UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field 

Operations (MS 5231)

Public Information copy of Exploration Plan

Control # - S-07728

Type - Supplemental Exploration Plan

Lease(s) - OCS-G32556 Block - 19 Atwater Valley Area

OCS-G33863 Block - 18 Atwater Valley Area

Operator - Shell Offshore Inc.

Wells A through G

%14FNJTVCNFSTJCMFBOE%SJMMTIJQ

Attached is a copy of the subject plan for public comments on issues that 

should be addressed in an Environmental Assessment.

It has been deemed submitted as of this date and is under review for approval.

Chiquita Hill

Plan Coordinator

Description -

Rig Type -

Subject:

From:

February 13, 2015
Shell Offshore Inc.

P. O. Box 61933

New Orleans, LA 70161-1933

United States of America

Tel +1 504 425 7215

Fax +1 504 425 6747

Email Sylvia.bellone@shell.com

Public Information Copy 

January 6, 2015 

Ms. Michelle Uli, Section Chief 

Bureau of Ocean Energy Management 

1201 Elmwood Park Boulevard 

New Orleans, LA 70123-2394 

 

Attn: Plans Group GM 1053C 

SUBJECT: Supplemental Exploration Plan 

 OCS-G 33863 and OCS-G 32556, Atwater Valley (AT) Blocks 18 and 19 

 Offshore Louisiana 

Dear Ms. Uli: 

 

In compliance with 30 CFR 550.211 and NTLs 2008-G04, 2009-G27 and 2010-N06, giving Exploration Plan guidelines, 

Shell Offshore Inc. (Shell) requests your approval of this Supplemental Exploration Plan to drill seven (7) wells at 

Atwater Valley (AT) Blocks 18 and 19. Operations are targeted to commence March 2015. 

This plan consists of a series of attachments describing our intended operations. The attachments we desire to be 

exempted from disclosure under the Freedom of Information Act are marked “Proprietary” and excluded from the 

Public Information Copies of this submittal. The cost recovery fee is attached to the proprietary copy of the plan.

Should you require additional information, please contact Tracy Albert at 504.425.4652 or tracy.albert@shell.com. 

Sincerely, 

Sylvia A. Bellone 

Page 1 Public Information Copy
SHELL OFFSHORE INC.

SUPPLEMENTAL EXPLORATION PLAN 

for 

OCS-G 33863, Atwater Valley 18 

OCS-G 32556, Atwater Valley 19 

PUBLIC INFORMATION COPY 

JANUARY 2015 

PREPARED BY: 

Tracy W. Albert 

 Regulatory Specialist 

504.425.4652 

tracy.albert@shell.com

Page 2 Public Information Copy
REVISIONS TABLE: 

Date of Request Plan Section What was Corrected Date Resubmitted

1/14/2015 Section 2J

 Section 9

 Section 18

Proprietary data

WCD Number

WCD Number

 1/16/2015

1/27/2015 Section 1 & 3 Attachments 1A, 1B & 3A 1/29/2015

Page 3 Public Information Copy
SUPPLEMENTAL EXPLORATION PLAN 

OCS-G 33863 Atwater Valley Block 18 

OCS-G 32556, Atwater Valley Block 19 

OFFSHORE LOUISIANA 

TABLE OF CONTENTS 

SECTION 1 PLAN CONTENTS 

SECTION 2 GENERAL INFORMATION 

SECTION 3 GEOLOGICAL AND GEOPHYSICAL INFORMATION 

SECTION 4 HYDROGEN SULFIDE - H2S INFORMATION 

SECTION 5 MINERAL RESOURCE CONSERVATION INFORMATION

SECTION 6 BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC 

 INFORMATION 

SECTION 7 WASTE AND DISCHARGE INFORMATION 

SECTION 8 AIR EMISSIONS INFORMATION 

SECTION 9 OIL SPILLS INFORMATION 

SECTION 10 ENVIRONMENTAL MONITORING INFORMATION 

SECTION 11 LEASE STIPULATIONS INFORMATION 

SECTION 12 ENVIRONMENTAL MITIGATION MEASURES INFORMATION 

SECTION 13 RELATED FACILITIES AND OPERATIONS INFORMATION 

SECTION 14 SUPPORT VESSELS AND AIRCRAFT INFORMATION 

SECTION 15 ONSHORE SUPPORT FACILITIES INFORMATION 

SECTION 16 SULPHUR OPERATIONS INFORMATION 

SECTION 17 COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION 

SECTION 18 ENVIRONMENTAL IMPACT ANALYSIS (EIA) 

