l(p) has additional requirements for mandatory federal Class I areas.
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5.3.1 Class II Area Visibility
The National Park Service identified two of Class II national monuments as areas of concern
(Notar 6/3/09): Cape Krusenstern National Monument and Bering Land Bridge National
Monument (see Figure 5-5). Based on the fact that the nearest Shell lease block in the Chukchi
Sea is 280 kilometers from the closest of these national monuments, the National Park Service
believes that the Shell project should not adversely affect visibility at the monuments (Notar
8/5/09).
Figure 5-5 - Location Map of Class II Area National Monuments
Barrow*
Chukchi Sea
Bering Sea VWderness
Cape Krusenstern National Monument
Bering Land Bridge National Preserve
Beaufort
Sea
Anchorage"
175
350
I Kilometers
A
Version: 06/05/09
Project No. 180-15
Shell OCS Lease Blocks
Chukchi Sea
AIR SCIENCES IMC.
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Fog is a natural occurring atmospheric event over land and over water. It usually forms when
moist air cools to below its dew point. Freezing fog occurs when liquid fog droplets freeze to
tiny particles in the air. Ice fog occurs when droplets have frozen into tiny crystals of ice in air
which generally requires temperatures below 30 degrees Fahrenheit (Air Sciences 6/1/09). EPA
estimates the water vapor emissions to be 67 ton per day from the Discoverer and 395 tons per
day from all combustion sources. Water vapor emissions from the Discoverer and the
Associated Fleet may contribute to fog formation depending on atmospheric conditions.
Visible exhaust plumes are expected from the Discoverer and Associated Fleets activities during
exploratory drilling activities. However, because of the location of Shell's operations in the
Chukchi Sea, visibility impairment from the exhaust plumes is not expected to be of concern.
5.3.2 Soils and Vegetation
Shell is required to provide an analysis of the impairment to soils and vegetation in the
significant impact area of the proposed new source that is expected to occur as a result of its
permitted activities and general commercial, residential, industrial, and other growth associated
with the project. Analysis for vegetation having no significant commercial or recreational value
is not required. All areas within the largest possible significant impact area radius of 50-
kilometers centered on the Discoverer are ocean. Shell analyzed the potential impacts from the
project on aquatic vegetation having commercial or recreational value and sediment by
reviewing published literature and consulting with numerous government agencies, local groups
and residents, and the University of Alaska (Air Sciences 6/1/09). Shell did not identify any
negative impacts on aquatic vegetation having significant commercial or recreational value nor
on sediment in the significant impact areas expected to be impacted by air emissions from
Shell's exploration drilling operations in the Chukchi Sea.
5.3.3 Growth
Temporary growth and support facilities are expected at several possible coastal locations to
support the project. The location of the growth and facilities could occur at Wainwright, Barrow,
Deadhorse and Kotzebue. Support facilities include storage facilities and aircraft hangers.
Rotating work crews could lodge at local hotels and trailer camps and helicopters will be used to
transport work crews to and from the Discoverer. In addition, Shell contemplates building a
warehouse, heated by either natural gas or heating oil, at either Wainwright or Barrow. As
shown in Table 5-15 and Table 5-16 below, the emissions associated with heating the warehouse
have been based on oil firing and considered in the modeling analysis and are not expected to
contribute to a violation of the NAAQS or noncompliance with PSD increments.
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Table 5-15 - Primary Operating Scenario #2 Predicted Total Concentration Impact
Comparison with NAAQS
Air
Pollutant
Averaging
Period
Predicted
(|ig/m3)
Existing
(|ig/m3)
Totalc
(|ig/m3)
NAAQS
(|ig/m3)
Percent
NAAQS
Sulfur Dioxide (S02)
3-Hour
56.20
17
73.2
1300
5.63
24-Hour
37.50
10
47.5
365
13.01
Annual
3.10
0.5
3.6
80
4.50
Nitrogen Dioxide
(N02)
Annual
3.70
2.0
5.70
100
5.70
Carbon Monoxide
(CO)
1-Hour
24.60
1050
1074.60
10000
10.75
8-Hour
22.10
941
963.1
40000
2.41
Particulate Matter
equal to or less than 10
microns (PMi0)
24-Hour
9.80
114
123.8
150
82.53
Particulate Matter
equal to or less than
2.5 microns (PM25)
24-Hour
9.80
23.0
32.8
35
93.71
Annual
0.81
3.3
4.11
15
27.40
Reference: Air Sciences 6/9/09.
a. The sum of the "predicted" impact and "existing" background.
Table 5-16 - Primary Operating Scenario #2 Predicted Concentration Impact Comparison
with Class II Area Air Quality Increments
Air
Pollutant
Averaging
Period
Predicted
(|ig/m3)
Increment
(|ig/m3)
Percent of
Increment
Sulfur Dioxide (S02)
3-Hour
56.20
512
10.98
24-Hour
37.50
91
41.21
Annual
3.10
20
15.50
Nitrogen Dioxide (N02)
Annual
3.70
25
14.80
Particulate Matter equal to or
less than 10 microns (PMi0)
24-Hour
9.80
30
32.67
Annual
0.81
17
4.76
Particulate Matter equal to or
less than 2.5 microns (PM2 5)
a
Reference: Air Sciences 6/9/09.
a. EPA has not promulgated PM2.5 increments.
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The Helicopter Discoverer will be utilized to rotate the work crews. A maximum of three trips
per day are expected. Because of the significant dispersion that occurs as a result of the
helicopter horizontal rotors, air quality modeling was not performed for the helicopter take off
and landings. Emissions associated with the helicopter are not expected to contribute to a
violation of the NAAQS or noncompliance with PSD increments.
5.3.4. Air Quality Related Values Including Visibility
Under 40 C.F.R. § 52.21(p), the Federal Land Managers are responsible for the management of
mandatory federal Class I areas, including the protection of air quality related values. The air
quality related values include sulfate and nitrate deposition and visibility impairment. The
nearest Class I areas are the NPS Denali National Park and the FWS Bering Sea Wilderness
Area, located approximately 950-kilometers southeast and 1100-kilometers south, respectively,
of Shell's proposed drilling locations in the Chukchi Sea. At this distance, the National Park
Service and the Fish and Wildlife Service are not expecting significant sulfate and nitrate
deposition, or visibility impairment impacts at these two mandatory federal Class I areas (Notar
8/5/09).
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6. OTHER REQUIREMENTS
6.1 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. 16 U.S.C. §1536(a)(2); see also 50
C.F.R. §§ 402.13, 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. 16 U.S.C. §1536(a)(4); see also 50
C.F.R. § 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. 50 C.F.R. § 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.
MMS is the lead federal agency for authorizing oil and gas exploration activities on the Alaska
outer continental shelf, including the Chukchi Sea. Therefore, MMS has served as the Lead
Agency for ESA Section 7 and MSA compliance for Shell's oil exploration activities. The U.S.
Fish and Wildlife Service has also completed an intra-agency Section 7 consultation in
connection with issuance of polar bear incidental take regulations (ITR) for oil and gas
exploration activities in the Chukchi Sea. See generally 73 Fed. Reg. 33212 (June 11, 2008). In
fulfilling our ESA obligations for this permitting action, EPA reviewed the ESA and MSA
consultation documents prepared by MMS and the following biological opinions (BOs) issued by
the Services upon conclusion of their inter-agency ESA consultations regarding impacts from
exploratory drilling on threatened and endangered (T&E) species and designated critical habitats
for listed species:
• U.S. FWS March 27, 2007, Biological Opinion for Chukchi Sea Planning Area Oil and
Gas Lease Sale 193 and Associated Seismic Surveys and Exploratory Drilling.
