Outer Continental 

Shelf 

Pre-Construction 

Air Permit Application 

Revised 

Frontier Discoverer 

Chukchi Sea 

Exploration 

Drilling Program 

PREPARED FOR: 

SHELL OFFSHORE INC. 

PROJECT NO. 180-15 

FEBRUARY 23, 2009 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc ii

CONTENTS Page

GLOSSARY .....................................................................................................................................................................VI

Abbreviations/Acronyms..............................................................................................................................................vii

Units and Measures....................................................................................................................................................viii

Pollutants....................................................................................................................................................................viii

1 INTRODUCTION........................................................................................................................................................... 1

2 PROJECT DESCRIPTION AND EMISSIONS .............................................................................................................. 3

2.1 Generators (FD-1 through FD-6)..................................................................................................................... 4

2.2 Generator SCR Ammonia Slip......................................................................................................................... 5

2.3 Emergency Generator (FD-8).......................................................................................................................... 6

2.4 Propulsion Engine (FD-7)................................................................................................................................ 6

2.5 MLC Air Compressors (FD-9, 10, and 11) and HPU Units (FD-12 and 13)..................................................... 6

2.6 Cranes (FD-14 and 15).................................................................................................................................... 7

2.7 Cementing Units (FD-16, 17, and 18).............................................................................................................. 7

2.8 Logging Units (FD-19 and 20) ......................................................................................................................... 7

2.9 Heaters/Boilers (FD-21 and 22)..................................................................................................................... 14

2.10 Waste Incinerator (FD-23)............................................................................................................................. 14

2.11 Diesel Fuel Tanks.......................................................................................................................................... 14

2.12 Ice Management and Anchor Handling Fleet ................................................................................................ 14

2.13 Oil Spill Response (OSR) Ships .................................................................................................................... 18

2.14 Resupply Ship ............................................................................................................................................... 19

2.15 Fuel Used ...................................................................................................................................................... 19

2.16 Residential, Commercial, and Industrial Growth ........................................................................................... 20

2.17 Emissions for Purposes of Modeling ............................................................................................................. 20

2.18 Emissions and Impacts as a Function of Load .............................................................................................. 21

2.19 Other Activities .............................................................................................................................................. 21

3 REGULATORY APPLICABILITY ................................................................................................................................ 25

4 EMISSION CONTROL TECHNOLOGY REVIEW....................................................................................................... 28

4.1 Best Available Control Technology (BACT) Overview................................................................................... 28

4.1.1 NOx BACT Analyses ................................................................................................................................. 30

4.1.1.1 NOx BACT for Diesel Generators ..................................................................................................... 34

4.1.1.2 NOx BACT Smaller Diesel Engines .................................................................................................. 35

4.1.1.3 NOx BACT Diesel Compressors....................................................................................................... 37

4.1.1.4 NOx BACT Boilers ............................................................................................................................ 38

4.1.1.5 NOx BACT Incinerator ...................................................................................................................... 39

4.1.2 SO2 BACT Analysis................................................................................................................................... 39

4.1.2.1 SO2 BACT for the Diesel Engines and Boilers ................................................................................. 41

4.1.2.2 SO2 BACT for the Incinerator ........................................................................................................... 42

4.1.3 Particulate Matter BACT Analysis ............................................................................................................. 43

4.1.3.1 PM BACT for the Diesel Engines ..................................................................................................... 46

4.1.3.2 PM BACT for the Diesel-Fired Boilers.............................................................................................. 47

4.1.3.3 PM BACT for the Incinerator ............................................................................................................ 48

4.1.4 CO BACT Analysis.................................................................................................................................... 48

4.1.4.1 CO BACT for the Diesel Engines ..................................................................................................... 50

4.1.4.2 CO BACT for the Diesel-Fired Boilers.............................................................................................. 52

4.1.4.3 CO BACT for the Incinerator ............................................................................................................ 52

4.1.5 CO2 BACT Analysis................................................................................................................................... 53

4.2 NSPS............................................................................................................................................................. 53

4.3 NESHAPs...................................................................................................................................................... 53

4.3.1 Compression Ignition (CI) Reciprocating Internal Combustion Engines (RICE) ....................................... 54
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CONTENTS - Continued Page

4.3.2 Commercial and Industrial Solid Waste Incinerator (CISWI) .................................................................... 54

4.3.3 Boilers ....................................................................................................................................................... 54

5 AMBIENT IMPACTS ................................................................................................................................................... 55

5.1 Model Selection ............................................................................................................................................. 56

5.2 Worst-Case Meteorological Data................................................................................................................... 56

5.3 Persistence Factors....................................................................................................................................... 57

5.4 Physical Characterization of the Emission Units ........................................................................................... 57

5.4.1 Discoverer ................................................................................................................................................. 57

5.4.2 Supporting Fleets ...................................................................................................................................... 58

5.4.3 Volume Source Characterization of Supporting Fleets ............................................................................. 59

5.5 Ambient Air Boundary and Receptors ........................................................................................................... 63

5.6 Positioning of Source Components Including Fleets for Modeling ................................................................ 63

5.7 PSD Modeling Assessment Phases – Preliminary Analysis and Full Impact Analysis.................................. 66

5.8 Nearby Sources............................................................................................................................................. 68

5.9 Selection of Drilling Locations to Determine Worst-Case Cumulative Impacts ............................................. 68

5.10 Post-Processing of the Impacts to Incorporate Annual Operating Restrictions into the Impacts .................. 70

6 BASELINE CONCENTRATIONS................................................................................................................................ 71

7 IMPACT MODELING RESULTS................................................................................................................................. 78

7.1 Worst-Case Concentration Impacts............................................................................................................... 78

7.2 Source Contribution Analyses at Maximum Impact Location ........................................................................ 81

7.3 Impacts from the Ice Management and Anchor Handler Fleet...................................................................... 82

7.4 Worst-Case Screening Impacts at Nearest Villages on Chukchi Coast ........................................................ 85

8 ADDITIONAL IMPACT ANALYSES............................................................................................................................ 87

8.1 Growth Analysis............................................................................................................................................. 87

8.2 Effects on Soils and Vegetation..................................................................................................................... 87

8.3 Visibility Analysis ........................................................................................................................................... 87

8.4 Ozone Analysis.............................................................................................................................................. 88

Tables 

Table 2-1: Discoverer and Associated Vessels Emission Units with Maximum Hourly Emissions That Could Occur 

Simultaneously................................................................................................................................................ 8

Table 2-2: Discoverer and Associated Vessels Emission Units with Annual Emissions.................................................. 9

Table 2-3: Proposed Owner-Requested Restrictions..................................................................................................... 10

Table 2-4: Proposed BACT Control Device Effectiveness ............................................................................................. 11

Table 2-5: Discoverer Diesel Fuel Tanks....................................................................................................................... 14

Table 2-6: Eligible Ice Management Ships..................................................................................................................... 17

Table 2-7: NOx Emissions and Impacts at Three Loads ................................................................................................ 22

Table 2-8: PM10 Emissions and Impacts at Three Loads............................................................................................... 22

Table 3-1: Significant Emission Rates ........................................................................................................................... 27

Table 4-1: Source Categories, Proposed BACT ............................................................................................................ 29

Table 4-2: Available NOx Control Technologies............................................................................................................. 31

Table 4-3: EPA Tier 1-3 Nonroad Diesel Engine NOx Emission Standards................................................................... 34
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CONTENTS - Continued Page

Table 4-4: Available SO2 Control Technologies............................................................................................................. 41

Table 4-5: Available PM Control Technologies.............................................................................................................. 44

Table 4-6: EPA Tier 1-3 Nonroad Diesel Engine PM Emission Standards.................................................................... 45

Table 4-7: Available CO Control Technologies.............................................................................................................. 49

Table 4-8: EPA Tier 1-3 Nonroad Diesel Engine CO Emission Standards.................................................................... 50

Table 5-1: Summary of Applicable Standards................................................................................................................ 55

Table 5-2: Wind Speed and Stability Class Combinations Used for Screening Modeling ............................................. 56

Table 5-3: Worst-Case Persistence Factors .................................................................................................................. 57

Table 5-4: Summary of SCREEN3 Output for Plume Rise ............................................................................................ 61

Table 5-5: Minimum Sigma Z Values from SCREEN3................................................................................................... 63

Table 5-6: Summary of Significant Impact Levels and Related Significant Areas ......................................................... 67

Table 6-1: Seasonal PM10 Concentrations at Badami.................................................................................................... 76

Table 6-2: Baseline Concentrations............................................................................................................................... 77

Table 7-1: Summary of Screening Maximum Estimated Short-Term and Annual Concentrations all Sources Combined

...................................................................................................................................................................... 78

Table 7-2: Impact Scenarios Used to Define Screening Maximum Annual Impacts from All Sources and Multiple 

Sequential Wells............................................................................................................................................ 79

Table 7-3: Combined Screening Maximum Impacts from.............................................................................................. 80

Table 7-4: Discoverer Source Contributions at the Screening Maximum Impact Locations .......................................... 81

Table 7-5: Maximum Impacts from Primary Ice Management Ship ............................................................................... 83

Table 7-6: Maximum Impacts from Secondary Ice Management Ship .......................................................................... 84

Table 7-7: Worst-Case Screening Impacts at Nearest Villages on Chukchi Coast........................................................ 86

Table 8-1: Maximum Measured Ozone Concentrations at North Slope Monitoring Stations......................................... 89

Table 8-2: Point Source Emissions of NOx and VOCs – North Slope............................................................................ 92

Figures 

Figure 1-1: Shell Gulf of Mexico Inc. Current Leases in the Chukchi Sea ....................................................................... 2

Figure 2-1: Photograph of the Discoverer...................................................................................................................... 12

Figure 2-2: Layout of Emission Units on the Discoverer................................................................................................ 13

Figure 2-3: Ice management and anchor handling ships locations for breaking of one-year ice................................... 16

Figure 5-1: Source and Receptor Locations for Worst-Case Impact Scenario .............................................................. 65

Figure 5-2: The Maximum Annual Impact Configuration for Sequential Drill Sites ........................................................ 70

Figure 6-1: Map of Ambient Monitoring Stations on the North Slope............................................................................. 72

Figure 6-2: Average Monthly NO2 Concentrations for North Slope Stations.................................................................. 74

Figure 6-3: Average Maximum 3-Hour SO2 Concentrations for North Slope Stations................................................... 75

Figure 6-4: Average Maximum 24-Hour SO2 Concentrations for North Slope Stations................................................. 75

Figure 6-5: Time Series of 1-Hour CO Concentrations at BPX - Liberty........................................................................ 76

Figure 8-1: Ozone Monitoring Stations on the North Slope ........................................................................................... 90
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc v

CONTENTS - Continued Page

Appendices 

Appendix A: Short-Term and Seasonal Emissions – One Unit per Page

Appendix B: Short-Term Emission Calculation Spreadsheets for Impact Modeling Input

 Seasonal Emission Spreadsheets

Appendix C: Emission Control Technology Review and References

Appendix D: SCREEN3 Model Output for Ice Management Fleet Loads Analyses

Appendix E: SCREEN3 Model Output for Plume Rise Determinations

Appendix F: Text Footnote References

Appendix G: Incinerator Exemption Letter
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc vi

GLOSSARY 

The Ice Management Fleet is the group of vessels while within 25 miles of the Drill Site with the 

primary purpose of breaking and/or diverting the ice in ice floes that might contact the 

Discoverer. This fleet has the secondary purpose of handling the Discoverer anchors. 

The Oil Spill Response (OSR) Fleet is the group of vessels while within 25 miles of the Drill Site 

with the primary purpose of being prepared for the unplanned event of an oil spill at the Drill 

Site, including cleanup activities. 

A Planned Well is a well selected in advance of the drilling season that is drilled to collect 

discrete information from a specific prospect. 

A Drilling Day is any day that the Discoverer is physically attached to the sea floor by at least one 

anchor for the expressed purpose of conducting drilling operations. 

A Drill Site is a location on the surface of the water occupied by the Discoverer in any one 

calendar year, and from this location the Discoverer is permanently or temporarily attached to the 

sea floor and erected thereon and used for the purpose of exploring resources there from. The 

site includes the area surrounding the planned well within a 1,000-meter radius of the planned 

well. The Discoverer is said to be occupying a Drill Site when at least one of its anchors is 

attached to the sea floor. 

Outer Continental Shelf (OCS) Source Activities include the following activities: 

• Air pollutant emitting activities undertaken by Discoverer emission units listed in Table 

2-1 of this application and occurring while the Discoverer is occupying a Drill Site, and 

• Air pollutant emitting activities undertaken by support vessel emission units listed in 

Table 2-1 of this permit and occurring while: a) the support vessel is physically attached 

to the Discoverer, and b) the Discoverer is occupying a Drill Site. 

• Emission units generating output exclusively for the purpose of propelling a vessel are 

not considered to be engaging in OCS Source Activities. 

An Exploratory Operation is the collection of all OCS Source Activities undertaken to construct a 

Planned Well and any other wells at that drill site during one season. 

The Exclusion Zone is an area defined on the sea surface by a circle with a radius of 1,000 meters 

centered on the well being drilled at that time. The public is restricted from the exclusion zone 

for it safety and the protection of the drilling operation equipment.
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc vii

Abbreviations/Acronyms

AAC.......................... Alaska Administrative Code 

AC............................. Intake air cooling 

ANSER..................... Arctic North Slope Eastern Region 

ASTM ....................... American Society of Testing and Materials 

APD.......................... Application for Permit to Drill 

BACT........................ Best available control technology 

BP.............................. British Petroleum 

BPX ........................... British Petroleum Exploration 

BPIP.......................... Building Profile Input Program 

CAA.......................... Clean Air Act 

CDPF ........................ Catalytic diesel particulate filter 

CEM.......................... Continuous emissions monitor 

CFR........................... Code of Federal Regulations 

CI .............................. Compression ignition 

CISWI....................... Commercial and industrial solid waste incinerator 

CPAI......................... Conoco Phillips Alaska Inc. 

Discoverer................. Frontier Discoverer Drillship 

DPF........................... Diesel particulate filter 

EAC .......................... Early action compact 

EDMS ....................... Emissions Data Management System 

EGR .......................... Exhaust gas recirculation 

Em............................. Emergency 

EPA........................... United States Environmental Protection Agency 

ESP............................ Electrostatic precipitators 

FGR........................... Flue gas recirculation 

GCP .......................... Good combustion practices 

GMP ......................... Good maintenance practices 

HIP ........................... High injection pressure 

HPU.......................... Hydraulic power unit 

I.C. ............................ Internal combustion 

ITR ............................ Ignition timing retard 

LAER........................ Lowest achievable emission rate 

LNB .......................... Low NOx burner 

LND.......................... Low NOx design 

LSF............................ Low sulfur fuel 

MLC.......................... Mud line cellars 

MSW......................... Municipal solid waste 

NA ............................ Not Applicable 

NAAQS.................... National Ambient Air Quality Standards 

NAICS...................... North American Industry Classification System 

NESHAPs ................ National Emission Standard for Hazardous Air Pollutants 

NSPS......................... New source performance standard 

NSR .......................... New source review 

OCS .......................... Outer Continental Shelf 

ORR .......................... Owner Requested Restriction 

OSR........................... Oil Spill Response 

OxyCat ..................... Oxidation catalyst 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc viii

PCV .......................... Positive crankcase ventilation 

PSD........................... Prevention of significant deterioration 

RACT........................ Reasonably available control technology 

RBLC ........................ RACT/BACT/LAER Clearinghouse 

RICE ......................... Reciprocating internal combustion Engines 

SCR........................... Selective catalytic reduction 

SDS ........................... Semi-dry scrubber 

SIA............................ Significant impact area 

SIL............................. Significant impact level 

SNCR........................ Selective non-catalytic reduction 

SOF ........................... Soluble organic fraction 

SSBOP ...................... Subsea blowout preventer 

Starbd....................... Starboard 

ULSD........................ Ultra-low sulfur distallate fuel (15 ppm sulfur content) 

Unit ID .................... Emission Unit Identification Number 

WI ............................. Water Injection 

WRAP ...................... Western Regional Air Partnership 

Units and Measures 

g ................................ grams 

gph............................ gallons per hour 

bhp............................ brake horsepower 

hp.............................. horsepower 

km............................. kilometers 

kts ............................. knots 

kW ............................ kiloWatts 

lbs ............................. pounds 

MMBtu..................... million British thermal units 

ppm .......................... parts per million 

tph............................. tons per hour 

tpy............................. tons per year 

Pollutants 

CO............................. Carbon Monoxide 

H2S............................ Hydrogen Sulfide 

HAPs ........................ Hazardous Air Pollutants 

HC ............................ Hydrocarbons 

NMHC ..................... Non Methane Hydocarbons 

NOX .......................... Oxides of Nitrogen 

NO2........................... Nitrogen Dioxide 

PM10.......................... Particulate Matter with an aerodynamic diameter less than 10 microns 

PM2.5 ......................... Particulate Matter with an aerodynamic diameter less than 2.5 microns 

SO2 ............................ Sulfur Dioxide 

SO3 ............................ Sulfur Trioxide 

VOC.......................... Volatile Organic Compounds 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 1

SECTION 1

INTRODUCTION 

Shell Offshore Inc. (Shell) is applying for a preconstruction permit from EPA Region 10 for the 

operation of the Discoverer drillship (source) and associated fleet in the Chukchi Sea beyond the 

25-mile Alaska seaward boundary. It is to be used for exploratory drilling activity (NAICS 

category 211111) on the Outer Continental Shelf (OCS) of the Chukchi Sea. As such, the 

application is made under the OCS permitting rules (40 CFR 55). The source will trigger major 

stationary source classification (40 CFR 52.21 (b) (1) (i)) and therefore, as prescribed in the OCS 

permitting rules, this application also addresses the federal New Source Review Permitting Rules 

(40 CFR 52.21). 

The application is for a portable major source permit to allow the Discoverer and its associated 

fleet to operate at any of Shell Gulf of Mexico Inc.’s current leases within the Chukchi Sea, all of 

which are beyond the 25-mile Alaska seaward boundary. Shell anticipates a drilling season of 

maximum 168 drilling days (5.5 months), beginning in July of each year. During this season, it 

would have the flexibility of drilling one or more wells or parts of wells, subject to the limitation 

that drilling at no single drill site would consume more than 84 drilling days. It is likely that the 

environmental conditions (ice) will limit the drilling season to less than these maxima. Drilling is 

planned to begin earliest July of 2010 and continue seasonally until the resource is adequately 

defined. 

Figure 1-1 shows the location of the current Shell Gulf of Mexico Inc. leases in the Chukchi Sea on 

which the Discoverer is to be permitted to operate. This region can be described as lying west of 

Wainwright (162° west longitude) and north of Point Lay (71° north latitude). 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 2 

Figure 1-1: Shell Gulf of Mexico Inc. Current Leases in the Chukchi Sea 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 3 

SECTION 2

PROJECT DESCRIPTION AND EMISSIONS 

The Discoverer is a drillship, converted for drilling in 1975 and substantially upgraded in 2007. It 

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. A listing of the Discoverer emission units is provided in Tables 2-1 and 

2-2. Except for the air compressors all of the source units are existing equipment. The mud line 

cellar (MLC) air compressors will be new engines. A photograph of the Discoverer is provided on 

Figure 2-1 and the locations of the various emission units on the Discoverer are shown on Figure 

2-2. These locations are important for the estimation of their impacts, discussed in greater detail 

in Section 5. 

Prior to mobilizing to the Chukchi Sea, the drillship is provisioned with sufficient supplies 

required to drill the initial drilling operations. Together with the ice management and anchor 

handler fleet, consisting of an icebreaker and an arctic class anchor handler/ice management 

vessel, the rig 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 anchor handler/ice management vessel; the mooring 

lines are tensioned; and the rig is thus positioned over the well. 

Upon completion of the mooring operation, the process to drill the 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 rig’s Subsea Blowout Preventers (SSBOP’s) below the mud line to avoid 

damage by ice keels should ice floes force the rig 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. A 36 inch diameter hole is drilled for the next 

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 (OSR) 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 

abandoned (P&A’d) using mechanical and/or cement plugs, or temporarily abandoned (T&A’d), 

which generally occurs upon completion of any of the interim operations of cementing the casing. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 4 

After the well is abandoned the SSBOP’s are retrieved. The anchors can then be retrieved and the 

rig can depart the drill site. The rig can move from the drill site after plugging and abandoning 

P&A’ing or T&A’ing a well. 

The rig may leave a drill site for a variety of reasons including P&A or T&A activities, adverse ice 

conditions, end of the drilling season, or desire to move to another drill site to start or finish a 

well previously T&A’d. If for any reason a second well is to be drilled within the 1,000-meter 

radius of the initial well, the second well will be restricted by the air permit as if it were an 

extension of the initial well that established the drill site. If the Discoverer moves more than 1,000-

meter from the first well, it establishes a new drill site and restarts the clock on the air permit 

restrictions. 

The Discoverer is a turret-moored drillship that underwent significant upgrades in 2007 so that it 

could operate in the arctic. The Discoverer crew works 12-hour shifts and lives on the rig in 

accommodations located at the stern of the ship. They work for three to four weeks and are 

transported to and from the rig by helicopter to Wainwright or Barrow, Alaska. 

The calculations of emissions for all emission units are shown in Appendices A and B, with the 

calculations on a per-emission-unit per page format in Appendix A and the calculations which 

feed into the impact modeling in Appendix B. Appendix A information flows from the 

Appendix B spreadsheets. Table 2-1 represents the maximum hourly emission rates for all the 

emission units of the Discoverer and associated fleets that could operate simultaneously. Shell 

requests several Owner Requested Restrictions (ORRs) that limit the short-term (up to 24-hours) 

operations and emissions for modeling purposes and these are incorporated in the emission 

calculations used for modeling (Appendix B, Page 2). The short-term engine and heater 

emissions are estimated using the engine or heater capacities converted to fuel heat consumption. 

Then these capacity consumption values are converted to emissions using manufacturer or 

generic (when model-specific factors are not available) emission factors. Then short-term ORRs 

(restrictions over a single day), Table 2-3, are applied as are the tailpipe control device 

guaranteed or estimated control technology efficiencies, Table 2-4. Shell’s expectation of Best 

Available Control Technology (BACT) in the form of fuel quality and tailpipe control efficiencies 

are incorporated in Tables 2-3 and 2-4. BACT selection is discussed in Section 4. The long-term 

(seasonal) ORRs, also in Table 2-3, are taken into account through a restriction in the length of 

operating season in the impact modeling phase. Incinerator emissions are calculated on the basis 

of emissions per unit charge and using an EPA generic emission factor since no manufacturer’s 

emission factors are available for this small device. 

2.1 Generators (FD-1 through FD-6) 

Six Caterpillar D399 generator sets provide the primary systems power for the drilling as well as 

the ship utilities and are operational at varying load levels throughout the drilling process. There 

are six emission units that comprise the capacity to routinely generate electrical power, with the 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 5 

expectation 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 maximum emissions, Shell requests the 

continuous electrical production limit of 80 percent of the six-engine design capacity as an ORR 

shown on Table 2-3. 

The generators will be retrofitted with selective catalytic reduction and oxidation catalyst control 

devices with control efficiencies as shown in Table 2-4. These controls are to be retrofitted by 

D.E.C. Marine AB, a Swedish company who has installed more NOx ship emission control 

systems than any other company in the world.1 The D.E.C. Marine AB control guarantees for 

NOx, CO, and VOCs are provided on Table 2-4. Control of particulate matter is estimated from 

an EPA report. Except for startup and shutdown, these engines will be operated at 50 percent 

capacity or greater so that the emission control devices will function effectively. Regarding the 

control efficiency of volatile organics by the oxidation catalyst, D.E.C. Marine AB has stated that 

the efficiency is related to the complexity of the volatile. Complexity is judged in terms of the 

number of carbon atoms of the organic compound; the more carbons, in general, the lower the 

control efficiency will be. The lower end of the typical range of control efficiency is assumed in 

the emissions calculations herein. 

2.2 Generator SCR Ammonia Slip 

Selective catalytic reduction (SCR) is being proposed for the Discoverer to reduce the NOx

emissions from the main driver engines (Caterpillar D399s). The SCR technology involves the 

injection of urea into the exhaust stream with a catalyst to convert the NOx to nitrogen and water. 