SECTION 19 ADMINISTRATIVE INFORMATION 

 

 

 

Page 4 Public Information Copy
SECTION 1: PLAN CONTENTS 

A. DESCRIPTION, OBJECTIVES & SCHEDULE 

Shell Offshore Inc. (Shell) is submitting a supplemental exploration plan (EP/plan) for Atwater Valley (AT) Block 18 

and 19, OCS-G 33863 and OCS-G 32556 respectfully. Anadarko Petroleum Corporation filed an initial exploration 

plan, N-9781, which was approved June 24, 2014 for these leases. The wells were not drilled. BHP drilled the 

Gnome Prospect on AT 18 (AT 18, Well 001) in September 2001. This well was plugged and abandoned. 

This supplemental EP will be for the drilling of seven new wells. Shell plans to drill one well in March 2015 and 

depending on the outcome of this drilling, the other locations in subsequent years. The well(s) will be drilled and 

temporarily abandoned with cement plugs and corrosion caps in accordance with 30 CFR 250.1721 until the well(s) are 

completed and developed under future plans. If the wells are unsuccessful, they will be permanently plugged and 

abandoned in accordance with the Bureau of Safety and Environmental Enforcement (BSEE) regulations. 

The drilling activities are planned to commence on or about March 2015 and last approximately 200 days per well. The 

timeframe to complete the initial drilling activities is an estimate based on the best available information regarding 

downhole conditions likely to be encountered while drilling each well and are not intended to be a limitation. 

The lease area is 70 statute miles from the nearest shoreline, 109 statute miles from the onshore support base at 

Port Fourchon, Louisiana and 94 statute miles from the helicopter base at Boothville, Louisiana. Water depths at 

the well sites range from 4,203’ to 4,432’ (Attachment 1A). 

The proposed rig will be either a dynamically positioned (DP) semi-submersible (Noble Jim Day or similar) or a Drill 

Ship (Noble Don Taylor or similar); both are self-contained drilling vessels with accommodations for a crew which 

include quarters, galley and sanitation facilities. The rigs will comply with the requirements in the Interim Final Rules. 

The drilling activities will be supported by the support vessels and aircraft as well as onshore support facilities as listed 

in Sections 14 and 15 of the EP. Shell has employed or contracted with trained personnel to carry out its exploration 

activities. Shell is committed to local hire, local contracting and local purchasing to the maximum extent possible. Shell 

personnel and contractors are experienced at operating in the Gulf of Mexico and are well versed in all Federal and 

State laws regulating operations. Shell’s employees and contractors share Shell’s deep commitment to operating in a 

safe and environmentally responsible manner. 

Shell, through its parent and affiliate corporations, has extensive experience safely exploring for oil and gas in the Gulf 

of Mexico. Shell will draw upon this experience in organizing and carrying out its drilling program. Shell believes that 

the best way to manage blowouts is to prevent them from happening. Significant effort goes into the design and 

execution of wells and into building and maintaining staff competence. In the unlikely event of a spill, Shell’s Regional 

Oil Spill Response Plan (OSRP) is designed to contain and respond to a spill that meets or exceeds the worst case 

discharge (WCD) as detailed in Section 9 of this EP. The WCD does not take into account potential flow mitigating 

factors such as well bridging, obstructions in wellbore, reservoir barriers, or early intervention. We continue to invest in 

research and development to improve safety and reliability of our well systems. All operations will be conducted in 

accordance with applicable federal and state laws, regulations and lease and permit requirements. Shell will have 

trained personnel and monitoring programs in place to ensure such compliance. 

B. LOCATION 

See attached location plat (Attachments 1A and 1B) and BOEM forms (Attachments 1C through 1I). 