• Programmatic Biological Opinion for Polar Bears on Chukchi Sea Incidental Take
Regulations, Fairbanks Fish and Wildlife Field Office, June 3, 2008
• National Marine Fisheries Service's (NMFS) revised Biological Opinion for Federal oil
and gas leasing and exploration by the Minerals Management Service (MMS) within the
Alaskan Beaufort and Chukchi Seas, July 17, 2008
Since the prior consultations and BO's address the same types of exploratory drilling activities
authorized by the air permit that EPA is issuing to Shell, EPA relied in part on those conclusions
for our final determination. EPA also gathered additional information regarding potential
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impacts of emissions of air pollutants on the T&E species in the Chukchi Sea Lease Sale 193
Area. Based upon the best available data, EPA determined that the issuance of this Clean Air
Act permit to Shell 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. EPA forwarded our determination to FWS and NOAA on September 4,
2009, and additional follow-up information was provided to NOAA on September 24, 2009. The
FWS and NOAA concurred in writing with our determination on September 23, 2009 and
October 26, 2009, respectively.
This proposed CAA permit includes a condition requiring Shell to comply with all other federal
regulations. This condition requires Shell to obtain an annual Letter of Authorization (LOA)
from the FWS in accordance with the ITR assuring further assessment of impacts to marine
mammals based on any new scientific data. Section 101 (a)(5) of the Marine Mammal Protection
Act (MMPA) directs the Secretary of Commerce to allow, upon request by U.S. citizens engaged
in a specific activity (other than commercial fishing) in a specified geographical region, the
incidental but not intentional taking of small numbers of marine mammals if certain findings are
made. Such authorization may be accomplished through issuance of an incidental harassment
authorization (IHA).
6.2 National Historic Preservation Act
Section 106 of the National Historic Preservation Act (NHPA) requires federal agencies to take
into account the effects of their undertakings on historic properties. Section 106 requires the lead
agency official to ensure that any federally funded, permitted, or licensed undertaking will have
no effect on historic properties that are on or may be eligible for the National Register of Historic
Places. The Section 106 process seeks to accommodate historic preservation concerns with the
needs of federal undertakings through consultation among the agency official and other parties
with an interest in the effects of the undertaking on historic properties, commencing at the early
stages of project planning. The goal of consultation is to identify historic properties potentially
affected by the undertaking, assess the potential effects of the undertaking on historic properties,
and seek ways to avoid, minimize, or mitigate any adverse effects on historic properties. If more
than one federal agency is involved in an undertaking, some or all the agencies may designate a
lead federal agency for this analysis. Section 106 requires the lead agency to consult with the
State Historic Preservation Office (SHPO) on actions that may affect historical sites. As the lead
action agency, MMS has consulted and will continue to consult with the SHPO on Shell's oil
exploration activities in federal waters. In a letter dated November 13, 2009, MMS sought the
SHPO's concurrence in MMS's determination that Shell's exploratory drilling in Lease Area 193
under Shell's Exploration Plan will have no effect on historic properties. The SHPO concurred
in MMS's determination on November 17, 2009. In fulfilling its NHPA obligations for this
permitting action, EPA intends to rely on these MMS consultations. EPA will conduct additional
compliance activities necessary to address any EPA-permitted activities not covered in MMS'
consultations.
6.3 Coastal Zone Management
The Alaska Coastal Management Program (ACMP), authorized by the State of Alaska's 1977
Alaska Coastal Management Act, is designed to protect Alaska's rich and diverse coastal
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resources to ensure a healthy and vibrant coast that sustains long-term economic and
environmental productivity. The ACMP requires that certain projects that will be conducted in
Alaska's coastal zone be reviewed by coastal resource management professionals and found
consistent with the statewide standards of the ACMP.
Pursuant to Title 11 of the Alaska Administrative Code at 11AAC 110.400 (b)(5), projects
requiring the following EPA permits must undergo an ACMP consistency review:
(A) permit required under 33 U.S.C. 1342 (Clean Water Act), authorizing discharge of
pollutants into navigable waters;
(B) permit required under 33 U.S.C. 1345 (Clean Water Act), authorizing disposal of
sewage sludge;
(C) permit under 40 C.F.R. Part 63 for new sources or for modification of existing
sources, or a waiver of compliance allowing extensions of time to meet air quality
standards under 42 U.S.C. 7412 (Clean Air Act); or
(D) air quality exemption granted under 40 C.F.R. 60.14 or 40 C.F.R. 64.2 for stationary
sources;
The OCS/PSD permit at issue in this action does not appear on the list. Thus, issuance of this
OCS/PSD permit is not required to be preceded by an ACMP consistency review.
6.4 Executive Order 12898 - Environmental Justice
Executive Order (EO) 12898, entitled "Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations," 59 Fed. Reg. 7629 (February 11, 1994)
(EO 12898), directs federal agencies, including EPA, to the extent practicable and permitted by
law, to identify and address, as appropriate, disproportionately high and adverse human health or
environmental effects of regulatory programs, policies, and activities on minority populations or
low-income populations. EO 12898 at § 1-101.
Consistent with EO 12898 and EPA's environmental justice policy (OEJ 7/24/09), in making
decisions regarding permits, such as OCS and PSD permits, 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. EPA's proposed OCS/PSD air permitting action on the
Chukchi Sea potentially affects a number of communities on the North Slope, many of which
participate in subsistence harvests of marine and terrestrial resources in the region. EPA's
review of demographic characteristics showed that many of the potentially impacted
communities have a significantly high percentage of Alaskan Natives, who are considered a
minority under EO 12898, and people who speak a language other than English at home (EJ
GAT 7/28/09).
EPA has taken several measures to provide meaningful involvement for the environmental
justice communities potentially impacted by this permit. EPA has recently developed the
"Region 10 North Slope Communications Protocol" to support the meaningful involvement of
the North Slope communities in EPA decision-making (NSCP 5/09). The development of the
public participation process for this permit was guided by the NSCP and will inform the
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communities of the North Slope about the OCS permitting program and this proposed OCS/PSD
permit. In an effort to engage the potentially affected communities early in the process,
managers of EPA Region 10's air and water programs conducted early outreach on air and water
permitting in May 2009 in Kotzebue and Barrow (EPA 7/27/09 Outreach Memo). EPA has held
meetings and conference calls to specifically solicit input on environmental justice concerns
related to this permitting action, as well as other potential OCS air permitting actions on the
Chukchi and Beaufort Seas (ICAS 7/23/09; NSB 6/26/09 Transcript). EPA held public hearings
and community meetings on the initial August 2009 proposal and has also scheduled a public
hearing on this new modified permit.
As described above, EPA has carefully considered and documented the environmental effects of
its proposed permitting decision by analyzing potential air emissions associated with the
exploration drilling activity to be conducted under the permit. As required by the applicable
OCS and PSD regulations, the terms and conditions of the final permit must ensure that activities
authorized by the permit will not cause a violation of the NAAQS. See 40 C.F.R. §§ 55.13(d),
52.21(a)(2)(iii) and 52.2l(k). NAAQS are national health-based standards that have been set at a
level such that their attainment and maintenance will protect public health and welfare, allowing
for an adequate margin of safety. See Section 109(b) of the CAA. EPA specifically solicits
comment on our proposed determination that the terms and conditions of the permit ensure
attainment of the NAAQS.
6.5 Executive Order 13175 - Tribal Consultation
Pursuant to Executive Order 13175 issued on November 9, 2000 and entitled, "Consultation and
Coordination with Indian Tribal Governments," federal agencies are required to have an
accountable process to assure meaningful and timely input by Tribal officials in the development
of regulatory policies on matters that have tribal implications. 65 Fed. Reg. 67249 (November 9,
2000). In accordance with Region 10's May 2009 North Slope Communications Protocol, a
regional policy for early community and tribal involvement, EPA held an informal informational
meeting in Barrow on May 29, 2009 to discuss the upcoming air permitting actions.
Prior to beginning the public comment period on the August 2009 proposed permit, EPA sent
letters to 11 potentially interested tribal governments, offering government-to-government
consultation opportunities on EPA's proposed action to issue Shell OCS/PSD permits for
exploration drilling on the Chukchi and Beaufort Seas. The letters were sent on June 26, 2009 to
Native Village of Point Hope, Native Village of Point Lay, Wainwright Traditional Council,
Native Village of Anuktuvuk Pass, Native Village of Atqasuk, Native Village of Barrow, Inupiat
Community of the Arctic Slope, Native Village of Kaktovik, Native Village of Nuiqsit, Native
Village of Kivalina, and Native Village of Kotzebue and specified that requests for consultation
be made no later than July 15, 2009. Because July is a busy time of year for Alaska Native
communities due to subsistence activities, EPA also attempted to contact each of these tribal
governments to ensure the letters were received.