Ideally, the urea will reduce NOx at a 1-to-1 ratio. However, because mixing within the stack is 

not ideal, a small portion passes through the system converted to ammonia but not to nitrogen 

and water and is released to the atmosphere (a process known as ammonia slip). The amount of 

ammonia slip from an SCR control device will theoretically begin at near zero and increase over 

the life of the catalyst (8 to 10 years). Other factors impacting ammonia slip are the amount of 

sulfur in the fuel, the water and oxygen content, and the exhaust temperature. Thus, a proper 

and efficient operation of the SCR control system will further minimize ammonia emissions. The 

D.E.C. Marine AB SCR system design is based on an algorithm that determines urea injection 

according to engine load and other operational factors. The system also includes a NOx exhaust 

monitor that cycles through the six SCR units. The cycle time, including the necessary zero and 

spanning, is one measurement per engine per hour. This measurement essentially verifies the 

load-based algorithm and adjusts it if necessary.2

 

1 Holmström, Per, D.E.C. Marine AB. [Letter to K. Craik, Shell]. October 9, 2008. 

2 Ibid. footnote 1. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 6 

The D.E.C. Marine AB system controls the ammonia slip through routine measurement of the 

NOx emissions and adjusts the urea injection rate to match the conversion needs. The operation 

of this feedback system is verified during initial stack tests and system certification.3

Because sulfur in the fuel can lead to SO2 to SO3 conversion (typically on the order of one 

percent), the presence of SO3 in the exhaust stream can lead to the formation of ammonium 

bisulfate and ammonium sulfate particles (aerosols). The formation of in-stack sulfate can be 

minimized by limiting the sulfur in the fuel and limiting the ammonia slip to three to five ppm 

for high sulfur fuels and less than 10 ppm for low sulfur fuels. For the Discoverer’s Caterpillar 

D399s, which will be fuelled with ultra-low sulfur diesel (less than 15 ppm) and which will be 

equipped with oxidation catalysts, D.E.C. Marine AB believes that the ammonia exhaust 

emissions will be much less than 10 ppm and close to zero.4 Thus, there is nearly no SO3 or 

ammonia emitted and available for conversion to aerosols. 

2.3 Emergency Generator (FD-8) 

The Discoverer will have one 130-hp emergency generator for use in powering the basic drillship 

utilities which include domestic and worker safety devices and excludes all drilling equipment. 

There are no planned uses of the emergency generator except for weekly exercising which 

involves operation for approximately 20 minutes at loads up to capacity.5 The seasonal 

emissions from this weekly 20-minute exercise are estimated at 0.016 ton NOx, which is 0.03 

percent of total Discoverer annual NOx emissions. Since these emissions are small they are 

grouped with the generator emissions for impact evaluation. 

2.4 Propulsion Engine (FD-7) 

The Discoverer propulsion engine will be shut down prior to placement of the first anchor and 

turned back on only after removal of the final anchor, so it will have no emissions during the 

time the drillship is a stationary source. 

2.5 MLC Air Compressors (FD-9, 10, and 11) and HPU Units (FD-12 and 13) 

The remainder of the diesel engines are used only occasionally for specialized and intermittent 

tasks. The MLC air compressors (FD-9, 10, and 11) and hydraulic power units HPU (FD-12 and 

13) are used for drilling the MCLs, which is the initial drilling activity, for about one week per 

well. These engines would be operated between 50 and 100 percent capacity during the week 

needed to evacuate the MLC. Shell requests ORRs of the equivalent of 48 days operation at 

capacity per season per group for these two source groups. The air compressors are to be new, 

 

3 Liljegren, Karin, D.E.C. Marine AB. [Communications with R. Steen, Air Sciences Inc.]. January 28, 2009. 

4 Liljegren, Karin, D.E.C. Marine AB. [Communications with K. Craik, Shell]. January 6, 2009. 

5 Wright, Alistair, Chief Engineer, Frontier Discoverer. [Communication with A. Wilson, Frontier Drilling]. January 21, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 7 

Tier 3 engines with no add-on emission controls, while the HPUs are existing engines with 

catalytic diesel particulate filters (CDPF) for control of oxidizable emissions (volatile organics, 

carbon monoxide, and hydrocarbon particulate matter). 

2.6 Cranes (FD-14 and 15)

The two cranes are mounted on and rotate on pedestals as shown on Figure 2-1 and the engines 

are mounted on the pedestal with the rotating crane. These are used very intermittently to move 

materials around the deck and to on-load supplies from the resupply ship. Their operating levels 

are highly variable depending on the load being moved. There is an ORR limiting the combined 

operation of the cranes to the equivalent of capacity operation for 38 percent of the season, to be 

demonstrated through tracking of fuel consumption for the purpose of limiting the long-term 

(seasonal) impacts. The crane engines have CDPFs for control of organic particulate matter, 

carbon monoxide, and volatile organics. 

2.7 Cementing Units (FD-16, 17, and 18)

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 P&A’ing wells. 

The cement 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. Thus, there will be no drilling and the generators will be 

operating only at low loads when cementing occurs. This decrease in generator emissions is not 

taken into account in the impact analysis herein. Shell requests an ORR of the equivalent of 

capacity operation for 30 percent of the day for the three cementing unit engines combined, to be 

demonstrated through tracking of fuel consumption. The cementing units are equipped with 

CDPFs for control of volatile organics, carbon monoxide, and organic particulate matter. 

2.8 Logging Units (FD-19 and 20)

The two logging units are used to gather information from each well when the drill stem is 

removed, and will operate only when the cementing units are not used and the prime movers are 

operating at a low load. The logging units operate at variable and unpredictable loads. The 

cementing units are used as a substitute for the logging units in the impact analysis and the 

logging units are to be include with the cementing units’ ORR since the logging units are smaller 

and produce less emissions per unit time than the cementing units and operate no more than the 

equivalent of capacity for 30 percent of any one day. In other words, the daily fuel consumption 

restriction on the cementing units is to include use of the logging units. The logging units also 

have CDPFs for control of volatile organics, carbon monoxide, and organic particulate matter. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 8 

Table 2-1: Discoverer and Associated Vessels Emission Units with Maximum Hourly Emissions That Could Occur Simultaneou

Maximum Emissions 

 Maximum Fuel Consumption (lb/hr) 1

 Rating (MMBtu/hr) 1 PM10 PM2.5 NOx SO2 CO Frontier Discoverer

 FD-1 Generator Engine 1,325 hp 7.7 0.22 0.22 0.87 1.23E-02 0.31 

 FD-2 Generator Engine 1,325 hp 7.7 0.22 0.22 0.87 1.23E-02 0.31 

 FD-3 Generator Engine 1,325 hp 7.7 0.22 0.22 0.87 1.23E-02 0.31 

 FD-4 Generator Engine 1,325 hp 7.7 0.22 0.22 0.87 1.23E-02 0.31 

 FD-5 Generator Engine 1,325 hp 7.7 0.22 0.22 0.87 1.23E-02 0.31 

 FD-6 Generator Engine 1,325 hp 7.7 0.22 0.22 0.87 1.23E-02 0.31 

 FD-7 Propulsion Engine 7,200 hp 0.0 0.00 0.00 0.00 0.00E+00 0.00 

 FD-8 Em. Generator 131 hp 0.3 0.09 0.09 1.35 4.88E-04 0.29  FD-9 MLC Compressor 540 hp 3.8 0.18 0.18 3.55 6.03E-03 3.11  FD-10 MLC Compressor 540 hp 3.8 0.18 0.18 3.55 6.03E-03 3.11  FD-11 MLC Compressor 540 hp 0.0 0.00 0.00 0.00 0.00E+00 0.00  FD-12 HPU Engine 250 hp 1.8 0.10 0.10 5.41 2.79E-03 0.33  FD-13 HPU Engine 250 hp 1.8 0.10 0.10 5.41 2.79E-03 0.33  FD-14 Port Deck Crane 365 hp 2.6 0.12 0.12 11.27 4.08E-03 0.49 

 FD-15 Starbd Deck Crane 365 hp 2.6 0.12 0.12 11.27 4.08E-03 0.49 

 FD-16 Cementing Unit 335 hp 2.3 0.14 0.14 7.25 3.74E-03 0.44  FD-17 Cementing Unit 335 hp 2.3 0.14 0.14 7.25 3.74E-03 0.44  FD-18 Cementing Unit 147 hp 1.0 0.06 0.06 3.18 1.64E-03 0.19  FD-19 Logging Winch2 128 hp 0.0 0.00 0.00 0.00 0.00E+00 0.00 

 FD-20 Logging Winch2 36 kW 0.0 0.00 0.00 0.00 0.00E+00 0.00  FD-21 Heat Boiler 7.97 MMBtu/hr 8.0 0.19 0.19 1.60 1.27E-02 0.62 

 FD-22 Heat Boiler 7.97 MMBtu/hr 8.0 0.19 0.19 1.60 1.27E-02 0.62 

 FD-23 Incinerator 276 lb/hr 0.97 0.97 0.41 3.45E-01 0.14 

 Total while drilling 84.4 3.91 3.91 68.33 0.48 12.46 Associated Fleets Maximum Emissions  Maximum Fuel Consumption (lb/hr) 1

 (MMBtu/hr) 1 PM10 PM2.5 NOx SO2 CO 

Ice Management Fleet - Generic

 Diesel Engines 321.7 32.17 32.17 1,029.51 65.00 273.46 

Incinerators 2-154 lb/hr 1.08 1.08 0.46 0.39 0.15 Total Ice Management Fleet 321.7 33.25 33.25 1,029.97 65.38 273.62 

Resupply Vessel - Generic 2.0 0.63 0.63 9.01 0.41 1.94 OSR Fleet 17.5 5.42 5.42 61.96 3.53 16.60 

Total All Fleet 341.2 39.30 39.30 1,100.95 69.32 292.16 

Total All 425.6 43.21 43.21 1,169.27 69.80 304.62 

1 All emissions are shown as the maximum 1-hour value. 2 Logging winches cannot operate simultaneously with cementing units. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 9 

Table 2-2: Discoverer and Associated Vessels Emission Units with Annual Emissions 

Maximum Emissions 

 Maximum Fuel Consumption (ton/yr) 

 Rating (MMBtu/yr) PM10 PM2.5 NOx SO2 CO V

Frontier Discoverer

 FD-1 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63  FD-2 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63  FD-3 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63  FD-4 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63  FD-5 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63  FD-6 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63  FD-7 Propulsion Engine 7,200 hp 0 0.00 0.00 0.00 0.00E+00 0.00  FD-8 Em Generator 131 hp 7 0.00 0.00 0.02 5.85E-06 0.00  FD-9 MLC Compressor 540 hp 4,355 0.10 0.10 2.05 3.47E-03 1.79 

 FD-10 MLC Compressor 540 hp 4,355 0.10 0.10 2.05 3.47E-03 1.79 

 FD-11 MLC Compressor 540 hp 0 0.00 0.00 0.00 0.00E+00 0.00  FD-12 HPU Engine 250 hp 2,016 0.06 0.06 3.11 1.61E-03 0.19  FD-13 HPU Engine 250 hp 2,016 0.06 0.06 3.11 1.61E-03 0.19  FD-14 Port Deck Crane 365 hp 3,915 0.09 0.09 8.63 3.12E-03 0.37  FD-15 Starbd Deck Crane 365 hp 3,915 0.09 0.09 8.63 3.12E-03 0.37  FD-16 Cementing Unit 335 hp 2,837 0.08 0.08 4.38 2.26E-03 0.27 

 FD-17 Cementing Unit 335 hp 2,837 0.08 0.08 4.38 2.26E-03 0.27 

 FD-18 Cementing Unit 147 hp 1,245 0.04 0.04 1.92 9.93E-04 0.12 

 FD-19 Logging Winch1 128 hp 0 0.00 0.00 0.00 0.00E+00 0.00 

 FD-20 Logging Winch1 36 kW 0 0.00 0.00 0.00 0.00E+00 0.00  FD-21 Heat Boiler 7.97 MMBtu/hr 32,135 0.38 0.38 3.23 2.56E-02 1.24  FD-22 Heat Boiler 7.97 MMBtu/hr 32,135 0.38 0.38 3.23 2.56E-02 1.24  FD-23 Incinerator 276 lb/hr 1.95 1.95 0.83 6.96E-01 0.28 

 Total while drilling 278,255 6.10 6.10 56.14 0.92 11.89 

Associated Fleets Maximum Emissions  Maximum Fuel Consumption (ton/yr) 

 (MMBtu/yr)

Fuel Use 

gal/yr PM10 PM2.5 NOx SO2 CO V

Ice Management Fleet - Generic 

 Diesel Engines 492,928 3,703,499 25 25 789 50 209 2 Incinerators 0.21 0.21 0.09 0.07 0.03 

Total Ice Management Fleet 492,928 3,703,499 25 25 789 50 210 2

Resupply Vessel - Generic 196.22 1474 0.03 0.03 0.43 0.02 0.09 OSR Fleet 23,483 176,435 4 4 42 2 11 

Total All Fleet 516,608 3,881,408 29 29 831 52 221 2

Total All 794,863 5,972,012 35 35 887 53 233 2

1 Logging winch emissions are included with cementing units.
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 10 

Table 2-3: Proposed Owner-Requested Restrictions

Compliance Condition Restriction How Calculated H

Operational RestrictionsSeason maximum drilling duration 

168 days/season 168 days/season x 24 hr/day = 4,032 hrs Fi

an

Drill site maximum drilling duration 

84 days/hole 84 days/season x 24 hr/day = 2,016 hrs Fi

an

Minimum distance between drill sites per drilling season 

1,000 meters Si

MLC compressors maximum use per drilling season 

48 days/season 48 day/season x 24 hr/day x 2 

engines x 540 hp/engine x 0.007 MMBtu/hp-hr x 7.5 gal/MMBtu= 

65,434 gal/ 

season 

Decococo

HPUs maximum use per season 

48 days/season 48 day/season x 24 hr/day x 2 

engines x 250 hp/engine x 0.007 MMBtu/hp-hr x 7.5 gal/MMBtu= 

30,293 gal/ 

season 

Decocoat 

Generator combined production maximum 

80% 80%x 6 engines x 1325 hp x 

kW/1.340hp= 

4,746 kW De

– c

Cementing & Logging units combined maximum 

30% (of cementing) 30% x (335 hp x 2 engines +147hp) 

x 0.007 MMBtu/hp-hr x 24 hr/day x 7.5 gal/MMBtu = 

309 gal/ 

day 

Decococo

Crane units combined maximum 

58,824 gal/season Max Fuel Consumption De

cocoat 

Sulfur content on all stationary source engines on drilling vessel 

0.0015% by weight Su

Sulfur content on all ships except the Discoverer

0.19% by weight Su

Ice management fleet fuel restriction while < 25 miles from drill site 

3,703,499 gal/season Fuel Consumption De

pu
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 11 

Table 2-4: Proposed BACT Control Device Effectiveness 

Compliance Condition Restriction Comments Reference 

Control Device EffectivenessGenerator SCR NOx control 

effectiveness 

0.5 g/kW-hr 50-100% of capacity CEM D.E.C. Marine AB letter, Octobe

test and CEM. 

Generator Oxidation Catalyst CO reduction efficiency 

80% D.E.C. Marine AB letter, Octobe

stack test. 

Generator Oxidation Catalyst VOC, HAPs, Formaldehyde reduction efficiency 

70% D.E.C. Marine AB letter, Octobe

Generator Oxidation Catalyst PM10 reduction efficiency 

50% D.E.C. Marine AB email, Februa

Small engines (other than Tier 3 engines) Catalytic Diesel Particulate Filter (CDPF) CO, VOC, HAPs, Formaldehyde reduction efficiency 

80% CleanAIR Systems PERMITTM F

claims 85%). 

Small engines CDPF PM10

reduction efficiency 

85% California Air Resource Board, 

January 2009, CleanAIR System
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 12 

Figure 2-1: Photograph of the Discoverer 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 13 

Figure 2-2: Layout of Emission Units on the Discoverer 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 14 

2.9 Heaters/Boilers (FD-21 and 22) 

The Discoverer has two diesel-fuelled boilers for providing heat for domestic and work space 

heating purposes, one for normal operation and the second as a backup although there could be 

times when both would operate. For impact analysis both are assumed to operate 

simultaneously at capacity and continuously. 

2.10 Waste Incinerator (FD-23)

Domestic and other non-hazardous materials are to be incinerated as needed. This man-camp 

style incinerator is a two-stage, batch-charged unit capable of burning 125 kg/hr of solid trash or 

1,000 lb of liquid sewage per day.6 Its incineration capacity is limited to 3 MMBtu/hr (850 kW) of 

heat. Its use rate is uncertain and batch size is unknown; so, its emissions are estimated assuming 

rated capacity use (125 kg/hr) for 24 hours per day and 168 days per year. 

2.11 Diesel Fuel Tanks 

The Discoverer fuel will consist exclusively of diesel which has a very low vapor pressure so the 

tanks will have negligible vent emissions and are not listed as separate sources, but they are to be 

tracked in the air permit and are listed in Table 2-5 for this purpose. 

Table 2-5: Discoverer Diesel Fuel Tanks 

EPA Source ID Discoverer ID Tank capacity (m3) 

FD-24 21P 538 

FD-25 29P 267 

FD-26 29S 267 

FD-27 21S 179 

FD-28 22S 150 

FD-29 23S 150 

FD-30 24S 135 

2.12 Ice Management and Anchor Handling Fleet 

The ice management and anchor handling fleet is expected to consist of two leased ships: an 

icebreaker and an anchor handler / ice management ship. The purpose of this fleet will be to 

manage the ice, which involves deflecting or in extreme cases breaking up any ice floes that could 

impact the Discoverer when it is drilling, and to handle the Discoverer anchors during connection 

to and separation from the sea floor. 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 

 

6 TeamTec Incinerators. Type GS 500C specifications. Fax February 19, 2007. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 15 

Discoverer would need to disconnect from its anchors and move off site. The 2003 – 2005 statistics 

on ice at the Sivulliq drill site in the Beaufort Sea show 15 percent frequency of ice at the drill site 

that would need to be fragmented and a 23 percent frequency of ice within 30 miles of the drill 

site.7 For the remainder of the time the ice management and anchor handling fleet would be 

either downwind of the Discoverer or beyond the 25-mile radius from the Discoverer in a warm 

stack mode (anchored and occupied). For a conservative estimate of the possible need for ice 

management, the sum of these two or 38 percent frequency is used. The Chukchi Sea is expected 

to have less ice, so this 38 percent frequency should represent a high-side frequency for the 

Chukchi Sea. 

When there is ice present at the drill site, ice disturbance will be limited to the minimum needed 

to permit drilling to continue. The most likely ice to be encountered will be first-year ice, and the 

ice management ships will be tasked to churn this up so that it will flow easily around and past 

the Discoverer without building up in front of it. This type of ice is fragmented by a continually 

moving icebreaker (in the extreme case, with thicker (up to 2-meter thick) ice, a rapidly (7 kts8) 

moving icebreaker) moving back and forth across the drift line, directly up-drift of the Discoverer 

and making sharp turns at both ends.9 The primary driver of the ice floe is the wind, so the ice 

management ships are upwind of the Discoverer when managing the ice. The Shell ice 

management expert provides a description of the location of the ice management ships during 

the breaking of the one-year ice.10 The icebreaker is positioned from 3 miles (4.8 km) to 12 miles 

(19 km) upwind on the drift line and the anchor handler will be located from the anchor buoy 

pattern to 6 miles (9.6 km) up-drift from the Discoverer. In the extreme case of thick ice, the width 

of the icebreaker swath will be about 3 miles (4.8 km) to either side of the drift line and the 

anchor handler 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.) With this travel pattern, the ice management ships would spend more time 

and emit more near the turn-around ends of the cross-wind pattern, but for this analysis, and to 

be conservative, the emissions are assumed to be spread uniformly in the cross-wind direction. 

This source configuration for modeling purposes is shown on Figure 2-3. 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. This is considered the case of highest emissions and impacts. 

 

7 Craik, Keith, Arctic Wells Advisor, Shell International Exploration and Production Inc. [Communication with R. Steen, Air Sciences 

Inc.]. January 19, 2009. 

8 Craik, Keith, Arctic Wells Advisor, Shell International Exploration and Production Inc. [Communication with R. Steen, Air Sciences 

Inc.]. January 13, 2009. 

9 Craik, Keith, Arctic Wells Advisor, Shell International Exploration and Production Inc. [Communication with R. Steen, Air Sciences 

Inc.]. February 10, 2009. 

10 Ibid. footnote 8. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 16 

Figure 2-3: Ice management and anchor handling ships locations for breaking of one-year 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. Although this is another emission 

scenario, the first-year ice is most common and is most efficiently broken at continuous high 

speed11 which involves the highest continuous power production and represents the highest 

emissions. Occasionally there can be ice build-up at the bow of the Discoverer that needs a nudge 

to slide past. In this event the anchor handler will pass close to the Discoverer bow and dislodge 

this ice with its propeller wash, an event that could take up to an hour. Since this is such a short 

activity, at low power, and operating side to side of the bow (rather than in front of), its 

emissions will be low and the impact will be small. The impact from this activity is not 

separately modeled. 

The emission units of the icebreaker and anchor handler consist of the diesel engines for 

propulsion, general purpose generators and heaters, and an incinerator as listed in Appendix B, 

Page Fleet-1. Short-term emissions from the ice management ships are calculated at maximum 

use of the emission units, which is 80 percent of capacity for the propulsion engines,12 and 100 

 

11 Ibid. footnote 8. 

12 U.S. EPA. Alaska Outer Continental Shelf Air Quality Control Minor Permit Approval To Construct. Permit Number: R100CS-AK07-02 (Revised). Kulluk Permit – Condition 9.2 (a) (i). June 18, 2008. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 17 

percent of capacity for the remaining emission units. The long-term emissions are calculated 

with these ships in this highest impact position for 38 percent of the season. 

The ice management and anchor handling fleet is expected to consist of two ships, an icebreaker 

and an ice-class anchor handler. The ice management fleet is leased from year to year and is 

likely to change from year to year. Thus, Shell requests that the permit allow for a generic ice 

management fleet. Furthermore, the fleet could consist of more or less than two ships depending 

on availability of ships and ice conditions. There are only a limited number of eligible ships at 

this time represented by the ice management ships listed in Table 2-6. The impacts of the generic 

fleet are defined herein by the ship with the lowest plume rise combined with a permit-restricted 

NOx emission limit (converted to a fuel limit as listed in Table 2-4). NOx is selected because the 

restriction is developed to limit NOx impacts from the ice management and anchor handling fleet. 

The propulsion engine exhaust stacks of the eight ships listed below were modeled for plume rise 

(Appendix B, Page Discoverer 4), the Vladimir Ignatjuk plumes were the lowest (Table 5.4), so the 

impact analysis described in Section 6 of this report are based on the permit limited emissions 

from this stack with lowest plume rise. Impacts from all other ships emitting at the same rate 

will have lower impacts. The defined NOx emission limit is established from the pair of ice 

management ships combined by calculating the daily and annual maximum energy consumption 

of the current pair of ice management ships and converting this to emissions using manufacturer 

emission factors. All other combinations of ice management ships will be expected to meet this 

NOx emission limit calculated using their own unique emission factors. 

Table 2-6: Eligible Ice Management Ships 

Ship Name and Owner 

Vladimir Ignatjuk, Murmansk Shipping 

Talagy, Smit 

Kapitan Dranitsyn, Murmansk Shipping 

Odin, Viking 

Nordica / Fennica, Finstaship 

Tor, Viking 

Balder, Viking 

Vidor, Viking 

The currently planned fleet consists of the Vladimir Ignatjuk as the icebreaker and the Nordica as 

the anchor handler/ice management ship. For purposes of the impact evaluation herein, their 

daily energy consumption (MMBtu/hr) is estimated from maximum operation of all emission 

units of these two ships. Seasonal emissions are estimated from these short-term values by 

multiplying the short-term values by 38 percent of the 168 days of the maximum season. The 

limits are to be tracked in the form of a combined annual fuel consumption limit using highest 

emission factor (lb/gallon) per group of engines based on stack testing of a typical propulsion 

engine and manufacturer emission factors for the smaller sources. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 18 

The anchor-handling 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. Placement 

involves backing the handler 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 process consumes no more than 18 hours. Anchor handler propulsion power during these 

18 hours is either low or at idle since it is precision work setting anchors, spooling-out lines, and 

tensioning lines. Since much of this activity takes place while the Discoverer is a stationary 

source, the anchor management emissions are already included in the ice management and 

anchor handler fleet emission inventory totals. 

Regarding possible impacts of this activity, since the anchor placement and retrieval occurs when 

all drilling, cementing, and logging activities are shut down, occurs while under low power of the 

anchor handler, and is spread over a two km diameter circle, the short-term (hourly and daily) 

impacts will not occur simultaneously with the larger Discoverer impacts. Emissions are much 

higher during drilling and when the two ice management ships are managing ice, and thus the 

anchor placement activity will not be a condition causing or contributing to highest impact. 

