# Outer Continental Shelf Pre-Construction Air Permit Application Revised

Frontier Discoverer Chukchi Sea Exploration Drilling Program

P REPARED FOR 

## : S HELL 

## O FFSHORE 

## I NC



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P ROJECT N O

. 180-15 F EBRUARY 23, 2009AirSci\Disco Major Chukchi Perm it 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 NO x BACT Analyses ................................................................................................................. ................ 30 4.1.1.1 NO x BACT for Diesel Generators .................................................................................................... . 34 4.1.1.2 NO x BACT Smaller Diesel Engines .................................................................................................. 3 5 4.1.1.3 NO x BACT Diesel Compressors....................................................................................................... 37 4.1.1.4 NO x BACT Boilers .................................................................................................................. .......... 38 4.1.1.5 NO x BACT Incinerator .............................................................................................................. ........ 39 4.1.2 SO 2 BACT Analysis................................................................................................................. .................. 39 4.1.2.1 SO 2 BACT for the Diesel Engines and Boilers ................................................................................. 41 4.1.2.2 SO 2 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 CO 2 BACT Analysis................................................................................................................. .................. 53 4.2 NSPS........................................................................................................................... .................................. 53 4.3 NESHAPs........................................................................................................................ .............................. 53

4.3.1 Compression Ignition (CI) Reciprocating Internal Combustion Engines (RICE) ....................................... 54AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc iii 

# 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 ................................................................ 6 3 5.7 PSD Modeling Assessment Phases – Prelimi nary 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...................................................................... 8 2 7.4 Worst-Case Screening Impacts at N earest 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 Un its 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: NO x Emissions and Impacts at Three Loads .......................................................................................... ...... 22
Table 2-8: PM 10

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 NO x Control Technologies.......................................................................................................... ... 31 Table 4-3: EPA Tier 1-3 Nonroad Diesel Engine NO x Emission Standards................................................................... 34AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc iv 

# CONTENTS - Continued Page

Table 4-4: Available SO 2 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 PM 10

Concentrations at Badami.................................................................................................... 76
Table 6-2: Baseline Concentrations............................................................................................ ................................... 77 Table 7-1: Summary of Screening Maximum Estimated S hort-Term and Annual Concentrations all Sources Combined

............................................................................................................................... ....................................... 78 Table 7-2: Impact Scenarios Used to Define Screening Ma ximum 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 Concentra tions at North Slope Monitoring Stations......................................... 89
Table 8-2: Point Source Emissions of NO x 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 ship s locations for breaking of one-year ice................................... 16 Figure 5-1: Source and Receptor Locat ions 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 NO 2 Concentrations for North Slope Stations.................................................................. 74 Figure 6-3: Average Maximum 3-Hour SO 2 Concentrations for North Slope Stations................................................... 75 Figure 6-4: Average Maximum 24-Hour SO 2 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 ...................................................................... ..................... 90AirSci\Disco Major Chukchi Perm it 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 LetterAirSci\Disco Major Chukchi Perm it 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 th e 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 surroundi ng 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 Perm it Application Revised-R15.doc vii 

## Abbreviations/Acronyms

AAC.......................... Alaska Admini strative 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 Prof ile Input Program CAA.......................... Clean Air Act CDPF ........................ Catalytic diesel particulate filter CEM.......................... Continuous em issions monitor CFR........................... Code of Federal Regulations CI .............................. Compre ssion ignition CISWI....................... Commercial an d 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 ga s recirculation Em............................. Emergency EPA........................... United States Environmental Protection Agency ESP............................ Electrostati c precipitators FGR........................... Flue gas recirculation GCP .......................... Good combustion practices GMP ......................... Good mainte nance practices HIP ........................... High injection pressure HPU.......................... Hydraulic power unit I.C. ............................ Internal combustion ITR ............................ Ignition timing retard LAER........................ Lowest achievable emission rate LNB .......................... Low NO x burner LND.......................... Low NO x 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 Indust ry 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 Reques ted Restriction OSR........................... Oil Spill Response OxyCat ..................... Oxidation catalystAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc viii PCV .......................... Positive crankcase ventilation PSD........................... Prevention of si gnificant deterioration RACT........................ Reasonably available control technology RBLC ........................ RACT/BACT/LA ER Clearinghouse RICE ......................... Reciprocating intern al 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 pe r million tph............................. tons per hour tpy............................. tons per year



## Pollutants

CO............................. Carbon Monoxide
H 2 S............................ Hydrogen Sulfide HAPs ........................ Hazardous Air Pollutants HC ............................ Hydrocarbons NMHC ..................... Non Methane Hydocarbons NO X .......................... Oxides of Nitrogen NO 2 ........................... Nitrogen Dioxide PM 10 .......................... Particulate Matter with an aerodyna mic diameter less than 10 microns PM 2.5 ......................... Particulate Matter with an aerodyna mic diameter less than 2.5 microns SO 2 ............................ Sulfur Dioxide SO 3 ............................ Sulfur Trioxide VOC.......................... Volatile Organic CompoundsAirSci\Disco Major Chukchi Perm it 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 Shel f (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 addresse s 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 In c.’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 mont hs), 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 mo re than 84 drilling days. It is likely that the environmental conditions (ice) will limit the drillin g season to less than th ese 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 Gu lf 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.doc2Figure 1-1: Shell Gulf of Mexico Inc. Current Leases in the Chukchi SeaAirSci\Disco Major Chukchi Perm it 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 cr itical 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 so urce 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 th e fleet’s capability to manage ice or conduct operations. Anchors are run and set by the anch or 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 excavate d 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 ri g 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 form ation 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 gene rally must be in positi on and be prepared to deploy in the unlikely event of an oil spill. Ad ditional intervals are drilled, cased, and cemented as required to reach and evaluate the geologic objective.

Upon completion of the evalua tion operations, the well is pr operly 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 Perm it Application Revised-R15.doc 4 After the well is abandoned the SSBOP’s are retrie ved. The anchors can then be retrieved and the rig can depart the drill site. The rig can move fr om 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 dril l 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 coul d operate simultaneously. Shell requests several Owner Requested Restrictions (ORR s) 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 fu el heat consumption. Then these capacity consumption values are co nverted to emissions using manufacturer or generic (when model-specific factor s 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 efficien cies, 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 ge neric emission factor si nce no manufacturer’s
emission factors are availa ble 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 lo ad levels throughout the drilling process. There are six emission units that comprise the capacity to routinely generate electrical power, with theAirSci\Disco Major Chukchi Perm it 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 perc ent of the six-engine design capacity as an ORR
shown on Table 2-3.

The generators will be retrofitted with selective catalytic reduction and ox idation catalyst control
devices with control efficiencies as shown in Tabl e 2-4. These controls are to be retrofitted by D.E.C. Marine AB, a Swedish company who has installed more NO x ship emission control systems than any other company in the world. 1 The D.E.C. Marine AB control guarantees for

NO x , CO, and VOCs are provided on Table 2-4. Co ntrol 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 oxid ation catalyst, D.E.C. Mari ne 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 NO x emissions from the main driver engines (Caterpi llar D399s). The SCR technology involves the injection of urea into the exhaust stream with a catalyst to convert the NO x to nitrogen and water. Ideally, the urea will reduce NO x at a 1-to-1 ratio. However, because mixing within the stack is not ideal, a small portion passes through the syst em 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 NO x 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 Perm it Application Revised-R15.doc 6 The D.E.C. Marine AB system controls the a mmonia slip through routine measurement of the

NO x 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 SO 2 to SO 3 conversion (typically on the order of one percent), the presence of SO 3 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. Ma rine AB believes that the ammonia exhaust emissions will be much less than 10 ppm and close to zero. 4 Thus, there is nearly no SO 3 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 NO x, which is 0.03 percent of total Discoverer annual NO x emissions. Since these emissions are small they are grouped with the generator emis sions 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 an chor, so it will have no emissions during the time the drillship is a stationary source.