EPA received a request for tribal consultation from the Inupiat Community of the Arctic Slope
(ICAS) and held a government-to-government consultation meeting with ICAS in Barrow on
September 23, 2009. Concerns expressed included drilling during November and December due
to severe winter conditions; a desire for more information regarding the air quality model; the
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reliability of self-monitoring data and a preference for monitoring data collected by an
independent third party; and a request that monitoring information and data be reported to the
communities.
ICAS also requested that EPA consult with all tribal governments on the North Slope and that
this occur in person in the local communities. Although EPA did not receive requests for
consultation from other tribal governments prior to the public hearings, EPA held informational
meetings for the local communities of Point Hope, Barrow, and Wainwright during the week of
September 21, 2009. The informational meeting in Point Hope on September 24, 2009, did end
up including an unscheduled government-to-government consultation meeting with the Native
Village of Point Hope. Concerns expressed at the consultation with the Native Village of Point
Hope included the adequacy of the baseline air quality data for the Chukchi and Beaufort Seas; a
desire for community involvement in the collection of baseline data collection and compliance
monitoring; and the potential impact on respiratory health. The Native Village of Point Hope
requested another opportunity for government-to-government consultation with EPA to discuss
their concerns prior to the finalization of the Shell OCS/PSD permit.
The concerns expressed by the tribal governments and other public comments were a factor in
EPA's decision to propose the new modified permit and initiate a second opportunity for public
comment. The new modified permit contains measures that further substantially reduce the air
emissions and associated impacts from Shell's exploration drilling program in the Chukchi Sea.
EPA is offering ICAS and the Native Village of Point Hope, the tribal governments that
requested consultation on the August 2009 initial proposed permit, the opportunity to consult on
this new modified proposed permit. Whenever possible, EPA will accommodate requests for
consultation received any time during the permitting process.
In addition to notifying these tribal governments of the opportunity for government-to-
government consultation, EPA will also notify tribal entities of the opportunity to provide public
comment on the proposed permit during the public comment period and to attend and provide
testimony during the scheduled public hearing.
6.6 National Environmental Policy Act
The National Environmental Policy Act (NEPA) establishes a national environmental policy and
goals for the protection, maintenance, and enhancement of the environment. NEPA includes a
process for implementing these goals by federal agencies when they undertake major federal
actions. The NEPA process involves an assessment of the environmental effects of a proposed
action and alternatives. For projects that have the potential for significant environmental effects
or that are environmentally controversial, a detailed statement called an Environmental Impact
Statement (EIS) is prepared.
Section 7(c) of the Energy Supply and Environmental Coordination Act of 1974 specifically
exempts actions under the CAA, including issuance PSD permits, from the requirements of
NEPA. EPA is therefore not required to develop an EIS prior to issuance of this permit.
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2009, Subject: North Slope Air Quality Control Region.
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Revised, Frontier Discoverer Chukchi Sea Exploration Drilling Program dated February 23,
2009.
Shell 5/29/09 Supp. App. Letter from Susan Childs, Shell, to Janis Hastings, EPA, dated May
29, 2009, re: Shell Offshore Inc. - Updated Response to March 12, 2009, Second EPA Letter of
Incompleteness.
Shell 9/17/09 Comments. Letter from Susan Childs, Shell, to EPA, dated September 17, 2009,
re: Shell Gulf of Mexico Inc. Comments on August 2009 Proposed Discoverer/Chukchi
OCS/PSD Permit to Construct.
Shell 10/20/09 Comments. Letter from Susan Childs, Shell, to EPA, dated October 20, 2009, re:
Shell Gulf of Mexico, Inc. Supplemental Comments on the August 2009 Proposed
Discoverer/Chukchi OCS/PSD Permit to Construct.
Shell 11/23/09 Supp. App. Letter from Susan Childs, Shell to Janis Hastings, dated November
23, 2009, re: Supplemental Application Support Materials in Response to November 17, 2009
Meeting.
Shell 12/9/09 Supp. App. Letter from Susan Childs, Shell to Rick Albright, EPA, dated
December 9, 2009, re: Shell Gulf of Mexico Inc. Supplement to Application for
Discover/Chukchi OCS/PSD Permit.
Shell 12/13/09 Supp. App. Letter from Susan Childs, Shell, to Rick Albright, EPA, dated
December 13, 2009, re: Shell Gulf of Mexico Inc. Supplement to Application for
Discoverer/Chukchi OCS/PSD Permit including Attachments A -1.
TRC 6/3/07. E-mail from Sabrina Pryor at Air Sciences, Inc. to PatNair, EPA, April 3, 2009, re:
Discoverer Stack Test Report -D399 (with attachment: June 13, 2007 NOx and Opacity
Emissions Testing Report of Frontier Discoverer, TRC Environmental Corporation, Woodinville,
Washington)
Venoco 4/19/02. Letter from Stephen Greig, Venoco Inc. to Eric Peterson, Santa Barbara
County APCD and Cy Oggins, CA State Lands Commission dated April 19, 2002, Subject:
Platform Holly Drilling Mud Degasser.
128
-------
Statement of Basis - Permit No. R100CS/PSD-AK-09-01
Frontier Discoverer Drillship - Chukchi Sea Exploration Drilling Program
WRAP 11/28/05. Offroad Diesel Retrofit Guidance Document, Volume 2, Retrofit
Technologies, Applications and Experience. Emissions Advantage. LLC. November 18, 2005.
129
-------
APPENDIX A (Revised January 5, 2010)
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Potential to Emit Emission Inventory
Summary of Annual Emissions
Frontier Discoverer Sources
Unit ID
Description
Make/Model
Potential to Emit
(tons/year)
CO
NOx
PM2.5
PM10
o
voc
Lead
FD-1
Generator Engine
Caterpillar D399
0.56
1.55
0.40
0.40
0.02
0.08
4.04E-04
FD-2
Generator Engine
Caterpillar D399
0.56
1.55
0.40
0.40
0.02
0.08
4.04E-04
FD-3
Generator Engine
Caterpillar D399
0.56
1.55
0.40
0.40
0.02
0.08
4.04E-04
FD-4
Generator Engine
Caterpillar D399
0.56
1.55
0.40
0.40
0.02
0.08
4.04E-04
FD-5
Generator Engine
Caterpillar D399
0.56
1.55
0.40
0.40
0.02
0.08
4.04E-04
FD-6
Generator Engine
Caterpillar D399
0.56
1.55
0.40
0.40
0.02
0.08
4.04E-04
FD-71
Propulsion Engine
Ml / 6UEC65
0.00
0.00
0.00
0.00
0.00
0.00
0.00
FD-8
Emergency Generator
Caterpillar 3304
4.30E-02
7.82E-02
1.54E-02
1.54E-02
3.51 E-05
8.16E-03
6.38E-07
FD-9-112
MLC Compressor
Caterpillar C-15
2.50
5.37
0.13
0.13
8.63E-03
5.37
1.57E-04
FD-12-133'4
HPU Engine
Detroit/8V71
0.25
8.18
0.16
0.16
4.71 E-03
0.12
8.56E-05
FD-14-15s
Deck Cranes
Caterpillar D343
0.20
9.50
0.07
0.07
6.76E-03
0.06
1.23E-04
FD-16-206
Cementing Units and Logging Winches
Various
0.66
11.84
0.29
0.29
5.71 E-03
3.01
1.04E-04
FD-21
Heat Boiler
Clayton 200 Boiler
1.25
3.23
0.38
0.38
2.56E-02
0.02
1.45E-04
FD-22
Heat Boiler
Clayton 200 Boiler
1.25
3.23
0.38
0.38
2.56E-02
0.02
1.45E-04
FD-23
Incinerator
TeamTec GS500C
0.39
0.06
0.09
0.10
0.03
0.04
2.68E-03
FD-24-307
Fuel Tanks
NA
0.01
FD-31
Supply Ship at Discoverer
NA
0.09
0.43
0.03
0.03
1.56E-04
0.03
2.85E-06
FD-328
Drilling Mud System
NA
0.06
FD-339
Shallow Gas Diverter System
NA
0.00
Sub-Total Emissions from Frontier Discoverer 10.00 51.23 3.95 3.96 0.23 9.23 0.01
Associated Fleets
Potential to Emit
(tons/year)