2.13 Oil Spill Response (OSR) Ships

The OSR fleet in the Chukchi is expected to consist of one offshore management/skimmer ship 

(currently the Nanuq), and three 34-foot boats. Two of the 34-foot boats will be used to tow 

containment booms while the third will act as a backup, for crew changes, and for re-fueling. The 

Nanuq is expected to be used only in the unplanned and unlikely event of an oil discharge to the 

water and normally will remain within about five km of the drillship and downwind, but at least 

two km away for safety purposes. The small craft 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 hours 

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 kts. With this slow speed and using 

the approximation that vehicle power is related to the square of the vehicle velocity,13 the 

Nanuq’s propulsion power is estimated to be less than 10 percent from one engine. The OSR 

Nanuq pilot estimates that the two small boats with two engines each will be at approximately 50 

percent.14

 

13 One form of Bernoulli’s Equation: P = k * (velocity)2. With a vehicle maximum of 14 kts, the power to move the ship at 1 kt is 

1/196 of full power or less than 1 percent of full power. Terminel, Michael, Alaska Operations Edison Chouest Offshore. 

[Communications with R. Steen, Air Sciences Inc.]. February12, 2009. 

14 Seltz, Richard H., Alaska Simops Coordinator. [Communication with R. Steen, Air Sciences Inc.]. February 12, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 19 

There will be two other vessels associated with the OSR fleet. One tanker will normally reside 25 

miles from the fleet. On occasion the tanker will come in for re-fueling and training purposes for 

short periods of time. The tanker’s function is to store oil and water from the Nanuq as it 

becomes full from cleanup operations. The Tug/Endeavor Barge will reside near the Chukchi 

coast. Its task is to perform near-shore clean up in the event oil goes in that direction. This ship 

combination will not come out to the drill site. Thus its emissions are not considered with the 

offshore OSR fleet. The OSR fleet will perform daily training when weather and seas permit, but 

will stay in the same area as the Discoverer, 2 or more km downwind. The emissions from the 

training exercises of this OSR fleet are based on daily training, eight hours per day, for the 168 

days season and the emission factors are taken from the Kulluk permit which represent the 

highest emission factors for the source category. For modeling purposes, the emissions are 

spread over a two km distance, two km downwind of the Discoverer. 

2.14 Resupply Ship 

The Discoverer is expected to be provisioned for the first few wells at the beginning of the season, 

and will be re-provisioned at intervals of 2 to 4 weeks, for a maximum of 8 re-provisionings. The 

supply ship is currently expected to be similar to the foreign-flagged Jim Kilabuk, if the drillship 

is resupplied out of Canada, or a similarly sized Jones Act compliance vessel, if resupplied out of 

Alaska. There will be no need for it to be within 25 miles of the Discoverer except for the time 

needed to approach, deliver, and leave the area. If it makes a delivery, it will attach to the 

Discoverer for less than 12 hours during which time one of its 292-hp generators will be operating 

at some power level, assumed for this impact analysis to be capacity, for ship utility powering. 

Its generator emissions while attached to the Discoverer are estimated (Tables 2-1 and 2-2) and its 

impacts are included in the impact analysis. 

2.15 Fuel Used 

Regarding the fuel used, the fleets will voluntarily use diesel fuel with sulfur content of 0.19 

percent or less to limit SO2 emissions from the fleet, and, as BACT, the Discoverer will use ultralow sulfur (15 ppm) fuel to minimize the SO2 emissions from the Discoverer. These are ORRs. 

Currently the ultra-low sulfur fuel is not available on the North Slope and, if needed now, would 

be barged from the northwest, from north through Canada, or purchased in the Far East. These 

fuel qualities are incorporated in the emission and impact assessments. No ultra-low sulfur fuel 

has been purchased by Shell for Alaska use so density and heat content can only be estimated 

from fuel recently purchased for North Slope use15, 16. These values are incorporated in the 

emission calculations of Appendix A and B. 

 

15 Skandinaviska Raffinaderi AB, SCANRAFF. Vladimir Ignatjuk Certificate of Quality. September 19, 2004. 

16 Keiser, Ronald, Domestic Fuels Manager, Shell Marine Products (US) Company. [Communication with C. Tengco, Shell]. 

January 26, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 20 

2.16 Residential, Commercial, and Industrial Growth 

The indirect activities associated with the Discoverer exploration activities are likely to include 

support facilities in Wainwright or Barrow, with possible minor activities in Deadhorse and 

Kotzebue. The facilities could include storage facilities and aircraft hangers. Crew 

accommodations are expected to be in existing hotels but could include some temporary trailer 

camps. Equipment change-out is expected to be by existing commercial means (airlines). 

Communications would be through existing communications center networks.17

2.17 Emissions for Purposes of Modeling 

For purposes of dispersion modeling, the short-term PM and NOx emissions represent maximum 

24-hour values because the impact standards are averaged over 24 hours or longer. While Page 1 

of Appendix A (Discoverer Emissions) contains the maximum hourly emissions, Page 2 emissions 

take into account any daily ORRs (limitations) in daily use. The Page 2 emissions are carried over 

to the modeling emission inputs. The CO and SO2 emissions on Page 2 used in the model are 

maximum 1-hour values (carried over with no modification from Page 1). Page 3 contains the 

stack dimensions used in the impact model. Page 4 contains the partial loads emissions and 

impacts analyses. Pages 5 through 7 contain the source conversion to forms that the model 

understands. Page 8 is a plan view of the Discoverer deck showing locations of the source and is 

identical to Figure 2-2. Page 9 contains the building dimensions used in the BPIP wake effect 

analysis. The following Pages 10 through 12 contain the tabulated hourly and annual emissions, 

including the hazardous air pollutants (HAPs), for inventorying purposes and Pages 13 and 14 

contain the emission factors used for all emission units. While the fleet emission summaries are 

on the Discoverer emissions sheets, the fleet emissions, by emission unit, are calculated and 

displayed on the Fleet Emissions, Pages 1 through 3. For a better understanding of the 

underlying calculations, it should be noted that values in blue are input values, values in black 

are calculated values. 

The emissions of criteria (NAAQS) and total HAPs pollutants for the Discoverer and the 

associated fleets are calculated and provided in Tables 2-1 and 2-2. These emissions are built on 

maximum emission unit use rates which account for any operational restrictions listed in 

Table 2-3, and emission factors provided either by stack tests, the manufacturers, or generic EPA 

factors when manufacturer factors are not available. The data used to construct these emission 

tables are provided in Appendix B. The ORRs in Table 2-3 will apply to normal exploration 

drilling and well completion operations and, except for fuel sulfur content, these restrictions are 

not applied to operations that are undertaken to protect human health, safety, or the environment 

in response to a well control event that might occur despite Shell having exercised reasonable due 

care to avoid such an occurrence. 

 

17 Pavia, Gene, Principal Consultant,UMIAQ. [Communication with R. Steen, Air Sciences Inc.]. January 22, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 21 

2.18 Emissions and Impacts as a Function of Load 

For purposes of estimating emissions and demonstrating that the maximum impacts are due to 

diesel engines running at maximum, which is 100 percent of capacity for all engines except the 

propulsion engines and 80 percent for the propulsion engines, the impacts of five of the larger 

diesel engines are modeled at three loads. Although these engines do not cause the largest local 

impacts, they are representative of different models of diesels and therefore should be 

representative of the smaller engines also. These are the engines that have the most complete 

emissions at partial load data available. Incinerator emissions at various loads are not available 

in the literature or from the manufacturer. Its anticipated use pattern is to receive occasional 

batches and to supply heat at design heat rate for short periods of time; so it would emit at 

capacity rate but for short periods of time. 

The propulsion engines for four ice management and anchor handler ships are modeled at three 

loads: 35, 57, and 80 percent load; and the Discoverer generator engines are modeled at 50, 75 and 

100 percent load. Each load has a separate emission factor and set of stack parameters, provided 

in Table 2-7 and Appendix B, Page 4 with references. From this table it is apparent that even 

though the engines may operate at low loads, it is the emissions and stack parameters of 

maximum load that causes the highest emissions and impacts. Therefore the impact analysis in 

Section 6 is based on engines operating at maximum load. 

2.19 Other Activities 

Tables 2-1 and 2-2 contain all the pollutant emitting activities associated with the project. EPA 

has asked specifically to address the possibility of emissions from drilling of relief wells, use of 

diverters, well control events, flares, well testing, fuel tanks, etc.18

 

18 EPA Comments, Attachment B, II.B.4. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 22 

Table 2-7: NOx Emissions and Impacts at Three Loads 

Load 

(% of capacity) Engine 

NOx emissions 

(g/s normalized) 

NOx impact 

(ug/m3) 

80 Vladimir Ignatjuk - Wärtsilä / 9ZL 1.000 65.5 

57 0.818 45.4 

35 0.354 22.4 

80 Kapitan Dranitsyn – Sulzer 9ZL40/48 1.000 46.6 

57 0.502 24.6 

35 0.345 16.7 

80 Fennica/Nordica - Wärtsilä / 16V32 1.000 49.2 

57 0.690 34.0 

35 0.508 25.0 

80 Tor Viking II – MaK 8M32C 1.000 44.9 

57 0.374 17.8 

35 0.189 9.2 

100 Discoverer – Caterpillar D399 1.000 32.4 

75 0.771 30.0 

50 0.545 25.4 

Table 2-8: PM10 Emissions and Impacts at Three Loads 

Load 

(% of capacity) Engine 

PM10 emissions 

(g/s normalized) 

PM10 impact 

(ug/m3) 

100 Discoverer – Caterpillar D399 1.000 32.4 

75 0.533 20.7 

50 0.315 14.7 

Shell does not plan to flow test wells, flare gas, or store liquid hydrocarbons recovered during 

well testing during its planned drilling campaign using the Discoverer. Therefore, no emissions 

from flaring or stored crude oil tank vapors are included in Tables 2-1 and 2-2. 19 The only fuel in 

use on the Discoverer and associated fleets will be diesel, which has an extremely low vapor 

pressure and therefore there will be negligible emissions from vented fuel tanks. Thus, no 

emissions are included in the emission inventory for these possible source categories. 

With respect to relief well emissions, in addition to the fact that any such drilling is an extremely 

remote contingency, Table 2-1 already includes the relevant emissions information. The only 

emissions that would be associated with well control events would be emissions produced from 

drilling the relief well in the very unlikely event that this were necessary to control a blowout. 

No emissions would be associated with emergency deployment of the ship’s Subsea Blowout 

Preventer (SSBOP). Table 2-1 provides hourly emissions estimates for drilling activities by the 

Discoverer and its associated ships. Those emissions estimates would apply to drilling whether 

 

19 Craik, Keith, Shell. [Communication with R. Steen, Air Sciences Inc]. February 4, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 23 

the well being drilled is a planned well or a relief well being drilled in response to a well control 

event. Thus, it is not necessary to revise Table 2-1 because it already incorporates the hourly 

emission rates during relief well drilling, in the exceedingly unlikely event that such drilling ever 

occurs. 

Table 2-2 provides the estimated annual emissions for the Discoverer and its associated ships, 

based upon operation at the hourly emissions rates for each emissions unit set forth in Table 2-1, 

in compliance with the ORRs on total days of operation per season in Table 2-3. 

Table 2-2 is essentially a specification of allowable emissions for all of the emissions units on or 

associated with the Discoverer under normal operating conditions. Allowable emissions are the 

maximum emissions allowed under the permit under normal operating conditions – here, the 

emissions that are allowed under the EPA-enforced ORRs in Table 2-3. See 40 CFR § 52.21(b) 

(16). EPA’s regulations indicate that allowable emissions should not include emissions that 

would occur only as a result of events outside of standard operating conditions. Appendix W to 

40 CFR Part 51, “Guidelines on Air Quality Models” instructs that emissions resulting from 

malfunctions should not be factored in to allowable emissions. 

Malfunctions which may result in excess emissions are not considered to be a normal operating 

condition. They generally should not be considered in determining allowable emissions. 

Emissions from emergency drilling operations, even more so than ordinary malfunctions, are 

highly unlikely, infrequent events and should not be considered the “normal operating 

condition” of the drilling operation. Therefore, they should not be separately factored into the 

allowable emissions under this permit as represented in Table 2-2. 

In addition to being consistent with EPA policy, restricting Table 2-2 to only those emissions 

associated with the ordinary operating conditions under the permit is the best and most accurate 

approach to conservatively and realistically estimating total annual emissions from these units. It 

is highly improbable that emissions relating to the potential drilling of an emergency relief well 

to address a well control event would ever occur. Therefore, Shell would maintain that it is 

neither informative nor appropriate to include such speculative emissions in this table of 

estimated “annual” emissions from drilling and associated activities. 

Shell drilling plans, protocols, and procedures and the MMS Application for Permit to Drill 

(APD) detail drilling operation precautions for avoiding blowouts during drilling operations. 

EPA has previously acknowledged that the odds that a well control event could occur during 

exploration drilling on the Alaska OCS and that a relief well would then be necessary to bring the 

well under control are almost 1 in 6,000. The inclusion in Table 2-2 of emissions from drilling 

activities that might occur only during one drilling operation in several thousand would 

incorrectly “skew” the data in that table, so as to make it unrepresentative of “annual” emissions 

and inaccurate for anticipated operations. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 24 

Because emissions from drilling a relief well are so unlikely to occur and are not reasonably 

foreseeable, Shell would further maintain that it is also not appropriate or practical to include 

such emissions in the air quality modeling for the Discoverer. In the highly unlikely event that, at 

some future time, the Discoverer’s drilling operations were to cause a violation of a NAAQS or the 

PSD increment due to emissions produced during emergency relief well drilling at the end of a 

drilling season, it is acknowledged that EPA would have discretion to take enforcement action 

against Shell for such a violation under the Agency’s policy on “excess emissions” that result 

from, inter alia, malfunctions. See “State Implementation Plans: Policy Regarding Excess 

Emissions During Malfunctions, Startup, and Shutdown,” Steven A. Herman, Assistant 

Administrator for Enforcement and Compliance (September 20, 1999) (“Herman 

Memorandum”). 20

 

20 This policy was reconfirmed in a memorandum issued by Eric Schaeffer, Director of the Office of Regulatory Enforcement, dated 

December 5, 2001, which clarified that the policy was intended to be applied prospectively to future SIP approvals. Although these 

guidance documents are designed to set out the standards under which EPA will approve a SIP, they also provide the most 

applicable guidance to of EPA’s policy regarding excess emissions for all permits, those issued pursuant to a SIP and those issued 

under federal regulations. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 25 

SECTION 3

REGULATORY APPLICABILITY 

The Discoverer is to be an “exploratory OCS source,” under 40 CFR Section 55.2, and will be 

regulated under 40 CFR Section 55.3 (c). Since it will be drilling beyond the 25-mile Alaska 

Seaward Boundary, it will be exempt from the Alaska-only requirements (40 CFR Sections 55.4, 

55.5, 55.11 and 55.12). Under Section 55.6 (a)(1), an OCS permit application is required, and 

under Section 55.6 (a)(3) the administrator (EPA Region 10) is instructed to follow the 

administrative procedures of 40 CFR Section 124, used to issue PSD permits. Section 55.6 (d) 

requires permitting by the Section 55.13 requirements. Sections 55.8 and 9 address compliance 

requirements and enforcement. Section 55.10 instructs the EPA to apply operational fees 

according to Part 71 requirements. Section 55.11 allows for the delegation of the administration 

of these rules. 

From a regulatory perspective, the OCS source is the Discoverer and it is regulated only when it is 

attached to the seabed (Section 55.2, “OCS source”). This stationary source includes any 

additional ships when physically attached to the Discoverer (Section 55.2, “OCS source”). For 

purposes of this permitting, the source, its emissions, and its emission controls and operational 

restrictions are described only for the drilling activity, which is defined as the time from 

placement of the first of eight anchors to removal of or detachment from the last anchor. The 

Discoverer’s emissions are not regulated (or defined) while not attached to the seabed. 

The “potential emissions” as defined in Section 55.2 are used to determine applicability of Section 

55.13 (d), which are the 40 CFR Section 52.21 (PSD) permitting rules and include the emissions 

from the Discoverer and associated fleets when they are within 25 miles of the drill site. The 

emissions in Tables 2-1 and 2-2 represent the emissions during the time the Discoverer is a 

stationary source and are appropriate for drilling impact modeling. They do not include the 

minor addition from the Discoverer propulsion emissions for the approximate four hours of time 

to bring the Discoverer the final 25 miles to the drill site and move it away (which would add less 

than one half ton of NOx emissions). As depicted in the last row of Table 2-2, the Discoverer and 

fleets totals for particulate matter (PM10 and PM2.5), nitrogen oxides (NOx), sulfur dioxide (SO2), 

carbon monoxide (CO), and volatile organic matter (VOC) exceed the thresholds of applicability 

(52.21 (b)(1)(i)). Therefore, Section 52.21 rules apply to this source, and it is unnecessary to 

consider the emissions from the approximate four hours to transport the Discoverer within 25 

miles to and from the drill site to determine whether the PSD rules are applicable. The PSD rules 

are applicable. 

This application focuses on the permitting requirements under Section 55.13, subsection (c), (d), 

(e), and (h). The applicability of subsection (d) is determined first, and since it is applicable to the 

Discoverer, the other subsections need not be addressed outside of (d) because they are embedded 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 26 

in the (d) requirements. Section 55.13 (d) requires the Discoverer OCS source to address the 40 

CFR Section 52.21 major source permitting rules and these rules include: 

Section (j) Control Technology Review: This review includes a best available control technology 

(BACT) review for all regulated NSR pollutants with the potential to be emitted in significant 

amounts, NSPS applicability and NESHAPs applicability determination. This review is in 

Section 4 of this application. 

Section (k) Source Impact Analysis: This demonstration that the Discoverer will not cause or 

contribute to a violation of NAAQS or PSD increment is included as Section 5 of this application. 

Section (m) Air Quality Analysis: This review of baseline concentrations of regulated NSR 

pollutants with the potential to be emitted in significant amounts is included in Section 6 of this 

application. 

Section (o) Additional Impact Analysis: This impact analysis of impairment to visibility, soils, and 

vegetation is included in Section 8 of this application. 

Section (p) Sources Impacting Federal Class I Areas: Shell claims exemption from this subsection 

because of the distance from the nearest Class I area. Denali National Park is the nearest Class I 

area and it is over 600 miles from the source, which is beyond the distance of concern and is not 

considered further herein. 

In the process of addressing the emission control technology, source impact analysis and air 

quality analysis requirements, the pollutants to be addressed are limited to those that have 

emissions greater than “significant emission rate” defined in Section 52.21 (b)(23) and the 

definition of “source” for the purpose of determining “significant emission rate” is not clearly 

defined. Table 3-1 shows the “Significant Emission Rate” for each pollutant and the 

corresponding projected emissions both from the Discoverer alone and from the Discoverer with 

the associated fleets, each under the proposed operating restrictions in Table 2-3. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 27 

Table 3-1: Significant Emission Rates 

Pollutant 

Significant 

Emission Rate 

Threshold 1

(tpy) 

Discoverer

Emission 

Limit 

(tpy) 

Discoverer and 

Fleet Emission 

Limit 

(tpy) 

Nitrogen Dioxide (NOx) 40 56.14 887 

Particulate Matter (PM2.5) 10 6.10 35 

Particulate Matter (PM10) 15 6.10 35 

Sulfur Dioxide (SO2) 40 0.92 53 

Carbon Monoxide (CO) 100 11.89 233 

Volatile Organics 40 2.53 26 

1 40 CFR Section 52.21 (b)(23) 

This application analysis is based on the conservative assumption that significant emission rates 

could include emissions from the Discoverer and its associated fleets. And therefore both a source 

impact analysis from the Discoverer and fleets, and Best Available Control Technology (BACT) 

analysis for Discoverer source units will be performed for NOx, PM2.5, PM10, SO2, and CO 

emissions. 

Regarding the impact analysis, this application demonstrates that the Discoverer will be in 

compliance with increment and the NAAQS at the Burger Prospect (71° 15’ N, 163° 13’ W), 

shown on Figure 1-1, which is expected to be its initial operating location. Thereafter, as a 

portable source, the Discoverer is proposing to drill at any of Shell Gulf of Mexico Inc.’s existing 

leases in the Chukchi Sea, beyond the 25-mile limit without the necessity of further 

demonstrating compliance with the PSD increment and NAAQS as long as it meets the definition 

of “portable.” Section 52.21 (i)(1)(viii), provides this exemption when a previously permitted 

source is relocated and its emissions will be temporary, its emissions will not exceed the permit 

limits at any new location, the emissions will impact no Class I area and will not contribute to 

any known increment or NAAQS violation, and reasonable notice of relocation is provided to the 

Administrator. Although not a permitting requirement, Shell also provides a hypothetical worstcase analysis of modeled ambient air quality impacts at the nearest Chukchi shoreline villages 

that are located closest to a Shell lease, with drilling assumed to occur on that least for the entire 

season (Section 7.4).
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 28 

SECTION 4

EMISSION CONTROL TECHNOLOGY REVIEW 

4.1 Best Available Control Technology (BACT) Overview 

Table 3-1 indicates that emissions from the Discoverer and its associated support vessels exceed 

the Significant Emission Rates established for NOx, PM10, SO2, and CO. According to 40CFR52.21 

(j) (2), a BACT analysis is to be performed on each emission unit on the Discoverer that emits these 

pollutants. 

BACT is defined in the PSD regulations as: 

“... an emission limitation 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 ... which [is determined to be achievable], on a case-by-case basis, taking 

into account energy, environmental, and economic impacts and other costs” [40 CFR 

52.21(b)(12)].

In a 1987 memorandum, EPA provided guidance on the “top-down” methodology for 

determining BACT. The “top-down” process involves the identification of all applicable control 

technologies according to control effectiveness. Evaluation begins with the “top,” or most 

stringent, control alternative. If the most stringent option is shown to be technically or 

economically infeasible or if environmental impacts are severe enough to preclude its use, then it 

is eliminated from consideration and the next most stringent control technology is similarly 

evaluated. This process continues until the BACT level under consideration cannot be eliminated 

by technical or economic considerations, energy impacts, or environmental impacts. The top 

control alternative that is not eliminated in this process becomes the proposed BACT basis.

This top-down BACT analysis process can be considered to contain five basic steps described 

below (from the EPA’s Draft New Source Review Workshop Manual, 1990).21 

1. Identify all available control technologies. 

2. Eliminate technically infeasible options. 

3. Rank remaining technologies by control effectiveness. 

4. Evaluate the most effective control based on a case-by-case consideration of energy, 

environmental, and economic impacts. 

5. Select BACT. 

 

21 U.S. EPA. New Source Review Workshop Manual Prevention of Significant Deterioration and Nonattainment Area Permitting. 

Draft October 1990.
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 29 

Shell applied EPA’s top-down methodology to groups of similar emission units on the Discoverer. 

For example, there are six large diesel generators that are identical, so individual BACT analyses 

are not warranted. Similarly, there are small diesel engines (<500 hp) and diesel fired 

compressors (540 hp) that are very similar and the BACT determinations for individual units 

would be redundant. 

Table 4-1 identifies the emission unit categories and summarizes the results of Shell’s BACT 

analysis. Additional detail is provided in the following sections. 

Table 4-1: Source Categories, Proposed BACT 

Source Category PM10 NOx SO2 CO 

Diesel Generators (1,325 hp) OxyCat SCR ULSD OxyCat 

Small Diesel Engines (<500 hp) CDPF GCP ULSD CDPF 

Diesel Compressors (540 hp) Tier 3 Tier 3 ULSD Tier 3 

Heater/boiler GCP GCP ULSD GCP 

Incinerator GCP GCP ULSD GCP 

SCR selective catalytic reduction 

OxyCat oxidation catalyst 

CDPF catalytic diesel particulate filter 

GCP good combustion practices 

Tier 3 EPA Non-Road Engine Tier 3 Emission Standards per 40 CFR 89.112 

ULSD Ultra-low sulfur distallate fuel (15 ppm sulfur content) 

An OCS exploratory drilling operation is substantially different than the industrial sources 

typically addressed by the PSD permit process. As a result, we find a number of areas where the 

typical permit process just doesn’t “fit.” For example, all of the emission units on the Discoverer, 

except for the MLC compressors, are existing units, purchased and used for many years prior to 

this application, so BACT is focused on retrofit technologies. 

One interpretation of applicable regulations is that the anchor handler vessels and resupply ship 

are part of the Discoverer “stationary source” when they are (however briefly) connected to the 

Discoverer. As part of the stationary source, one might conclude that BACT must be applied to 

the emission units on these vessels. Shell has not conducted a detailed BACT analysis for these 

vessels because there is no way implementation of emission controls beyond good operating 

practices could be cost effective. 

