ENVIRON International Corp. 8235 YMCA Plaza Drive, Suite 300, Baton Rouge, LA 70810

V +1 225.408.2696 F +1 225.408.2747

environcorp.com

May 19, 2014

Ms. Heather M. Ceron

Chief – Air Permits Section

USEPA Region 4

61 Forsyth Street SW

Atlanta, GA 30303-8960

Re: Statoil Gulf Services, LLC

Incompleteness Letter Response for

Title V Permit Significant Modification and PSD Permit Major Modification Application

Title V and PSD Permit No. OCS-EPA-R4012

Dear Ms. Ceron:

On behalf of Statoil Gulf Services, LLC (Statoil), ENVIRON International Corporation (ENVIRON) is 

submitting this response to the May 7, 2014 incompleteness letter Statoil received from the United 

States Environmental Protection Agency (EPA) regarding the permit application dated March 27, 

2014 for a Title V Permit Significant Modification and PSD Permit Major Modification to Outer 

Continental Shelf (OCS) Permit No. OCS-EPA-R4012. 

Below we have listed each incompleteness item listed by EPA in its May 7, 2014 incompleteness 

letter, followed by our response to each item. As required, this response is being provided within 60 

days of the date of the referenced incompleteness letter.

Incompleteness Item #1:

1. Offshore Support Vessels (OSVs) and crew boats are not dedicated to any particular drilling 

vessel or campaign. Therefore, to allow for flexibility to use any available vessel in the support 

fleet and to more efficiently meet project needs, Statoil determined the total hours of operations 

for up to three OSVs and one crew boat operating simultaneously based on historical drilling 

campaigns using representative vessels, the OSV Peyton Candies and the crew boat Sybil 

Graham. Statoil then used AP-42 emissions factors in conjunction with this determination to 

estimate annual and maximum hourly emissions from the support vessels. Annual emissions 

were based on two main engines per support vessel running at 100 percent load for 2,570 hours 

for the OSV s and 618 hours for the crew boat per campaign of approximately 180 days per year. 

Maximum hourly emissions for the support vessels were based on two main engines on each

support vessel running at 75 percent load, and the short-term NAAQS and PSD increment 

analysis assumes crew and supply boats operate at 50% load for 18 hours a day.

Because the support vessels are not owned or operated by Statoil directly, the EPA is concerned 

that compliance demonstration monitoring and recordkeeping will be too onerous and difficult to 

maintain on an ongoing basis throughout each drilling campaign to demonstrate continual 

compliance. Permit requirements that would be necessary using this approach may include 

monitoring and recordkeeping associated with hours of operation, engine load, and gallons of 

diesel fuel used by each support vessel when within 25 miles of the drilling vessel. 

Please provide a specific methodology for demonstrating continual compliance with the operating 

limitations assumed for the third party vessels.
USEPA Region 4 - 2 - May 19, 2014

Response to Item #1:

The following response addresses Statoil’s proposed methodology for demonstrating continual 

compliance with the short-term and annual emissions resulting from the OSVs and crew boats that 

will be associated with the Developer.

Short-Term Compliance

The distribution of OSV and crew boat main engine operating loads for a given day were associated 

with the Class I area visibility modeling analysis performed for the Breton Wilderness Area, not any 

criteria pollutant ambient air quality standard analysis. ENVIRON recently submitted to Ms. Jill 

Webster (the federal land manager for the Breton Wilderness Area) a revised Class I area visibility 

modeling analysis for the Breton Wilderness Area, and this revised analysis incorporates the same 

short-term emissions for the OSVs and crew boats that were included in the short-term NO2, PM10, 

and PM2.5 modeling presented in the March 27, 2014 permit modification application for Permit No. 

OCS-EPA-R4012. This revised Class I area visibility modeling analysis demonstrates compliance 

with the relevant visibility standard and was approved via email by Ms. Jill Webster on May 15, 2014. 

Therefore, the requested permit modification no longer involves any distribution of OSV and crew 

boat main engine operating loads for a given day.

Statoil proposes the following daily diesel usage limits for OSVs and crew boats, respectively: 13,058 

gallons per day and 6,620 gallons per day. In general, these proposed daily diesel usage rates have 

been calculated based on short-term modeling basis engine operating rates occurring for an entire 

day for an OSV and crew boat, respectively, and the same AP-42 diesel engine horsepower output to 

fuel conversion factor used in the March 27, 2014 permit application (0.0511 gallons of diesel per 

horsepower-hour (hp-hr)). The proposed OSV daily diesel usage limit was based on three OSVs

operating two main engines each at 75% load each (1,775.2 hp-hr per engine) for 24 hours per day. 