Description
CO
NOx
PM2.5
PM10
so2
VOC
Lead
Ice Management Fleet - Generic
Ice Breaker# 1
Ice Breaker #2
160.50
237.17
849.88
71.19
33.60
11.15
38.43
11.79
0.65
0.68
35.87
27.69
3.74E-02
3.73E-02
Resupply Ship - Generic
0.56
4.24
0.26
0.32
1.13E-03
0.10
2.06E-05
OSR Fleet - Generic
Nanuq - Main Ship
Oil Spill Response, Kvichak No. 1, 2 and 3 Work Boats
39.14
1.72
172.35
39.39
1.86
0.78
2.51
0.78
0.39
0.04
13.59
0.80
2.81 E-02
7.51 E-04
Sub-Total Emissions from Fleets 439.08 1,137.04 47.64 53.82 1.76 78.05 0.10
TOTAL PROJECT EMISSIONS 449.08 1188.27 51.58 57.78 1.99 87.28 0.11
Notes
1 Propulsion engine is not used when Discoverer is an OCS Source
2 Combined use of all 3 MLC Compressor engines are limited by an aggregate fuel usage limit.
3 Combined use of both HPU are limited by an aggregate fuel usage limit.
4 PTE of HPU Units and Incinerator are based on maximum use of that emission unit in accordance with alternative operating scenarios.
5 Combined use of both deck cranes are limited by an aggregate fuel usage limit.
6 Combined use of all five cementing unit and logging winch engines are limited by an aggregate fuel usage limit.
7 Tanks calculations and software outputs are listed separately but are summarized in this table.
8 Drilling mud system calculations are listed separately but are summarized in this table.
9 Shallow gas diverter system is not expected to be used as part of planned operations
1/5/2010
Page A-1 ofA-25
-------
Shell Offshore Inc.
OCS/PSD Permit for
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Operating Level5:
Maximum Hourly Fuel Use3'5:
Control Equipment:
Emissions are on a per-engine basis
Pollutant
Emission
Factors4
Emission Factor
Units
Maximum Hours of
Operation
Control
Efficiency6
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
882.7
g/hr
24
4032
0.8
0.28
6.72
0.56
0.035
0.035
0.016
NOx
0.5
g/kW-h
24
4032
0.77
18.48
1.55
0.097
0.097
0.045
PM2.5
251.2
g/hr
24
4032
0.5
0.20
4.8
0.40
0.025
0.025
0.012
PM10
251.2
g/hr
24
4032
0.5
0.20
4.8
0.40
0.025
0.025
0.012
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
Emissions are on a per-engine basis.
Pollutant
Emission
Factors
Emission
Factor Units
Maximum Hours of
Operation4
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
6.2
g/hp-hr
2.00
48
1.79
3.58
4.30E-02
0.226
0.019
1.24E-03
NOx
11.28
g/hp-hr
2.00
48
3.26
6.52
7.82E-02
0.411
0.034
2.25E-03
PM2.5
2.21
g/hp-hr
2.00
48
0.64
1.28
1.54E-02
0.081
0.007
4.42E-04
PM10
2.21
g/hp-hr
2.00
48
0.64
1.28
1.54E-02
0.081
0.007
4.42E-04
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3:
Control Equipment:
FD-9-11 MLC Compressor
Caterpillar C-15
Liquid distillate, #1 or #2
540 hp
190 lbs/hour
Tier 3 engines
Hourly and daily emissions are on a per-engine basis. Annual emissions are for all three MLC compressor engines in aggregate.
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Operation4'5
Control
Efficiency6
Potential to Emit
Potential to Emit in g/sec
Daily (hrs)
Annual (gal)
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
1.86
g/kW-h
24
81,346
1.65
39.6
2.50
0.208
0.208
0.072
NOx
4.0
g/kW-h
24
81,346
3.55
85.2
5.37
0.447
0.447
0.154
PM2.5
0.2
g/kW-h
24
81,346
0.5
0.1
2.4
0.13
0.013
0.013
0.004
PM10
0.2
g/kW-h
24
81,346
0.5
0.1
2.4
0.13
0.013
0.013
0.004
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
FD-12-13 HPU Engine
Detroit 8V-71
Liquid distillate, #1 or #2
250 hp
104 lbs/hour
Clean Air Systems PERMIT™ Filter for control of CO, PM2.5, PM10and VOC
Hourly emissions are on a per-engine basis. Daily and annual emissions are for both HPU engines in aggregate.
Maximum Operation6'7
Potential to Emit
Potential to Emit in g/sec
Pollutant
Emission
Factors
Emission Factor
Units
Daily (gal)
Annual8 (gal)
Control
Efficiency4'5
Hourly,
Ib/hr
Daily7,
lb/day
Annual7,
tPV
One-Hour
24-Hour
365-Day
Base Case S
:enario
Base Case Scenario
CO
2.99
g/hp-hr
0
44,338
0.9
0
0
0.25
0
0
0.007
NOx
9.81
g/hp-hr
0
44338
0
0
8.18
0
0
0.235
PM2.5
1.26
g/hp-hr
0
44338
0.85
0
0
0.16
0
0
0.005
PM10
1.26
g/hp-hr
0
44338
0.85
0
0
0.16
0
0
0.005
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
FD-14-15 Deck Cranes
Caterpillar D343
Liquid distillate, #1 or #2
365 hp
20.76 gallons/hour
Clean Air Systems PERMIT™ Filter for control of CO, PM2.5, PM10and VOC
Hourly and daily emissions are on a per-engine basis. Annual emissions are for both deck cranes in aggregate.
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Operation6,8
Control
Efficiency4'5
Potential to Emit
Potential to Emit in g/sec
Daily (hrs)
Annual (gal)8
Hourly, Ib/hr
Daily, lb/day
Annual8, tpy
One-Hour
24-Hour
365-Day
CO
593.6
g/hr
24
63,661
0.9
0.13
3.12
0.20
0.016
0.016
0.006
NOx
2810.9
g/hr
24
63,661
6.2
148.80
9.50
0.781
0.781
0.273
PM2.5
129.8
g/hr
24
63,661
0.85
0.04
0.96
0.07
0.005
0.005
0.002
PM10
129.8
g/hr
24
63,661
0.85
0.04
0.96
0.07
0.005
0.005
0.002
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
FD-16-17 Cementing Unit
Detroit 8V-71N
Liquid distillate, #1 or #2
335 hp
139 lbs/hour
Clean Air Systems PERMIT™ Filter for control of CO, PM2.5, PM10 and VOC
Emissions are on a per engine basis at 100% load
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation6
Control Efficiency4'5
Potential to Emit6
Potential to Emit in g/sec
Daily
Annual
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
One-Hour
CO
2.99
g/hp-hr
0.9
0.22
0.028
NOx
9.81
g/hp-hr
7.25
0.913
PM2.5
1.26
g/hp-hr
0.85
0.14
0.018
PM10
1.26
g/hp-hr
0.85
0.14
0.018
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
Emissions are on a per-engine basis.
Pollutant
Emission
Factors6
Emission Factor
Units
Maximum Hours of
Operation7
Control Efficiency4'5
Potential to Emit7
Potential to Emit in g/sec
Daily
Annual
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
One-Hour
CO
6.55
g/hp-hr
0.9
0.21
0.026
NOx
11.72
g/hp-hr
3.8
0.479
PM2.5
1.92
g/hp-hr
0.85
0.09
0.011
PM10
1.92
g/hp-hr
0.85
0.09
0.011
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
Emissions are on a per-engine basis.
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation4
Control
Efficiency5
Potential to Emit4
Potential to Emit in g/sec
Daily
Annual
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
One-Hour
CO
3.5
g/kW-h
0.8
0.29
0.037
NOx
4.0
g/kW-h
1.64
0.207
PM2.5
0.2
g/kW-h
0.85
0.01
0.001
PM10
0.2
g/kW-h
0.85
0.01
0.001
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3
Control Equipment:
Emissions are on a per-engine basis.