• Supply vessels. There are expected to be a maximum of 8 resupply events. When 

supplies are delivered, the supply vessel would be tied alongside the Discoverer for 

a maximum of 12 hours, for a season maximum of 96 hours, and with only the 

generator operating. Emission calculations in Appendix A indicated the generator 

on the supply ship could emit up to 860 lb NOx and 60 lb PM10 during this period. 

Since this will be a leased vessel, it may only serve the Discoverer for one season. 

Given this low emission rate, the total emissions would be small. It is 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 30 

inconceivable that implementation of additional controls on the supply vessel 

generator could be cost effective. 

• Anchor handler. Setting the anchors is expected to require approximately 18 hours 

of low speed operation of the anchor handling vessel. Even with the possible 

drilling of four wells (eight anchor handling events), annual emissions will be 

small. It is inconceivable that implementation of additional controls on the leased 

anchor hander vessel, that could be used with the Discoverer for only one season, 

could be cost effective. 

4.1.1 NOx BACT Analyses 

Step 1 – Available Control Technologies 

There are two sources of nitrogen that when oxidized result in NOx emissions – nitrogen in the 

fuel and nitrogen in the combustion air. Oxidation fixation of atmospheric nitrogen is known as 

thermal NOx. The production of thermal NOx is a function of combustion flame temperature. 

The available NOx control technologies for the Discoverer’s engines, boilers, and incinerator can be 

characterized by the following two categories: combustion control and post-combustion exhaust 

treatment. In combustion control, thermal NOx is reduced by lowering the peak combustion 

temperature. Post-combustion exhaust treatment relies on the removal of NOx from the exhaust 

stream through adsorption or reduction. 

Available NOx control technologies for the Discoverer’s engines, boilers, and incinerator were 

determined by searching the EPA RACT/BACT/LAER Clearinghouse (RBLC) and the California 

Air Resources Board Statewide Best Available Control Technology Clearinghouse (CA-BACT). 

The search conditions and a summary of the resulting control technologies are provided in Table 

4-2. The complete database downloads are provided in Appendix C. For the RBLC, only those 

determinations made after January 1, 1999, were downloaded because older determinations are 

typically less stringent. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 31 

Table 4-2: Available NOx Control Technologies 

Source Category Clearinghouse Search Conditions Control Technologies 

Diesel IC Engines (>500 hp) RBLC Process Code = 17.110 None, AC, HIP, ITR, 

LND, SCR, TIER 2/3, 

WI 

 CA-BACT I.C. Engines - CI, NonEmergency (>500 hp) None, AC, SCR, ITR 

Diesel IC Engines (≤500 hp) RBLC Process Code = 17.210 None, AC, ITR, LND 

 CA-BACT I.C. Engines - CI, NonEmergency (≤500 hp) None, AC, ITR, WI* 

Boiler (≤100 MMBtu/hr) RBLC Process Code = 13.220 None, LNB, FGR 

 CA-BACT Boilers – Oil Fired 

(≤100 MMBtu) 

No determinations 

Incinerator RBLC Process Description = 

Incinerator; Fuel = 

Solid Waste 

None, SNCR 

 CA-BACT No determinations 

*Unit was never installed. 

CI Compression Ignition. 

Process Code Key: 

17.110 - Large Internal Combustion Engines (>500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

17.210 - Small Internal Combustion Engines (≤500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

13.220 - Commercial/Institutional-Size Boilers/Furnaces (≤100 million BTU/H); Distillate Fuel Oil (ASTM #1, 2, includes 

kerosene, aviation, diesel fuel). 

Control Technology Key: 

AC Intake Air Cooling 

FGR Flue Gas Recirculation 

HIP High Injection Pressure 

ITR Injection Timing Retard 

LNB Low NOx Burners 

LND Low NOx Design 

SCR Selective Catalytic Reduction 

SNCR Selective Non-Catalytic Reduction 

TIER 2/3 EPA Non-Road Engine Emission Standards per 40 CFR 89.112 

WI Water Injection 

None No specific technology listed or good combustion practices 

Diesel-fueled Reciprocating Engines 

The available NOx combustion control technologies for diesel engines identified in the RBLC and 

CA-BACT are injection timing retard (ITR), intake air cooling (AC), high injection pressure (HIP), 

low NOx design (LND), Tier 2 or 3 level controls, water injection (WI), and good combustion 

practices. The RBLC and CA-BACT also listed lean burn, air-to-fuel ratio control, turbocharger, 

clean fuel, and preventative maintenance as part of the NOx control description. These 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 32 

technologies or work practices are not specific to NOx reduction and, therefore, are not discussed 

further.22

ITR reduces NOx emissions in reciprocating engines by delaying the injection of fuel in the engine 

from when the chamber is at its smallest to a time when the compression chamber is expanding. 

The larger volume in the compression chamber lowers peak combustion temperature, thus 

reducing thermal NOx formation. Lower peak combustion temperature can also be achieved 

with charge air coolers (AC), common to turbo charged engines, which reduce the intake 

manifold temperature. The combination of ITR and AC may reduce NOx by 10 to 50 percent (up 

to 40 percent from ITR and an additional 10 percent from AC).23

Cooling the flame with ITR and/or AC reduces NOx at the expense of incomplete combustion, 

resulting in the formation of PM, VOC, and CO emissions and reduced fuel economy.24 The fuel 

economy penalty can be reduced by increasing injection pressure. High injection pressure (HIP) 

can accomplish better fuel atomization which leads to better combustion and reduced PM 

emissions. ITR also has a negative impact by contamination of lube oil with soot which increases 

engine wear.25 

In WI systems, water acts as an inert gas and also absorbs heat in the process of evaporation. 

Both effects cause a decrease in the peak combustion temperature, thus reducing thermal NOx

formation by up to 50 percent.26 The main disadvantage of WI is the large amount of extremely 

pure water required. In general, reduction of NOx by one percent requires one percent of water 

in the water-fuel system.27 In other words, achieving a 50 percent NOx reduction requires 

running the engine using a 1:1 mix of water and diesel fuel. Another problem with the 

introduction of water in the combustion chamber is the potential for liquid droplets to contact the 

cylinder surface. In this case, there would be an immediate disintegration of the lubrication oil 

film, damaging the engine. Cold temperature environments (such as the Arctic Ocean) are also 

problematic for WI systems due to the potential for freezing. 

The RBLC also lists low NOx design (LND) for several engines, but does not describe the actual 

NOx combustion control technology. It is assumed that these determinations are referring to 

specific combustion chamber designs which provide good mixing of fuel and air before the start 

 

22 Turbocharged engines with after- or inter-cooling can increase fuel efficiency, but it is the air intake cooling that provides the 

actual NOx control. Clean fuels with low nitrogen contents do reduce NOx produced from fuel-bound nitrogen. However, the amount 

of NOx produced from the fuel-bound nitrogen in distillate fuel oil constitutes only a small fraction of the total NOx. Lean burn, air-tofuel ratio control, and preventative maintenance are more related to engine performance than NOx control. 

23 Khair, Magdi K. DieselNet Technology Guide. Engine Design for NOx Control. May 2002. 

24 DieselNet Technology Guide. Engine Design for Low Emissions. March 2003. 

25 Ibid. footnote 24. 

26 Genesis Engineering Inc. & Levelton Engineering Ltd. Non-Road Diesel Emissions Reduction Study. October 14, 2003. 

27 Ibid. footnote 24. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 33 

of combustion. These designs are intrinsic to the particular model of engine associated with each 

RBLC determination for LND. 

Although not listed in the RBLC or CA-BACT, exhaust gas recirculation (EGR) is a new diesel 

engine NOx combustion control technology which is becoming commercially available. In 

October 2002, several heavy-duty engine manufacturers introduced their new EPA-certified 

engines equipped with EGR systems.28 EGR is a method by which a portion of the engine’s 

exhaust gas is returned to its combustion chambers via the inlet system in order to reduce 

thermal NOx formation. In general, the most important factor contributing to the NOx reduction 

effect of EGR is the decrease in the peak combustion temperature caused by the heat adsorption 

and oxygen reduction effects of the returned inert exhaust gas. The NOx emission benefit of EGR 

comes at a cost: increased PM, HC, and CO emissions, a fuel economy penalty, and potential 

engine wear and durability issues.29 EGR demonstration tests have shown NOx reductions from 

EGR of 40 to 50 percent.30

The only post-combustion exhaust treatment control technology listed in the RBLC and 

CA-BACT for diesel engines is Selective Catalytic Reduction (SCR). SCR systems use ammonia 

or urea to selectively reduce NOx to elemental nitrogen and water. SCR injects ammonia or urea 

into the exhaust upstream of a catalyst bed. The operating temperature for various catalysts are 

175°C to 250°C for platinum catalysts, 300°C to 450°C for vanadium catalysts, and 350°C to 600°C 

for zeolite catalysts.31 SCR systems are commonly used on stationary sources,32 as they require a 

fixed ammonia or urea tank in a containment area, a fixed catalyst bed and injection system, and 

a fixed NOx measurement and control system. Several of the Discoverer engines are portable so it 

is relevant to note that there are no SCR determinations in the RBLC or CA-BACT for engines 

listed as portable units.33 An SCR system can achieve approximately 90 percent NOx reduction.34

Regardless of the technology applied to achieve BACT, the control option must result in an 

emission rate no less stringent than the applicable New Source Performance Standard (NSPS) 

emission rate, if any NSPS standard for that pollutant is applicable to the source. EPA has 

promulgated exhaust emission standards for non-road engines under 40 CFR 89.112 in 1998. 

Most of the Discoverer engines are older than 1998. However, the MLC compressors (540 hp) will 

be new engines. The 1998 non-road engine regulations are structured in three tiers. In each tier, 

the emission standards are phased in over several years. Tier 1 standards were phased in from 

 

28 Khair, Magdi K. DieselNet Technology Guide. Exhaust Gas Recirculation. November 2006. 

29 Ibid. footnote 28. 

30 Ibid. footnote 28. 

31 Ibid. footnote 26. 

32 U.S. EPA. Office of Transportation and Air Quality. Clean Construction USA, Retrofit Strategies. September 28, 2007. 

33 RBLC ID MS-0086 is incorrectly listed as a portable unit. This engine was a temporary unit that Chevron Products Company 

rented for 9 months for use at a single location (i.e., stationary unit). It was then removed from the site. Brown, Carla. Mississippi 

Department of Environmental Quality. [Communication with D. Steen, Air Sciences Inc.]. February 9, 2009. 

34 Ibid. footnote 26. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 34 

1996 to 2000. The more stringent Tier 2 standards took effect from 2001 to 2006. The still more 

stringent Tier 3 standards were phased in between 2006 and 2008. Tier 3 standards apply only 

for engines from 37-560 kW. The NOx emission standards for larger generators are provided in 

Table 4-3. 

Table 4-3: EPA Tier 1-3 Nonroad Diesel Engine NOx Emission Standards 

 NMHC+NOx NOx

Engine Power Tier Year g/kWh (g/bhp-hr) 

225 ≤ kW < 450 Tier 1 1996 - 9.2 (6.9) 

(300 ≤ hp < 600) Tier 2 2001 6.4 (4.8) - 

 Tier 3 2006 4.0 (3.0) - 

450 ≤ kW < 560 Tier 1 1996 - 9.2 (6.9) 

(600 ≤ hp < 750) Tier 2 2002 6.4 (4.8) - 

 Tier 3 2006 4.0 (3.0) - 

kW ≥ 560 Tier 1 2000 - 9.2 (6.9) 

(hp ≥ 750) Tier 2 2006 6.4 (4.8) - 

NMHC Non-methane hydrocarbons. 

Diesel-Fired Boilers 

There are two 8 MMBtu/hr boilers on the Discoverer. The available NOx combustion control 

technologies for diesel-fired boilers less than or equal to 100 MMBtu/hr identified in the RBLC 

and CA-BACT, and show in Table 4-2, are LNB, FGR, and good combustion practices. LNB 

combustion system reduces thermal NOx by reducing the peak combustion temperature relative 

to conventional burners. LNB designs are specific to the manufacturer. FGR reduces NOx

emissions by recirculating a portion of the boiler flue gas into the main combustion chamber. 

This process reduces the peak combustion temperature and lowers the percentage of oxygen in 

the combustion air/flue gas mixture, thus retarding the formation of thermal NOx. 

Waste Incinerator 

The available NOx combustion control technologies for waste incinerators identified in the RBLC 

and CA-BACT, and shown in Table 4-2, are SNCR and good combustion practices. The SNCR 

process involves injecting either ammonia or urea into the firebox of the incinerator, at a location 

where the flue gas is between 1,600°F and 2,100°F, to react with the NOx formed in the 

combustion process. The resulting products of the chemical reaction are elemental nitrogen, 

carbon dioxide, and water. 

4.1.1.1 NOx BACT for Diesel Generators 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.2, the available control technologies for the Discoverer’s six diesel 

generators (FD-1 through FD-6 – 1,325 hp Caterpillar D399 Marine Generator Set) are ITR, AC, 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 35 

HIP, LND, Tier 2 or 3 level controls, WI, EGR, and SCR. LND, Tier 2 or 3 level controls, EGR, and 

WI are considered technically infeasible. LND and Tier 2 or 3 level controls are intrinsic to the 

original engine design which are not part of the Caterpillar D399 design. EGR is not available for 

these older model engines. WI is considered technically infeasible due to the cold climate in 

which these generators will operated, the potential engine retrofit incompatibility, the excessive 

pure water requirements and limited available ship space for storing the water, and the potential 

engine damage risk associated with this technology. 

ITR, AC, and HIP are considered technically feasible for this generator model. SCR is also 

considered technically feasible because the engines are stationary on the vessel deck. 

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for Generators FD-1 through FD-6 are ranked by 

control effectiveness as follows: 

1. SCR – 90 percent control 

2. ITR, AC, and/or HIP – 10 to 50 percent control 

3. Good Combustion Practices 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

Shell proposes to apply SCR, the most effective NOx control option to Generators FD-1 through 

FD-6. Shell acknowledges that there is ammonia slip associated with SCR. 

Step 5 – Selection of BACT

Shell proposes to employ SCR technology to achieve 0.5 gram/kW-hr. DEC Marine, the supplier 

to several other vessels applying SCR, indicates this is the highest efficiency control available for 

the Discoverer’s diesel-fired generators35. 

4.1.1.2 NOx BACT Smaller Diesel Engines 

Step 2 –Technical Feasibility 

The Discoverer’s small diesel engines include: 

• FD-12 and FD-13, HPU Engines – 250 hp Detroit 8V-71, 

• FD-14 and FD-15, Cranes – 365 hp Caterpillar D343, 

• FD-16 and FD-17, Cementing Units – 335 hp Detroit 8V-71N, 

• FD-18, Cementing Unit – 147 hp GM 3-71, 

• FD-19, Logging Winch – 128 hp Detroit 4-71N, and 

• FD-20, Logging Winch – 36 kW 4024TF270. 

 

35 Ibid. footnote 1. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 36 

As discussed in Section 4.1.2, the available control technologies for engines under 500 hp are ITR, 

AC, LND, WI, and good combustion practices. LND, EGR, and WI are considered technically 

infeasible. LNDs are intrinsic to the original engine design which are not part of the design for 

these engines. EGR was not available for these older model engines. WI is considered technically 

infeasible due to the cold climate in which these generators will operated, the potential engine 

retrofit incompatibility, the excessive pure water requirements and limited available ship space 

for storing the water, and the potential engine damage risk associated with this technology. 

There are no determinations for installing SCR on diesel engines under 500 hp. This implies 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. In addition, the HPUs, 

cranes, and logging units are portable in the sense that the units move during use. Portable 

commercial retrofit SCR tailpipe systems, which include urea tanks, are not available, so this 

control option is considered technically infeasible as retrofits for these units. 

The cementing units are stationary on the vessel deck; Shell is unaware of any instance where 

SCR technology has been installed on deck-utility engines (under 500 hp) on exploration vessels. 

While it may be technically feasible in some applications, SCR controls on the Discoverer could 

only be installed in a horizontal configuration. Because the SCR units have a footprint 

approximately double that of the cementing engines, SCR would consume too much deck space 

and would seriously affect the safety of necessary nearby deck operations. This impact to safety 

of operations makes SCR technically infeasible for implementation on the Discoverer. 

ITR and AC are considered technically feasible for these engines. 

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for Engines FD-12 through FD-20 are ranked by 

control effectiveness as follows: 

1. ITR and AC – 10 to 50 percent control 

2. ITR – up to 40 percent control 

3. AC – approximately 10 percent control 

4. Good Combustion Practices 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

As discussed in Section 4.1.2, ITR and AC reduce NOx at the expense of incomplete combustion; 

this increases PM, VOC, and CO emissions, reduced fuel economy, and contaminates the lube oil 

with soot.24 Furthermore, as discussed below, Engines FD-12 through FD-20 will be equipped 

with CDPF controls to reduce PM and CO emissions. CDPF requires a degree of combustion 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 37 

control, so it is likely that ITR will have a negative effect on this control. Due to these energy and 

environmental considerations, neither ITR nor AC is considered BACT. 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s diesel-fired small engines. 

Good combustion practices require operating and maintaining the equipment according to the 

manufacturer’s recommendations to maximize fuel efficiency and minimize emissions. 

4.1.1.3 NOx BACT Diesel Compressors 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.2, the available control technologies for the Discoverer’s three diesel 

MLC compressors (FD-9 through FD-11 – 540 hp Caterpillar C-15 engines) are ITR, AC, HIP, 

LND, Tier 2 or 3 level controls, WI, EGR, and SCR. Tier 2 or 3 level controls are considered 

technically feasible for this engine model, as it is already configured to meet the Tier 3 emission 

standards. Since these engines are designed and tuned to meet Tier 3, they are incompatible with 

incorporating combustion control technologies such as ITR, AC, HIP, LND, and EGR on top of 

the Tier-3 controls. Note, the C-15 combustion control technology for meeting Tier 3 already 

incorporates the technologies of cooling and EGR.36 

WI is considered technically infeasible due to the cold climate in which these generators will 

operated, the potential engine retrofit incompatibility, the excessive pure water requirements and 

limited available ship space for storing the water, and the potential engine damage risk 

associated with this technology. 

The MLC compressors (Caterpillar C-15) engines are portable (moved back and forth from 

storage to operating location when needed due to limited deck space). There are no 

determinations for installing SCR on portable diesel engines. This implies that SCR is not BACT 

for the portable engines due to technical infeasibility and/or due to energy, environmental, 

and/or economic impacts. Shell is not aware of any instance where this control technology has 

been installed on deck-utility engines of this small size on exploration vessels previously. 

Additionally, the SCR units could only be installed in a horizontal configuration (they have a 

footprint approximately double that of the air compressors) which consumes limited and 

valuable deck space and seriously impacts the safety of necessary nearby deck operations. The 

portable nature of the engines and this impact to safety of operations makes SCR technically 

infeasible. 

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for Engines FD-9 through FD-11 are ranked by 

control effectiveness as follows: 

 

36 Caterpillar brochure. Cat® C15 for Fleet and Line Haul Performance, ACERTTM Technology for 2007. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 38 

1. Tier 3 Emission Standards of 4.0 g/kWh of NMHC+NOx

2. Tier 2 Emission Standards of 6.4 g/kWh of NMHC+NOx

3. Good Combustion Practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

Shell proposes that the Tier 3 emissions standards are the BACT and that additional evaluation is 

not required. However, it is important to note that the Tier 3 Emission Standards also limit CO 

and PM emissions. 

Step 5 – Selection of BACT

Shell proposes the Tier 3 Emission Standards of 4.0 g/kWh of NMHC+NOx as BACT for 

Discoverer’s diesel-fired compressors. 

4.1.1.4 NOx BACT Boilers 

Step 2 –Technical Feasibility 

There are two boilers (FD-21 and FD-22 – 8 MMBtu/hr Clayton 200) providing general heat to the 

Discoverer. Only one boiler will operate at a time and the second will serve as a backup. As 

discussed in Section 4.1.2, the available control technologies for these boilers are LNB, FGR, and 

good combustion practices. LNB and FGR are considered technically infeasible for this model 

boiler. The LNB option for this boiler is only available for natural gas and propane fuels.37 The 

FGR option available for the Clayton 200 diesel boiler is provided as package during the original 

installation. Clayton Industries (the manufacturer) does not know of any cases where FGR has 

been retrofitted on an existing unit purchased without FGR, as in the case of the Discoverer’s

boilers.38 

There are no determinations for installing SCR on diesel boilers under 100 MMBtu/hr. This 

implies that SCR is not BACT for this diesel boiler category due to technical infeasibility and/or 

due to energy, environmental, and/or economic impacts. This control technology has never been 

required (or installed to Shell’s knowledge) on utility boilers of this small size on exploration 

vessels. More importantly, the boilers are located adjacent to the engine room which is being 

expanded to accommodate SCR on the generators. There is no deck space for additional SCR 

units beyond those proposed for the generators. Thus, SCR is considered technically infeasible in 

for this situation. 

Step 3 – Control Effectiveness Ranking 

The only technically feasible control option for the two boilers (FD-21 and FD-22) is good 

combustion practices. 

 

37 Clayton Industries brochure. Advanced Low NOx Technology. http://www.claytonindustries.com. August 2007. 

38 Services Department. Clayton Industries. [Communication with D. Steen, Air Sciences Inc.]. February 11, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 39 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT, thus this step is not required. 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s diesel-fired boilers. Good 

combustion practices require operating and maintaining the equipment according to the 

manufacturer’s recommendations to maximize fuel efficiency and minimize emissions. 

4.1.1.5 NOx BACT Incinerator 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.2, the available control technologies for the Discoverer’s incinerator 

(FD-22 – 276 lb/hr TeamTec/GS500C) are SNCR and good combustion practices. SNCR is 

considered technically infeasible for this incinerator. The Discoverer’s incinerator is very small in 

comparison to the incinerator listed in the RBLC with SNCR (575 tons per day; 48,000 lb/hr). 

Based on communication with TeamTec, the manufacturer, they are not aware of any control 

technologies that have been installed on this model of incinerator for control of any of the 

pollutants.39 Shell is not aware of any control technology installations on this or similar-sized 

incinerators. 

Step 3 – Control Effectiveness Ranking 

The only technically feasible control technology for the incinerator FD-23 is good combustion 

practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT, thus this step is not required. 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s incinerator. Good combustion 

practices require operating and maintaining the equipment according to the manufacturer’s 

recommendations to maximize fuel efficiency and minimize emissions. 

4.1.2 SO2 BACT Analysis 

Step 1 – Available Control Technologies 

The combustion of fuels containing sulfur produces SO2 emissions. The available SO2 control 

technologies for the Discoverer’s engines, boilers, and incinerator can be characterized by the 

 

39 Bulien, Ole. TeamTec Marine Products. [Communication with K. Lewis, Air Sciences Inc.]. February 11, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 40 

following two categories: combustion of low-sulfur fuels and post-combustion exhaust 

treatment. Post-combustion exhaust treatment relies on the removal of SO2 from the exhaust 

stream through adsorption. 

The available SO2 control technologies for the Discoverer’s engines, boilers, and incinerator were 

determined based on searches performed on the RBLC and CA-BACT. The search conditions and 

a summary of the resulting control technologies are provided in Table 4-4. The complete 

downloads are provided in Appendix C. For the RBLC, only those determinations made after 

January 1, 1999, were downloaded. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 41 

Table 4-4: Available SO2 Control Technologies 

Source Category Clearinghouse Search Conditions Control Technologies 

Diesel IC Engines (>500 hp) RBLC Process Code = 17.110 None, LSF 

 CA-BACT I.C. Engines - CI, NonEmergency (>500 hp) None, LSF 

Diesel IC Engines (≤500 hp) RBLC Process Code = 17.210 None, LSF 

 CA-BACT I.C. Engines - CI, NonEmergency (≤500 hp) None, LSF

Boiler (≤100 MMBtu/hr) RBLC Process Code = 13.220 None, LSF 

 CA-BACT Boilers – Oil Fired 

(≤100 MMBtu) 

No determinations 

Incinerator RBLC Process Description = 

Incinerator; Fuel = 

Solid Waste 

None, LSF, SDS 

 CA-BACT No determinations 

CI Compression Ignition. 

Process Code Key: 

17.110 - Large Internal Combustion Engines (>500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

17.210 - Small Internal Combustion Engines (≤500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

13.220 - Commercial/Institutional-Size Boilers/Furnaces (≤100 million BTU/H); Distillate Fuel Oil (ASTM #1, 2, includes 

kerosene, aviation, diesel fuel). 