C. RIG SAFETY AND POLLUTION FEATURES 

The rig (Noble Jim Day or similar or Noble Don Taylor or similar) will comply with all of the regulations of the 

American Bureau of Shipping (ABS), International Maritime Organization (IMO) and the United States Coast Guard 

(USCG). All drilling operations will be conducted under the provisions of 30 CFR, Part 250, Subpart D and other 

applicable regulations and notices, including those regarding the avoidance of potential drilling hazards and safety 

and pollution prevention control. Such measures as inflow detection and well control, monitoring for loss of 

circulation and seepage loss and casing design will be our primary safety measures. Primary pollution prevention 

measures are contaminated and non-contaminated drain system, mud drain system and oily water processing. 

The following drain items are typical for rigs in Shell’s fleet.

Page 5 Public Information Copy
DRAIN SYSTEM POLLUTION FEATURES 

Drains are provided on the rig in all spaces and on all decks where water or oil can accumulate. The drains are 

divided into two categories, non-contaminated and contaminated. All deck drains are fitted with a removable strainer 

plate to prevent debris from entering the system. 

Deck drainage from rainfall, rig washing, deck washing and runoff from curbs and gutters, including drip pans and 

work areas, are discharged depending on if it comes in contact with the contaminated or non-contaminated areas of 

the Rig. 

1) Non-contaminated Drains 

Non-contaminated drains are designated as drains that under normal circumstances do not contain hydrocarbons 

and can be discharged directly overboard. These are mostly located around the main deck and outboard in places 

where it is unlikely that hydrocarbons will be found. 

Drains within 50 feet of a designated chemical storage area which uses the weather deck as a primary containment 

means shall be designated “normally plugged.” An adequate number of drains around the rig shall be designated as 

“normally open” to allow run-off of rain water. Normally open drains shall have a plug located in a conspicuous area 

near the drain which can be easily installed in the event of a spill. 

The rig’s drain plug program consists at a minimum of a weekly check of all deck drains leading to the sea to verify 

that their status is as designated. If normally open they shall verify that the drain is open and that the plug is 

available in the area. If normally closed they shall verify that the plug is securely installed in the drain. 

In the event a leak or spill is observed, the event shall be contained (drain plug installation and/or spill kit 

deployment as appropriate) and reported immediately. 

Rig personnel shall ensure that the perimeter kick-plates on weather decks are maintained and drain plugs are in 

place as needed to ensure a proper seal. 

2) Contaminated Drains 

Contaminated drains are designated as drains that contain hydrocarbons and cannot be discharged overboard. 

When oil-based mud is used for drilling it will have to be collected in portable tanks and sent to shore for processing. 

3) Mud Drain System 

None 

4) Oily Water Processing 

Oily water is collected in an oily water tank. It must be separated and not pumped overboard until oil content is <15 

ppm. The separated oil is pumped to a dirty oil tank and has to be sent ashore for disposal. On board the MODU an 

oil record log has to be kept according to instructions included in the log. Any and all pollution pans are subjected to 

a sheen test before being pumped out. If the water passes the sheen test then it is pumped overboard. If it does 

not pass the sheen test then the water/oil mixture is pumped to a dirty oil tank and sent to shore for disposal. All 

waste oil that is sent in to be disposed of is recorded in the MODU’s oil log book.

All discharges will be in accordance with applicable NPDES permits. See Section 18, EIA. 

5) Lower Hull Bilge System 

 The main bilge system is designed to drain the pontoons. There are Goulds electrically driven, self-priming 

centrifugal pumps - one for each main pump room. The aux pumps can be pump out with the bilge pump 

but has to be lined up manually from the main pump room. 

 Bilge water is pumped overboard after a sheen test has been completed. 

Page 6 Public Information Copy
 The pontoon bilge pumps are operable from the Bridge and have audible and visual bilge alarms set for 

high and low levels. 

 Portable submersible pumps are carried onboard the rig to service all column void spaces and are also 

used for emergency bilge pumps in the event of the main pump room flooding. 

 Alternate means of pumping the bilges in each pontoon pump room include the use of: 

– The ballast system emergency bilge valve which is operated from the control panel. 

– Portable submersible pumps 

– Emergency bilge suction line connected directly to the ballast manifold. (Main Pump rooms only) 

The Bilge pumps are manual/automatic type pumps. They are equipped with sensors that give a high and a highhigh alarm. They are set to a point at which the water gets to a certain point they will automatically turn on to pump 

water out in order to keep flooding under control. The pumps are also capable of being put in manual mode in which 

they can be turned on by hand. 