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation7
Control Efficiency4'5
Potential to Emit7
Potential to Emit in g/sec
Daily
Annual
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
One-Hour
CO
5.5
g/kW-hr
0.9
0.03
0.004
NOx
7.5
g/kW-hr
0.43
0.054
PM2.5
0.60
g/kW-hr
0.85
0.01
0.001
PM10
0.60
g/kW-hr
0.85
0.01
0.001
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model:
Fuel:
Rating:
Control Equipment:
FD-16-20 Cementing Units and Logging Winches
See pages A-7 - A-10 for details
Liquid distillate, #1 or #2
See pages A-7 - A-10 for details
Clean Air Systems PERMIT™ Filter for control of CO, PM2.5, PM10 and VOC on all engines except FD-19
Emissions are for all cementing unit and logging winch engines in aggregate.
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Operation1
Control
Efficiency3
Potential to Emit2
Daily (gal)
Annual (gal)
Hourly, Ib/hr
Daily, lb/day
Annual, tpy
CO
0.66
g/hp-hr
320
53,760
7.88
0.66
NOx
11.72
g/hp-hr
320
53,760
140.98
11.84
PM2.5
0.288
g/hp-hr
320
53,760
3.46
0.29
PM10
0.288
g/hp-hr
320
53,760
3.46
0.29
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit:
Make/Model1:
Fuel:
Rating2:
Maximum Hourly Fuel Use3:
Control Equipment:
FD-21-22 Heat Boilers
Clayton 200
Liquid distillate, #1 or #2
7.97 MMBtu/hr
424 lbs/hour
None
Emissions are on a per-boiler basis at 100% load
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
14.8
lbs/day
24
4,032
0.62
14.8
1.25
0.078
0.078
0.036
NOx
38.50
lbs/day
24
4,032
1.6
38.50
3.23
0.202
0.202
0.093
PM2.5
4.50
lbs/day
24
4,032
0.19
4.50
0.38
0.024
0.024
0.011
PM10
4.50
lbs/day
24
4,032
0.19
4.50
0.38
0.024
0.024
0.011
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Emissions Unit: FD-23 Incinerator
Make/Model1: T eamT ec GS500C
Fuel2: Waste material
Rating3: 276 lbs/hour converted from 125 kg/hr
Control Equipment: None
Hourly emissions are for one incinerator at 100% load
Maximum Operation, lbs
of Waste4
Potential to Emit
Pollutant
Emission
Factors
Emission Factor
Units
Daily
Annual5
Control
Efficiency
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
Base Case Scenario
CO
31
lbs/ton
1300
50,400
4.28
20.15
0.39
NOx
5
lbs/ton
1300
50,400
0.69
3.25
0.06
PM2.5
7.00
lbs/ton
1300
50,400
0.97
4.55
0.09
PM10
8.2
lbs/ton
1300
50,400
1.13
5.33
0.10
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit: FD-31 Supply Ship at Discoverer
Fuel: Liquid distillate, #1 or #2
Equipment Type: Internal Combustion Engine
Rating1: 292 hp
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation2
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
0.95
Ib/MMBtu
12
96
1.94
23.30
0.09
0.245
0.122
2.68E-03
NOx
4.41
Ib/MMBtu
12
96
9.01
108.17
0.43
1.136
0.568
1.24E-02
PM2.5
0.31
Ib/MMBtu
12
96
0.63
7.60
0.03
0.080
0.040
8.75E-04
PM10
0.31
Ib/MMBtu
12
96
0.63
7.60
0.03
0.080
0.040
8.75E-04
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit
Fuel:
Ice Breaker #1
Liquid distillate, #1 or #2, and waste materials for incinerator
Equipment Type:
Aggregate Rating, Propulsion Engines1:
Max. Aggregate Limit, Propulsion Engines2:
Aggregate Rating, Generation Engines1:
Max. Aggregate Limit, All Engines2:
Max. Aggregate Limit, All Engines3:
Internal Combustion Engines
28400
22720
2800
19,030
17,508
hp
hp
hp
kW
kWe
mechanical kW
electrical kW
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Operation
(kWe-hr)
Control
Efficiency
Potential to Emit3
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
3.35
g/kW-hr
420,188
28,233,704
140.36
3,368.64
113.17
17.685
17.685
3.256
NOx
5.876
Ib/MMBtu
420,188
28,233,704
1049.69
25,192.53
846.38
132.258
132.258
24.347
PM2.5
0.22
Ib/MMBtu
420,188
28,233,704
39.30
943.22
31.69
4.952
4.952
0.912
PM10
0.249
Ib/MMBtu
420,188
28,233,704
44.48
1067.55
35.87
5.605
5.605
1.032
S02
0.000030
lb/lb
420,188
28,233,704
0.28
6.84
0.23
0.036
0.036
0.007
VOC
0.60
g/kW-hr
420,188
28,233,704
25.17
604.15
20.30
3.172
3.172
0.584
Lead
2.90E-05
Ib/MMBtu
420,188
28,233,704
5.18E-03
0.12
4.18E-03
6.53E-04
6.53E-04
1.20E-04
Emissions Factor References
CO, VOC From maximum of AP-42, Section 3.4, Table 3.4-1 or IVL and Lloyd's data from
Verification of Ship Emission Estimates with Monitoring Measurements to Improve Inventory Modeling, Final Report
Prepared for California Air Resource Board, by James J. Corbett, 23 November 2004 - see page 25
NOx Emission factors relied upon by Shell in 9/17/2009 submittal to establish annual, owner-requested emission limits
pm2.5, PM10 Emission factors relied upon by Shell in 9/17/2009 submittal to establish daily, owner-requested emission limits
S02 Based on fuel sulfur content: 0.000015 by weight
Lead Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA-454/R-98-006, May 1998, page 5-45
Aggregate Rating, Heat Boiler(s)1: 10 00 MMBtu/hr
Maximum Hourly Fuel Use5: 75 gallons/hour
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
5
lb/103 gal
24
4,032
3.76E-01
9.02
0.76
0.047
0.047
0.022
NOx
20.00
lb/103 gal
24
4,032
1.50E+00
36.06
3.03
0.189
0.189
0.087
PM2.5
3.30
lb/103 gal
24
4,032
2.48E-01
5.95
0.50
0.031
0.031
0.014
PM10
3.30
lb/103 gal
24
4,032
2.48E-01
5.95
0.50
0.031
0.031
0.014
S02
0.213
lb/103 gal
24
4,032
1.60E-02
0.38
0.03
2.02E-03
2.02E-03
9.28E-04
VOC
0.34
lb/103 gal
24
4,032
2.55E-02
0.61
0.05
3.22E-03
3.22E-03
1.48E-03
Lead
0.000009
Ib/MMBtu
24
4,032
9.00E-05
0.00
1.81E-04
1.13E-05
1.13E-05
5.22E-06
Emissions Factor References
CO, NOx AP-42 Table 1.3-1, boilers < 100 MMBtu/hr
PM2.5 Assumed to be same as for PM10
PM10 AP-42 Table 1.3-1 (filterable for PM) and AP-42 Table 1.3-2 (total condensible)
S02 AP-42 Table 1.3-1, boilers < 100 MMBtu/hr a Sulfur content of fuel: 0.000015 byweight
VOC AP-42 Table 1.3-3, commercial boilers
Lead AP-42, Table 1.3-10
Equipment Type: Incinerator
Aggregate Rating1: 154.00 Ib/hr Emissions are for all incinerators on board the vessel
Maximum Hours of
Operation
Potential to Emit
Potential to Emit in g/sec
Pollutant
Emission
Factors
Emission Factor
Units
Daily
Annual
Control
Efficiency
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
300
lbs/ton
24
4032
23.10
554.40
46.57
2.911
2.911
1.34
NOx
3
lbs/ton
24
4032
0.23
5.54
0.47
0.029
0.029
0.014
PM2.5
9.1
lbs/ton
24
4032
0.70
16.82
1.41
0.088
0.088
0.041
PM10
13.3
lbs/ton
24
4032
1.02
24.58
2.06
0.129
0.129
0.059
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit: Ice Breaker #1
(CONTINUED)
Total Emissions for Icebreaker #1
Potential to Emit