## 2.5 MLC Air Compressors (FD-9, 10, a nd 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 OR Rs of the equivalent of 48 days operation at capacity per season per group fo r 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 Perm it Application Revised-R15.doc 7 Tier 3 engines with no add-on emission contro ls, 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 cran e. 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 consumpt ion for the purpose of limiting the long-term (seasonal) impacts. The crane engines have CD PFs for control of orga nic 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 co nnections, 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 consum ption. The cementing units are equipped with CDPFs for control of volatile organics, carb on monoxide, and organic particulate matter.



## 2.8 Logging Units (FD-19 and 20)

The two logging units are used to gather inform ation from each well when the drill stem is removed, and will operate only when the cementin g units are not used and the prime movers are operating at a low load. The logging units oper ate 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 th e cementing units and operate no more than the equivalent of capacity for 30 pe rcent 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, ca rbon monoxide, and organic particulate matter.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc8Table 2-1: Discoverer and Associated Vessels Emission Units with Maximum Hourly Emissions That Could Occur SimultaneouslyMaximum EmissionsMaximum Fuel Consumption(lb/hr)1Rating (MMBtu/hr)1PM10PM2.5NOxSO2CO VOC LeadFrontier DiscovererFD-1 Generator Engine 1,325 hp 7.70.22 0.22 0.87 1.23E-02 0.31 0.04 2.24E-04FD-2 Generator Engine 1,325 hp 7.70.22 0.22 0.87 1.23E-02 0.31 0.04 2.24E-04FD-3 Generator Engine 1,325 hp 7.70.22 0.22 0.87 1.23E-02 0.31 0.04 2.24E-04FD-4 Generator Engine 1,325 hp 7.70.22 0.22 0.87 1.23E-02 0.31 0.04 2.24E-04FD-5 Generator Engine 1,325 hp 7.70.22 0.22 0.87 1.23E-02 0.31 0.04 2.24E-04FD-6 Generator Engine 1,325 hp 7.70.22 0.22 0.87 1.23E-02 0.31 0.04 2.24E-04FD-7 Propulsion Engine 7,200 hp 0.0 0.00 0.00 0.00 0.00E+00 0.00 0.00 0.00E+00FD-8 Em. Generator 131 hp 0.3 0.09 0.09 1.35 4.88E-04 0.29 0.10 8.86E-06FD-9 MLC Compressor 540 hp 3.8 0.18 0.18 3.55 6.03E-03 3.11 1.20 1.10E-04FD-10 MLC Compressor 540 hp 3.8 0.18 0.18 3.55 6.03E-03 3.11 1.20 1.10E-04FD-11 MLC Compressor 540 hp 0.0 0.00 0.00 0.00 0.00E+000.00 0.00 0.00E+00FD-12 HPU Engine 250 hp 1.8 0.100.10 5.41 2.79E-03 0.33 0.11 5.08E-05FD-13 HPU Engine 250 hp 1.8 0.100.10 5.41 2.79E-03 0.33 0.11 5.08E-05FD-14 Port Deck Crane 365 hp 2.60.12 0.12 11.27 4.08E-03 0.49 0.16 7.41E-05FD-15 Starbd Deck Crane 365 hp 2.60.12 0.12 11.27 4.08E-03 0.49 0.16 7.41E-05FD-16 Cementing Unit 335 hp 2.3 0.14 0.14 7.25 3.74E-03 0.44 0.15 6.80E-05FD-17 Cementing Unit 335 hp 2.3 0.14 0.14 7.25 3.74E-03 0.44 0.15 6.80E-05FD-18 Cementing Unit 147 hp 1.0 0.06 0.06 3.18 1.64E-03 0.19 0.07 2.98E-05FD-19 Logging Winch2128 hp 0.0 0.00 0.00 0.000.00E+00 0.00 0.00 0.00E+00FD-20 Logging Winch236 kW 0.0 0.00 0.00 0.000.00E+00 0.00 0.00 0.00E+00FD-21 Heat Boiler 7.97 MMBtu/hr 8.00.19 0.19 1.60 1.27E-02 0.62 0.01 5.39E-10FD-22 Heat Boiler 7.97 MMBtu/hr 8.00.19 0.19 1.60 1.27E-02 0.62 0.01 5.39E-10FD-23 Incinerator 276 lb/hr0.97 0.97 0.41 3.45E-01 0.14Total while drilling 84.43.91 3.91 68.33 0.4812.46 3.69 1.98E-03Associated FleetsMaximum EmissionsMaximum Fuel Consumption(lb/hr)1(MMBtu/hr)1PM10PM2.5NOxSO2CO VOC LeadIce Management Fleet - GenericDiesel Engines 321.7 32.17 32.17 1,029.51 65.00 273.46 26.35 9.33E-03Incinerators2-154lb/hr1.08 1.08 0.46 0.39 0.15Total Ice Management Fleet321.7 33.25 33.25 1,029.97 65.38 273.62 26.35 9.33E-03Resupply Vessel - Generic2.0 0.63 0.63 9.01 0.41 1.94 0.65 5.93E-05OSR Fleet17.5 5.42 5.42 61.96 3.53 16.60 5.57 5.07E-04Total All Fleet341.2 39.30 39.30 1,100.95 69.32 292.16 32.56 9.90E-03Total All425.6 43.21 43.21 1,169.27 69.80 304.62 36.25 1.19E-021All emissions are shown as the maximum 1-hour value.2Logging winches cannot operate simultaneously with cementing units.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc9Table 2-2: Discoverer and Associated Vessels Emission Units with Annual EmissionsMaximum EmissionsMaximum Fuel Consumption(ton/yr)Rating (MMBtu/yr)PM10PM2.5NOxSO2CO VOC Lead HAPsFrontier DiscovererFD-1 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63 0.08 4.51E-04 0.02FD-2 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63 0.08 4.51E-04 0.02FD-3 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63 0.08 4.51E-04 0.02FD-4 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63 0.08 4.51E-04 0.02FD-5 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63 0.08 4.51E-04 0.02FD-6 Generator Engine 1,325 hp 31,082 0.45 0.45 1.76 2.48E-02 0.63 0.08 4.51E-04 0.02FD-7 Propulsion Engine 7,200 hp 0 0.00 0.00 0.00 0.00E+00 0.00 0.00 0.00E+00 0.00FD-8 Em Generator 131 hp 7 0.00 0.00 0.02 5.85E-06 0.00 0.00 1.06E-07 0.00FD-9 MLC Compressor 540 hp 4,355 0.100.10 2.05 3.47E-03 1.79 0.69 6.31E-05 0.01FD-10 MLC Compressor 540 hp 4,355 0.100.10 2.05 3.47E-03 1.79 0.69 6.31E-05 0.01FD-11 MLC Compressor 540 hp 0 0.00 0.00 0.00 0.00E+00 0.000.00 0.00E+00 0.00FD-12 HPU Engine 250 hp 2,016 0.06 0.06 3.11 1.61E-03 0.19 0.06 2.92E-05 0.00FD-13 HPU Engine 250 hp 2,016 0.06 0.06 3.11 1.61E-03 0.19 0.06 2.92E-05 0.00FD-14 Port Deck Crane 365 hp 3,915 0.09 0.09 8.63 3.12E-03 0.37 0.12 5.68E-05 0.00FD-15 Starbd Deck Crane 365 hp 3,915 0.09 0.09 8.63 3.12E-03 0.37 0.12 5.68E-05 0.00FD-16 Cementing Unit 335 hp 2,837 0.080.08 4.38 2.26E-03 0.27 0.09 4.11E-05 0.00FD-17 Cementing Unit 335 hp 2,837 0.080.08 4.38 2.26E-03 0.27 0.09 4.11E-05 0.00FD-18 Cementing Unit 147 hp 1,245 0.040.04 1.92 9.93E-04 0.12 0.04 1.80E-05 0.00FD-19 Logging Winch1128 hp 0 0.00 0.00 0.00 0.00E+00 0.00 0.00 0.00E+00 0.00FD-20 Logging Winch136 kW 0 0.00 0.00 0.00 0.00E+00 0.00 0.00 0.00E+00 0.00FD-21 Heat Boiler 7.97 MMBtu/hr 32,135 0.38 0.38 3.23 2.56E-02 1.24 0.02 1.09E-09 0.00FD-22 Heat Boiler 7.97 MMBtu/hr 32,135 0.38 0.38 3.23 2.56E-02 1.24 0.02 1.09E-09 0.00FD-23 Incinerator 276 lb/hr1.95 1.95 0.83 6.96E-01 0.28Total while drilling 278,255 6.10 6.10 56.14 0.92 11.892.53 3.10E-03 0.15Associated FleetsMaximum EmissionsMaximum Fuel Consumption(ton/yr)(MMBtu/yr)Fuel Usegal/yrPM10PM2.5NOxSO2CO VOC Lead HAPsIce Management Fleet - GenericDiesel Engines 492,928 3,703,499 25 25 789 50 209 20 7.15E-03 0.96Incinerators 0.21 0.21 0.09 0.07 0.03Total Ice Management Fleet492,928 3,703,499 25 25 789 50 210 20 7.15E-03 0.96Resupply Vessel - Generic196.22 1474 0.03 0.03 0.43 0.020.09 0.03 2.85E-06 0.00OSR Fleet23,483 176,435 4 4 42 2 11 4 3.41E-04 0.05Total All Fleet516,608 3,881,408 29 29 831 52 221 24 7.49E-03 1.01Total All794,863 5,972,012 35 35 887 53 233 26 1.06E-02 1.161Logging winch emissions are included with cementing units.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc10Table 2-3: Proposed Owner-Requested RestrictionsCompliance Condition Restriction How Calculated How DocumentedOperational RestrictionsSeason maximum drillingduration168days/season 168 days/season x 24 hr/day = 4,032hrs First anchoring attached to lastanchor removed, by clock.Drill site maximumdrilling duration84days/hole 84 days/season x 24 hr/day = 2,016hrs First anchoring attached to lastanchor removed, by clock.Minimum distancebetween drill sites perdrilling season1,000metersSite center to site center, GPS.MLC compressorsmaximum use per drillingseason48days/season 48 day/season x 24 hr/day x 2engines x 540 hp/engine x 0.007MMBtu/hp-hr x 7.5 gal/MMBtu=65,434gal/seasonDemonstrated using fuelconsumption – dipstick on thecombined MLC compressorconsumption at day fuel tank.HPUs maximum use perseason48days/season 48 day/season x 24 hr/day x 2engines x 250 hp/engine x 0.007MMBtu/hp-hr x 7.5 gal/MMBtu=30,293gal/seasonDemonstrated using fuelconsumption – dipstick on thecombined HPU consumptionat day fuel tank.Generator combinedproduction maximum80%80%x 6 engines x 1325 hp xkW/1.340hp=4,746kW Demonstrated by power meter– combined.Cementing & Loggingunits combined maximum30%(of cementing) 30% x (335 hp x 2 engines +147hp)x 0.007 MMBtu/hp-hr x 24 hr/dayx 7.5 gal/MMBtu =309gal/dayDemonstrated using fuelconsumption – dipstick on thecombined cementing/loggingconsumption at day fuel tank.Crane units combinedmaximum58,824gal/season Max Fuel ConsumptionDemonstrated using fuelconsumption – dipstick on thecombined crane consumptionat day fuel tank.Sulfur content on allstationary source engineson drilling vessel0.0015%by weightSupplier documentation.Sulfur content on all shipsexcept theDiscoverer0.19%by weightSupplier documentation.Ice management fleet fuelrestriction while < 25 milesfrom drill site3,703,499gal/season Fuel Consumption Demonstrated using fuelpurchase records.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc11Table 2-4: Proposed BACT Control Device EffectivenessCompliance Condition Restriction Comments ReferenceControl Device EffectivenessGenerator SCR NOxcontroleffectiveness0.5g/kW-hr 50-100% of capacity CEM D.E.C. Marine AB letter, October 9, 2008, initial stacktest and CEM.Generator Oxidation Catalyst COreduction efficiency80%D.E.C. Marine AB letter, October 9, 2008, and initialstack test.Generator Oxidation CatalystVOC, HAPs, Formaldehydereduction efficiency70%D.E.C. Marine AB letter, October 9, 2008.Generator Oxidation CatalystPM10reduction efficiency50%D.E.C. Marine AB email, February 9, 2009.Small engines (other than Tier 3engines) Catalytic DieselParticulate Filter (CDPF) CO,VOC, HAPs, Formaldehydereduction efficiency80%CleanAIR Systems PERMITTMFilter Manual. (Manualclaims 85%).Small engines CDPF PM10reduction efficiency85%California Air Resource Board, Currently Verified,January 2009, CleanAIR Systems PERMITTM.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc12Figure 2-1: Photograph of the DiscovererAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 13 Figure 2-2: Layout of Emission Units on the DiscovererAirSci\Disco Major Chukchi Perm it 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 th e second as a backup although there could be times when both would operate. For impa ct 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 no t 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 (m 3 )