The proposed crew boat daily diesel usage limit was based on one crew boat operating four main 

engines at 75% load each (1,350 hp-hr per engine) for 24 hours per day.

The following draft permit conditions are proposed to comply with these daily diesel usage limits for 

the OSVs and crew boats associated with the Developer.

• The permittee shall maintain OSV diesel fuel records to demonstrate that total OSV diesel 

fuel usage is less than or equal to 13,058 gallons per day when within 25 miles of the drilling 

vessel.

• The permittee shall maintain crew boat diesel fuel records to demonstrate that crew boat 

diesel fuel usage is less than or equal to 6,620 gallons per day when within 25 miles of the 

drilling vessel.

Statoil intends to demonstrate compliance with the above requirements by relying on OSV and crew 

boat engine monitoring systems, which record data such as engine fuel usage, engine load, and 

engine operating hours for these vessels.

Long-Term Compliance

As indicated on page 1-3 of the March 27, 2014 permit modification application for Permit No. OCSEPA-R4012, Statoil did not propose to modify the currently permitted annual diesel usage limits for 

the OSVs and crew boats (621,468 gallons per year on a rolling 12-month total basis and 235,176 
USEPA Region 4 - 3 - May 19, 2014

gallons per year on a rolling 12-month total basis, respectively) associated with the Developer. 

Therefore, Statoil proposes that the modified version of Permit No. OCS-EPA-R4012 include the 

following permit conditions included in the current version of this permit for long-term OSV and crew 

boat emissions compliance purposes: permit condition 6.20 (Offshore Support Vessels Operating

Limits), 6.21 (Crew Boats Operating Limits), and permit condition 6.24 (Compliance Monitoring and 

Recordkeeping Requirements for Support Vessel Engines).

Incompleteness Item #2:

2. Although Statoil is not proposing to add any additional lease blocks with this permit modification,

they have requested authorization to conduct drilling activities at locations in the eastern Gulf of 

Mexico further from the Class I areas addressed in the application's air quality analysis.

Please provide specific information on what is being proposed with respect to any lease block 

"further from shore and Class I areas," and a corresponding discussion or demonstration 

regarding how the modeling conducted for this application incorporates the proposed expansion.

Response to Item #2:

Statoil is requesting the flexibility to perform exploratory drilling at lease blocks in the eastern Gulf of 

Mexico other than those specifically listed in the current version of Permit No. OCS-EPA-R4012 

without having to revise this permit to list any lease blocks that may be acquired in the future. If the 

location of a new lease block falls under the same condition used to judge the worst-case location 

(which was taken as the corner of the lease block closest to shore and the Class I areas), then Statoil 

believes it reasonable to include language in the PSD permit that allows for exploration within that 

lease block. The following information is provided to support this request.

Figure 1 included in Attachment 1 shows the active (as of May 14, 2014) lease blocks as gray 

squares, with those listed in the current Statoil PSD permit application highlighted in green. The 

“corner of the closest lease block” used in the modeling is the NW corner of the northern-most green 

lease block. 

Also shown is the line at 87.5°W that divides BOEM and EPA jurisdiction (orange), the Military 

Mission Line at 86°41’W (pink), along with the Class I (purple) and Class II (red) receptors. The 

closest Class I receptor is 176 km (109 statute miles, or 95 nautical miles) from the “corner of the 

closest lease block” modeling location. The closest Class II receptor is 93 km (58 statute miles, or 50 

nautical miles) from the modeling location. 

The area under Congressional moratoria via the Gulf of Mexico Energy Security Act (GOMESA) of 

2006 is shown in Figure 1 in yellow. The Department of Interior is prohibited from leasing any more 

blocks in the yellow area, so it is currently impossible for Statoil to obtain the right to explore in this 

area.

The purple rings in Figure 1 enclose all points within 176 km of whichever receptor in each Class I 

area is closest to the modeling location. The dark blue line is plotted at a constant 93 km from the 

Class II receptors. Statoil is seeking the flexibility to explore at lease blocks outside the purple and 

blue lines. Therefore, the lease blocks Statoil is seeking the flexibility to use, that are subject to a 

PSD permit, lie between the orange line and the yellow area.

As can be seen in Figure 1, there are only two small areas where the purple rings intersect the blue 

line. The eastern intersection which is subject to GOMESA, and thus is not available to Statoil for 
USEPA Region 4 - 4 - May 19, 2014

exploratory purposes. The western intersection contains a small area under EPA jurisdiction that, 

although it contains no currently active lease blocks, would require some language to prevent Statoil 

from exploring any closer to Breton Wilderness under this PSD permit.