6) Emergency Bilge System 

Main ballast pumps may also be used for emergency bilge pumping directly from the pump rooms via remotely 

actuated direct bilge suction valves on the ballast system. These valves will operate in a fully flooded compartment. 

The ballast pumps can be supplied from the emergency switchboard. 

7) Oily Water Drain/Separation System 

Oily water/engine room bilge water is collected in an oily water tank. It must be separated and not pumped 

overboard until oil content is <15 ppm. The separated oil is pumped to a dirty oil tank and has to be sent ashore for 

disposal. On board all drilling Units, an oil record log has to be kept according to instructions included in the log. The 

rig floor has two skimmer tanks and each is subjected to a sheen test before pumping overboard to ensure 

environmental safety. All three anchor winch windlasses have skimmer tanks and are subjected to sheen tests before 

discharge as well. 

8) Drain, Effluent and Waste Systems 

 The rig’s drainage system is designed in line with our environmental and single point discharge policies.

Drains are either hazardous, i.e. from a hazardous area as depicted on the Area Classification drawings, or 

non-hazardous drains from nonhazardous areas. 

 To prevent migration of hazardous materials and flammable gas from hazardous to non-hazardous areas, 

the drainage systems are segregated. 

 The rig drainage systems tie into oily water separators that take out elements in the drainage that could 

harm the environment. This is part of Noble’s initiative to be good stewards of the environment. 

9) Rig Floor Drainage 

The rig floor is typically outfitted with a Facet International MAS 34-3 separator. The separator has coalescent plates 

that remove the solids from the drainage and the remaining drainage goes to a skimmer tank. From the skimmer 

tank it is drained to one of the column dirty oil tank systems where it is then sent through 2 separators and cleaned 

further to reduce oil content to less than 15 ppm. 

10) Columns #3 & 4 

The drains on the decks and machinery spaces are separated at mid ship and directed to either the #3 or #4 

columns. The separators in these columns go through three cycles of circulation and remove oil to <15 ppm, then 

discharge the clean product to sea. 

11) Main Engine Rooms 

The engine rooms have their own drainage and handling system. The engine rooms are outfitted with a dirty oil tank 

and the drainage in the tank is processed through the separator, the waste from the separator goes back to the dirty 

oil tank and the clean water (<15 ppm) goes overboard. 

Page 7 Public Information Copy
12) Helideck Drains 

The helideck has a dedicated drainage system around its perimeter to drain heli-fuel from a helicopter incident. The 

fuel can be diverted to the designated heli fuel recovery tank which is located under the Helideck structure. 

Operating configurations are as follows: 

– The overboard piping valves and hydrocarbons take on valves are closed and locked. To unlock overboard or 

take on valves a permit has to be filled out. 

– The oily water collection tank overflow valve is closed. 

– The drill floor drains are lined-up to the drill floor skimmer tank. The skimmer tanks have a high alarm which 

sounds by means of an air horn. Before tanks are pumped out a sheen test is performed. Water is pumped

out the skimmer tanks down the shunt line. Oil containment side is pumped out into 550 gal tote tanks. 

– The BOP test area drains are normally lined-up to drain overboard. 

– The oily water separator continuously circulates the oily water collection tank. Waste oil is discharged into 

the waste oil tank and oily water is re-circulated back into the oily water collection tank. Clean water is 

pumped overboard, which is controlled/monitored by the oil content detector, set at 15 ppm. 

– The solids control system is capable of being isolated for cuttings collection. 

– The bilge system is normally pumped directly overboard after a sheen test has been performed. 

– The engine dirty oil sump can be drained down in port column oily water separator which discharges water 

overboard from the water side and oil being pumped out into a 550 gal tote tank oil containment side. There 

is a high audible alarm on the ballast control panel. 