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
163.84
3932.06
160.50
1051.42
25234.14
849.88
40.25
965.99
33.60
45.75
1098.08
38.43
0.49
11.84
0.65
32.90
789.56
35.87
0.02
0.52
3.74E-02
Potential to Emit in g/sec
One-Hour
24-Hour
365-Day
20.643
20.643
4.617
132.476
132.476
24.448
5.071
5.071
0.967
5.765
5.765
1.105
0.062
0.062
0.019
4.145
4.145
1.032
2.73E-03
2.73E-03
1.08E-03
Conversions Used
453.59 g/lb
2,000 lbs/ton
745.7 watts/hp
7.076 lbs/gal
133,098 Btu/gal
Footnotes/Assumptions
1 Maximum equipment ratings per e-mail and attachments of 5/14/2009 from Air Sciences (Rodger Steen) to EPA (Pat Nair):
Propulsion engines: 28400 hp at maximum 80% load
Generator engines: 2800 hp
Boilers: 10 MMBtu/hr
Incinerator: 154 Ib/hr
2 Fuel usage from AP-42, Section 3.3, brake specific fuel consumption from footnote c to Table 3.3.1
7000 Btu/hp-hr converted based on aggregate engine rating, and fuel density and heat content
3 Minimum generator efficiency based on conservative data from Shell submittal to EPA dated 11/23/2009 (pages 6 - 7):
Engine minimum generator efficiency: 92%
4 Owner requested limits: PM2.5 hourly emissions limit: 42.2 lbs
PM10 hourly emissions limit: 48.0 lbs
1/5/2010
Page 16 of 25
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit:
Fuel:
Ice Breaker #2 - Tor Viking Scenario
Liquid distillate, #1 or #2, and waste materials for incinerator
Equipment Type:
Aggregate Rating, Propulsion Engines1:
Max. Aggregate Limit, Propulsion Engines2:
Aggregate Rating, Generation Engines1:
Max. Aggregate Limit, All Engines2:
Max. Aggregate Limit. All Engines3:
Internal Combustion Engines
17660
14128
2336
12,277
11,786
hp
hp
hp
kW
kWe
mechanical kW
electrical kW
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Operation
(kWe-hr)
Control
Efficiency
Potential to Emit4
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
3.35
g/kW-hr
282,867
18,058,216
90.55
2173.25
69.37
11.409
11.409
1.996
NOx
0.106
lb/gal
282,867
18,058,216
91.78
2202.82
70.31
11.565
11.565
2.023
PM2.5
0.0573
Ib/MMBtu
282,867
18,058,216
6.60
158.49
5.06
0.832
0.832
0.146
PM10
0.0573
Ib/MMBtu
282,867
18,058,216
6.60
158.49
5.06
0.832
0.832
0.146
-------
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit:
Ice Breaker #2 - Tor Viking Scenario
(CONTINUED)
Total Emissions for Tor Viking
Potential to Emit
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
113.29
2718.91
115.20
92.22
2213.20
71.19
7.33
175.82
6.52
7.64
183.44
7.16
0.38
9.00
0.53
23.81
571.32
27.69
1.95E-02
0.47
3.51 E-02
Potential to Emit in g/sec
One-Hour
24-Hour
365-Day
14.274
14.274
3.314
11.619
11.619
2.048
0.923
0.923
0.187
0.963
0.963
0.206
0.047
0.047
0.015
2.999
2.999
0.796
2.45E-03
2.45E-03
1.01E-03
Maximum Emissions for lcebreaker#2 ( max of Tor Viking and Hull
Potential to Emit
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
234.48
5627.51
237.17
92.22
2213.20
71.19
11.37
272.87
11.15
11.69
280.49
11.79
0.51
12.19
0.68
23.81
571.32
27.69
2.14E-02
0.51
3.73E-02
Potential to Emit in g/sec
One-Hour
24-Hour
365-Day
29.544
29.544
6.822
11.619
11.619
2.048
1.433
1.433
0.321
1.473
1.473
0.339
0.064
0.064
0.019
2.999
2.999
0.796
2.69E-03
2.69E-03
1.07E-03
Conversions Used
453.59 g/lb
2,000 lbs/ton
745.7 watts/hp
7.076 lbs/gal
133,098 Btu/gal
Footnotes/Assumptions
1 Maximum equipment ratings per Shell submittal to EPA dated 9/17/2009:
Propulsion engines: 17660 hp at maximum
Non-propulsion Generator engines: 2336 hp
Boilers: 1.37 MMBtu/hr
Incinerator: 151.23 Ib/hr
2 Maximum operating limit Shell submittal to EPA dated 9/17/2009 (Attachment A, page 23):
Propulsion engines, in aggregate: 80%
3 Minimum generator efficiency based on MaK engine specs per Shell submittal to EPA dated 11/23/2009 (Attachment B, page 14):
Propulsion engine minimum generator efficiency: 96%
4 Fuel usage from AP-42, Section 3.3, brake specific fuel consumption from footnote cto Table 3.3.1
7000 Btu/hp-hr converted based on aggregate engine rating, and fuel density and heat content
1/5/2010
Page 18 of 25
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit
Fuel:
Ice Breaker #2- Hull 247
Liquid distillate, #1 or #2, and waste materials for incinerator
Internal Combustion Engines
24000 kW mechanical kW
19200 kW mechanical kW
17664 kWe electrical kW
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Operation
(kWe-hr)
Control
Efficiency
Potential to Emit4
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
5.0
g/kW-hr
423,936
31,904,074
211.64
5,079.48
191.13
26.667
26.667
5.498
NOx
1.8
g/kW-hr
423,936
31,904,074
76.19
1,828.61
68.81
9.6
9.6
1.979
PM2.5
0.25
g/kW-hr
423,936
31,904,074
10.58
253.97
9.56
1.333
1.333
0.275
PM10
0.25
g/kW-hr
423,936
31,904,074
10.58
253.97
9.56
1.333
1.333
0.275
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit: Ice Breaker #2 - Hull 247
(CONTINUED)
Total Emissions for Hull 247
Potential to Emit
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
234.48
5627.51
237.17
77.02
1848.48
70.48
11.37
272.87
11.15
11.69
280.49
11.79
0.51
12.19
0.68
15.61
374.74
22.52
2.14E-02
0.51
3.73E-02
Potential to Emit in g/sec
One-Hour
24-Hour
365-Day
29.544
29.544
6.822
9.704
9.704
2.027
1.433
1.433
0.321
1.473
1.473
0.339
0.064
0.064
0.019
1.967
1.967
0.648
2.69E-03
2.69E-03
1.07E-03
Conversions Used
453.59 g/lb
2,000 lbs/ton
745.7 watts/hp
7.076 lbs/gal
133,098 Btu/gal
Footnotes/Assumptions
1 Maximum equipment ratings per Shell submittal to EPA dated 9/17/2009 (Attachment A, page 23):
Propulsion engines: 24000 kW mechanical
Non-propulsion Generator engines: 0 hp
Boilers: 4 MMBtu/hr
Incinerator: 151.23 Ib/hr
2 Maximum operating limit Shell submittal to EPA dated 9/17/2009 (Attachment A, page 23):
Propulsion engines, in aggrega 80%
3 Minimum generator efficiency based on Shell submittal to EPA dated 11/23/2009:
Propulsion engine minimum generator efficiency: 92%
4 Fuel usage from AP-42, Section 3.3, brake specific fuel consumption from footnote cto Table 3.3.1
7000 Btu/hp-hr
5 Shell has requested an annual NOx limit of 58.39 tpy per 9/17/2009 submittal
6 Fuel usage converted based on boiler rating and fuel heat content.
1/5/2010
Page 20 of 25
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit: Supply Ship - Generic
Fuel: Liquid distillate, #1 or #2
Equipment Type: Internal Combustion Engines
Aggregate Rating1: 7784 hp
Owner Requested Limit (Daily, Annual)2: 6344 hp Emissions are for all engines in aggregate.