There are no other possible lease blocks closer to the Class II receptors, because of the GOMESA 

moratoria. Thus no further language in the permit is necessary to prohibit Statoil from exploring at 

lease blocks closer to the Class II receptors – the permit language can simply rely on or refer to the 

GOMESA moratoria.

Figure 2 included in Attachment 2 is taken from the ENVIRON report “Background PM2.5 Analysis 

for the Eastern Gulf of Mexico Outer Continental Shelf” dated April, 2013. It shows the similarity of 

the character of the winds over the Gulf of Mexico waters, especially the three buoys surrounding the 

lease blocks between the 87.5°W line and the GOMESA moratoria area. We therefore expect that 

concentration-by-downwind distance predicted by CALPUFF would not vary significantly at any of the 

lease blocks in this area – source to receptor distance is the key predictor of pollutant concentrations

in this regime.

We therefore propose to include the following language in the modified version of Permit No. OCSEPA-R4012.

• Statoil is hereby authorized to construct and operate air emissions units and to conduct other 

air pollutant emission activities at an OCS source at the following locations: DeSoto Canyon 

lease blocks 143, 187, 188, 230, 231, 625, 669, 670, 671, 715, 716, 759, 760, and 804 in 

Lease Sales 213 and 222, or any lease block further from the Breton Wilderness Class I area, 

located on the OCS waters of the Gulf of Mexico east of longitude 87.5°W, and outside of the 

current Congressional moratoria area as specified by the Gulf of Mexico Energy Security Act 

of 2006, and not within 75 nautical miles of the state seaward boundary of Florida. 

This language is similar to the language in the revised PSD permit issued on December 11, 2012 to

Anadarko Petroleum Corporation. It should be noted that the 75 nautical miles of the state seaward 

boundary of Florida reference included in the above proposed condition is based on the 50 nm (93 

km) distance from the modeling location to the nearest Class II receptor, plus the 25 nm distance 

between the Class II receptors and the state seaward boundary of Florida. 

Incompleteness Item #3:

3. Please provide more specific information regarding how the gross annual fuel limitations will be 

used to ensure compliance with annual and short term standards given the 12 varying operating 

scenarios presented in the application and the absence of limiting conditions on the hours of 

operation for the Developer's main engines. Please include corresponding details of a 

compliance methodology, including specific information regarding how load data will be logged 

and continual compliance demonstrated in the discussion.

Response to Item #3:

Statoil’s previous permit application was based on five main engines operating at 60% load (shortterm operating scenario) and three main engines operating at 60% load (annual operating scenario.)

EPA’s compliance options for short-term emissions were 1) Parametric Monitoring; 2) Install CEMS; 

or 3) Annual Stack Testing. Annual compliance is based on tracking annual fuel consumption.

These same compliance options are found in each of the OCS exploratory drilling permits issued by 

EPA Region 4. 
USEPA Region 4 - 5 - May 19, 2014

In the permit modification application submitted on March 27, 2014, Statoil based short-term 

emissions on five main engines at their worst case emission rate (plus 5% safety factor) recorded 

during the October 2013 testing and long-term emissions were based on actual main engine 

operating data collected during a recent drill campaign that occurred from June 2013 – September 

2013.

The following response addresses Statoil’s proposed methodology for demonstrating continual 

compliance with the main engine short term and annual emission limits. 

Short-Term Emissions

As discussed in the permit modification application, Statoil based short-term air quality impacts (1-hr 

and 24-hr) from the Developer main engines using the maximum NOX, PM10, and PM2.5 emissions 

measured during the October 2013 emissions tests with an added five percent safety factor. 

Maximum hourly NOX emissions were based on main engine No. 5 operating at 60 percent load (77.4 

lb/hr * 1.05 = 81.3 lb/hr.) Maximum PM10 and PM2.5 emissions were based on main engine No. 5 

operating at 30 percent load. The ambient air quality analysis provided in the permit application 

indicates maximum 1-hour NOX, 24-hour PM10, and 24-hour PM2.5 ambient concentrations were well 

below the applicable significant impact levels (SILs.)

Statoil proposes that the current monitoring and recordkeeping provisions as specified in condition 

number 6.22 for demonstrating compliance with the main engine emission limits: 1) Parametric 

Monitoring; 2) Install CEMS; or 3) Annual Stack Testing are more than adequate to ensure 

compliance with the short-term emission limitations. Specifically, permit condition numbers 6.22.1.4, 

6.22.2.5, and 6.22.3.6 require the permittee to determine the main engine emission rate of NOx CO2, 

CO, VOC, and PM/PM10/PM2.5 in g/kW-hr for each engine from the hourly emission rate results in 

each rolling 24-hour period and total annual emission in TPY on a 12 month rolling basis.