Control Technology Key: 

LSF Low Sulfur Fuel (defined as ≤0.1 weight percent sulfur for the purpose of this analysis) 

SDS Semi-Dry Scrubber 

None No specific technology listed 

The available SO2 control technology for diesel engines and diesel-fired boilers less than or equal 

to 100 MMBtu/hr identified in the RBLC and CA-BACT is the use of Low Sulfur Fuel (LSF). For 

the purpose of this analysis, LSF is considered to be 0.1 percent sulfur by weight or less. Fuel 

sulfur contents listed in the RBLC and CA-BACT determinations ranged from ≤0.0015 to ≤0.5 

weight percent. The most prevalent fuel sulfur contents listed for the diesel engines and dieselfired boilers were ≤0.05 and ≤0.15 weight percent, respectively. 

For the Discoverer’s incinerator, SO2 is produced from the combustion of the diesel fuel used to 

heat the furnace and the combustion of solid waste which typically contains small amounts of 

sulfur. The RBLC and CA-BACT listed LSF and Semi-Dry Scrubber (SDS) as the available control 

technologies for waste incinerators. In a SDS, particles of an alkaline sorbent are injected into a 

flue gas and SO2 is adsorbed producing a solid by-product. 

4.1.2.1 SO2 BACT for the Diesel Engines and Boilers 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.3, the available control technology for the Discoverer’s diesel engines 

and diesel-fired boilers is LSF. LSF is considered technically feasible for these diesel combustion 

units. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 42 

Shell notes that wet scrubbers were not identified as control options for internal combustion 

engines and small boilers in the RBLC or the CA-BACT databases. In fact, wet scrubbers may be 

technically feasible, but were determined by the BACT analyses to not be cost effective because 

emissions from small units are low. In fact, it is not uncommon at land-based industrial facilities 

to use wet scrubbers to control SO2 emissions from large boilers that combust low-sulfur fuels. 

However, that approach would not be technically feasible in the case of the Discoverer for a 

number of reasons, including the lack of space for the scrubber, the lack of fresh water, and the 

lack of space for the solid waste material that forms from scrubbing SO2. In addition, there 

would be substantial concerns about keeping the scrubber water in a liquid state in the Arctic 

environment and generators would have to be operated more in order to produce electricity for 

the scrubber operation. Shell is confident that wet scrubbers would not be technically feasible in 

this application. 

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for the Discoverer’s diesel engines and diesel-fired 

boilers are ranked by control effectiveness as follows. 

1. Ultra-low sulfur fuel: ≤0.0015 weight percent sulfur (15 ppm). 

2. Low sulfur diesel: ≤0.05 weight percent sulfur. 

3. Higher sulfur diesel fuels: >0.05 weight percent sulfur. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT so additional analyses are not 

warranted. 

Step 5 – Selection of BACT

Shell proposes the exclusive use of ultra-low sulfur diesel, which is the lowest sulfur diesel fuel 

available, as BACT for Discoverer’s diesel engines and diesel-fired boilers. 

4.1.2.2 SO2 BACT for the Incinerator 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.3, the available control technologies for the Discoverer’s incinerator are 

LSF and SDS. SDS is considered technically infeasible for this incinerator. The Discoverer’s

incinerator is very small in comparison to the incinerator listed in the RBLC with SDS (350 tons 

per day; 29,000 lb/hr). Based on communication with TeamTec, the manufacturer, they are not 

aware of any control technologies that have been installed on this model of incinerator for control 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 43 

of any of the pollutants.40 Shell is not aware of any control technology installations on this or 

similar-sized incinerators. 

LSF is considered technically feasible. 

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for the Discoverer’s incinerator are ranked by control 

effectiveness as follows. 

1. Ultra-low sulfur fuel – ≤0.0015 weight percent sulfur. 

2. Non-low sulfur fuel. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT and additional analyses are not 

warranted. 

Step 5 – Selection of BACT

To minimize SO2 production from the diesel used to heat the furnace, Shell proposes the 

exclusive use of ultra-low sulfur diesel, which is the lowest sulfur diesel fuel available, as BACT 

for Discoverer’s incinerator. 

4.1.3 Particulate Matter BACT Analysis 

This section addresses BACT for particulate matter, which we refer to generically as PM. We 

acknowledge that virtually all the PM is PM10 and PM2.5. 

Step 1 – Available Control Technologies 

Diesel PM is a complex mixture of compounds which are formed through a number of different 

mechanisms. PM is comprised of the soluble organic fraction (SOF), the insoluble (solid) fraction, 

and the sulfate fraction. Fuel and lube oil contribute to the SOF fraction. The insoluble fraction is 

primarily dry carbonaceous soot from “too-rich-to-burn” fuel combustion. The sulfate fraction is 

produced from the sulfur in diesel fuel. This fraction can only be controlled by limiting fuel 

sulfur content. 

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. The complete 

downloads are provided in Appendix C. For the RBLC, only those determinations made after 

January 1, 1999, were downloaded. 

 

40 Ibid. footnote 39. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 44 

Table 4-5: Available PM Control Technologies 

Source Category Clearinghouse Search Conditions Control Technologies 

Diesel IC Engines (>500 hp) RBLC Process Code = 17.110 None, LSF, PCV, Tier 

2/3 

 CA-BACT I.C. Engines - CI, NonEmergency (>500 hp) None, OxyCat, LSF, 

PCV, DPF 

Diesel IC Engines (≤500 hp) RBLC Process Code = 17.210 None, LSF, PCV 

 CA-BACT I.C. Engines - CI, NonEmergency (≤500 hp) None, LSF, PCV 

Boiler (≤100 MMBtu/hr) RBLC Process Code = 13.220 None 

 CA-BACT Boilers – Oil Fired 

(≤100 MMBtu) 

No determinations 

Incinerator RBLC Process Description = 

Incinerator; Fuel = 

Solid Waste 

None, ESP 

 CA-BACT No determinations 

CI Compression Ignition. 

Process Code Key: 

17.110 - Large Internal Combustion Engines (>500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

17.210 - Small Internal Combustion Engines (≤500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

13.220 - Commercial/Institutional-Size Boilers/Furnaces (≤100 million BTU/H); Distillate Fuel Oil (ASTM #1, 2, includes 

kerosene, aviation, diesel fuel). 

Control Technology Key: 

DPF Diesel Particulate Filter 

LSF Low Sulfur Fuel 

OxyCat Oxidation Catalyst 

PCV Positive Crankcase Ventilation 

TIER 2/3 EPA Non-Road Engine Emission Standards per 40 CFR 89.112 

None No specific technology listed or good combustion practices 

Diesel Engines 

The available PM combustion control technologies for diesel engines identified in the RBLC and 

CA-BACT, and show in Table 4-5, are LSF, oxidation catalyst (OxyCat), diesel particulate filter 

(DPF), Tier 2 or 3 level controls, and positive crankcase ventilation (PCV). Although not listed in 

the RBLC or CA-BACT, the combination of OxyCat and DPF referred to as catalytic diesel 

particulate filter (CDPF) in also an available control technology for PM reduction. 

LSF reduces the sulfate PM fraction by limiting the amount of sulfur in the fuel that is available 

for sulfate formation. An OxyCat removes the SOF of PM through catalytic oxidation of the 

combustible organic matter resulting in an overall PM control efficiency of 50 percent.41 A DPF 

removes the insoluble (solid) fraction of PM (soot) by filtration with an overall PM control 

 

41 Holmström, Per. D.E.C. Marine AB. [Communication with R. Steen, Air Sciences Inc.]. February 9, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 45 

efficiency of 40 to 50 percent.42,43 CDPFs remove both the SOF and the insoluble fraction of PM 

with an overall PM control efficiency of 85 percent.44

The crankcase of a combustion engine accumulates gases and oil mist called blowby that leak into 

the crankcase from the combustion chamber and other sources. The blowby gases must be 

vented from the crankcase to prevent damage. Due to the fact that blowby gas contains PM, 

which is 100 percent SOF,45 it should be handled such that it does not contribute to PM 

emissions. The PCV system was developed to remove blowby from the engine and to prevent 

those vapors from being expelled into the atmosphere. The PCV system does this by directing 

the blowby back to the intake manifold so it can be combusted. 

Regardless of the technology applied to achieve BACT, the control option must result in an 

emission rate no less stringent than the applicable NSPS emission rate, if any NSPS standard for 

that pollutant is applicable to the source. As discussed above in the NOx BACT analysis, EPA has 

promulgated exhaust emission standards for non-road engines under 40 CFR 89.112 in 1998. 

Engines designed to meet Tier 2 or 3 PM emission standards typically employ a combination of 

low PM emitting engine designs and DPF or CDPF.46 The overall PM control for Tier 3 engines is 

85 percent.47 The NSPS PM emission standards for larger generators are provided in Table 4-6. 

Table 4-6: EPA Tier 1-3 Non-road Diesel Engine PM Emission Standards 

Engine Power Tier Year 

PM 

g/kWh (g/bhp-hr)

225 ≤ kW < 450 Tier 1 1996 0.54 (0.4) 

(300 ≤ hp < 600) Tier 2 2001 0.2 (0.15) 

 Tier 3 2006 0.2 (0.15) 

450 ≤ kW < 560 Tier 1 1996 0.54 (0.4) 

(600 ≤ hp < 750) Tier 2 2002 0.2 (0.15) 

 Tier 3 2006 0.2 (0.15) 

kW ≥ 560 Tier 1 2000 0.54 (0.4) 

(hp ≥ 750) Tier 2 2006 0.2 (0.15) 

Diesel-Fired Boilers 

 

42 Khair, Magdi K. DieselNet Technology Guide. Engine Design for PM Control. May 2002. 

43 Majewski, Addy W. DieselNet Technology Guide. Diesel Particulate Filters. July 2001. 

44 California EPA. Air Resource Board. Verification Procedure - Currently Verified, CleanAIR Systems PERMIT. January 26, 

2009. http://www.arb.ca.gov/diesel/verdev/vt/cvt.htm 

45 Jaaskelainen, Hannu. DieselNet Technology Guide. Crankcase Ventilation. January 2009. 

46 Ibid. footnote 36. 

47 The Tier 3 PM emission standard for large non-road engines is 0.2 g/kWh or 0.15 g/hp-hr. The base case is considered to be 

approximately 1 g/hp-hr. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 46 

As shown in Table 4-5, there are no PM control technologies listed in the RBLC and CA-BACT for 

diesel-fired boilers less than or equal to 100 MMBtu/hr. Therefore, good combustion practices 

and the combustion of clean diesel fuel is the only available control technology for consideration 

in this analysis. 

Incinerators 

The available PM control technologies for incinerators identified in the RBLC and CA-BACT, and 

show in Table 4-5, are electrostatic precipitators (ESP) and good combustion practices. An ESP 

uses electrostatic charges to move particulates from a gas stream onto a collection surface. The 

electric field is created through electrodes that are maintained at a high voltage. 

4.1.3.1 PM BACT for the Diesel Engines 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.4, the available control technologies for the Discoverer’s diesel engines 

are LSF, OxyCat, DPF, CDPF, Tier 2 or 3 level controls, and PCV. Tier 2 or 3 level controls and 

PCV are intrinsic to the original engine design. Therefore, these control technologies are only 

considered technically feasibility if they are already a part of the design of the Discoverer’s diesel 

engines; (e.g., Discoverer’s three diesel MLC compressors, FD-9 through FD-11 – 540 hp 

Caterpillar C-15 engines, are configured to meet the Tier 3 emission standards). LSF, OxyCat, 

DPF, and CDPF are all considered technically feasible for all of the Discoverer’s diesel engines 

except the Cat D399s (FD-1 through 6) that also have SCR control. D. E. C. Marine only offers to 

do a feasibility analysis if CDPFs are to be considered and note that, if a feasible design can be 

developed, that maintenance of the CDPFs will be required monthly.48

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for the Discoverer’s diesel engines are ranked by 

control effectiveness as follows: 

1. CDPF – 85 percent control (technically feasible for all engines except Caterpillar D399 

with SCR); Tier 3 – 85 percent control (technically feasible for the Caterpillar C-15 

engines only), 

2. OxyCat – 50 percent control, 

3. DPF – 40 to 50 percent control, 

4. Good Combustion Practices. 

LSF is included in all the above technologies. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

 

48 Ibid footnote 41. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 47 

For the Discoverer’s six diesel generators (FD-1 through FD-6 – 1,325 hp Caterpillar D399 Marine 

Generator Set), the top control option (CDPF) is commercially infeasible. Furthermore, as 

demonstrated in Appendix C, the cost CDPF for these diesel generators is approximately $20,000 

to $30,000 per ton of PM removed. This is not cost effective. 

For the Discoverer’s three diesel MLC compressors (FD-9 through FD-11 – 540 hp Caterpillar C15), the top control option from Step 3 (Tier 3 emission controls) is proposed as BACT; additional 

analysis of other impacts is not required. 

For the Discoverer’s small diesel engines (FD-12 and FD-13, HPU Engines – 250 hp Detroit 8V-71; 

FD-14 and FD-15, Cranes – 365 hp Caterpillar D343; FD-16 and FD-17, Cementing Units – 335 hp 

Detroit 8V-71N; FD-18, Cementing Unit – 147 hp GM 3-71; FD-19, Logging Winch – 128 hp 

Detroit 4-71N; and FD-20, Logging Winch – 36 kW 4024TF270), the top control option from Step 3 

(CDPF) is proposed as BACT, thus this step is not required. 

Step 5 – Selection of BACT

Shell proposes the following control options as BACT: 

• Diesel generators (FD-1 through FD-6) – OxyCat, 

• Diesel MLC compressors (FD-9 through FD-11) – Tier 3, 

• Small diesel engines (FD-12 through FD-20) – CDPF. 

4.1.3.2 PM BACT for the Diesel-Fired Boilers 

Step 2 –Technical Feasibility 

There are two boilers (FD-21 and FD-22 – 8 MMBtu/hr Clayton 200) providing general heat to the 

Discoverer. Only one boiler will be operating and the second will serve as a backup. As discussed 

in Section 4.1.4, the only available PM control technology for these boilers is good combustion 

practices. 

Step 3 – Control Effectiveness Ranking 

The only technically feasible control technologies for the two boilers (FD-21 and FD-22) is good 

combustion practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT, thus this step is not required. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 48 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s boilers. Good combustion 

practices require operating and maintaining the equipment according to the manufacturer’s 

recommendations to maximize fuel efficiency and minimize emissions. 

4.1.3.3 PM BACT for the Incinerator 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.4, the available control technologies for the Discoverer’s incinerator 

(FD-22 – 276 lb/hr TeamTec/GS500C) are ESP and good combustion practices. ESP is considered 

technically infeasible for this incinerator. The Discoverer’s incinerator is very small in comparison 

to the incinerator listed in the RBLC with SNCR (350 tons per day; 29,000 lb/hr). In 

communication with TeamTec, the manufacturer, they are not aware of any control technologies 

that have been installed on this model of incinerator for control of any of the pollutants.49 Shell is 

not aware of any control technology installations on this or similar-sized incinerators. 

Step 3 – Control Effectiveness Ranking 

The only technically feasible control technologies for the incinerator FD-23 is good combustion 

practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT, thus this step is not required. 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s incinerator. Good combustion 

practices require operating and maintaining the equipment according to the manufacturer’s 

recommendations to maximize fuel efficiency and minimize emissions. 

4.1.4 CO BACT Analysis 

Step 1 – Available Control Technologies 

The available CO 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. The complete 

downloads are provided in Appendix C. For the RBLC, only those determinations made after 

January 1, 1999, were downloaded. 

 

49 Ibid. footnote 40. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 49 

Table 4-7: Available CO Control Technologies 

Source Category Clearinghouse Search Conditions Control Technologies 

Diesel IC Engines (>500 hp) RBLC Process Code = 17.110 None, OxyCat, Tier 

2/3 

 CA-BACT I.C. Engines - CI, NonEmergency (>500 hp) None, OxyCat 

Diesel IC Engines (≤500 hp) RBLC Process Code = 17.210 None 

 CA-BACT I.C. Engines - CI, NonEmergency (≤500 hp) None, OxyCat 

Boiler (≤100 MMBtu/hr) RBLC Process Code = 13.220 None 

 CA-BACT Boilers – Oil Fired 

(≤100 MMBtu) 

No determinations 

Incinerator RBLC Process Description = 

Incinerator; Fuel = 

Solid Waste 

None 

 CA-BACT No determinations 

CI Compression Ignition. 

Process Code Key: 

17.110 - Large Internal Combustion Engines (>500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

17.210 - Small Internal Combustion Engines (≤500 HP); Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). 

13.220 - Commercial/Institutional-Size Boilers/Furnaces (≤100 million BTU/H); Distillate Fuel Oil (ASTM #1, 2, includes 

kerosene, aviation, diesel fuel). 

Control Technology Key: 

OxyCat Oxidation Catalyst 

TIER 2/3 EPA Non-Road Engine Emission Standards per 40 CFR 89.112 

None No specific technology listed or good combustion practices 

Diesel Engines 

The available CO combustion control technologies for diesel engines identified in the RBLC and 

CA-BACT are OxyCat and Tier 2 or 3 level controls. OxyCat reduces CO emission through 

catalytic oxidation of these combustible gases, resulting in an overall CO control efficiency of 80 

percent.50 Engines designed to meet Tier 2 or 3 emission standards typically employ a 

combination of advanced combustion technology and catalytic oxidation. The CO control for 

Tier 3 engines is assumed to be similar to a CDPF (80 percent51). Although not listed in the RBLC 

or CA-BACT, CDPF reduces CO emission through catalytic oxidation with an overall control 

efficiency of 80 percent.52

Regardless of the technology applied to achieve BACT, the control option must result in an 

emission rate no less stringent than the applicable NSPS emission rate, if any NSPS standard for 

that pollutant is applicable to the source. As discussed above in the NOx and PM BACT analyses, 

 

50 Ibid. footnote 1. 

51 CleanAIR Systems, Inc. PERMITTM Filter CleanAIR Catalyzed Diesel Particulate Filters Installation and Maintenance Manual. 

2006. 

52 Ibid. footnote 51. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 50 

EPA promulgated exhaust emission standards for non-road engines under 40 CFR 89.112 in 1998. 

The CO emission standards for larger generators are provided in Table 4-8. 

Table 4-8: EPA Tier 1-3 Nonroad Diesel Engine CO Emission Standards 

Engine Power Tier Year 

CO 

g/kWh (g/bhp-hr)

225 ≤ kW < 450 Tier 1 1996 11.4 (8.5) 

(300 ≤ hp < 600) Tier 2 2001 3.5 (2.6) 

 Tier 3 2006 3.5 (2.6) 

450 ≤ kW < 560 Tier 1 1996 11.4 (8.5) 

(600 ≤ hp < 750) Tier 2 2002 3.5 (2.6) 

 Tier 3 2006 3.5 (2.6) 

kW ≥ 560 Tier 1 2000 11.4 (8.5) 

(hp ≥ 750) Tier 2 2006 3.5 (2.6) 

Diesel-Fired Boilers 

There are no CO control technologies listed in the RBLC and CA-BACT for diesel-fired boilers 

less than or equal to 100 MMBtu/hr. Therefore, good combustion practices and the combustion 

of clean diesel fuel is the only available control technology for consideration in this analysis. 

Incinerators 

There are no CO or VOC control technologies listed in the RBLC and CA-BACT for waste 

incinerators. Therefore, good combustion practices and the combustion of clean diesel fuel is the 

only available control technology for consideration in this analysis. 

4.1.4.1 CO BACT for the Diesel Engines 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.5, the available control technologies for the Discoverer’s diesel engines 

are OxyCat, CDPF, and Tier 2 or 3 level controls. Tier 2 or 3 level controls are intrinsic to the 

original engine design. Therefore, these control technologies are only considered technically 

feasibility if they are already a part of the design of the Discoverer’s diesel engines; (e.g., 

Discoverer’s three diesel MLC compressors, FD-9 through FD-11 – 540 hp Caterpillar C-15 

engines, are configured to meet the Tier 3 emission standards.) OxyCat and CDPF are both 

considered technically feasible for each of the Discoverer’s diesel engines. 

Step 3 – Control Effectiveness Ranking 

The technically feasible control technologies for the Discoverer’s diesel engines are ranked by 

control effectiveness as follows: 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 51 

1. CDPF – 80 percent control (technically feasible for all engines); Tier 3 – 80 percent 

control (technically feasible for the Caterpillar C-15 engines only), 

2. OxyCat – 80/70 percent control for CO/VOC, respectively, 

3. Good Combustion Practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

For the Discoverer’s six diesel generators (FD-1 through FD-6 – 1,325 hp Caterpillar D399 Marine 

Generator Set), the top control option (CDPF) is technically infeasible. Even if it were feasible, it 

provides the same level of CO control as the next control option (OxyCat). Considering the total 

capital cost of CDPF of $640,000 for six units, as shown in Appendix C, the economic impact of 

CDPF does not justify the marginal environmental benefit. CDPF is considered not to be costeffective. 

For the Discoverer’s three diesel MLC compressors (FD-9 through FD-11 – 540 hp Caterpillar C15), the top control option from Step 3 (Tier 3 emission controls) is proposed as BACT. Further 

analysis is not required. 

For the Discoverer’s small diesel engines (FD-12 and FD-13, HPU Engines – 250 hp Detroit 8V-71; 

FD-14 and FD-15, Cranes – 365 hp Caterpillar D343; FD-16 and FD-17, Cementing Units – 335 hp 

Detroit 8V-71N; FD-18, Cementing Unit – 147 hp GM 3-71; FD-19, Logging Winch – 128 hp 

Detroit 4-71N; and FD-20, Logging Winch – 36 kW 4024TF270), the top control option from Step 3 

(CDPF) is proposed as BACT. Further analysis is not required. 

Step 5 – Selection of BACT

Shell proposes the following control options as BACT: 

• Diesel generators (FD-1 through FD-6) – OxyCat 

• Diesel MLC compressors (FD-9 through FD-11) – Tier 3 

• Small diesel engines (FD-12 through FD-20) – CDPF 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 52 

4.1.4.2 CO BACT for the Diesel-Fired Boilers 

Step 2 –Technical Feasibility 

There are two boilers (FD-21 and FD-22 – 8 MMBtu/hr Clayton 200) providing general heat to the 

Discoverer. Only one boiler will be operating and the second will serve as a backup. As discussed 

in Section 4.1.5, the only available CO control technology for these boilers is good combustion 

practices. 

Step 3 – Control Effectiveness Ranking 

The only technically feasible control technologies for the two boilers (FD-21 and FD-22) is good 

combustion practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT. Further analysis is not required. 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s boilers. Good combustion 

practices require operating and maintaining the equipment according to the manufacturer’s 

recommendations to maximize fuel efficiency and minimize emissions. 

4.1.4.3 CO BACT for the Incinerator 

Step 2 –Technical Feasibility 

As discussed in Section 4.1.5, the only available control technology for the Discoverer’s incinerator 

is good combustion practices. 

Step 3 – Control Effectiveness Ranking 

The only technically feasible control technologies for the incinerator FD-23 is good combustion 

practices. 

Step 4 – Evaluate the most effective control based on energy, environmental, and economic 

impacts 

The top control option from Step 3 is proposed as BACT. Further analysis is not required. 

Step 5 – Selection of BACT

Shell proposes good combustion practice as BACT for Discoverer’s incinerator. Good combustion 

practices require operating and maintaining the equipment according to the manufacturer’s 

recommendations to maximize fuel efficiency and minimize emissions. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 53 

4.1.5 CO2 BACT Analysis 

Shell recognizes that the EPA is considering whether and how to regulate CO2 under the Clean 

Air Act and that the agency may establish by rule or policy a requirement that major sources 

perform a BACT analysis for CO2 emissions. At this time, Shell believes it is premature to 

address projected CO2 emissions in this permit application for purposes of possible control. 

4.2 NSPS 

Candidate source types for NSPS applicability (40 CFR 60) are the fuel tanks (Subparts Ka and 

Kb), the incinerator (Subpart CCCC), the boilers (Subpart Dc), and the internal combustion 

engines (Subpart IIII). 

NSPS Subpart Ka applies to petroleum liquids tanks with a capacity of greater than 420,000 

gallons, which is well above tank 21P (142,140 gallons), the largest Discoverer tank. NSPS Subpart 

Kb applies to petroleum liquids tanks manufactured after July 1984. All Discoverer tanks were 

manufactured before 1984, and therefore none are affected sources. 

The incinerator has been manufactured in 2006 or later, so NSPS Subpart CCCC is applicable. 

Since the incinerator will be classified as a CISWI incinerator and qualifies as a small (less than 35 

tons per day) Municipal Solid Waste (MSW) incinerator, it will be exempt from most of the CCCC 

requirements. An exemption request is attached as Appendix G. Its applicable NSPS 

requirements will consist of the attached initial notification to the EPA administrator and 

quarterly record-keeping of the waste material burned. 

NSPS Subpart Dc is applicable to boilers equal to or greater than 10 MMBtu/hr design capacity. 