Maximum Hourly Fuel Use2: 334 gallons/hour
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation4
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
lb/hr1
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
3.35
g/kW-hr
4
32
34.89
139.57
0.56
4.396
0.733
0.016
NOx
25.40
g/kW-hr
4
32
264.92
1059.68
4.24
33.379
5.563
0.122
PM2.5
1.54
g/kW-hr
4
32
16.06
64.25
0.26
2.024
0.337
0.007
PM10
1.92
g/kW-hr
4
32
20.02
80.10
0.32
2.523
0.421
0.009
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit: Oil Spill Response Main Ship - Nanuq
Fuel: Liquid distillate, #1 or #2, and waste materials for incinerator
Equipment Type: Propulsion Engines - Caterpillar 3608 Internal Combustion Engines
Aggregate Rating1: 5420 kW
Pollutant
Emission Factors
Emission Factor
Units
Maximum Operation
(gallons)2
Control
Efficiency5'6
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr3
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
0.73
g/kW-hr
3,000
504,000
0.9
0.87
7.57
0.64
0.11
0.04
0.018
NOx
13.62
g/kW-hr
3,000
504,000
162.70
1412.02
118.61
20.5
7.413
3.412
PM2.5
0.17
g/kW-hr
3,000
504,000
0.85
0.30
2.64
0.22
0.038
0.014
0.006
PM10
0.17
g/kW-hr
3,000
504,000
0.85
0.30
2.64
0.22
0.038
0.014
0.006
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit:
Oil Spill Response Main Ship - Nanuq
(CONTINUED)
Footnotes/Assumptions
1 Equipment population, rating and usage based on vessel Nanuq per permit application dated February 23, 2009, Appendix B, page 16
Hourly emissions are based on the aggregate rating of all equipment on board except for the emergency generator
2 Owner requested limits per e-mail and attachments of 5/14/2009 from Air Sciences (Rodger Steen) to EPA (Pat Nair), and
Shell's updated request dated 9/17/2009:
4 Fuel usage from AP-42, Section 3.3, brake specific fuel consumption from footnote c to Table 3.3.1
7000 Btu/hp-hr converted based on aggregate engine rating, and fuel density and heat content
5 PM10 control efficiency based on California Air Resources Board, Verification of Diesel Emission Control Strategies, 3/12/2009 (website),
April 24, 2009 letter from CleanAIR Systems and April 20, 2007 quote from CleanAIR Systems, transmitted by April 27, 2009 e-mail from
Air Sciences (Rodger Steen) to EPA (Pat Nair)
6 CO and VOC control efficiency from April 24, 2009 letter from CleanAIR Systems and April 20, 2007 quote from CleanAIR Systems,
Propulsion Engines expected to not exceed (in aggregate):
Maximum fuel usage:
Generator usage expected to not exceed (in aggregate):
Maximum fuel usage:
47000 kW-hr/day
3000 gal/day
11,350 kW-hr/day
800 gal/day
204.7 g/kW-hr
3 Fuel usage per permit application dated 2/23/2009, Appendix B, page 51
1/5/2010
Page A-23 of A-25
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Fleet Unit
Fuel:
Oil Spill Response, Kvichak 34-foot No. 1, 2 and 3 Work Boats (three)
Liquid distillate, #1 or #2
Equipment Type: Internal Combustion Engines - propulsion
Make/Model1: Cummins QSB
Aggregate Rating1: 1800 hp Emissions are for all Cummins QSB engines
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
0.155
g/hp-hr
24
4,032
0.62
15
1.24
0.078
0.078
0.036
NOx
4.644
g/hp-hr
24
4,032
18.43
442
37.15
2.322
2.322
1.069
PM2.5
0.077
g/hp-hr
24
4,032
0.31
7
0.62
0.039
0.039
0.018
PM10
0.077
g/hp-hr
24
4,032
0.31
7
0.62
0.039
0.039
0.018
O
0.000030
lb/lb fuel
24
4,032
0.02
0
0.04
0.003
0.003
0.001
VOC
0.078
g/hp-hr
24
4,032
0.31
7
0.62
0.039
0.039
0.018
Lead
0.000029
Ib/MMBtu
24
4,032
3.65E-04
0.01
7.37E-04
4.60E-05
4.604E-05
2.12E-05
Emissions Factor References
CO, NOx, PM2.5, PMio, VOC From permit application dated February 23, 2009, Appendix B, page 64
PM2.5 and PM10 emissions assumed to be same as PM emissions
Lead Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA-454/R-98-006, May 1998, page 5-45
Equipment Type: Internal Combustion Engines - generators
Aggregate Rating1: 36 h]3 Emissions are for all generator engines
Pollutant
Emission
Factors
Emission Factor
Units
Maximum Hours of
Operation
Control
Efficiency
Potential to Emit
Potential to Emit in g/sec
Daily
Annual
Hourly,
Ib/hr
Daily,
lb/day
Annual, tpy
One-Hour
24-Hour
365-Day
CO
0.95
Ib/MMBtu
24
4,032
0.24
6
0.48
0.03
0.03
0.014
NOx
4.410
Ib/MMBtu
24
4,032
1.11
27
2.24
0.14
0.14
0.064
PM2.5
0.31
Ib/MMBtu
24
4,032
0.08
2
0.16
0.01
0.01
0.005
PM10
0.31
Ib/MMBtu
24
4,032
0.08
2
0.16
0.01
0.01
0.005
O
(/)
0.000030
lb/lb fuel
24
4,032
4.02E-04
1.00E-02
8.10E-04
0
0
0
VOC
0.35
Ib/MMBtu
24
4,032
0.09
2
0.18
0.011
0.011
0.005
Lead
0.000029
Ib/MMBtu
24
4,032
7.31 E-06
1.75E-04
1.47E-05
9.21 E-07
9.208E-07
4.24E-07
Emissions Factor References
CO, NOx, PM2.5, PM10, VOC From AP-42, Section 3.3, Table 3.3-1
Lead Locating and Estimating Air Emissions from Sources of Lead and Lead Compounds, EPA-454/R-98-006, May 1998, page 5-45
Conversions Used
453.59 g/lb
2,000 lbs/ton
745.7 watts/hp
7.076 lbs/gal
133,098 Btu/gal
Footnotes/Assumptions
1 Equipment population, rating and usage based on 3 work boats per permit application dated February 23, 2009, Appendix B,
pages 16, 67 - Each of three identical Kvichak 34-foot boats has two 305 hp propulsion engines and a 12 hp generator
2 7000 Btu/hp-hr converted based on aggregate engine rating, and fuel density and heat content
3 Sulfur content of fuel: 0.000015 by weight
1/5/2010
Page A-24 of A-25
-------
Shell Offshore Inc.
OCS/PSD Permit for
Frontier Discoverer Chukchi Sea Exploration Drilling Program
Criteria Pollutant Emission Inventory
Reference Table 1
Fuel Properties for Distillate Fuel Used on All Emission Units on the Discoverer
Fuel heat
value:
Fuel density:
133,098 Btu/gal
847.9 kg/m3
7.076 lbs/gal
Keiser, Ronald email to Chris Tengco, 01/26/09, see permit application dated February 23,
2009, Appendix F, page 27.
SCANRAFF-Vladimir Ignatjuk Certificate of Quality. 09/19/04.
converted based on 453.59 g/lb and
264.17 gal/m3
Reference Table 2
Comparison of Controlled Emission Factors for Cementing Units and Logging Winches
Pollutant
Detroit
8V71N
Emission
Factors
cont. (g/hp-
hr)
Detroit 3V-
71
Emission
Factors
cont. (g/hp-
hr)
John Deere
Emission
Factors,
cont. (g/kW-
hr)
John Deere
Emission
Factors,
cont. (g/hp-
hr)
Caterpillar
C7
Emission
Factors, cont.