It is important to note that the Developer main engines are equipped with an on board computer 

system and data recorder that records specific operating data for each of the main engines on 1-

second intervals. The engine data management system collects and stores individual engine load 

and hours of operation data as well as various other operating parameters. This data will be utilized 

along with the above cited compliance methods (as relevant) to ensure compliance with the shortterm emission limitations.

Long-Term Emissions

In the permit modification application, Statoil proposes to revise the Developer annual fuel usage limit 

from 2,654,931 gallons per 180-day drilling campaign to 2,459,150 gallons per 180-day drilling 

campaign based on actual main engine operating data provided by Maersk. The previous fuel usage 

rate was based on three main engines operating at 60% load for 180 days. The permit modification 

application refines the annual fuel use estimate by taking into account the realities that the Developer

main engines operate at various load conditions over the course of a 180-day drilling campaign. As 

discussed previously, Maersk provided actual main engine operating data for June 2013 –

September 2013 in order to determine the frequency (number of hours) each engine is operated 

within specific engine load conditions.

The air quality impact analysis for the more refined main engine operating scenario indicated annual 

average Class I and Class II CALPUFF predictions were orders of magnitude less than the applicable 

SILs. To provide EPA with the most conservative main engine modeling scenario, ENVIRON used 
USEPA Region 4 - 6 - May 19, 2014

the existing short-term CALPUFF modeling files (worst case short-term operating scenario discussed 

above) to calculate annual average concentrations at the Class I and Class II receptors. The annual 

average CALPUFF results, using maximum short-term emissions from the main engines plus three 

OSVs and one Crew boat, for Class I and Class II areas are summarized in the tables below. The 

conservative modeling results indicate that operating at their maximum short-term emission rates for 

the entire year would result in Class I and Class II CALPUFF-predicted particulate matter

concentrations less than all applicable annual SILs. Predicted annual NO2 concentration in Breton 

Wilderness would very slightly exceed the Class I SIL, but Statoil would point out that it would be 

impossible to operate the main engines in this manner for every hour in three consecutive years, 

especially considering Statoil will be using a 180-day/year drilling schedule. 

The permit modification application modeling analysis was based on 554 tons of NOX/yr, but the 

tables presented below (short-term emissions for the entire campaign) are based on hourly 

equivalent of 1,545 tons of NOX/yr. In essence, Statoil could double annual emissions from the 

drilling campaign and remain below the applicable annual average SILs.

Maximum Predicted Class I Annual Concentrations

Criteria Pollutant Averaging Period

Developer 

Max. Concentration

(μg/m3)

EPA SIL 

(μg/m3)

NO2 a Annual 0.106 0.1

PM2.5 b Annual 0.003 0.06 c

PM10 Annual 0.003 0.2

a NOX was conservatively assumed to be 75% converted to NO2.

b 100th percentile (maximum) values are presented (not 98th percentile) using direct PM2.5 emissions only.

c The Class I PM2.5 SIL was vacated on January 22, 2013,but presented here for comparison.

Maximum Predicted Class II Annual Concentrations

Criteria Pollutant Averaging Period

Developer 

Max. Concentration

(μg/m3)

EPA SIL 

(μg/m3)

NO2 a Annual 0.25 1

PM2.5 b Annual 0.0073 0.3 c

PM10 Annual 0.0080 1

a NOX was conservatively assumed to be 75% converted to NO2.

b 100th percentile (maximum) values are presented (not 98th percentile) using direct PM2.5 emissions only.

c The Class II PM2.5 SIL was vacated on January 22, 2013,but presented here for comparison.

Statoil contends that tracking annual fuel use and compliance with the current monitoring and 

recordkeeping requirements contained in permit condition 6.22 for the Developer main engines along 

with the data collected from the on board computer system provide a reliable method to ensure 

compliance with the annual average ambient standards and emission limits.
USEPA Region 4 - 7 - May 19, 2014

Incompleteness Item #4:

4. Please provide a discussion regarding the variability of emissions rates at a given load, from the 

eight identical main engines on board the Developer, including any insight that the engines' 

manufacturer may be able to provide.

Response to Item #4:

Statoil requested additional information from Maersk and Wartsila to better understand the operating 

conditions of the Developer main engines during the October 2013 emissions tests. Maersk provided 

information on the general condition of the engines during the test, including the October 2013 

monitoring reports for each of the eight main engines. The condition-based monitoring (cbm) reports 

show all of the engines were operating within their normal ranges. Furthermore, the main engines 

were also following their recommended manufacture’s maintenance procedures and schedule.