Since the two Discoverer boilers are under 10 MMBtu/hr, they are exempt. 

All diesel engines, except the cementing engines, were manufactured prior to July 11, 2005, and 

therefore are exempt from NSPS IIII. The cementing engines, FD-16, 17, and 18, are new Tier 3 

engines to which NSPS IIII applies. At a size of less than 10 liters per cylinder, the operator is to 

operate the engine to meet the manufacturer’s Tier 3 emission limits, which translates to applying 

good maintenance practices (GMP). Shell will practice GMP. 

4.3 NESHAPs 

The Discoverer’s total hazardous air pollutants (HAPs) emissions, including the fleets (Appendix 

A, Page 9), are estimated at 2.2 tons per year, which are under the 10 tons per year single HAP, 

and 25 tons per year combined HAPs emission major source threshold, and therefore, the 

Discoverer is categorized as an area source of HAPs per § 63.2 (40 CFR 63, Subpart A - National 

Emission Standards for Hazardous Air Pollutants – General Provisions – Definitions). 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 54 

4.3.1 Compression Ignition (CI) Reciprocating Internal Combustion Engines (RICE) 

Emission units FD-1 through FD-20 are CI RICE located at an area source of HAPs and thus 

subject to 40 CFR 63, Subpart ZZZZ (National Emission Standards for Hazardous Air Pollutants 

for Stationary Reciprocating Internal Combustion Engines) per § 63.6585. All of these CI RICE, 

except for FD-16 through FD-18, are constructed before June 12, 2006, and therefore categorized 

as an existing RICE at area source of HAPs per § 63.6590 (a) (1) (iii). FD-16 through FD-18 

commenced (or will commence) construction after June 12, 2006 and therefore qualify as a new 

RICE at area source of HAPs per § 63.6590 (a) (2) (iii). The existing sources (FD-1 through FD-15, 

and FD-19 through FD-20) do not have to meet the requirements of 40 CFR 63, Subparts ZZZZ 

and A, and do not require initial notification per § 63.6590 (b) (3). The new sources (FD-16 

through FD-18) are not subject to compliance requirements for this Subpart per § 63.6590 (c). 

4.3.2 Commercial and Industrial Solid Waste Incinerator (CISWI) 

HAPs emission standards for non-hazardous waste combustors are addressed in applicable NSPS 

under Section 129 (h) (2) of the 1990 Clean Air Act Amendments. Emission unit FD-23 is a CISWI 

subject to NSPS under 40 CFR 60, Subpart CCCC, but exempt from requirements of this Subpart, 

except for notification and recordkeeping, per § 60.2020 (c) (2). Therefore, the HAPs emission 

standards listed in this Subpart are not applicable to FD-23. 

4.3.3 Boilers 

Emission units FD-21 and FD-22 are utility boilers on the Discoverer. These boilers are not subject 

to the 40 CFR 63, Subpart DDDDD - National Emission Standards for Hazardous Air Pollutants 

for Industrial, Commercial, and Institutional Boilers and Process Heaters; because this Subpart is 

applicable to boilers located at a major source of HAPs per § 63.7485. Therefore, emission units 

FD-21 and FD-22 are not subject to NESHAPs. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 55 

SECTION 5

AMBIENT IMPACTS 

Under the New Source Review regulations, 40 CFR Part 52.21, Section k and o, Shell is to 

demonstrate that source impacts will be in compliance with ambient standards and impairment 

limits using EPA-acceptable estimation procedures. These procedures involve dispersion 

modeling as described in Appendix W of Part 51. This application section addresses the methods 

for modeling the impacts from the Discoverer and its associated fleets for demonstration of 

compliance with the NAAQS (Subpart d) and PSD (Subpart c) increments, listed in Table 5-1. 

The modeling is performed according to Appendix W of Part 51 (Guideline on Air Quality 

Models). At EPA Region 10’s direction, Shell is applying a conservative screening dispersion 

modeling for this impact analysis, at least until actual meteorological data can be obtained. The 

EPA-approved ISC-PRIME model is used herein with EPA screening meteorology and EPArecommended worst persistence factors for converting one-hour maximum concentrations to 

other averaging periods. 

Compliance is demonstrated at and beyond a 900-meter radius which is within the 1,000-meter 

safety exclusion zone and the nearest location of public access. Owner-requested restrictions 

limiting operation of the sources are taken into account in the analysis. This impact analysis 

demonstrates how the Discoverer and associated fleets are modeled in accordance with these 

regulations as provided in Shell’s Frontier Discoverer Alaska Outer Continental Shelf (OCS) 

Exploratory Drilling Program Air Quality Impact Modeling Protocol (dated November 12, 2008) 

provided to EPA Region 10. 

Table 5-1: Summary of Applicable Standards 

Pollutant 

Averaging 

Time 

NAAQS 1

(μg/m3) 

PSD Class II 

Increment 

(μg/m3) 

Nitrogen Dioxide (NO2) Annual 100 25 

Particulate Matter (PM2.5) 24-hour 35 NA 

Annual 15 NA 

Particulate Matter (PM10) 24-hour 150 30 

Annual 50 17 

3-hour 1,300 512 

24-hour 365 91 

Sulfur Dioxide (SO2) 

Annual 80 20 

Carbon Monoxide (CO) 1-hour 40,000 NA 

8-hour 10,000 NA 

1 National Ambient Air Quality Standards 

NA not applicable 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 56 

5.1 Model Selection 

At this time, representative meteorological data meeting the EPA Region 10’s dispersion 

modeling requirements is not available for the Chukchi Sea OCS locations. Thus, the ability to 

use refined modeling was eliminated, at least for now, and only screening modeling is available 

to Shell. The most recent version (04269) of the ISC-PRIME dispersion model was used. The ISCPRIME model is a U.S. EPA-approved, steady-state, multiple-source, Gaussian plume model. It 

offers a screening mode; it can characterize sources which are substantially affected by building 

wake effects, such as the source units on the Discoverer; it resolves impacts in a three-dimensional 

receptor grid; and it allows for consideration of the actual spatial distribution of sources, all of 

which is important in this analysis. The sources in this analysis are distributed over a wide area 

and the model is capable of characterizing this spatial distribution. 

5.2 Worst-Case Meteorological Data 

The dispersion model is used with screening meteorology (meteorological assumptions that 

result in impacts equal to or higher than those to be expected). An ISC-PRIME compatible 

meteorological data set was generated using the SCREEN3 model’s array of possible wind speed 

and stability combinations. The screening meteorological data contain all possible wind speeds 

for all of the dispersion categories listed in the U.S. EPA’s SCREEN3 Model User's Guide (EPA454/B-95-004) and as shown in Table 5-2. This meteorological data is considered to contain the 

theoretical worst-case dispersion conditions regardless of whether these conditions will actually 

occur at the project locations. The Discoverer will have its bow pointing into the wind when it is 

drilling as described in Section 5.7. Thus, the combinations of speed and stability are applied 

from a single wind direction (winds blowing from the east to the west). 

Table 5-2: Wind Speed and Stability Class Combinations Used for Screening Modeling 

Wind Speed (m/sec) 

Stability 1 1.5 2 2.5 3 3.5 4 4.5 5 8 10 15 20 

A * * * * * 

B * * * * * * * * * 

C * * * * * * * * * * * 

D * * * * * * * * * * * * * 

E * * * * * * * * * 

F * * * * * * * 

The guidance provided in the SCREEN3 Model User’s Guide for mixing heights is utilized as 

follows. The mixing heights used for neutral and unstable conditions (Classes A-D) are based on 

an estimate of the mechanically-driven mixing height. The mechanical mixing height for these 

conditions equals 320 times the wind speed. For stable conditions (Classes E-F), the mixing 

height is set equal to 10,000 meters to represent unlimited mixing. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 57 

Section 3.4 of EPA’s Screening Procedures for Estimating the Air Quality Impact of Stationary 

Sources, Revised (EPA-454/R-92-019, October 1992) document allows the use of measured 

ambient temperatures in lieu of a default temperature value of 293 K. Per EPA Region 10’s 

recommendation, the ambient temperature for the screening meteorological data is based on the 

long-term average temperature at Barrow, Alaska. Based on data from the Western Regional 

Climate Center,53 from 1949 to 2007, the average daily high and low temperatures at Barrow were 

15.7°F and 4.9°F, respectively. Thus, the average of these two values, 10.3°F (261.1°K), was 

utilized in the screening meteorological data set. 

5.3 Persistence Factors 

The model in screening mode produces 1-hour maximum impacts. These screening 1-hour 

concentrations generated by the model are converted to longer-term concentrations by using 

multipliers (i.e., worst-case persistence factors) required by EPA Region 10. To obtain the 

estimated maximum concentration for 3-hour, 8-hour, 24-hour, and annual averaging times, the 

1-hour average model output is multiplied by the worst-case persistence factor values provided 

in Table 5-3. 

Table 5-3: Worst-Case Persistence Factors 

Averaging 

Period 

Persistence 

Factor 1

3-hour 1.0 

8-hour 0.9 

24-hour 0.6 

Annual 0.1 

1 Worst-case factors from EPA’s 

Screening Procedures for Estimating the 

Air Quality Impact of Stationary 

Sources, Revised (EPA-454/R-92-019, 

October 1992) document. 

5.4 Physical Characterization of the Emission Units 

5.4.1 Discoverer 

A listing of the physical source release characteristics of the source units and a plan view of the 

Discoverer source unit configuration are provided on Pages 3 and 8 of Appendix B. Stack 

parameters listed for Discoverer sources are representative of 100% load. 

Per EPA’s Screening Procedures for Estimating the Air Quality Impact of Stationary Sources, 

Revised (EPA-454/R-92-019, October 1992) document: Sources that emit the same pollutant from 

 

53 Western Region Climate Center. Climatological data for Barrow, Alaska. http://www.wrcc.dri.edu/cgi-bin/cliMAIN.pl?ak0546 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 58 

several stacks with similar parameters that are within about 100 meters of each other may be 

analyzed by treating all of the emissions as coming from a single representative stack. Several 

sources on the Discoverer are located next to each other and merging the stacks for modeling 

purposes is appropriate because of similarities in source size and location. For these, singlesource stack parameters with combined emissions are used. Given the configuration of the stacks 

and structures on the Discoverer, plumes may be down-washed and pulled into the buildings’ 

wake region. For this analysis, the building downwash parameters used in ISC-PRIME are 

calculated using the Building Profile Input Program (BPIP) version (Version 04274). The building 

height and location information used in the BPIP analysis are provided on Page 9 of Appendix B. 

5.4.2 Supporting Fleets 

With respect to the modeling of impacts from the fleets associated with the Discoverer, the ice 

management and anchor handling fleet is considered to be a generic fleet and the resupply ship a 

generic supply ship. There is to be a specifically defined OSR fleet. Emissions from all three are 

estimated and impacts included in the analyses. 

Primary and secondary ice management ship emissions are modeled as line sources at the closest 

distance to the Discoverer at which the ships will normally operate. As described in Section 2.11, 

when there is ice to be broken the primary ice management ship is normally positioned from 3 

miles to 12 miles upwind on the drift line. The width of the swath will be about 3 miles to either 

side of the drift line and defined by a roughly elliptical movement pattern. The secondary ice 

management ship will be located from the anchor buoy pattern to 6 miles up-drift from the

Discoverer, moving laterally 1.5 miles to either side of the drift line and also in an elliptical 

pattern. 

For modeling purposes, the icebreaker emissions are placed on a line nearest the Discoverer at 3 

miles (4.8 kilometers) upwind and spanning 3 miles (4.8 kilometers) on each side of the drift line. 

The nearest edge of activity for the anchor handler/ice management ship is 1 kilometer upwind 

of the Discoverer and spanning a line 1.5 miles (2.4 kilometers) on either side of the drift line. 

This OSR fleet is expected to consist of one managing oil response ship, the Nanuq, and three 

small (34-foot) craft that dock on the Nanuq. Typically, the OSR fleet will be operating several 

miles from the Discoverer. The only planned activity for the OSR fleet is training, an 8-hour per 

day exercise, modeled at the closest normal distance of two kilometers downwind. The training 

is expected to be contained within a 2-mile area, modeled as a two kilometers line source. 

The ice management and OSR fleets are modeled as a series of elevated line sources as described 

in more detail in the next section. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 59 

5.4.3 Volume Source Characterization of Supporting Fleets 

In a January 26, 2009, memo from Shell representatives to EPA Region 10,54 a detailed description 

of the volume source characterization of the support fleets was provided and based on 

subsequent discussions with EPA, the following characterization of the support fleets is utilized 

in the modeling analysis. 

The ice management and OSR fleets are characterized in the air quality impact analysis using an 

elevated line source (series of adjacent volume sources) at the nearest edge of anticipated activity 

to the Discoverer. This configuration is worst-case since, in reality, the ice management fleet will 

be breaking up ice at and beyond (e.g., further away from the Discoverer) the nearest edge of 

anticipate ice management activity. The line source characterization is designed to simulate the 

effect of mobile sources moving around and emitting plumes which rise and form a layer of 

emissions above ground (e.g., smearing in space of a plume from a moving ship) which is then 

advected downwind towards the Discoverer. This design simulates the effect of ice management 

fleet under its highest emitting scenario, which is a continual churning up of one-year ice drifting 

toward the Discoverer. 

Determination of Effective Emission Heights for Volume Sources 

According to Section 1.2 in the User’s Guide for the Industrial Source Complex (ISC3) Dispersion 

Models, Volume II - Description of Model Algorithms (EPA-454/95-003b, September 1995), the 

effective emissions height for elevated volume sources needs to be assigned. The plume heights 

for the fleet emissions are estimated using SCREEN3 (an alternate screening model that provides 

a printout of plume rise) which accounts for the mechanical and buoyant lift from the ship’s 

stacks. Per EPA’s request, as provided in Section 2.11, Shell has compiled a list of potential ships 

which could be used for ice management and anchor handling activities. The stack 

characteristics of the main propulsion engines for each ship are used with the SCREEN3 

algorithms to define the plume height for the ice management fleet emissions (in ISC-PRIME) as 

shown on Appendix B, Page 3. Building downwash information related to these sources in 

provided on Appendix B, Page 9. 

Note that some of the ice management ships have horizontal stacks which are modeled in 

accordance with Alaska DEC’s recommendations. Alaska DEC’s recommended adjustments 

provide for the retention of buoyancy while addressing the impediment to the vertical 

momentum of the release. 

 

54 Martin, Tim, Air Sciences Inc. [Technical memo Herman Wong, EPA Region 10]. Description of Volume Source 

Characterization of Icebreaker Fleets, Shell Discoverer Chukchi Sea Permit Application. January 26, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 60 

The following procedure was utilized to model horizontally emitting stacks: 

• Set the actual stack velocity (Vactual), in meters per second, to an adjusted stack exit 

velocity (Vadjusted) of 0.001 meter per second. 

• To conserve volumetric flow, determine an adjusted stack diameter (Dadjusted) by 

adjusting the actual stack inside diameter (Dactual), in meters, to account for 

buoyancy of the plume by using the following equation: 

• Dadjusted = 31.6(Dactual)(Vactual)0.5

Use the adjusted parameters, Vadjusted and Dadjusted, in the modeling analysis. 

These source characteristics and building dimension information were used as inputs to 

SCREEN3 to obtain an estimate of final plume rise. For every meteorological condition listed in 

Table 5-2 (including the combination of 20 meters per second, and D stability), SCREEN3 

calculates plume rise values and provides a listing of meteorological conditions associated with 

the maximum-predicted ground-level concentrations at downwind distances from a source. 

Appendix E provides the SCREEN3 output for each of the ice management ships. 

The ice management fleet will be managing ice upwind of the Discoverer given the mobile nature 

of the fleets, the plumes from the fleets will rise and spread out at some height. The final plume 

rise for each ship was chosen to represent the height of the volume sources for ISC-PRIME. The 

final plume height for the generic ice management and anchor handler fleet was conservatively 

chosen as the lowest plume rise value for any ship at 1,000 meters upwind of the Discoverer, 

which the closest location of any ship to the Discoverer (see Table 5-4). 

In reality, the support ships will typically be located much further away than 1,000 meters from 

the Discoverer and much higher plume rise values would be appropriate. Based on the data 

highlighted in Table 5-4, the lowest final plume rise for the primary and secondary ice 

management ships is 35.66 meters (based on worst-case plume rise from the Vladimir Ignatjuk) 

and is used to define the volume source release heights for the ice management fleet in ISCPRIME. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 61 

Table 5-4: Summary of SCREEN3 Output for Plume Rise 

 Minimum Plume Rise from SCREEN3 

Downwind OSR Kapitan Fennica/ Vladimir Tor Odin Balder Vidar 

Distance(m) Fleet Dranitsyn Nordica Ignatjuk Talagy Viking II Viking II Viking Viking 

100 5.41 35.92 33.00 27.25 26.09 32.47 31.76 32.47 32.47 

200 7.75 37.18 35.71 33.30 28.48 35.01 44.02 35.01 35.01 

300 11.09 39.58 39.50 28.04 31.09 48.03 44.02 48.03 48.03 

400 18.06 42.57 43.85 30.34 34.06 48.03 44.02 48.03 48.03 

500 18.06 45.32 44.68 30.8 36.53 48.03 44.02 48.03 48.03 

600 18.06 47.26 44.68 35.66 36.53 48.03 44.02 48.03 48.03 

700 27.33 47.26 44.68 35.66 36.53 48.03 44.02 48.03 48.03 

800 27.33 47.26 44.68 35.66 36.53 48.03 44.02 48.03 48.03 

900 27.33 47.26 44.68 35.66 36.53 48.03 44.02 48.03 48.03 

1,000 28.31 47.26 44.68 35.66 36.53 48.03 44.02 48.03 48.03 

1,100 28.31 47.26 44.68 35.66 43.48 48.03 44.02 48.03 48.03 

1,200 28.31 47.26 44.68 43.93 43.48 48.03 44.02 48.03 48.03 

1,300 28.31 47.26 44.68 43.93 43.48 48.03 44.02 48.03 48.03 

1,400 28.31 47.26 44.68 43.93 43.48 48.03 44.02 48.03 48.03 

1,500 28.31 50.01 46.53 43.93 43.48 48.03 44.02 48.03 48.03 

1,600 28.31 50.01 46.53 43.93 43.48 48.03 44.02 48.03 48.03 

1,700 28.31 50.01 46.53 43.93 43.48 48.03 44.02 48.03 48.03 

1,800 28.31 50.01 46.53 43.93 43.48 48.03 44.02 48.03 48.03 

1,900 28.31 50.01 46.53 43.93 43.48 48.03 44.02 48.03 48.03 

2,000 28.31 50.01 46.53 43.93 50.39 48.03 44.02 48.03 48.03 

2,100 28.31 50.01 46.53 46.24 50.39 48.03 44.02 48.03 48.03 

2,200 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,300 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,400 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,500 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,600 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,700 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,800 28.31 50.01 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

2,900 28.31 54.13 48.96 43.93 50.39 48.03 44.02 48.03 48.03 

3,000 28.31 54.13 48.96 46.24 50.39 48.03 44.02 48.03 48.03 

3,500 28.31 54.13 52.29 46.24 50.39 48.03 44.02 48.03 48.03 

4,000 28.31 54.13 52.29 49.16 50.39 48.03 44.02 48.03 48.03 

4,500 28.31 54.13 57.09 53.02 50.39 48.03 44.02 48.03 48.03 

5,000 28.31 60.79 57.09 53.02 53.15 48.03 44.02 48.03 48.03 

5,500 28.31 60.79 57.09 53.02 56.64 48.03 44.02 48.03 48.03 

6,000 28.31 60.79 57.09 58.34 56.64 48.03 44.02 48.03 48.03 

6,500 28.31 60.79 57.09 58.34 112.28 48.03 44.02 48.03 48.03 

7,000 28.31 60.79 64.5 58.34 112.28 48.03 44.02 48.03 48.03 

7,500 28.31 60.79 64.5 58.34 112.28 48.03 44.02 48.03 48.03 

8,000 28.31 60.79 64.5 66.22 112.28 48.03 44.02 48.03 48.03 

8,500 28.31 60.79 64.5 66.22 112.28 48.03 44.02 48.03 48.03 

9,000 28.31 72.67 64.5 66.22 112.28 48.03 44.02 48.03 48.03 

9,500 28.31 72.67 64.5 66.22 112.28 48.03 44.02 48.03 48.03 

10,000 28.31 72.67 64.5 66.22 112.28 48.03 44.02 48.03 48.03 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 62 

Determination of the Volume Sources Spacing and Dimensions 

For each ship, the elevated line source is divided into a series of volume sources and each volume 

source is assigned initial X, Y, and Z dimensions following Section 1.2 in the User’s Guide for the 

Industrial Source Complex (ISC3) Dispersion Models, Volume II - Description of Model 

Algorithms (EPA-454/95-003b dated September 1995). 

The line source for the primary and secondary ice management ships is composed of a series of 

adjacent squares with 100 meters on each side. EPA has suggested that the volume sources could 

be spaced based on the size of the ice management ships which are generally around 100 meters 

long. The line source for the OSR fleet is composed of a series of adjacent squares, each 50 meters 

on side. The OSR fleet vessels could potentially range in size from 34-foot (~10 meter) boats, to 

the Nanuq which is roughly 100 meters in length. The line source of the OSR fleet is composed of 

a series of adjacent squares which represent both the larger and the smaller ships so a fleet 

average of approximately 50 meters is used to represent the OSR fleet. 

Shell has chosen to conservatively model all emissions from the OSR fleet out of the low stacks of 

the smaller, 34-foot craft. In reality, the impacts from the OSR fleet are based on emissions from 

both the smaller craft and the larger Nanuq. For comparison, the stacks of the 34-foot craft are 11 

feet above the water while the stack of the Nanuq is approximately 50 feet above the water. 

Initial dispersion for volume sources is characterized by two parameters, σy (sigma Y) and σz 

(sigma Z). For the ice management and anchor handling fleet, the sigma Y value for each volume 

source is determined by dividing the physical horizontal dimension of the volume, 100 meters, 

by 2.15 as recommended in the ISC User’s Guide. The sigma Y value for each volume of the OSR 

fleet is 50 meters, divided by 2.15. Thus, the sigma Y values for the OSR fleet and ice 

management fleet used as input to the ISC-PRIME model are 46.5 and 23.3 meters, respectively. 

EPA has recommended that Shell utilize the smallest, most conservative sigma Z values 

predicted by SCREEN3 for input to the ISC-PRIME model. Table 5-5 lists the smallest SCREEN3-

predicted sigma Z values for both the OSR and ice management fleets. Based on this table, the 

sigma Y and sigma Z values for the OSR fleet and ice management fleet are 5.23 meters and 11.02 

meters, respectively. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 63 

Table 5-5: Minimum Sigma Z Values from SCREEN3 

Source Name 

SCREEN3 

Model ID 

Minimum

Sigma Z 

OSR Fleet OILSPL3 5.23 

Kapitan Dranitsyn KAPITAN2 17.18 

Fennica/Nordica FENNICA2 15.04 

Vladimir Ignatjuk VLADIGN2 11.02 

Talagy TALAGY 12.1 

Tor Viking II TOR_H 16.68 

Odin Viking II ODIN_H 16.84 

Balder Viking BALD_H 16.68 

Vidar Viking VIDAR_H 16.68 

A listing of the assumed locations and source characteristics for the primary and secondary ice 

management ships and the OSR fleet are provided on Pages 5, 6 and 7 of Appendix B. 

5.5 Ambient Air Boundary and Receptors 

Shell has submitted a request to the US Coast Guard, for issuance of a safety exclusion and 

equipment protection zone surrounding the Discoverer to a radius of 1,000 meters, which is 

approximately equal to its anchor pattern radius. To be conservative, an ambient air boundary of 

900 meters is used herein. The Discoverer is anchored with eight lines equally spaced around the 

vessel and fanning out from the mooring turret. 

To capture maximum screening impacts from the Discoverer and its associated fleet, receptors are 

placed every 100 meters throughout a 13-kilometer by 10-kilometer area covering all activity 

areas upwind and downwind of the Discoverer. Receptors are spaced around the 900-meter 

boundary every 25 meters. In addition, a high resolution line of receptors is placed downwind of 

the Discoverer spanning the width of the Discoverer (three receptors spaced every 15 meters 

spanning north-south). Receptors on this line (located directly downwind of the Discoverer) are 

spaced: every 25 meters between the exclusion zone and 8 kilometers from the Discoverer, every 

100 meters from 8 kilometers to 50 kilometers, and every 500 meters beyond 50 kilometers. All 

maximum impact locations are captured by this high resolution line. Receptor locations for the 

worst-case modeling scenario are shown on Figure 5-1. 