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 Perm it Application Revised-R15.doc 15 Discoverer would need to disconnect from its anchors an d move off site. The 2003 – 2005 statistics on ice at the Sivulliq drill site in the Beaufort Se a show 15 percent frequency of ice at the drill site that would need to be fragmented and a 23 percen t 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 conser vative estimate of the possible need for ice management, the sum of these two or 38 percent fr equency 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 thic ker (up to 2-meter thick) ice, a rapidly (7 kts 8 ) 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 th e 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 an d the ice management fleet would be moving at near full speed to fragment this ice. This is cons idered the case of highest emissions and impacts.

7 Craik, Keith, Arctic Wells Advisor, Shell International Exploration and Production Inc. [Communication with R. Steen, Air Sci ences Inc.]. January 19, 2009. 8 Craik, Keith, Arctic Wells Advisor, Shell International Exploration and Production Inc. [Communication with R. Steen, Air Sci ences Inc.]. January 13, 2009. 9 Craik, Keith, Arctic Wells Advisor, Shell International Exploration and Production Inc. [Communication with R. Steen, Air Sci ences Inc.]. February 10, 2009. 10

Ibid. footnote 8.AirSci\Disco Major Chukchi Perm it 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 speed 11 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 anch or 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 ic e management ships are calculated at maximum use of the emission units, which is 80 perc ent 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 Perm it 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 ex pected 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 co nsist of more or less than two ships depending on availability of ships and ice conditions. Ther e 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

NO x emission limit (converted to a fuel limit as listed in Table 2-4). NO x is selected because the restriction is developed to limit NO x impacts from the ice management and anchor handling fleet. The propulsion engine exhaust stacks of the eigh t 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 NO x 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

NO x 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 pu rposes of the impact evaluation herein, their daily energy consumption (MMBtu /hr) is estimated from maximu m 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 percen t of the 168 days of the maximum season. The
limits are to be tracked in the form of a combin ed 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 Perm it 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 a pproximately 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 pr ecision 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 ar e 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 co nsist 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 unpla nned 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. [Communicati on with R. Steen, Air Sciences Inc.]. February 12, 2009.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 19 There will be two other vessels associated with th e 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 da ily 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 take n from the Kulluk permit which represent the highest emission factors for the source catego ry. 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 firs t 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 on e 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 voluntaril y use diesel fuel with sulfur content of 0.19 percent or less to limit SO 2 emissions from the fleet, and, as BACT, the Discovererwill use ultralow sulfur (15 ppm) fuel to minimize the SO 2 emissions from the Discoverer . These are ORRs. Currently the ultra-low sulfur fuel is not availabl e on the North Slope and, if needed now, would be barged from the northwest, from north throug h Canada, or purchased in the Far East. These fuel qualities are incorporated in the emission an d 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 use 15

, 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 Perm it 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 existi ng communications center networks. 17



## 2.17 Emissions for Purposes of Modeling

For purposes of dispersion modeling, the short-term PM and NO x 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 SO 2 emissions on Page 2 used in the model are maximum 1-hour values (carried over with no mo dification 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 cont ain 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 us ed 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 o ccur 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 Perm it Application Revised-R15.doc 21 