D. Storage Tanks – Noble Jim Day DP Semi-Submersible or similar: 

Type of Storage Tank

Type of

Facility

Tank

Capacity 

(bbls)

Number 

of

Tanks

Total

Capacity 

(bbls)

Fluid

Gravity (Specific)

Diesel Tank in stbd 1 

80% fill in all hull tanks

Drilling Rig 3597 1 Marine Diesel (0.91 SG)

Diesel Tank in stbd 2 Drilling Rig 2713 1 Marine Diesel (0.91 SG)

Diesel Tank in stbd 3 Drilling Rig 3456 1 Marine Diesel (0.91 SG)

Diesel Tank in stbd 4 Drilling Rig 653 1 Marine Diesel (0.91 SG)

Diesel Tank in port 1 Drilling Rig 2090 1 Marine Diesel (0.91 SG)

Diesel Tank in port 2 Drilling Rig 1366 1 Marine Diesel (0.91 SG)

Diesel Tank in port 3 Drilling Rig 4787 1 Marine Diesel (0.91 SG)

Diesel Tank in port 4 Drilling Rig 3456 1 Marine Diesel (0.91 SG)

Total storage in hull 

tanks

Drilling Rig 22118 Marine Diesel (0.91 SG)

Diesel Settling Tanks Drilling Rig 129 1 Marine Diesel (0.91 SG)

Diesel Settling Tanks Drilling Rig 129 1 Marine Diesel (0.91 SG)

Diesel Settling Tanks Drilling Rig 139 1 Marine Diesel (0.91 SG)

Diesel Settling Tanks Drilling Rig 129 1 Marine Diesel (0.91 SG)

Diesel Day Tank Drilling Rig 100 1 Marine Diesel (0.91 SG)

Diesel Day Tank Drilling Rig 115 1 Marine Diesel (0.91 SG)

Diesel Day Tank Drilling Rig 114 1 Marine Diesel (0.91 SG)

Diesel Day Tank Drilling Rig 115 1 Marine Diesel (0.91 SG)

Total engine room diesel Drilling Rig 970 Marine Diesel (0.91 SG)

Lube Oil Tank Drilling Rig 86.25 4 345 Lube Oil (0.91 SG)

Page 8 Public Information Copy
Storage Tanks – Noble Don Taylor Drillship or similar: 

Type of Storage 

Tank

Type of

Facility

Tank

Capacity (bbls)

Number of

Tanks

Total

Capacity (bbls)

Fluid

Gravity (Specific)

Fuel oil Drilling Rig 2,889 4 11,556 Marine Diesel (0.91 SG)

Fuel oil Drilling Rig 3,225 4 12,900 Marine Diesel (0.91 SG)

Fuel oil Drilling Rig 2,887 4 11,548 Marine Diesel (0.91 SG)

Fuel oil Drilling Rig 2,680 4 10,720 Marine Diesel (0.91 SG)

Fuel oil Drilling Rig 178 8 1,424 Marine Diesel (0.91 SG)

E. Pollution Prevention Measures 

Pursuant to NTL 2008-G04 the proposed operations covered by this EP do not require Shell to specifically address 

the discharges of oil and grease from the rig during rainfall or routine operations. Nevertheless, Shell has provided 

this information as part of its response to 1(c) above. 

F. Additional Measures 

 

 HSE (health safety and environment) are the primary topics in pre-tour and pre-job safety meetings. The 

discussion around no harm to people or environment is a key mindset. All personnel are reminded daily to 

inspect work areas for safety issues as well as potential pollution issues. 

 All tools that come to and from the rig have their pollution pans inspected, cleaned and confirmation of 

plugs installed prior to leaving dock and prior to loading on the boat. 

 Preventive maintenance of rig equipment includes visual inspection of hydraulic lines and reservoirs on 

routine scheduled basis. 

 All pollution pans on rig are inspected daily. 

 Containment dikes are installed around all oil containment, drum storage areas, fuel vents and fuel storage 

tanks. 

 All used oil and fuel is collected and sent in for recycling. 

 Every drain on the rig is assigned a number on a checklist. The checklist is used daily to verify drain plugs 

are installed. 

 All trash containers are checked and emptied daily. The trash containers are kept covered. Trash is disposed 

of in a compactor and shipped in via boat. 

 The rig is involved in a recycling program for cardboard, plastic, paper, glass and aluminum.

 Fuel hoses and SBM are changed on annual basis. 

 TODO spill prevention fittings are installed on all liquid take on hoses. 

 Waste paint thinner is recycled on board with a solvent still to reduce hazard of shipping and storage. 

 All equipment on board utilizes Envirorite hydraulic fluid as opposed to hydraulic oil. 

 Shell has obtained ISO14001 certification. 