5.6 Positioning of Source Components Including Fleets for Modeling 

The screening modeling emissions scenario is developed with the ice management fleet operating 

upwind of the Discoverer to break up any ice so it will flow around it, and the OSR fleet operating 

downwind of the Discoverer, the safe and protected side, and the direction in which any oil spill 

would drift. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 64 

The Discoverer will have its bow pointing into the wind when it is drilling. This is accomplished 

through a mechanical drive that rotates the ring that forms the anchor tie relative to the hull and 

is for the purpose if minimizing ice buildup on the Discoverer’s hull during drilling. The selection 

of the direction from the Discoverer in which to locate the fleet is made first by arbitrarily 

orienting the Discoverer with the helideck facing west and the bow facing east as shown on Page 8 

of Appendix B. For the impact analysis, the wind is blowing from the east towards the bow of 

the Discoverer. 

The fleet spatial orientation includes the OSR fleet operating with the nearest edge of activity 

located approximately two kilometers downwind of the edge of the Discoverer. The two ice 

management ships (primary and secondary) will be operating upwind of the Discoverer. The 

nearest edge of secondary ice management activity will be 1 kilometer upwind of Discoverer and 

the nearest edge of primary ice management activity will be 4.8 kilometers (3 miles) upwind. The 

resupply ship emissions are explicitly modeled when the ship is docked to the Discoverer. The 

resupply ship generally ties to the drillship stern first (back of ship) with a 50-foot standoff from 

the edge of the drillship when onloading/offloading. For this modeling analysis, it is assumed 

that the resupply ship is continuously located 12 hours per day near the Discoverer for 32 days per 

drilling season. In reality, the resupply ship will only visit the Discoverer for a few days per 

season for 12 hours per visit. These emissions are allowed to be down-washed in the wake of the 

Discoverer, just as the Discoverer source units emissions will be to some degree. 

Figure 5-1 provides the locations of the Discoverer and support fleets for the worst-case impact 

scenario. 

A listing of the assumed locations and source characteristics for the ice management fleet are 

provided on Pages 6, 7 and 8 of Appendix B. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 65 

Figure 5-1: Source and Receptor Locations for Worst-Case Impact Scenario 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 66 

5.7 PSD Modeling Assessment Phases – Preliminary Analysis and Full 

Impact Analysis 

The PSD requirements provide for land use area classification as a function of the amount of 

growth of air emission sources and impacts allowed before significant air quality deterioration 

would occur. Class I areas have the smallest impact increments and thus allow only a small 

degree of air quality deterioration. Class II areas should be able to accommodate normal, wellmanaged industrial growth and are afforded a less stringent level of air quality deterioration than 

Class I areas. 

The nearest Class I area (Denali National Park) is located more than 950 km from the proposed 

Shell activities on the Chukchi Sea OCS. Therefore, impacts to the Class I area are insignificant 

and are not evaluated in the impact analyses and the following discussion pertains only to 

impacts at Class II areas. 

The PSD modeling analysis involves two phases: a preliminary analysis (referred to as a 

significant impact analysis) and, if required, a full impact analysis. The preliminary analysis 

estimates ambient concentrations resulting from the proposed project for pollutants that trigger 

PSD requirements. 

The results of the preliminary analysis determine whether a full impact analysis (facility plus 

competing regional sources) for a particular pollutant is necessary. If the ambient impacts from 

the preliminary analysis are greater than the PSD Significant Impact Levels (SILs) shown in Table 

5-6 then the extent of the Significant Impact Area (SIA) of the proposed project is to be 

determined. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 67 

Table 5-6: Summary of Significant Impact Levels and Related Significant Areas 

Pollutant 

Averaging

Time 

PSD Class II 

SIL 

(μg/m3) 

Screening Model 

Max. SIA 

(kilometers) 

Nitrogen Dioxide (NO2) Annual 1 50.0 

Particulate Matter 24-hour NA NA 

(PM2.5) Annual NA NA 

Particulate Matter 24-hour 5 18.8 

(PM10) Annual 1 2.8 

3-hour 25 Impact not 

significant 

24-hour 5 29.8 

Sulfur Dioxide (SO2) 

Annual 1 Impact not 

significant 

Carbon Monoxide (CO) 1-hour NA NA 

8-hour NA NA 

SIL Significant Impact Level 

SIA Significant Impact Area 

NA not applicable 

Initially, the SIA is determined for every relevant averaging time for a particular pollutant. The 

final SIA for that pollutant is the largest area for each of the various averaging times. According 

to the EPA’s Draft New Source Review Workshop Manual (EPA, 1990), the SIA is a circular area 

with a radius extending from the source to: (1) the most distant point where approved dispersion 

modeling predicts a significant ambient impact will occur, or (2) a modeling receptor distance of 

50 kilometers, whichever is less. Therefore, a SIA cannot be greater than 50 kilometers for any 

pollutant. From Table 5-6, the SIAs for NO2, PM10, and SO2 are 50, 18.8, and 29.8 kilometers, 

respectively. 

The full impact analysis expands the preliminary impact analysis by considering emissions from 

both the proposed project as well as other sources in the SIA (the competing sources). The full 

impact analysis may also consider other sources outside the SIA that could cause significant 

impacts in the SIA of the proposed source. The results from the full impact analysis are used to 

demonstrate compliance with NAAQS and PSD increments. The source inventory for the 

cumulative NAAQS analysis includes all nearby sources that have significant impacts within the 

proposed source SIA, while the source inventory for the cumulative PSD increment analysis is 

limited to increment-affecting sources (new sources and changes to existing sources that have 

occurred since the applicable increment baseline date). 

The full impact analysis is limited to receptor locations within the proposed project's SIA. The 

modeling results from the NAAQS cumulative impact analysis are added to representative 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 68 

ambient background concentrations, and the total concentrations are compared to the NAAQS. 

However, the modeled air quality impacts for all increment-consuming sources are directly 

compared to the PSD increments to determine compliance (without consideration of ambient 

background concentrations). 

5.8 Nearby Sources 

For any pollutant, the Discoverer’s maximum predicted SIA, using conservative screening 

modeling, is 50 kilometers. The Discoverer is to be used for exploratory drilling activity at Shell's 

Burger Prospect oil and gas lease blocks (Figure 1-1) which is over 90 kilometers offshore. 

Because of the remote offshore location of the Shell leases and the lack of any significant nearby 

sources, impacts from other sources (e.g., competing sources) were not considered in the impact 

analysis. Per EPA’s request, Alaska DEC was contacted and confirmed that there are no other 

competing sources near the Shell project.55 Therefore, the maximum predicted concentrations 

from only the Discoverer activities on the Chukchi OCS are added to the ambient baseline 

concentrations (described in Section 6) for comparison to the NAAQS and the PSD increment. 

Emissions of lead are insignificant and were not evaluated. 

5.9 Selection of Drilling Locations to Determine Worst-Case Cumulative 

Impacts 

It is impossible to terminate one well site operation and move, set anchors, and commence 

operation on a second well on the same day, so additive short-term impacts (i.e., combined 

impacts of 24 hours or less) from two sequential Discoverer wells cannot exist. On the other hand, 

it is possible that annual impacts could be additive from the Discoverer drilling sequentially at 

different locations. 

Additive annual impacts are addressed by including the impacts from a first drill site lasting 84 

days and a second drill site that is drilled at a minimum distance from the first drill site of 1,000 

meters and upwind, for another 84 days. Shell has offered this 1,000-meter minimum drill site 

separation distance (in any drill season) as a permit restriction (ORR). It is possible for the 

Discoverer to drill at more than two drill sites in the same drilling season. In these cases, all drill 

sites would be separated by at least 1,000 meters and the total duration of drilling of the first, 

second, third, fourth drill site and so on summed could not be greater than a maximum 168-day 

season. Maximum impacts would involve one drill site being drilled for, hypothetically, 84 days 

and the impacts would be at the downwind edge of the safety and equipment protection 

exclusion zone, supplemented by the impacts of the additional drill sites, all of which would be at 

a distance of at least 1,000 meters and also upwind of the receptor of maximum impact from the 

first drill site, as shown on Figure 5-2. Thus, both Cases A and B shown in Figure 5-2 will result 

in the same worst-case impact value. In both of these cases, the maximum impacts from one drill 

site added to the maximum impacts from a second drill site (separated by 1,000 meters) will 

 

55 Schuler, Alan, Alaska DEC [Communications with T. Martin, Air Sciences Inc.]. January, 26, 2009. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 69 

result in the worst-case impact for two drill sites. In both cases, the impacts from both drill sites 

overlap at the ambient air boundary of at least 900 meters. For this to occur, the predominant 

wind pattern would need to shift up to 180 degrees between the well drillings, which is an 

absurd combination of assumptions, but is the nature of a screening analysis that provides an 

impact estimate below which the maximum actual impact will be. Since all of those additional 

drill sites together could have emissions lasting no more than 84 days combined, the impacts of 

those additional drill sites would be no greater than the impact from only a second drill site being 

drilled for 84 days. So, the highest impact of any undefined number of drill sites drilled would 

be equal to the two-drill site scenario with the drill sites separated by 1,000 meters. This is the 

scenario that is used to define the maximum screening impacts, which will necessarily exceed the 

real maximum impacts. Additionally, the worst-case maximum additive annual impact occurs at 

a unique point at which, under the annual average standard (chronic exposure), a member of the 

public is assumed to remain located for the entire duration of the drilling of two or more wells, 

which, of course, will not happen. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 70 

Figure 5-2: The Maximum Annual Impact Configuration for Sequential Drill Sites 

5.10 Post-Processing of the Impacts to Incorporate Annual Operating 

Restrictions into the Impacts 

Shell proposes several long-term (seasonal) owner-requested restrictions to restrict the use of the 

MLC compressors and HPUs to the equivalent of capacity operation for 48 days per season, and 

the ice management ships to the equivalent of capacity operation for 64 days (38 percent of a 168-

day season) per season. The resupply ship is expected to be used only a few days per season. To 

account for these reduced usages, it is assumed that all are modeled as emitting for no more than 

32 days per 84-day period and the following modeling approach is utilized. First, the model is 

run with all sources included and then the 1-hour impacts are post-processed by multiplying by 

the persistence factor (Table 5-3) and adjusting impacts by 32 days/365 days. Then the model is 

run with all sources except the HPU engines, air compressors, resupply vessel, OSR fleet, and ice 

management fleets (called the “No xxd” model runs) and then post-processed by multiplying by 

the persistence factor and adjusting impacts by (84 days - 32 days)/365 days. 

When these impacts are added together on a receptor-by-receptor basis, effectively 32 days of the 

ORR sources are accounted for while 84 days of operations of all other sources are accounted for. 

This approach considers the worst-case meteorological condition at each receptor for both sets of 

model runs while also maintaining spatial relationships to allow for a more realistic pattern of 

dispersion from the sources emitting together as a group. The sum of the two model runs for 

each pollutant represents the maximum combined impact from two drill sites. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 71 

SECTION 6 

BASELINE CONCENTRATIONS 

When comparing a project’s impact to the NAAQS, an ambient background concentration is 

needed. The background concentration represents impacts from natural and anthropogenic 

sources not included in the impact modeling analysis. The Shell Burger Prospect drill site 

location on the Alaska OCS will be far (90 kilometers) from the Alaska shoreline and away from 

significant sources of pollution so that existing air quality concentrations can be represented with 

a regional value. According to the Guideline on Air Quality Models (40 CFR 51, Appendix W, 

Section 8.2.2c), if there are no monitors located in the vicinity of the source, a “regional site” may 

be used to determine background concentrations. A “regional site” is one that is located away 

from the area of interest, but is impacted by similar natural and distant man-made sources. Shell 

asserts that the data collected as part of both BP's Arctic North Slope Eastern Region (ANSER) 

monitoring program (near the BP Badami facility in 1999) and the Shell/CPAI Wainwright 

monitoring program represent regional background concentrations. While the Badami data sets 

are more than three years old, there has been little or no industrial or residential growth within a 

25-kilometer radius of this station since the data were collected that would make these data sets 

unrepresentative of present-day conditions. 

Shell and CPAI began monitoring NO2, PM2.5, PM10, SO2, CO, and O3 concentrations at 

Wainwright, Alaska in November 2008. The Wainwright and Badami monitoring stations are 

both remotely located (minimal influence of industry and other human activities) and are the 

most representative “regional sites” on the North Slope for estimating offshore monitoring 

concentrations. A map of the ambient monitoring stations on the North Slope is provided in 

Figure 6-1. Shell utilizes available Wainwright monitoring data (beginning in November 2008 

through December 2008) to demonstrate that the ANSER baseline data are in-fact regionally 

representative (or higher than) the Chukchi Sea. Shell will submit Wainwright ambient data 

through April 2009 to verify that the Badami data set is representative of the Wainwright and 

Chukchi baseline. Impact modeling results in Section 7 show that with these estimates of 

baseline the NAAQS are met and that even with a significant increase, the standards would still 

be met. 

Because Badami is a regional site with an entire year of data, Shell utilizes the maximum 

measured concentrations from both the Wainwright station and Badami station to represent 

Chukchi Sea baseline concentrations. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 72 

Figure 6-1: Map of Ambient Monitoring Stations on the North Slope 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 73 

Per the quality assurance plan for the Wainwright monitoring program,56 the Wainwright 

monitoring station is located in a relatively pristine area. The Wainwright power plant, to the 

north, and the water treatment plant, to the west, are the largest single stationary sources in the 

area. Collectively, emissions from fuel-oil fired home heating within the community also 

contribute a significant amount of emissions to the local airshed. The Search and Rescue 

Headquarters building, from which the Wainwright sampling is being conducted, has two fueloil fired heaters and no other combustion sources. Special care is being taken to locate sample 

inlets as far away as possible from these sources, and generally upwind of them. However, it is 

anticipated that impacts from these sources may be measured from time to time. Data collected 

that is known to be impacted by emissions from the Search and Rescue Headquarters building 

will be flagged prior to reporting. Shell will also flag hours which are obviously influenced by 

naturally occurring wildfires as these values are not representative of typical ambient 

background concentrations. If these local sources have any impact on the station, they would 

tend to elevate the Wainwright data. Therefore, this station provides an upper bound on the 

Chukchi baseline concentrations. 

The Wainwright data (November 2008 – December 2008) collected prior to the final modeling 

analysis will not include calendar quarter #3 (July, August, September), so available North Slope 

monitoring data has been reviewed to demonstrate that non-summer values at Wainwright can 

be used to conservatively represent background concentrations. 

Figures 6-2, 6-3, and 6-4 provide a quarterly breakdown of average monthly NO2 concentrations, 

average maximum 3-hour SO2 concentrations, and average maximum 24-hour SO2 concentrations 

at all monitoring locations on the North Slope. From these figures, it is evident that gaseous 

pollutant concentrations are highest in the wintertime months (Q1, Q4) and lowest in the summer 

months (Q3). 

There are three stations on the North Slope that monitor CO (Wainwright, BPX – Liberty, and 

CPAI – Kuparuk River). Hourly CO data is only available from Alaska DEC for the BPX – 

Liberty station and is provided in Figure 6-5. A review of hourly data from BPX – Liberty 

indicates that CO concentrations are generally higher in the wintertime months and lower in the 

summertime months with the exception of an abnormal spike in mid-September, 2007. This 

spike was caused by naturally occurring wildfires and is not representative of typical ambient 

background concentrations. In mid-September 2007, a large, 250,000 acre wild fire was burning 

to the south of the Prudhoe Bay area which elevated pollutant levels on the North Slope.57 Even 

during this fire episode, the highest measured CO concentration at BPX – Liberty (highest on 

North Slope) was still only 4.3% of the 1-hour NAAQS value. 

 

56 Conoco Phillips Alaska, Inc., Wainwright Near-Term Ambient Air Quality Monitoring Quality Assurance Project Plan prepared by 

ENSR Corporation. Document No.: 01865-100-2100. November 2008. 

57 U.S. Department of Interior, Bureau of Land Management. Wildland Fire Dataset for Alaska. 

http://agdc.usgs.gov/data/blm/fire/index.html 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 74 

Therefore, higher concentrations of pollutants, primarily resulting from combustion related 

activities (i.e., NO2, SO2, CO and PM2.5), are highest in the wintertime when atmospheric 

conditions are more stable, dispersion is poorer, and residential heating emissions (e.g., wood 

smoke, fuel-oil heaters, etc.) are higher. Utilization of Wainwright data collected during the 

wintertime months will provide conservative background concentrations for offshore locations. 

Figure 6-2: Average Monthly NO2 Concentrations for North Slope Stations 

Average Monthly NO2 Concentrations

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

0.018

 BPX - Badami

(ANSER)

 BPX - Liberty BPX - Prudhoe Bay (A

Pad)

 BPX - Prudhoe Bay

(CCP)

 CPAI - Alpine

(Nuiqsut)

NO2 Concentration (ppm)

Q1

Q2

Q3

Q4
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 75 

Figure 6-3: Average Maximum 3-Hour SO2 Concentrations for North Slope Stations 

Figure 6-4: Average Maximum 24-Hour SO2 Concentrations for North Slope Stations 

Average Max. 3-Hour Concentrations

0.000

0.002

0.004

0.006

0.008

0.010

0.012

0.014

0.016

0.018

 BPX - Badami

(ANSER)

 BPX - Liberty BPX - Prudhoe Bay (A

Pad)

 BPX - Prudhoe Bay

(CCP)

 CPAI - Alpine

(Nuiqsut)

SO2 Concentration (ppm)

Q1

Q2

Q3

Q4

Average Maximum 24-Hour SO2 Concentrations

0.000

0.001

0.002

0.003

0.004

0.005

0.006

 BPX - Badami

(ANSER)

 BPX - Liberty BPX - Prudhoe Bay (A

Pad)

 BPX - Prudhoe Bay

(CCP)

 CPAI - Alpine (Nuiqsut)

SO2 Concentration (ppm)

Q1

Q2

Q3

Q4
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 76 

Figure 6-5: Time Series of 1-Hour CO Concentrations at BPX - Liberty 

Measured PM10 concentrations are locally effected by emission sources such as blowing dust 

from river channels, fugitive emissions from nearby roads, etc. The Wainwright and Badami 

stations are assumed to be minimally impacted by fugitive sources of PM10 emissions compared 

to other North Slope stations such as Nuiqsut which is sited close to loess-rich Colville River 

channels, where clay-sized material easily becomes airborne when dry. 

Table 6-1 shows the seasonal breakdown of PM10 measurements at Badami. At Badami, there is a 

bi-modal PM10 distribution where impacts are higher in both the wintertime (Q1) and the 

summertime (Q3) and lower in the fall and spring. The summertime PM10 concentrations at 

Badami are influenced by locally generated dust sources associated with drier soil/road 

conditions and human activities at the Badami facility and the nearby Badami airport. 

Table 6-1: Seasonal PM10 Concentrations at Badami 

PM10 Concentration (ug/m3) 

Quarter Max. 24-Hour Quarter Avg. 

Q1 9.5 2.6 

Q2 5.5 1.5 

Q3 12.4 2.8 

Q4 6.4 1.4 

1-Hour CO Concentration (ppm)

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

1.80

1-Feb

15-Feb

1-Mar

15-Mar29-Mar

12-Apr26-Apr

10-May24-May

7-Jun

21-Jun

5-Jul

19-Jul

2-Aug

16-Aug30-Aug

13-Sep27-Sep

11-Oct25-Oct

8-Nov

22-Nov

6-Dec

20-Dec

3-Jan

17-Jan31-Jan

CO Concentration (ppm)

Wildfire Impacts
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 77 

The Shell project will be remotely located over open water and away from land-based sources of 

dust and other combustion-related activities. There is no industry on the Chukchi Sea coast 

within 90 kilometers of the Burger site location in the Chukchi Sea. Without local crustal and 

combustion-related sources, maximum offshore concentrations are expected to occur in the 

wintertime under stable atmospheric conditions. Wintertime measurements at Wainwright and 

year-round measurements at Badami are available and the highest values (excluding hours 

influenced by wildfires) from these two regional datasets provide a conservative estimate of 

offshore ambient background concentrations for Shell’s proposed project location and drilling 

season. 

Table 6-2 provides a representative estimate of regional background concentrations in remote 

locations of the Alaska OCS where there are no significant pollution sources. The Wainwright 

monitored concentrations will be updated with data through April 2009 for verification of the 

results herein. 

Table 6-2: Baseline Concentrations 

Monitored Concentrations 

Pollutant 

Averaging 

Time 

Badami 1

(μg/m3) 

Wainwright 2

(μg/m3) 

Maximum 

(μg/m3) 

NO2 Annual 3 2 3 

24-hour N/A 9 5 PM2.5 Annual N/A 2 2 

24-hour 12 9 12 

PM10 Annual 2 --- 2 

3-hour 18 18 18 

SO2 24-hour 16 10 16 

Annual 3 --- 3 

1-hour N/A 896 896 CO 

8-hour N/A 514 514 

1 Based on BP's Arctic North Slope Eastern Region (ANSER) monitoring program, which took 

place east of BP's Badami facility in 1999. 

2 Wainwright data provided is preliminary data for November and December 2008; values to 

be updated as more data becomes available. 

NA Not applicable 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 78 

SECTION 7

IMPACT MODELING RESULTS 

7.1 Worst-Case Concentration Impacts 

The Discoverer drilling impact summary of Table 7-1 is developed from the individual source 

impacts and background concentrations (for NAAQS) for all applicable averaging times. Because 

this two-drill site scenario defines the worst-case annual impact, Shell’s Chukchi Sea exploratory 

drilling program will comply with the NAAQS and PSD increments. The modeling results and 

associated calculations for the annual impacts are provided in Table 7-2. Results and associated 

calculations for both short-term and annual impacts are summarized in Table 7-3. All electronic 

modeling files and associated calculations are provided in the CD. 

Table 7-1: Summary of Screening Maximum Estimated Short-Term and Annual Concentrations all 

Sources Combined 

Pollutant 

Averaging 

Time 

NAAQS1

(μg/m3) 

Screening 

Model Max. 

Impact Plus 

Background2

(μg/m3) 

PSD Class II 

Increment 

(μg/m3) 

Screening 

Model Max. 

Impact No 

Background3

(μg/m3) 

Nitrogen Dioxide 

(NO2) 

Annual 100 14.4 25 11.1 

Particulate Matter 24-hour 35 31.6 NA NA 

(PM2.5) Annual 15 2.9 NA NA 

Particulate Matter 24-hour 150 35.3 30 22.9 

(PM10) Annual 50 3.4 17 1.4 

3-hour 1,300 35.8 512 17.6 

24-hour 365 26.2 91 10.6 

Sulfur Dioxide 

(SO2) 

Annual 80 3.1 20 0.5 

Carbon 1-hour 40,000 1,025.9 NA NA 

Monoxide (CO) 8-hour 10,000 631.2 NA NA 

1 National Ambient Air Quality Standards 

2 Maximum modeled impacts plus background concentrations are compared to the NAAQS. 

3 Maximum modeled impacts only (no background concentrations included) are compared to the PSD Increments. 

NA Not applicable 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 79 

Table 7-2: Impact Scenarios Used to Define Screening Maximum Annual Impacts from All Sources 

and Multiple Sequential Wells 

Max. Impact 

Location 

Pollutant Model Run Impact Category X(m) Y(m) 

Modeled 

1-Hour 

Impact 2

Persistence 

Factor 

Emis. 

Adjust 3

Conc. 

(μg/m3) 

NO2 4 All Sources 900 m from Rig 1 -884.3 55 637.9 0.10 0.0877 4.2 

 No xxd 2 900 m from Rig 1 -884.3 55 125.7 0.10 0.1425 1.3 

 All Sources 900 m from Rig 1 -884.3 55 637.9 0.10 0.0877 4.2 

 No xxd 2 900 m from Rig 1 -884.3 55 125.7 0.10 0.1425 1.3 

Total Annual NO2 Impact (μg/m3) 5 > 11.1 

Max. Impact 

Location 

Pollutant Model Run Impact Category X(m) Y(m) 

Modeled 

1-Hour 

Impact 2

Persistence 

Factor 

Emis. 

Adjust 3

Conc. 

(μg/m3) 

PM10 & All Sources 900 m from Rig 1 -884.3 55 38.1 0.10 0.0877 0.3 

PM2.5 No xxd 2 900 m from Rig 1 -884.3 55 26.9 0.10 0.1425 0.4 

 All Sources 900 m from Rig 1 -884.3 55 38.1 0.10 0.0877 0.3 

 No xxd 2 900 m from Rig 1 -884.3 55 26.9 0.10 0.1425 0.4 

Total Annual PM10 and PM2.5 Impact (μg/m3) 5 > 1.4 

Max. Impact 

Location 

Pollutant Model Run Impact Category X(m) Y(m) 

Modeled 

1-Hour 

Impact 2

Persistence 

Factor 

Emis. 