## 2.18 Emissions and Impacts as a Function of Load

For purposes of estimating emissions and demo nstrating that the maximum impacts are due to diesel engines running at maximu m, which is 100 percent of capacity for all engines except the propulsion engines and 80 percent for the propulsi on engines, the impacts of five of the larger diesel engines are modeled at three loads. Alth ough these engines do not cause the largest local impacts, they are representative of differen t models of diesels and therefore should be representative of the smaller engines also. Thes e 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 referenc es. 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 an d 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, flar es, well testing, fuel tanks, etc. 18

18

EPA Comments, Attachment B, II.B.4.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 22 Table 2-7: NO x Emissions and Impacts at Three Loads

Load (% of capacity) Engine NO x emissions (g/s normalized) NO x impact (ug/m 3 ) 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: PM 10 Emissions and Impacts at Three Loads

Load (% of capacity) Engine PM 10 emissions (g/s normalized) PM 10 impact (ug/m 3 )

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 ga s, 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 vapo rs 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 inve ntory 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 co ntrol 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 emerge ncy deployment of the ship’s Subsea Blowout Preventer (SSBOP). Table 2-1 provides hourly em issions estimates for drilling activities by the

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

19

Craik, Keith, Shell. [Communication with R. Steen, Air Sciences Inc]. February 4, 2009.AirSci\Disco Major Chukchi Perm it 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 Tabl e 2-1 because it already incorporates the hourly emission rates during relief well drilling, in the ex ceedingly unlikely event that such drilling ever

occurs.

Table 2-2 provides the estima ted 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 allowabl e 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 emission s are not considered to be a normal operating condition. They generally should not be considered in determining allowable emissions.

Emissions from emergency drilling operations, ev en 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 oper ating conditions under the permit is the best and most accurate approach to conservatively and realistically estimati ng 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 av oiding 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 Perm it 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 Agen cy’s policy on “excess emissions” that result from, inter alia, malfunctions. See “State Im plementation Plans: Policy Regarding Excess Emissions During Malfunctions, Startup, an d Shutdown,” Steven A. Herman, Assistant Administrator for Enforcement and Comp liance (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 t hese 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 iss ued under federal regulations.AirSci\Disco Major Chukchi Perm it 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 so urce”). 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 remova l 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 wi thin 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 NO x emissions). As depicted in the last row of Table 2-2, the Discoverer and fleets totals for particulate matter (PM 10 and PM 2.5 ), nitrogen oxides (NO x ), sulfur dioxide (SO 2 ), 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 appr oximate 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 addresse d outside of (d) because they are embeddedAirSci\Disco Major Chukchi Perm it 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 sign ificant 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 ar ea. 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 cont rol 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 propos ed operating restrict ions in Table 2-3.AirSci\Disco Major Chukchi Perm it 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 (NO x ) 40 56.14 887 Particulate Matter (PM 2.5 ) 10 6.10 35 Particulate Matter (PM 10 ) 15 6.10 35 Sulfur Dioxide (SO 2 ) 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 NO x , PM 2.5 , PM 10 , SO 2 , 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-m ile 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), provid es 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 requir ement, 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 dril ling assumed to occur on that least for the entire season (Section 7.4).AirSci\Disco Major Chukchi Perm it 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 NO x , PM 10 , SO 2 , 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 ma ximum 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, environm ental, and economic impact s and other costs” [40 CFR 52.21(b)(12)].

In a 1987 memorandum, EPA provided guid ance 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 Perm it 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 smal l 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 PM 10 NO x SO 2 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 substa ntially 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.” Fo r example, all of the emission units on the Discoverer
, except for the MLC compressors, are existing unit s, 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 no t 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 vess el 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 NO x and 60 lb PM 10 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 isAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 30 inconceivable that implementation of ad ditional 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 ha ndling vessel. Even with the possible drilling of four wells (eight anchor handling events), annual emissions will be small. It is inconceivable that implementa tion 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 NO x 

### BACT Analyses

Step 1 – Available Control Technologies
There are two sources of nitrogen that when oxidized result in NO x emissions – nitrogen in the fuel and nitrogen in the combustion air. Oxidat ion fixation of atmospheric nitrogen is known as
thermal NO x . The production of thermal NO x is a function of combustion flame temperature.

The available NO x 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 NO x is reduced by lowering the peak combustion temperature. Post-combustion exhaust treatment relies on the removal of NO x from the exhaust stream through adsorption or reduction.

Available NO x 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 Perm it Application Revised-R15.doc 31 Table 4-2: Available NO x Control Technologies

Source Category Clearinghouse Search Conditions Control Technologies Diesel IC Engines (>500 hp) RBLC Proc ess Code = 17.110 None, AC, HIP, ITR, LND, SCR, TIER 2/3, WICA-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, LNDCA-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 NO x Burners
LND Low NO x 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 liste d or good combustion practices

Diesel-fueled Reciprocating Engines

The available NO x 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 NO x design (LND), Tier 2 or 3 level controls, water injection (WI), and good combustion practices. The RBLC and CA-BACT also listed le an burn, air-to-fuel ratio control, turbocharger, clean fuel, and preventative ma intenance as part of the NO x control description. TheseAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 32 technologies or work practices are not specific to NO x reduction and, therefore, are not discussed
further. 22

ITR reduces NO x emissions in reciprocating engines by delaying the injection of fuel in the engine
from when the chamber is at its smallest to a ti me when the compression chamber is expanding. The larger volume in the compression chamber lowers peak combustion temperature, thus reducing thermal NO x 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 combin ation of ITR and AC may reduce NO x 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 NO x at the expense of incomplete combustion, resulting in the formation of PM, VOC, an d 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 NO x 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 NO x by one percent requires one percent of water in the water-fuel system. 27 In other words, achieving a 50 percent NO x 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 envi ronments (such as the Arctic Ocean) are also problematic for WI systems due to the potential for freezing.

The RBLC also lists low NO x design (LND) for several engines, but does not describe the actual

NO x combustion control technology. It is assume d 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 NO x control. Clean fuels with low nitrogen contents do reduce NO x produced from fuel-bound nitrogen. However, the amount of NO x produced from the fuel-bound nitrogen in distillate fuel oil constitutes only a small fraction of the total NO x . Lean burn, air-tofuel ratio control, and preventative maintenance are more related to engine performance than NO x control. 23

Khair, Magdi K. DieselNet Technology Guide. Engine Design for NO x 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 Perm it 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 NO x 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 cham bers via the inlet system in order to reduce
thermal NO x formation. In general, the most important factor contributing to the NO x reduction effect of EGR is the decrease in the peak combus tion temperature caused by the heat adsorption and oxygen reduction effects of the re turned inert exhaust gas. The NO x emission benefit of EGR comes at a cost: increased PM, HC, and CO emis sions, a fuel economy penalty, and potential engine wear and durability issues. 29 EGR demonstration tests have shown NO x 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 NO x 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 NO x 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 NO x 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. M ississippi Department of Environmental Quality. [Communication with D. Steen, Air Sciences Inc.]. February 9, 2009. 34

Ibid. footnote 26.AirSci\Disco Major Chukchi Perm it 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 NO x emission standards for larger generators are provided in
Table 4-3.

Table 4-3: EPA Tier 1-3 Nonroad Diesel Engine NO x Emission Standards

NMHC+NO x NO x 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 NO x 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 NO x by reducing the peak combustion temperature relative to conventional burners. LNB designs are sp ecific to the manufacturer. FGR reduces NO x emissions by recirculating a portion of the boiler flue gas into the main combustion chamber. This process reduces the peak combustion temper ature and lowers the percentage of oxygen in the combustion air/flue gas mixture, th us retarding the formation of thermal NO x .

Waste Incinerator

The available NO x 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 NO x formed in the combustion process. The resulting products of the chemical reaction are elemental nitrogen, carbon dioxide, and water.



### 4.1.1.1 NO x 

### 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 Caterp illar D399 Marine Generator Set) are ITR, AC,AirSci\Disco Major Chukchi Perm it 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 te chnically 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 feas ible for this generator model. SCR is also considered technically feasible because the en gines are stationary on the vessel deck.