It should be noted that the main engines are normally operated using a load sharing system, which 

allows the power management system on the Developer to automatically distribute electrical load 

over the available main engines. If additional load is required by drill vessel equipment, the available 

engines increase equally to meet the load requirement. The main engines do not have a system to 

maintain a constant fuel/air ratio during these load changes, which can lead to temporary rich or lean 

fuel/air mixtures that can affect emissions. During the October 2013 emissions tests, the engines 

were operating using the load sharing system, which yields test results that are most representative 

of actual operating conditions during the drilling campaign, but may result in variability of test results. 

While this may have contributed to variability in the test results across the eight main engines, Statoil 

believes this was the appropriate mode for the emissions tests as the load sharing system is utilized 

during normal drilling campaign operations on the Developer. Future emissions tests could be 

completed by excluding each engine individually from the load sharing system, which would allow the 

engine to have a constant load set manually; however, testing outside the normal operating 

conditions would not be representative of actual emissions and the results would thus not be ideal for 

establishing a permit basis. 

Lastly, the results from the October 2013 emissions tests on the Developer have been compared to 

the results from emissions tests performed on other drilling vessel main engines. Emissions test 

results that have been utilized in OCS permit applications for Shell Offshore Inc. (Noble Globetrotter I

drillship) and BHP Billiton Petroleum, Inc. (C.R.Luigs drillship and Development Driller 1 semisubmersible) were compiled. The average, minimum, and maximum emission rate (g/kW-hr) was 

calculated for each pollutant at each tested load. The percent change between the minimum and the 

average emission rates and the percent change between the maximum and the average emission 

rates were then calculated for each pollutant at each tested load. Finally, the maximum of these 

percent changes was calculated to determine the most variable percent change for each pollutant. 

Please see the table below for the maximum percent change for each drilling vessel.
USEPA Region 4 - 8 - May 19, 2014

Emissions Tests Results Variability Comparison

Pollutant

Maximum Percent Change (%)

Developer 

(Statoil)

Noble Globetrotter I 

(Shell)

C.R.Luigs 

(BHP Billiton)

Development Driller 1 

(BHP Billiton)1

CO 46.26 38.28 38.78 62.18

NOx 17.79 28.16 17.23 51.58

THC 25.68 42.02 -- 15.73/14.64

PM 48.05 35.502 -- 75.68/32.86

1 The data provided by EPA for THC and PM for the Development Driller 1 had some data points crossed out. The maximum percent 

change was calculated both including the crossed out data points (the first value listed above) and excluding the crossed out data points 

(the second value listed above) since it was not apparent why the data was marked as such. 2 The PM data for Shell represents PM10.

The Development Driller 1 had the highest maximum percent change for CO, NOX, and PM. The 

Noble Globetrotter I had the highest maximum percent change for THC. Based on this data, 

variability in the emissions test results at a given load from the eight identical main engines on board 

the Developer is not unusual. In fact, this data indicates the variability of the test results from the 

Developer emissions tests is less variable when compared to test results of the engines on other 

drilling vessels.

We look forward to working with you and your staff during your review of this response, and we will 

be glad to answer any questions you may have. Please feel free to contact me at (225) 408-2691 or 

via email at the following address: mcarbon@environcorp.com.

Sincerely,

Michael Carbon

Principal, Air Sciences

Enclosures

cc: Foster Wade, Statoil

Don Evans, Statoil

Kjersti Seim, Statoil

Ms. Jill Webster (electronic CD copy)

UNITED STATES DEPARTMENT OF THE INTERIOR

U.S. Fish and Wildlife Service

National Wildlife Refuge System

Branch of Air Quality

7333 W. Jefferson Ave., Suite 375 

Lakewood, CO 80235-2017
Attachment 1
Figure 1. Lines of constant distance from Class I (purple circles) and Class II (blue line) receptors, with current lease block (green) and 

active lease block (gray), Class I (purple) and Class II (red) receptors, the 87.5°W line (orange), and the Military Mission Line (pink).

Bradwell Bay

Chassahowitzka Wilde

Saint Marks Wilderness

Breton Wilderness

600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700

LCC (RPO Projection) Easting, km

-1600

-1500

-1400

-1300

-1200

-1100

-1000

-900

-800

CC o t g, 
Attachment 2
Figure 2. Windrose Plots from Various ASOS Stations and Buoys, with Active Lease Blocks