 Shell uses low sulfur fuel. 

G. Description of Previously Approved Lease Activities 

Shell does not have any previous activity on these leases. 

Page 9 Public Information Copy
Page 10 Public Information Copy
Page 11 Public Information Copy
Attachment 1B – Bottom Hole Locations 

Proprietary Data

Page 12 Public Information Copy
Attachment 1C 

U. S. Department of the Interior OMB Control Number: 1010-0151

Bureau of Ocean Energy Management OMB Approval Expires: 12/31/2014 

OCS PLAN INFORMATION FORM 

General Information

Type of OCS Plan: X Exploration Plan (EP) DOCD

Company Name: Shell Offshore Inc. BOEM Operator Number: 0689

Address: P. O. Box 61933 Contact Person: Tracy Albert

New Orleans, LA 70161-1933 Phone Number: (504) 425-4652

E-Mail Address: tracy.albert@shell.com

Lease(s): G33863 & G32556 Area: AT Block(s): 18 & 19 Project Name (If Applicable): DeepSleep

Objective(s): X Oil Gas Sulphur Salt Onshore Base: Fouchon/Boothville Distance to Closest Land (Miles): 70

Description of Proposed Activities (Mark all that apply)

X Exploration drilling Development drilling

Well completion Installation of production platform

Well test flaring (for more than 48 hours) Installation of production facilities

Installation of caisson or platform as well protection structure Installation of satellite structure

Installation of subsea wellheads and/or manifolds Commence production

Installation of lease term pipelines Other (Specify and describe) Pipeline appurtenance

Have you submitted or do you plan to submit a Conservation Information Document to accompany this plan? Yes X No

Do you propose to use new or unusual technology to conduct your activities? Yes X No

Do you propose any facility that will serve as a host facility for deepwater subsea development? Yes X No

Do you propose any activities that may disturb a BOEM-designated high-probability archaeological area? Yes X No

Have all of the surface locations of your proposed activities been previously reviewed and approved by BOEM? Yes X No

Tentative Schedule of Proposed Activities

Proposed Activity Start Date End Date No. of Days

See attached schedule

Description of Drilling Rig Description of Production Platform

Jackup X Drillship Caisson Tension leg platform

Gorilla Jackup Platform rig Well protector Compliant tower

Semisubmersible Submersible Fixed platform Guyed tower

X DP Semisubmersible Other (Attach Description) Subsea manifold Floating production system

Drilling Rig Name (If Known): Noble Jim Day (or similar)

 Noble Don Taylor (or similar) 

Spar Other (Attach Description)

Description of Lease Term Pipelines

From (Facility/Area/Block) To (Facility/Area/Block) Diameter (Inches) Length (Feet)

N/A

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.) 

 

Page 13 Public Information Copy
Attachment 1C (Continued) 

Proposed Schedule 

Proposed Activity Start Date End Date No. of Days

Drill Well A 3/15/2015 10/01/2015 200

Drill Well B 1/1/2016 7/16/2016 200

Drill Well C 1/1/2017 7/20/2017 200

Drill Well D 1/1/2018 7/20/2018 200

Drill Well E 1/1/2019 7/20/2019 200

Drill Well F 1/1/2020 7/19/2020 200

Drill Well G 1/1/2021 7/20/2021 200

Page 14 Public Information Copy
Attachment 1D

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): A Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 33863

Area Name Atwater Valley

Block No. 18

Blockline

Departures

(in feet)

N/S Departure: 1,083’ FNL

E/W Departure: 2,701’ FEL

Lambert X-Y 

coordinates

X: 979,379 

Y: 10,152,357 

Latitude/

Longitude

Latitude 27° 57' 41.060"

Longitude -89° 02' 53.547"

TVD (Feet): MD (Feet): Water Depth (Feet): 4,253’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 15 Public Information Copy
Attachment 1E 

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): B Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 33863

Area Name Atwater Valley

Block No. 18

Blockline

Departures

(in feet)

N/S Departure: 2,735’ FNL

E/W Departure: 2,715’ FEL

Lambert X-Y 

coordinates

X: 979,365

Y: 10,150,705

Latitude/

Longitude

Latitude 27° 57' 24.703"

Longitude -89° 02' 53.394"