Step 3 – Control Effectiveness Ranking
The technically feasible control technologies fo r Generators FD-1 through FD-6 are ranked by
control effectivene ss 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 SC R, the most effective NO x 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 th is is the highest efficiency control available for
the Discoverer’s diesel-fired generators 35

.



### 4.1.1.2 NO x 

### 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 Perm it 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 thes e generators will operated, the potential engine retrofit incompatibility, the excessive pure wate r 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 th is 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 configurat ion. Because the SCR units have a footprint approximately double that of the cementing en gines, 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 technicall y 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 effectivene ss 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 NO x at the expense of incomplete combustion; this increases PM, VOC, and CO emissions, reduce d fuel economy, and contaminates the lube oil
with soot. 24 Furthermore, as discussed below, En gines FD-12 through FD-20 will be equipped
with CDPF controls to reduce PM and CO emissi ons. CDPF requires a degree of combustionAirSci\Disco Major Chukchi Perm it 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, neithe r 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 NO x 

### 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 tu ned to meet Tier 3, they are incompatible with incorporating combustion control technologies su ch 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 incompatib ility, the excessive pure water requirements and limited available ship space for storing the wa ter, 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 dies el engines. This implies that SCR is not BACT for the portable engines due to technical infeas ibility 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 effectivene ss as follows:

36

Caterpillar brochure. Cat® C15 for Fleet and Line Haul Performance, ACERTTM Technology for 2007

.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 38 1. Tier 3 Emission Standards of 4.0 g/kWh of NMHC+NO x 2. Tier 2 Emission Standards of 6.4 g/kWh of NMHC+NO x 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+NO x as BACT for
Discoverer’s diesel-fired compressors.



### 4.1.1.4 NO x 

### 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 co nsidered 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 bo iler 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 purc hased without FGR, as in the case of the Discoverer’s
boilers. 38

There are no determinations for installing SCR on diesel boilers unde r 100 MMBtu/hr. This implies that SCR is not BACT for this diesel boil er category due to technical infeasibility and/or due to energy, environmental, and/or economic im pacts. This control technology has never been required (or installed to Shell’s knowledge) on ut ility boilers of this small size on exploration vessels. More importantly, the boilers are locate d 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 NO x 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 Perm it 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 NO x 

### 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 th e equipment according to the manufacturer’s
recommendations to maximize fuel ef ficiency and minimize emissions.



### 4.1.2 SO 2 

### BACT Analysis

Step 1 – Available Control Technologies

The combustion of fuels cont aining sulfur produces SO 2 emissions. The available SO 2 control technologies for the Discoverer’s engines, boilers, and incinerato r 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 Perm it Application Revised-R15.doc 40 following two categories: combustion of lo w-sulfur fuels and post-combustion exhaust
treatment. Post-combustion exhaust treatment relies on the removal of SO 2 from the exhaust stream through adsorption.

The available SO 2 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 Perm it Application Revised-R15.doc 41 Table 4-4: Available SO 2 Control Technologies

Source Category Clearinghouse Search Conditions Control Technologies Diesel IC Engines (>500 hp) RBLC Process Code = 17.110 None, LSFCA-BACT I.C. Engines - CI, NonEmergency (>500 hp) None, LSF

Diesel IC Engines ( ≤ 500 hp) RBLC Process Code = 17.210 None, LSFCA-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 SO 2 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, SO 2 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, pa rticles of an alkaline sorbent are injected into a flue gas and SO 2 is adsorbed producing a solid by-product.



### 4.1.2.1 SO 2 

### 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 Perm it Application Revised-R15.doc 42 Shell notes that wet scrubbers were not identifi ed 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 SO 2 emissions from large boilers th at combust low-sulfur fuels. However, that approach would not be te chnically 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 ma terial that forms from scrubbing SO 2 . 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 we t 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 propos ed 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 SO 2 

### 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 communicatio n with TeamTec, the manufacturer, they are not aware of any control technologies that have been installed on this model of incinerator for controlAirSci\Disco Major Chukchi Perm it 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 propos ed as BACT and additional analyses are not
warranted.

Step 5 – Selection of BACT

To minimize SO 2 production from the diesel used to heat the furnace, Shell proposes the exclusive use of ultra-low sulfur diesel, which is th e 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 PM 10 and PM 2.5

. Step 1 – Available Control Technologies
Diesel PM is a complex mixture of compounds wh ich 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 fr om “too-rich-to-burn” fuel combus tion. 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 Perm it 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 2/3CA-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, PCVCA-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 liste d 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 OxyC at 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 Perm it 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 engi ne 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 atmosp here. 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 applicab le NSPS emission rate, if any NSPS standard for that pollutant is applicable to the source. As discussed above in the NO x 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 Perm it 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 incinera tors identified in the RBLC and CA-BACT, and show in Table 4-5, are electrostatic precipitator s (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 effectivene ss 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 Perm it 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 em ission 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 D 343; 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 Perm it 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 th e equipment according to the manufacturer’s
recommendations to maximize fuel ef ficiency 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 th e equipment according to the manufacturer’s
recommendations to maximize fuel ef ficiency 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 Perm it 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 Proc ess Code = 17.110 None, OxyCat, Tier 2/3CA-BACT I.C. Engines - CI, NonEmergency (>500 hp) None, OxyCat

Diesel IC Engines ( ≤ 500 hp) RBLC Process Code = 17.210 NoneCA-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 liste d 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 percent 51 ). 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 applicab le NSPS emission rate, if any NSPS standard for that pollutant is applicable to the source. As discussed above in the NO x and PM BACT analyses,

50

Ibid. footnote 1. 51 CleanAIR Systems, Inc. PERMIT TM

Filter CleanAIR Catalyzed Diesel Particulate Filters Installation and Maintenance Manual

. 2006. 52

Ibid. footnote 51.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 50 EPA promulgated exhaust emission standards for no n-road engines under 40 CFR 89.112 in 1998. The CO emission standards for larger ge nerators 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 practice s 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 effectivene ss as follows:AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 51 1. CDPF – 80 percent control (t echnically 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 tech nically 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 ofCDPF 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 em ission 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 D 343; 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) – CDPFAirSci\Disco Major Chukchi Perm it 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 th e equipment according to the manufacturer’s
recommendations to maximize fuel ef ficiency 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 th e equipment according to the manufacturer’s
recommendations to maximize fuel ef ficiency and minimize emissions.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 53 

### 4.1.5 CO 2 

### BACT Analysis
Shell recognizes that the EPA is considering whether and how to regulate CO 2 under the Clean Air Act and that the agency may establish by ru le or policy a requirement that major sources perform a BACT analysis for CO 2 emissions. At this time, Shel l believes it is premature to address projected CO 2 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 ther efore 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 Wast e (MSW) incinerator, it will be exempt from most of the CCCC requirements. An exemption request is attach ed 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 cement ing 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 Pollutan ts – General Provisions – Definitions).AirSci\Disco Major Chukchi Perm it 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 Emi ssion Standards for Haza rdous 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 requ irements 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, bu t 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 Emi ssion Standards for Haza rdous 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 Perm it 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 proced ures. 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 (S ubpart 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 here in with EPA screening meteorology and EPArecommended worst persistence factors for conv erting one-hour maximum concentrations to other averaging periods.