Adjust 3

Conc. 

(μg/m3) 

SO2 All Sources 900 m from Rig 1 -884.3 55 17.4 0.10 0.0877 0.2 

 No xxd 2 900 m from Rig 1 -884.3 55 8.2 0.10 0.1425 0.1 

 All Sources 900 m from Rig 1 -884.3 55 17.4 0.10 0.0877 0.2 

 No xxd 2 900 m from Rig 1 -884.3 55 8.2 0.10 0.1425 0.1 

Total Annual SO2 Impact (μg/m3) 5 > 0.5 

Assume 84 days per drilling location and 32 days of operation for HPU engines, air compressors, and resupply, ice 

management, and OSR ships at each location. 

1 Assume that the minimum separation distance between drilling locations is 1,000 meters and that there is at least a 900-

meter ambient air boundary for annual impacts. 

 Assume two drilling locations for annual impacts (i.e., 84-day duration at each drilling location during a 168-day 

drilling season). 

2 For each drill site, modeled 1-hour impacts for both sets of model runs (i.e., A) all sources and B) no HPUs, 

compressors, and resupply, ice management, or OSR ships (also call “No xxd” model run) which results in the highest 

combined impact after emissions adjustments are made. 

3 Annual emissions adjustment to modeled hourly emissions to account for duration at each drill site. Model run with 

all sources is adjusted by 32 days/365 days (i.e., 0.0877) and model run with no HPUs, compressors, and resupply, ice 

management, or OSR ships is adjusted by (84 days - 32 days)/365 days (i.e., 0.1425). 

4 Assume that NO2 = NOx * 0.75. 

5 Total modeled impact (without background) is the sum of the impacts at or beyond at least a 900 ambient air boundary 

of the Discoverer plus the impacts at or beyond 900 meters (for annual impacts only). 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 80 

Table 7-3: Combined Screening Maximum Impacts from All Sources and Multiple Sequential Wells 

Concentration (μg/m3) 

Pollutant 

Averaging 

Period 

Max. 

Modeled 

1-Hour 

Impact 

900 m 

Persistence 

Factor 

Emis. 

Adj. 2

Hole #1 

Impact at 

or beyond 

900 m 1

Hole #2 

Impact at 

or beyond 

900 m 1 Background 

Total 

No 

Background 4

Total 

w/ 

Background 5

PSD Class 

II 

Increment 

(μg/m3) Comply? 

NA

(μ

 NO2 3 Annual See Calculations in Table 7-2 5.5 5.5 3.3 11.1 14.4 25 Yes  PM2.5 24-Hour 38.1 0.6 1 22.9 --- 8.7 22.9 31.6 --- ---  Annual See Calculations in Table 7-2 0.7 0.7 1.5 1.4 2.9 --- ---  PM10 24-Hour 38.1 0.6 1 22.9 --- 12.4 22.9 35.3 30 Yes  Annual See Calculations in Table 7-2 0.7 0.7 2.0 1.4 3.4 17 Yes  SO2 3-Hour 17.6 1.0 1 17.6 --- 18.2 17.6 35.8 512 Yes 1 24-Hour 17.6 0.6 1 10.6 --- 15.6 10.6 26.2 91 Yes  Annual See Calculations in Table 7-2 0.3 0.3 2.6 0.5 3.1 20 Yes  CO 1-Hour 129.8 1.0 1 129.8 --- 896.1 129.8 1,025.9 --- --- 40 8-Hour 129.8 0.9 1 116.8 --- 514.4 116.8 631.2 --- --- 10

Assume 84 days per drilling location and 32 days of operation for HPU engines, air compressors, cranes, and resupply, ice management, and OSR ships a1 Assume that minimum separation distance between drilling locations is 1,000 meters and that there is a 900-meter safety exclusion zone for annual imp

Assume two drilling locations for annual impacts (i.e., 84-day duration at each drilling location during a 168-day drilling season). 

Short-term impacts are adequately addressed with one drilling location. 

2 Annual emissions adjustment to modeled hourly emissions; assume 84 days per location and the HPU engines, air compressors, and resupply, ice man

limited to 32 days per location. Short-term emissions are not adjusted since 24 hour/day operations are considered. 

3 Assume that NO2 = NOx * 0.75. 4 Total modeled impact without background is the sum of the maximum impact at the or beyond at least a 900-meter ambient air boundary from the Dis

beyond 900 meters (for annual impacts only). 

5 Total modeled impact without background is the sum of the maximum impact at or beyond at least a 900-meter ambient air boundary of the Discoverer

meters (for annual impacts only), and background concentrations. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 81 

Note that the worst-case impacts in Table 7-3 are also compared to the significant monitoring 

concentration thresholds. For any criteria pollutant that Shell proposes to emit in significant 

quantities, continuous monitoring data may be required as part of the air quality analysis. The 

permitting agency has discretionary authority to exempt a permit applicant from this data 

requirement if, 1) the highest modeled ambient impacts, or 2) the existing ambient pollutant 

concentrations are less than the significant monitoring concentration listed in Table 7-3. Both 

existing ambient background PM10 concentrations and maximum modeled impacts exceed the 

significant monitoring thresholds. The ambient background concentration of SO2 exceeds the 

significant monitoring thresholds, but not the maximum modeled impacts. As part of the 

Wainwright monitoring program, these pollutants along with other criteria pollutants are being 

gathered for use in the ambient impact analysis. 

7.2 Source Contribution Analyses at Maximum Impact Location 

EPA has asked that Shell provide a breakdown of individual source contributions. A source 

contribution analysis for 24-hour average PM10 (and PM2.5) and annual average NO2 is provided 

in Table 7-4. These pollutants and averaging times are presented since these are the highest 

impacts relative to the applicable ambient standards. Maximum impacts for annual NO2 are 

driven by poorer dispersing engines (HPU engines and cementing units) on the Discoverer while 

24-hour PM10 impacts are dominated by the incinerator on the Discoverer. 

Table 7-4: Discoverer Source Contributions at the Screening Maximum Impact Locations 

Impact Contribution (%) 1

 Source Description 

Model Source 

ID Annual NO2 24-Hour PM10

 Stack #1: 6 Main Drill Engines MAINENGS 1 1 

 Stack #2: 2 Air Compressors COMPENGS 3 3 

 Stack #3: 2 HPU Engines HPPENGS 24 10 

 Stack #4: 3 Cementing Units CEMENT 28 5 

 Stack #5a: Crane Engine (port) CRANE_PT 4 1 

 Stack #5b: Crane Engine (stbd) CRANE_SB 15 4 

 Stack #6: 2 Heat Boilers HEATBOIL 7 7 

 Stack #7: 1 Incinerator INCIN_D 3 57 

 Resupply Ship KILABUK 1 1 

 Oil Spill Response Ships OILSPL01-40 0 0 

 Ice Management (Secondary) BRK_B01-48 10 7 

 Ice Management (Primary) BRK_A01-96 5 4 

 Total > 100 100 

1 Maximum impacts occur on the 900 meter ambient air boundary directly downwind of the Discoverer. 

Maximum impact receptor is -884.3, 55.0 and impact date is 01050412 (yymmddhh). 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 82 

7.3 Impacts from the Ice Management and Anchor Handler Fleet 

EPA has asked that Shell provide a table showing the maximum concentration impacts from both 

the primary and the secondary ice management ships and its locations. As expected, if the 

impacts from all source operations show compliance with the ambient standards as shown in 

Table 7-3 above, then the impacts from each of the ice management ships individually will also 

be less than the ambient standards. The maximum impacts from the primary ice management 

fleet and secondary ice management fleet are provided below in Table 7-5 and 7-6, respectively, 

and impacts are well below the PSD increment and NAAQS thresholds. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 83 

Table 7-5: Maximum Impacts from Primary Ice Management Ship 

Concentration (μg/m3) Coordinate of Max. 

Impact Receptor 

Pollutant 

Averaging 

Period X (m) Y (m) 

Max. 

Modeled 

1-Hr 

Impact 

(μg/m3) 

Persistence 

Factor 

Emission 

Adjustment 1

Max. 

Modeled 

Impact 

(μg/m3) Background 

Total No 

Background 

Total w/ 

Background (μg

NO2 Annual 4,800.0 -4,500.0 78.3 0.1 0.1753 1.0 3.3 1.0 4.3 2

PM2.5 24-Hour 4,800.0 -4,500.0 2.5 0.6 1 1.5 8.7 1.5 10.2 -

 Annual 4,800.0 -4,500.0 2.5 0.1 0.1753 0.04 1.5 0.04 1.5 -

PM10 24-Hour 4,800.0 -4,500.0 2.5 0.6 1 1.5 12.4 1.5 13.9 3

 Annual 4,800.0 -4,500.0 2.5 0.1 0.1753 0.04 2.0 0.04 2.0 1

SO2 3-Hour 4,800.0 -4,500.0 5.0 0.9 1 4.5 18.2 4.5 22.7 5

 24-Hour 4,800.0 -4,500.0 5.0 0.6 1 3.0 15.6 3.0 18.6 9 Annual 4,800.0 -4,500.0 5.0 0.1 0.1753 0.1 2.6 0.1 2.7 2

CO 1-Hour 4,800.0 -4,500.0 20.8 1.0 1 20.8 896.1 20.8 916.9 -

 8-Hour 4,800.0 -4,500.0 20.8 0.9 1 18.7 514.4 18.7 533.1 -

1 For short-term impacts assume 24-hour day operations (adjustment = 1) for annual impacts assume 64 days per drilling season (adjustment = 64 days/365 2 Impacts without background concentrations are compared to the PSD increments. 3 Impacts including background concentrations are compared to the NAAQS. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 84 

Table 7-6: Maximum Impacts from Secondary Ice Management Ship 

Concentration (μg/m3) Coordinate of 

Max. 

Impact Receptor 

PS

In

Pollutant 

Averaging 

Period X (m) Y (m) 

Max. 

Modeled 

1-Hr 

Impact 

(μg/m3) 

Persistence 

Factor 

Emission 

Adjustment 1

Max. 

Modeled 

Impact 

(μg/m3) Background 

Total 

No 

Background 

Total 

w/ 

Background (μg/m

NO2 Annual 976.1 -331.6 177.9 0.1 0.1753 2.3 3.3 2.3 5.6 25 

PM2.5 24-Hour 976.1 -331.6 5.7 0.6 1 3.4 8.7 3.4 12.1 --- 

 Annual 976.1 -331.6 5.7 0.1 0.1753 0.1 1.5 0.1 1.6 --- 

PM10 24-Hour 976.1 -331.6 5.7 0.6 1 3.4 12.4 3.4 15.8 30 

 Annual 976.1 -331.6 5.7 0.1 0.1753 0.1 2.0 0.1 2.1 17 

SO2 3-Hour 976.1 -331.6 11.3 0.9 1 10.2 18.2 10.2 28.4 512 

 24-Hour 976.1 -331.6 11.3 0.6 1 6.8 15.6 6.8 22.4 91  Annual 976.1 -331.6 11.3 0.1 0.1753 0.2 2.6 0.2 2.8 20 

CO 1-Hour 976.1 -331.6 47.3 1.0 1 47.3 896.1 47.3 943.4 --- 

 8-Hour 976.1 -331.6 47.3 0.9 1 42.5 514.4 42.5 556.9 --- 

1 For short-term impacts assume 24-hour day operations (adjustment = 1) for annual impacts assume 64 days per drilling season (adjustment = 64 days/365 2 Impacts without background concentrations are compared to the PSD increments. 3 Impacts including background concentrations are compared to the NAAQS. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 85 

7.4 Worst-Case Screening Impacts at Nearest Villages on Chukchi Coast 

Based on Figure 1-1, the nearest coastal villages to the existing Shell leases are Wainwright and 

Point Lay, which are approximately 110 and 100 kilometers away from the nearest Shell leases, 

respectively. Worst-case impacts from the proposed project using the screening analysis are 

provided in Table 7-7 and are well below the NAAQS, PSD increments, and significant 

concentrations. Impacts from the proposed project at these locations are lower than the 

measured background concentrations (existing air quality levels) representative of these pristine 

areas.
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 86 

Table 7-7: Worst-Case Screening Impacts at Nearest Villages on Chukchi Coast 

Concentration (μg/m3) 

Max. Modeled 1

Pollutant 

Averaging 

Period Wainwright Point Lay Background

Total No 

Background

Total w/ 

Background 

PSD Class 

II 

Increment 2 

(μg/m3) Comply?

NA

(μ

NO2 Annual 1.0 1.1 3.3 1.1 4.4 25 Yes PM2.5 24-Hour 1.7 1.8 8.7 1.8 10.5 --- ---  Annual 0.1 0.1 1.5 0.1 1.6 --- --- PM10 24-Hour 1.7 1.8 12.4 1.8 14.2 30 Yes  Annual 0.1 0.1 2.0 0.1 2.1 17 Yes SO2 3-Hour 4.5 4.8 18.2 4.8 23.0 512 Yes 1 24-Hour 2.7 2.9 15.6 2.9 18.5 91 Yes  Annual 0.1 0.1 2.6 0.1 2.7 20 Yes CO 1-Hour 20.6 22.0 896.1 22.0 918.1 --- --- 4

 8-Hour 18.6 19.8 514.4 19.8 534.2 --- --- 1

1 The nearest villages to Shell's Chukchi leases are Wainwright (~110 km away) and Point Lay (~100 km away). 2 Total impact without background is compared to the PSD increments. 3 Total impact with background is compared to the NAAQS.
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 87 

SECTION 8

ADDITIONAL IMPACT ANALYSES 

In addition to the NAAQS and PSD increment analyses, 40 CFR 52.21(o) requires that PSD 

applicants also address the impact from the proposed project on associated growth, soils and 

vegetation of significant commercial value impacts, and visibility impairment. EPA has also 

requested that Shell evaluate the proposed project’s impact on ozone concentrations. 

8.1 Growth Analysis 

The specifics of expected secondary emissions associated with shoreline growth is addressed in 

Section 2.15 Because of the limited and temporary nature of the exploratory drilling program, 

indirect impacts on industrial, commercial, and residential growth will be insignificant. The 

emissions presented for the project already include all anticipated emissions, including those 

from support activities (e.g., resupply ships, ice management fleet, etc.). There will be no 

substantial increase in community growth needed to support the exploratory drilling program. 

Therefore, it is not anticipated that the project will result in more than a negligible increase in air 

emissions associated with growth. 

8.2 Effects on Soils and Vegetation 

According to the EPA’s Draft New Source Review Workshop Manual (EPA, 1990), the analysis of 

air pollutant impacts on soils and vegetation is to be based on an inventory of soils and 

vegetation types found in the impact area. Permit applicants are not required to provide an 

analysis of the impact on vegetation having no significant commercial or recreational value. 

Because the drilling project will be located far offshore over open water, there are no soils or 

vegetation in the Discoverer project’s SIAs (within 50 kilometers). Therefore, no further analysis is 

warranted. 

8.3 Visibility Analysis 

Visibility impacts can be in the form of visible plumes (“plume blight”) or a general, area-wide 

reduction in visibility (“regional haze”). Visibility has been identified as an air quality-related 

value for the Alaska Class I areas as defined in the Clean Air Act (CAA). Impacts from new 

sources on Class I areas within 200 kilometers of a stationary source are of special concern to 

Federal Land Managers. The nearest Class I area (Denali National Park) is located more than 950 

kilometers from the proposed exploratory drilling activities. In addition to this great distance, 

many sources associated with the exploratory drilling program are mobile and their plumes will 

be broken up and dispersed over large areas. The Brooks Range would break up any coherent 

plumes moving toward Denali National Park. Given these factors, the impacts to the nearest 

Class I area are considered insignificant and were not evaluated. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 88 

The EPA and the state of Alaska have not established visibility thresholds for Class II areas, and 

the exploratory program is located far offshore where any coherent plumes will be broken up 

and dispersed over large areas over water. In addition, there are no visibility or other special 

protection areas in Alaska (18 AAC 50.025) located near the project. 

Visible plumes are nearly completely a result of PM emissions. The PM emissions from the 

Discoverer will be minimized through the use of oxidation catalysts and CDPFs on all on the 

diesel engines. It is possible that these engines will emit a visible plume during cold startup and 

these could last for several minutes. With the tailpipe control technology, these plumes should 

disappear quickly. There are expected to be some visible plumes in the near-field from emissions 

from the ice management and anchor handling fleet activity. However, given the mobile nature 

of these sources, plumes would be expected to be more coherent near the ice management and 

anchor handling ships and then the plumes would disperse and be broken up by movement of 

the ships and ambient winds. 

The Clean Air Act established two types of national air quality standards, primary and 

secondary. Primary standards set limits to protect public health, including the health of 

"sensitive" populations such as asthmatics, children, and the elderly. Secondary standards set 

limits to protect public welfare, including protection against decreased visibility, damage to 

animals, crops, vegetation, and buildings. Permitting authorities located in EPA Region 10 have 

utilized the secondary ambient air quality standards to address Class II visibility issues.58 

Therefore, for all Shell project sources, impacts to visibility are considered acceptable since the 

project’s impacts are well below the secondary NAAQS for all pollutants. 

8.4 Ozone Analysis 

Because the proposed project’s NOx emissions exceed 100 tons per year, EPA has asked that Shell 

provide a qualitative discussion on ozone impacts. The Chukchi coastline nearest to the Shell 

project is part of the State of Alaska’s Northern Alaska Intrastate Air Quality Control Region (40 

CFR 81.246). This region is designated as attainment or unclassifiable for all criteria pollutants, 

including ozone (40 CFR part 81.302). 

Shell began monitoring ozone concentrations at Wainwright, Alaska in November 2008. The 

nearest historical ozone monitoring stations to the Shell project are located on Alaska’s North 

Slope as shown in Figure 8-1. Measured ozone concentrations at these monitoring stations, 

which are impacted by major oil and gas operations, are provided in Table 8-1. According to the 

U.S. Department of Energy, the Prudhoe Bay, Kuparuk River, and Alpine oil fields are ranked 1, 

3, and 4, respectively, as the largest oil fields in the United States based on estimated oil 

 

58 Coburg Power, L.L.C. Prevention of Significant Deterioration Permit Application – Coburg Power Generating Plant, Coburg, 

Oregon. Submitted to Lane Regional Air Pollution Authority. February 2002. 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 89 

production.59 As shown in Table 8-1, the measured ozone concentrations in/near these large oil 

fields are all well below the ozone NAAQS. 

Table 8-1: Maximum Measured Ozone Concentrations at North Slope Monitoring Stations 

 Max. Monitored Ozone Concentration (ppb) 

Facility Data Dates 1-Hour 8-Hour 

Shell/CPAI - 

Wainwright November 2008 1 35 34 

Barrow - NOAA/GMD 2003, 2004, 2005 2 52 50 

BPX - Badami 1999 3 48 48 

BPX - Prudhoe Bay 2006, 2007 3 52 44 

BPX - Prudhoe Bay 2006, 2007 3 73 43 

CPAI - Alpine Nov. 2004 - Dec. 2005 3 64 49 

CPAI - Kuparuk River June 2001 - June 2002 3 45 45 4

Ambient Standard (ppb) > 120 5 75 6

1 Preliminary data subject to change. 

2 Most recent three years of data from the World Data Centre for Greenhouse Gases; 

http://gaw.kishou.go.jp/cgi-bin/wdcgg/accessdata.cgi?index=BRW471N00-NOAA&select=inventory 

3 This data is the most recent available data available from Alaska DEC for these stations. 

4 Data pertaining to 8-hour average not available at this time. Conservatively assume that the maximum 1-hour 

concentration persists for 8 hours. 

5 Effective May 27, 2008, EPA revised the 8-hour primary ozone NAAQS, designed to protect public health, to a level 

of 75 ppb. 

An area meets the revised 8-hour standards if the 3-year average of the annual fourth-highest daily maximum 

8-hour average at an ozone monitor is less than or equal to the level of the standard (75 ppb). 

6 As of June 15, 2005, EPA revoked its 1-hour ozone standard in all areas except the 8-hour nonattainment Early 

Action Compact (EAC) areas. 

The State of Alaska’s Ambient Air Quality Standards for ozone, as amended in its regulations through November 9, 

2008, (18 AAC 50.010(4)) are only based on the 1-hour standard of 120 ppb, and the standards for the federal 8-hour 

standard are not listed in the Alaska regulations. 

 

59 U.S. Department of Energy. Energy Information Administration Webpage: 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/current/pdf/appb.pdf#page=9 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 90 

Figure 8-1: Ozone Monitoring Stations on the North Slope 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 91 

The latest data from the Western Regional Air Partnership (WRAP) Emissions Data Management 

System (EDMS)60 indicates North Slope Borough emissions in 2002 (latest year of data available) 

from all sources (mobile, non-mobile, point, etc.) of NOx (i.e., an ozone precursor), were 

approximately 42,500 tons/year and 1,600 tons/year, respectively. Table 8-2 provides a 

summary of NOx emissions for point sources (i.e., oil and gas facilities) located in the Deadhorse, 

Prudhoe Bay, and Kuparuk areas of the North Slope. Existing North Slope point source 

emissions of NOx are approximately 41,000 tons/year, which represent 22 times more NOx than 

those from the proposed portable Shell project. 

Measured ozone concentrations on the more industrialized North Slope, which take into account 

impacts from much larger sources of ozone precursors, are no more than two thirds of the 8-hour 

ambient air quality standard (well below the standards). In addition, Shell’s proposed project 

will be located far offshore and its precursor emissions will be sufficiently dispersed before even 

impacting onshore areas. Given these factors, the proposed Shell exploratory program’s 

emissions contribution to ozone formation is not expected to be significant and the project should 

not cause or contribute to an exceedance of the ambient standards for ozone. 

 

60 Western Regional Air Partnership (WRAP) Emissions Data Monitoring System (EDMS) Database. Emissions Inventory Reports 

(EDMS). http://vista.cira.colostate.edu/tss/edms.aspx 
AirSci\Disco Major Chukchi Permit Application Revised-R15.doc 92 

Table 8-2: Point Source Emissions of NOx and VOCs – North Slope 

Emission

Point Source Name City 

Trans Alaska Pipeline System Pump Station 1 North Slope 

ConocoPhillips Central Production Facility #2 Kuparuk BP Exploration (Alaska) - Inc. - Flow Station #2 Prudhoe Bay BP Exploration (Alaska) - Inc. - Gathering Center #2 (GC-2) Prudhoe Bay BP Exploration (Alaska) - Inc. - Flow Station #1 (FS-1) Prudhoe Bay BP Exploration (Alaska) - Inc. - Seawater Injection Plant East Prudhoe Bay BP Exploration (Alaska) - Inc. - Seawater Treatment Plant - PBU Prudhoe Bay Trans Alaska Pipeline System Pump Station 3 Prudhoe Bay BP Exploration (Alaska) - Inc. - Central Power Station Prudhoe Bay ConocoPhillips Central Production Facility #1 Umiat Meridian - Kuparuk BP Exploration (Alaska) - Inc. - Gathering Center #3 (GC-3) Prudhoe Bay BP Exploration (Alaska) - Inc. - Central Gas Facility Deadhorse BP Exploration (Alaska) - Inc. - Milne Point Production Facility North Slope BP Exploration (Alaska) - Inc. - Badami Development Deadhorse ConocoPhillips Alpine Central Processing Facility Umiat Meridian BP Exploration (Alaska) - Inc. - Central Compressor Plant Deadhorse Haliburton Energy Services - Inc. - Deadhorse Facility Deadhorse BP Exploration (Alaska) - Inc. - Endicott Production Facility Prudhoe Bay ConocoPhillips Alaska - Kuparuk Seawater Treatment Plant Kuparuk BP Exploration (Alaska) - Inc. - Lisburne Production Center Prudhoe Bay ConocoPhillips Alaska - Central Production Facility #3 Kuparuk BP Exploration (Alaska) - Inc. - Northstar Production Facility Deadhorse BP Exploration (Alaska) - Inc. - Gathering Center #1 (GC-1) Prudhoe Bay BP Exploration (Alaska) - Inc. - Flow Station #3 Prudhoe Bay 

Total > 4
APPENDIX A 

Short-Term and Seasonal Emissions – One Unit per Page 
APPENDIX B 

Short-Term Emission Calculation Spreadsheets for Impact 

Modeling Input 

Seasonal Emission Spreadsheets 
APPENDIX C 

Emission Control Technology Review and References 
APPENDIX D 

SCREEN3 Model Output for Ice Management Fleet Loads 

Analyses 
APPENDIX E 

SCREEN3 Model Output for Plume Rise Determinations 
APPENDIX F 

Text Footnote References 
APPENDIX G 

Incinerator Exemption Letter