(g/kW-hr)
Caterpillar
C7
Emission
Factors,
uncont. (g/hp-
hr)
Maximum
Emission
Factor
Emission
Factor Units
CO
0.299
0.66
0.55
0.41
0.70
0.52
0.66
g/hp-hr
NOx
9.81
11.72
7.5
5.59
4.0
2.98
11.72
g/hp-hr
PM2.5
0.19
0.29
0.09
0.07
0.03
0.02
0.29
g/hp-hr
PM-io
0.19
0.29
0.09
0.07
0.03
0.02
0.29
g/hp-hr
VOC
0.148
0.20
0.75
0.56
4.0
2.98
2.98
g/hp-hr
S02 emissions not compared as they are based on mass balance
Reference Table 3
Comparison of Emission Factors for Marine Engines
AP-42
Maximum
Section 3.4
IV L
Lloyd's
EF
Pollutant
Ib/hp-hr
g/kW-hr
g/kW-hr
g/kW-hr
g/kW-hr
CO
5.50E-03
3.35
1.4
1.6
3.35
NOx5
0.056
25.40
18.1
17
25.40
PM2.5
0.00056
0.34
1.54
1.54
PM10
0.00058
0.35
1.92
1.5
1.92
S025
1.2135E-05
0.01
0
0.798
0.80
VOC
0.000705
0.43
0.6
0.5
0.60
Reference Table 4
Comparison of Emission Factors for
Marine Engines and External Combustion
AP_42
Maximum
Marine
Marine
Engine
Engine
Section 1.3
Tables 1 to
EF
EF
EF1
3
Pollutant
g/kW-hr
lb/103 gal
lb/103 gal
lb/103 gal
CO
3.35
104.58
5
104.58
NOx5
25.40
794.01
20.00
794.01
PM2.5
1.54
48.14
3.30
48.14
PM10
1.92
60.02
3.30
60.02
S025
0.80
24.94
26.98
26.98
VOC
0.60
18.76
0.34
18.76
1 Conversions based on 745.7 watts/hp
453.59 g/lb
Brake specific fuel consumption: 7000 Btu/hp-hr
1/5/2010
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APPENDIX B
ORIGINAL MODELING RESULTS FOR
SECONDARY OPERATING SCENARIOS:
ADJUSTED FOR CHANGES TO PRIMARY OPERATING
SCENARIO #1 AND
WITH MOST RECENT BACKGROUND LEVELS
1
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Table 1
Secondary Operating Scenario #1 and #2 Predicted d Total Concentration Impact Comparison with NAAQS
Air
Pollutant
Averaging
Period
Existing
(ng/m3)
Scenario a
NAAQS
(ng/m3)
Percent c
SOS #1
SOS #2
Predicted d
(ng/m3)
Total b
(ng/m3)
Predicted d
(ng/m3)
Total b
(ng/m3)
Sulfur Dioxide (S02)
3-Hour
1300
24-Hour
365
Annual
80
Nitrogen Dioxide (N02)
Annual
100
Carbon Monoxide (CO)
1-Hour
10000
8-Hour
40000
Particulate Matter equal to or
less than 10 microns (PM10)
24-Hour
91
18.92
109.92
19.40
110.40
150
73.60
Particulate Matter equal to or
less than 2.5 microns (PM2 5)
24-Hour
11
18.50
29.50
18.40
29.40
35
84.29
Annual
15
Reference: Shell 5/29/09 Rev. App.; Environ 7/15/09-PM10; Environ 7/15/09-PM2.5; Environ 7/16/09 Bow Washing"!; Environ 7/16/09-Bow
Washing2.
a. SOS #1: Discoverer bow ice removal by Ice Breaker B occurs concurrently with drilling activities.
SOS #2: Supply ship transit for replenishment of Frontier Discover occurs concurrently with drilling activities.
b. The sum of the "predicted" impact and "existing" background.
c. Percent is higher of SOS #1 and SOS #2.
d. Predicted values have been adjusted to reflect the reduction in PM10 and PM2.5 impacts from POS #1.
2
-------
Table 2
Secondary Operating Scenario #3 and #4 Predicted d Total Concentration Impact Comparison with NAAQS
Air
Pollutant
Averaging
Period
Existing
(ng/m3)
Scenario a
NAAQS
(ng/m3)
Percent c
SOS #3
SOS #4
Predicted d
(ng/m3)
Total b
(ng/m3)
Predicted d
(ng/m3)
Totalb
(ng/m3)
Sulfur Dioxide (S02)
3-Hour
17
68.80
85.80
68.80
85.80
1300
6.60
24-Hour
10
26.80
36.80
26.80
36.80
365
10.08
Annual
0.5
2.00
2.50
2.00
2.50
80
3.13
Nitrogen Dioxide (N02)
Annual
2.0
18.20
20.20
18.20
20.20
100
20.20
Carbon Monoxide (CO)
1-Hour
1050
396.60
1446.60
396.60
1446.60
10000
14.47
8-Hour
941
356.90
1297.90
356.90
1297.90
40000
3.24
Particulate Matter equal to or
less than 10 microns (PM10)
24-Hour
91
19.40
110.40
19.40
110.40
150
73.60
Particulate Matter equal to or
less than 2.5 microns (PM2 5)
24-Hour
11
18.40
29.40
18.40
29.40
35
84.00
Annual
2.8
1.30
4.10
1.30
4.10
15
27.33
Reference: Shell 5/29/09 Rev. App.
a. SOS #3: Supply ship replenishment of Discoverer occurs concurrently with drilling activities .
SOS #4: Testing of emergency generators occurs concurrently with drilling activities.
b. The sum of the "predicted" impact and "existing" background.
c. Percent is higher of SOS #3 and SOS #4.
d. Predicted values have been adjusted to reflect the reduction in impacts from POS #1.
3
-------
Table 3
Secondary Operating Scenario #5 and #6 Predicted Total Concentration Impact Comparison with NAAQS
Scenario a,b
SOS #5
SOS #6
Air
Averaging
Existing
Predicted 8
Total c
Predicted 8
Total c
NAAQS
Pollutant
Period
(ng/m3)
(ng/m3)
(ng/m3)
(ng/m3)
(ng/m3)
(ng/m3)
Percent d
Sulfur Dioxide (S02)
3-Hour
1300
24-Hour
365
Annual
80
Nitrogen Dioxide (N02)
Annual
100
Carbon Monoxide (CO)
1-Hour
10000
8-Hour
40000
Particulate Matter equal to or
less than 10 microns (PM10)
24-Hour
91
26.10
117.10
26.10
117.10
150
78.07
Particulate Matter equal to or
less than 2.5 microns (PM2 5)
24-Hour
11
17.07
28.07
17.07
28.07
35
80.20
Annual
15
Reference: Environ 7/15/09-PM10; Environ 7/15/09-PM2.5; Environ 7/16/09 Bow Washingl; Environ 7/16/09-Bow Washing2.
a. SOS #5: Anchor deployment by ice breaker.
SOS #6: Anchor retrieval by ice breaker.
b. Only PM10 and PM2.5 were modeled for SOS #5 and SOS #6 because their total concentration under POS #1 approached NAAQS.
c. The sum of the "predicted" impact and "existing" background.
d. Percent is higher of SOS #5 and SOS #6.
e. Predicted values do not reflect the reductions in PM10 and PM2.5 emissions since the original proposal.
4
-------
Table 4
Secondary Operating Scenario Predicted c Concentration Impacts Comparison
with Class II Area Air Quality Increments
Air
Pollutant
Averaging
Period
Secondary Operating Scenarios
Increment
(Hg/m3)
Percent
HI SOS a
#1
#2
#3
#4
#5
#6
Sulfur Dioxide (SO2)
3-Hour
68.80
68.80
512
13.44
24-Hour
26.80
26.80
91
29.45
Annual
2.00
2.00
20
10.00
Nitrogen Dioxide (NO2)
Annual
18.20
18.20
25
72.80
Particulate Matter equal to or
less than 10 microns (PM10)
24-Hour
18.92
19.40
19.40
19.40
26.10
26.10
30
87.00
Annual
1.90
1.90
17
11.18
Particulate Matter equal to or
less than 2.5 microns (PM2.5)
b
Reference: Shell 5/29/09 Supp. App.
a. Percent of highest prediction amongst the six scenarios.
b. EPA has not promulgated PM2.5 increments.
c. Predicted values have been adjusted to reflect the reduction in impacts from POS #1.
5
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