Compliance is demonstrated at and beyond a 900-m eter 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 a ccount 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 Di scoverer 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 ( μ g/m 3 ) PSD Class II
Increment

( μ g/m 3 ) Nitrogen Dioxide (NO 2 ) Annual 100 25
24-hour 35 NA Particulate Matter (PM 2.5 )
Annual 15 NA
24-hour 150 30 Particulate Matter (PM 10 )
Annual 50 17 3-hour 1,300 512
24-hour 365 91 Sulfur Dioxide (SO 2 )

Annual 80 20 1-hour 40,000 NA Carbon Monoxide (CO)
8-hour 10,000 NA

1 National Ambient Air Quality Standards NA not applicableAirSci\Disco Major Chukchi Perm it 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 meteor ological 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 me teorological 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 he ights 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 he ight. 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 mete rs to represent unlimited mixing.AirSci\Disco Major Chukchi Perm it 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 1 992) 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 conv erted 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 th e 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 characteri stics 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 th e 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?ak0546AirSci\Disco Major Chukchi Perm it 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 an d 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 Pr ofile 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 consider ed 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 hand ler/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 ma naging oil response ship, the Nanuq, and three small (34-foot) craft that dock on the Nanuq. Ty pically, 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 distan ce 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 Perm it 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 ch aracterization 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 so urces) 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 sour ce 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 Emissi on Heights for Volume Sources

According to Section 1.2 in the User’s Guide for the Industrial Source Co mplex (ISC3) Dispersion Models, Volume II - Description of Model Algo rithms (EPA-454/95-003b, September 1995), the effective emissions height for elevated volume so urces needs to be assigned. The plume heights for the fleet emissions are estimated using SCREEN 3 (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 an d 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 ic e management fleet emissi ons (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 Perm it Application Revised-R15.doc 60 The following procedure was utilized to model horizontally emitting stacks:

• Set the actual stack velocity (V actual ), in meters per second, to an adjusted stack exit velocity (V adjusted ) of 0.001 meter per second.

• To conserve volumetric flow, determ ine an adjusted stack diameter (D adjusted ) by adjusting the actual stack inside diameter (D actual ), in meters, to account for buoyancy of the plume by using the following equation:

• D adjusted = 31.6(D actual )(V actual ) 0.5

Use the adjusted parameters, V adjusted and D adjusted , 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 concentratio ns 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 he ight 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 lo cated much further away than 1,000 meters from
the Discoverer and much higher plume rise values woul d 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 wors t-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 Perm it 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 48.03AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 62 Determination of the Volume So urces 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 (I SC3) 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 bo th 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 emissi ons from the OSR fleet out of the low stacks of the smaller, 34-foot craft. In reality, the impa cts 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 Nanu q is approximately 50 feet above the water.

Initial dispersion for volume sources is characterized by two parameters, σ y (sigma Y) and σ z (sigma Z). For the ice management and anchor ha ndling 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 sm allest, 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 Perm it 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 Gu ard, 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 ex clusion 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 de veloped 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 Perm it 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 th at 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 wi nd 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 secondar y) 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 ar e 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 ch aracteristics for the ice management fleet are provided on Pages 6, 7 and 8 of Appendix B.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc65Figure 5-1: Source and Receptor Locations for Worst-Case Impact ScenarioAirSci\Disco Major Chukchi Perm it 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 cl assification as a function of the amount of growth of air emission sources and impacts allo wed before significant air quality deterioration
would occur. Class I areas have the smallest impact increments and thus allow only a smalldegree 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 th e 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 Perm it Application Revised-R15.doc 67 Table 5-6: Summary of Significant Impact Levels and Related Significant Areas

Pollutant Averaging
Time PSD Class II
SIL ( μ g/m 3 ) Screening Model
Max. SIA (kilometers) Nitrogen Dioxide (NO 2 ) Annual 1 50.0
24-hour NA NA Particulate Matter (PM 2.5 ) Annual NA NA 24-hour 5 18.8 Particulate Matter (PM 10 ) Annual 1 2.8 3-hour 25 Impact not significant 24-hour 5 29.8 Sulfur Dioxide (SO 2 )

Annual 1 Impact not significant 1-hour NA NA Carbon Monoxide (CO)
8-hour NA NA

SIL Significant Impact Level SIA Significan t 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 fo r 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 SI A cannot be greater than 50 kilometers for any pollutant. From Table 5-6, the SIAs for NO 2 , PM 10 , and SO 2 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 source s in the SIA (the competing sources). The full impact analysis may also consider other source s outside the SIA that could cause significant impacts in the SIA of the proposed source. The re sults 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 inventor y for the cumulative PSD increment analysis is limited to increment-affecting sources (new sour ces 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 propos ed project's SIA. The modeling results from the NAAQS cumulative im pact analysis are added to representativeAirSci\Disco Major Chukchi Perm it 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 Sh ell leases and the lack of any significant nearby sources, impacts from other sources (e.g., compet ing 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 co mparison 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 su mmed 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 ed ge of the safety and equipment protection exclusion zone, supplemented by the impacts of the a dditional drill sites, al l 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 Perm it 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 de grees 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 im pact will be. Since al l 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 scen ario with the drill sites separated by 1,000 meters. This is the
scenario that is used to define the maximum scr eening impacts, which will necessarily exceed the real maximum impacts. Addition ally, the worst-case maximum additive annual impact occurs at a unique point at which, under the annual averag e 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 Perm it 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-re quested 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 capa city 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 modeli ng 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 im pacts by 32 days/365 days. Then the model is run with all sources except the HPU engines, ai r 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 oper ations of all other sources are accounted for. This approach considers the worst-case meteorologic al condition at each receptor for both sets of model runs while also maintaining spatial relation ships 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 co mbined impact from two drill sites.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 71 SECTION 6 

# BASELINE CONCENTRATIONS

When comparing a project’s impact to the NAAQ S, an ambient background concentration is needed. The background concentration repres ents 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 NO 2 , PM 2.5 , PM 10 , SO 2 , CO, and O 3 concentrations at Wainwright, Alaska in November 2008. The Wainwright and Badami monitoring stations are both remotely located (minimal influence of in dustry 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 (begi nning in November 2008 through December 2008) to demonstrate that th e 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 Wainwr ight station and Badami station to represent
Chukchi Sea baseline concentrations.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc72Figure 6-1: Map of Ambient Monitoring Stations on the North SlopeAirSci\Disco Major Chukchi Perm it 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 RescueHeadquarters 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 demonstr ate that non-summer values at Wainwright can be used to conservatively repr esent background concentrations.

Figures 6-2, 6-3, and 6-4 provide a quarterly breakdown of average monthly NO 2 concentrations, average maximum 3-hour SO 2 concentrations, and average maximum 24-hour SO 2 concentrations at all monitoring locations on the North Slope. From these figures, it is evident that gaseous pollutant concentrations are highest in the winter time 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 wint ertime months and lower in the summertime months with the exception of an ab normal 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 el evated 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.htmlAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 74 Therefore, higher concentrations of pollutants , primarily resulting from combustion related activities (i.e., NO 2 , SO 2 , CO and PM 2.5 ), 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 Wa inwright data collected during the wintertime months will provide conservative background concentr ations for offshore locations.

Figure 6-2: Average Monthly NO 2 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
Q4AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 75 Figure 6-3: Average Maximum 3-Hour SO 2 Concentrations for North Slope Stations

Figure 6-4: Average Maximum 24-Hour SO 2 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
Q4AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 76 Figure 6-5: Time Series of 1-Hour CO Concentrations at BPX - Liberty

Measured PM 10 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 PM 10 emissions compared to other North Slope stations such as Nuiqsut which is sited close to loess-rich Colville River channels, where clay-sized material easi ly becomes airborne when dry.

Table 6-1 shows the seasonal breakdown of PM 10 measurements at Badami. At Badami, there is a
bi-modal PM 10 distribution where impacts are higher in both the wintertime (Q1) and the summertime (Q3) and lower in the fall and spring. The summertime PM 10 concentrations at Badami are influenced by locally generated du st sources associated with drier soil/road conditions and human activities at the Badami facility and the nearby Badami airport.

Table 6-1: Seasonal PM 10 Concentrations at Badami

PM 10 Concentration (ug/m 3 ) 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 1.801-Feb15-Feb1-Mar15-Mar29-Mar12-Apr26-Apr10-May24-May7-Jun21-Jun5-Jul19-Jul2-Aug16-Aug30-Aug13-Sep27-Sep11-Oct25-Oct8-Nov22-Nov6-Dec20-Dec3-Jan17-Jan31-JanCO Concentration (ppm)

Wildfire ImpactsAirSci\Disco Major Chukchi Perm it 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 representati ve 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 ( μ g/m 3 ) Wainwright 2 ( μ g/m 3 ) Maximum ( μ g/m 3 )

NO 2 Annual 3 2 3 24-hour N/A 9 5 PM 2.5 Annual N/A 2 2
24-hour 12 9 12 PM 10 Annual 2 --- 2
3-hour 18 18 18
24-hour 16 10 16 SO 2 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 da ta for November and December 2008; values to

be updated as more data becomes available. NA Not applicableAirSci\Disco Major Chukchi Perm it 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 concentrat ions (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 NAAQS 1 ( μ g/m 3 ) Screening Model Max. Impact Plus Background 2 ( μ g/m 3 ) PSD Class II
Increment

( μ g/m 3 ) Screening Model Max. Impact No Background 3 ( μ g/m 3 ) Nitrogen Dioxide (NO 2 ) Annual 100 14.4 25 11.1

24-hour 35 31.6 NA NA Particulate Matter (PM 2.5 ) Annual 15 2.9 NA NA 24-hour 150 35.3 30 22.9 Particulate Matter (PM 10 ) 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 (SO 2 )
Annual 80 3.1 20 0.5 1-hour 40,000 1,025.9 NA NA Carbon Monoxide (CO) 8-hour 10,000 631.2 NA NA

1 National Ambient Air Quality Standards

2 Maximum modeled impacts plus background co ncentrations are compared to the NAAQS.

3 Maximum modeled impacts only (no ba ckground concentrations included) ar e compared to the PSD Increments. NA Not applicableAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 79 Table 7-2: Impact Scenarios Used to Define Screening Maximum Annual Impacts from All Sources and Multiple Se quential Wells

Max. Impact
Location Pollutant Model Run Impact Category X(m) Y(m) Modeled
1-Hour Impact 2 Persistence
Factor Emis. Adjust 3 Conc. ( μ g/m 3 )

NO 2 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 NO 2 Impact ( μ

g/m 3 ) 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. ( μ g/m 3 )

PM 10 & All Sources 900 m from Rig 1 -884.3 55 38.1 0.10 0.0877 0.3

PM 2.5 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 PM 10 and PM 2.5 Impact ( μ

g/m 3 ) 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. ( μ g/m 3 )

SO 2 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 SO 2 Impact ( μ

g/m 3 ) 5 > 0.5
Assume 84 days per drilling location and 32 days of operat ion 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 im pacts for both sets of model runs (i .e., A) all sources and B) no HPUs,

compressors, and resupply, ice management, or OSR ships (a lso call “No xxd” model run) wh ich 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 NO 2 = NO x * 0.75.

5 Total modeled impact (without background) is the sum of th e 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.doc80Table 7-3: Combined Screening Maximum Impacts fromAll Sources and Multiple Sequential WellsConcentration (μg/m3)PollutantAveragingPeriodMax.Modeled1-HourImpact900 mPersistenceFactorEmis.Adj.2Hole #1Impact ator beyond900 m1Hole #2Impact ator beyond900 m1BackgroundTotalNoBackground4Totalw/Background5PSD ClassIIIncrement(μg/m3) Comply?NAAQS(μg/m3)Comply?Sig.MonitoringConce.(μg/m3) Exceed?NO23Annual See Calculations in Table 7-2 5.5 5.5 3.3 11.1 14.4 25 Yes 100 Yes 14 NoPM2.524-Hour 38.1 0.6 1 22.9 --- 8.7 22.9 31.6 --- --- 35 Yes --- ---Annual See Calculations in Table 7-2 0.7 0.7 1.5 1.4 2.9 --- --- 15 Yes --- ---PM1024-Hour 38.1 0.6 1 22.9 --- 12.4 22.9 35.3 30 Yes150 Yes 10 YesAnnual See Calculations in Table 7-2 0.7 0.7 2.0 1.4 3.4 17 Yes 50 Yes --- ---SO23-Hour 17.6 1.0 1 17.6 --- 18.2 17.6 35.8 512 Yes 1,300 Yes --- ---24-Hour 17.6 0.6 1 10.6 --- 15.6 10.6 26.2 91 Yes365 Yes 13 NoAnnual See Calculations in Table 7-2 0.3 0.3 2.6 0.5 3.1 20 Yes 80 Yes --- ---CO 1-Hour 129.8 1.0 1 129.8 ---896.1 129.8 1,025.9 --- --- 40,000 Yes --- ---8-Hour 129.8 0.9 1 116.8 --- 514.4 116.8 631.2 --- --- 10,000 Yes 575 NoAssume 84 days per drilling location and 32 days of operation forHPU engines, air compressors,cranes, and resupply, ice management, and OSR ships at each location.1Assume that minimum separation distance between drilling locations is 1,000 meters and that there is a 900-meter safety exclusion zone 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).Short-term impacts are adequatelyaddressed with one drilling location.2Annual emissions adjustment to modeled hourly emissions; assume84 days per location and the HPU engines, air compressors, andresupply, ice management, and OSR ships arelimited to 32 days per location. Short-term emissions arenot adjusted since 24 hour/dayoperations are considered.3Assume that NO2= NOx* 0.75.4Total modeled impact without background is the sum of the maximum impact at the or beyond at least a 900-meter ambient air boundary from theDiscovererand the impact at orbeyond 900 meters (for annual impacts only).5Total modeled impact without background is the sum of the maximum impact at or beyond at least a 900-meter ambient air boundaryof theDiscoverer, the impact at or beyond 900meters (for annual impacts only), and background concentrations.AirSci\Disco Major Chukchi Perm it 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 pollut ant 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 PM 10 concentrations and maximum modeled impacts exceed the significant monitoring thresholds. The ambient background concentration of SO 2 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 PM 10 (and PM 2.5 ) and annual average NO 2 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 NO 2 are driven by poorer dispersing engines (HPU engines and cementing units) on the Discoverer while
24-hour PM 10 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 NO 2 24-Hour PM 10 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 Perm it Application Revised-R15.doc 82 

## 7.3 Impacts from the Ice Manageme nt and Anchor Handler Fleet

EPA has asked that Shell provide a table showin g 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 comp liance 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 ma ximum 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.doc83Table 7-5: Maximum Impacts from Primary Ice Management ShipConcentration (μg/m3)Coordinate of Max.Impact ReceptorPSD Class IIIncrement2NAAQS3PollutantAveragingPeriodX (m) Y (m)Max.Modeled1-HrImpact(μg/m3)PersistenceFactorEmissionAdjustment1Max.ModeledImpact(μg/m3)BackgroundTotal NoBackgroundTotal w/Background(μg/m3) Comply? (μg/m3) Comply?NO2Annual 4,800.0 -4,500.0 78.3 0.10.1753 1.0 3.3 1.0 4.3 25 Yes 100 YesPM2.524-Hour 4,800.0 -4,500.0 2.5 0.6 1 1.5 8.7 1.5 10.2 --- --- 35 YesAnnual 4,800.0 -4,500.0 2.5 0.10.1753 0.04 1.5 0.04 1.5 --- --- 15 YesPM1024-Hour 4,800.0 -4,500.0 2.5 0.61 1.5 12.4 1.5 13.9 30 Yes 150 YesAnnual 4,800.0 -4,500.0 2.5 0.10.1753 0.04 2.0 0.04 2.0 17 Yes 50 YesSO23-Hour 4,800.0 -4,500.0 5.0 0.91 4.5 18.2 4.5 22.7 512 Yes 1,300 Yes24-Hour 4,800.0 -4,500.0 5.0 0.61 3.0 15.6 3.0 18.6 91 Yes 365 YesAnnual 4,800.0 -4,500.0 5.0 0.10.1753 0.1 2.6 0.1 2.7 20 Yes 80 YesCO 1-Hour 4,800.0 -4,500.0 20.8 1.0 1 20.8 896.1 20.8 916.9 --- --- 40,000 Yes8-Hour 4,800.0 -4,500.0 20.8 0.91 18.7 514.4 18.7 533.1 --- --- 10,000 Yes1For short-term impacts assume24-hour day operations (adjustment = 1) for annual impacts assume 64 days per drilling season (adjustment = 64 days/365 days).2Impacts without background concentrationsare compared to the PSD increments.3Impacts including background concentrations are compared to the NAAQS.AirSci\Disco Major Chukchi Permit Application Revised-R15.doc84Table 7-6: Maximum Impacts from Secondary Ice Management ShipConcentration (μg/m3)Coordinate ofMax.Impact ReceptorPSD Class IIIncrement2NAAQS3PollutantAveragingPeriodX (m) Y (m)Max.Modeled1-HrImpact(μg/m3)PersistenceFactorEmissionAdjustment1Max.ModeledImpact(μg/m3)BackgroundTotalNoBackgroundTotalw/Background(μg/m3) Comply? (μg/m3) Comply?NO2Annual 976.1 -331.6 177.9 0.1 0.1753 2.3 3.3 2.3 5.6 25 Yes 100 YesPM2.524-Hour 976.1 -331.6 5.7 0.61 3.4 8.7 3.4 12.1 --- --- 35 YesAnnual 976.1 -331.6 5.7 0.1 0.1753 0.1 1.5 0.1 1.6 --- --- 15 YesPM1024-Hour 976.1 -331.6 5.7 0.6 13.4 12.4 3.4 15.8 30 Yes 150 YesAnnual 976.1 -331.6 5.7 0.1 0.1753 0.1 2.0 0.1 2.1 17 Yes 50 YesSO23-Hour 976.1 -331.6 11.3 0.9 110.2 18.2 10.2 28.4 512 Yes 1,300 Yes24-Hour 976.1 -331.6 11.3 0.6 16.8 15.6 6.8 22.4 91 Yes 365 YesAnnual 976.1 -331.6 11.3 0.1 0.1753 0.2 2.6 0.2 2.8 20 Yes 80 YesCO 1-Hour 976.1 -331.6 47.3 1.01 47.3 896.1 47.3 943.4 --- --- 40,000 Yes8-Hour 976.1 -331.6 47.3 0.9 142.5 514.4 42.5 556.9 --- --- 10,000 Yes1For short-term impacts assume24-hour day operations (adjustment = 1) for annual impacts assume 64 days per drilling season (adjustment = 64 days/365 days).2Impacts without background concentrations are compared to the PSD increments.3Impacts including background concentrations are compared to the NAAQS.AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 85 

## 7.4 Worst-Case Screening Impacts at Ne arest 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 prop osed 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.doc86Table 7-7: Worst-Case Screening Impacts at NearestVillages on Chukchi CoastConcentration (μg/m3)Max. Modeled1PollutantAveragingPeriodWainwright Point LayBackgroundTotal NoBackgroundTotal w/BackgroundPSD ClassIIIncrement2(μg/m3)Comply?NAAQS3(μg/m3) Comply?Shell Impact% NAAQSNO2Annual 1.0 1.1 3.3 1.1 4.4 25 Yes 100 Yes 1PM2.524-Hour 1.7 1.8 8.7 1.8 10.5 --- --- 35 Yes 5Annual 0.1 0.1 1.5 0.1 1.6 --- --- 15 Yes 0.4PM1024-Hour 1.7 1.8 12.4 1.8 14.2 30 Yes 150 Yes 1Annual 0.1 0.1 2.0 0.1 2.1 17 Yes 50 Yes 0.1SO23-Hour 4.5 4.8 18.2 4.8 23.0 512 Yes 1,300 Yes 0.424-Hour 2.7 2.9 15.6 2.9 18.5 91 Yes 365 Yes 1Annual 0.1 0.1 2.6 0.1 2.7 20 Yes 80 Yes 0.1CO 1-Hour 20.6 22.0 896.1 22.0 918.1 --- --- 40,000 Yes 0.18-Hour 18.6 19.8 514.4 19.8 534.2 --- --- 10,000 Yes 0.21The nearest villages to Shell's Chukchi leases are Wainwright (~110 km away) and Point Lay (~100 km away).2Total impact without background is compared to the PSD increments.3Total impact with background is compared to the NAAQS.AirSci\Disco Major Chukchi Perm it 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 pr oposed 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 asso ciated with shoreline growth is addressed in Section 2.15 Because of the limited and tempor ary nature of the exploratory drilling program, indirect impacts on industrial, commercial, and residential growth will be insignificant. The emissions presented for the project already incl ude all anticipated emissions, including those from support activities (e.g., resupply ships, ic e 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. Perm it 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 ac tivities. In addition to this great distance, many sources associated with the exploratory dril ling 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 Perm it 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 ad dition, there are no visi bility 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 woul d disperse and be broken up by movement of the ships and ambient winds.

The Clean Air Act established two types of na tional air quality standards, primary and secondary. Primary standards set limits to protect public health, including the health of "sensitive" populations such as asthmatics, child ren, 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 NO x emissions exceed 100 tons per year, EPA has asked that Shell provide a qualitative discussion on ozone impact s. 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 attain ment 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 Perm it Application Revised-R15.doc 89 production. 59 As shown in Table 8-1, the measured oz one concentrations i n/near these large oil fields are all well below the ozone NAAQS.

Table 8-1: Maximum Measured Ozone Concentrat ions 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/access data.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-ye ar 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 oz one, 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_g as/data_publications /crude_oil_natural_gas_reserve s/current/pdf/appb.pdf#page=9AirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 90 Figure 8-1: Ozone Monitoring Stations on the North SlopeAirSci\Disco Major Chukchi Perm it Application Revised-R15.doc 91 The latest data from the Western Regional Air Partnership (WRAP) Emis sions 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 NO x (i.e., an ozone precursor), were approximately 42,500 tons/year and 1,600 tons/year, respectively. Table 8-2 provides a summary of NO x 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 NO x are approximately 41,000 tons/year, which represent 22 times more NO x than those from the proposed portable Shell project.

Measured ozone concentrations on the more indust rialized North Slope, which take into account impacts from much larger sources of ozone precurso rs, 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 factor s, 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 exceedan ce 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.aspxAirSci\Disco Major Chukchi Permit Application Revised-R15.doc92Table 8-2: Point Source Emissions of NOxand VOCs – North SlopeEmissions (tons/year)Point Source Name CityNOxTrans Alaska Pipeline System Pump Station 1 North Slope 269ConocoPhillips Central Production Facility #2 Kuparuk 1,759BP Exploration (Alaska) - Inc. - Flow Station #2 Prudhoe Bay 1,398BP Exploration (Alaska) - Inc. - Gathering Center #2 (GC-2) Prudhoe Bay 1,212BP Exploration (Alaska) - Inc. - Flow Station #1 (FS-1) Prudhoe Bay 1,240BP Exploration (Alaska) - Inc. - Seawater Injection Plant East Prudhoe Bay 275BP Exploration (Alaska) - Inc. - Seawater Treatment Plant - PBU Prudhoe Bay 163Trans Alaska Pipeline System Pump Station 3 Prudhoe Bay 251BP Exploration (Alaska) - Inc. - Central Power Station Prudhoe Bay 3,830ConocoPhillips Central Production Facility #1 Umiat Meridian - Kuparuk 2,181BP Exploration (Alaska) - Inc. - Gathering Center #3 (GC-3) Prudhoe Bay 1,752BP Exploration (Alaska) - Inc. - Central Gas Facility Deadhorse 5,695BP Exploration (Alaska) - Inc. - Milne Point Production Facility North Slope 517BP Exploration (Alaska) - Inc. - Badami Development Deadhorse 64ConocoPhillips Alpine Central Processing Facility Umiat Meridian 1,058BP Exploration (Alaska) - Inc. - Central Compressor Plant Deadhorse 8,256Haliburton Energy Services - Inc. - Deadhorse Facility Deadhorse 235BP Exploration (Alaska) - Inc. - Endicott Production Facility Prudhoe Bay 2,700ConocoPhillips Alaska - Kuparuk Seawater Treatment Plant Kuparuk 101BP Exploration (Alaska) - Inc. - Lisburne Production Center Prudhoe Bay 1,782ConocoPhillips Alaska - Central Production Facility #3 Kuparuk 1,498BP Exploration (Alaska) - Inc. - Northstar Production Facility Deadhorse 326BP Exploration (Alaska) - Inc. - Gathering Center #1 (GC-1) Prudhoe Bay 3,060BP Exploration (Alaska) - Inc. - Flow Station #3 Prudhoe Bay 1,629Total >41,252

# 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