TVD (Feet): MD (Feet): Water Depth (Feet): 4,219’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 16 Public Information Copy
Attachment 1F 

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): C Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 32556

Area Name Atwater Valley

Block No. 19

Blockline

Departures

(in feet)

N/S Departure: 3,108’ FNL

E/W Departure: 620’ FWL

Lambert X-Y 

coordinates

X: 982,700

Y: 10,150,332

Latitude/

Longitude

Latitude 27° 57' 21.563"

Longitude -89° 02' 16.145"

TVD (Feet): MD (Feet): WD (Feet): 4,268’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 17 Public Information Copy
Attachment 1G 

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): D Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 33863

Area Name Atwater Valley

Block No. 18

Blockline

Departures

(in feet)

N/S Departure: 3,871’ FNL

E/W Departure: 2,430’ FEL

Lambert X-Y 

coordinates

X: 979,650

Y: 10,149,569

Latitude/

Longitude

Latitude 27° 57' 13.505"

Longitude -89° 02' 50.004"

TVD (Feet): MD (Feet): WD (Feet): 4,203’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 18 Public Information Copy
Attachment 1H 

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): E Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 33863

Area Name Atwater Valley

Block No. 18

Blockline

Departures

(in feet)

N/S Departure: 2,637’ FNL

E/W Departure: 3,692’ FEL

Lambert X-Y 

coordinates

X: 978,388

Y: 10,150,803

Latitude/

Longitude

Latitude 27° 57' 25.511"

Longitude -89° 03' 04.304"

TVD (Feet): MD (Feet): WD (Feet): 4,208’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 19 Public Information Copy
Attachment 1I 

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): F Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 32556

Area Name Atwater Valley

Block No. 19

Blockline

Departures

(in feet)

N/S Departure: 7,819’ FNL

E/W Departure: 6,291’ FWL

Lambert X-Y 

coordinates

X: 988,371

Y: 10,145,621

Latitude/

Longitude

Latitude 27° 56' 35.857"

Longitude -89° 01' 12.055"

TVD (Feet): MD (Feet): MD (Feet): 4,285’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 20 Public Information Copy
Attachment 1J 

OCS PLAN INFORMATION FORM (CONTINUED) 

Include one copy of this page for each proposed well/structure 

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or structure, reference previous name): G Subsea Completion

Anchor Radius (if applicable) in feet: NA Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 32556

Area Name Atwater Valley

Block No. 19

Blockline

Departures

(in feet)

N/S Departure: 7,914’ FNL

E/W Departure: 9,139’ FWL

Lambert X-Y 

coordinates

X: 991,219

Y: 10,145,526

Latitude/

Longitude

Latitude 27° 56' 35.382"

Longitude -89° 00' 40.291"

TVD (Feet): MD (Feet): WD (Feet): 4,432’

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No.

Area Block X Coordinate Y Coordinate Length of Anchor Chain on 

Seafloor

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that 

BOEM collects this information as part of an applicant’s Exploration Plan or Development Operations Coordination Document submitted for 

BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the 

Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection 

of information unless it displays a currently valid Office of Management and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). 

The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination 

Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, 

including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart 

B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of 

Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

Form BOEM-0137 (December 2011-Supercedes all previous editions of form BOEM-0137 which may not be used.)

Page 21 Public Information Copy
SECTION 2: GENERAL INFORMATION 

A. Application and Permits 

There are no individual or site-specific permits other than general NPDES outfall number, rig move notification, and 

Application for Permit to Drill (APD) that need to be obtained. Prior to beginning exploration operations, an APD 

will be submitted and approved by the Bureau of Safety and Environmental Enforcement (BSEE). 

B. Drilling Fluids 

See Section 7, Table 7A for a list of drilling fluids to be used. 

C. Production 

Information regarding production is not included in this EP as such information is only necessary in the case of 

DOCDs. 

D. Oil Characteristics 

Information regarding oil characteristics is not included in this EP as such information is only necessary in the 

case of DOCDs. 

E. New Or Unusual Technology 

Shell is not proposing to use new or unusual technology as defined in 30 CFR 250.200 to carry out the proposed 

activities in this EP. 

F. Bonding 

The bond requirement for the activities proposed in this EP are satisfied by an area-wide bond furnished and 

maintained according to 30 CFR Part 256, Subpart I-Bonding; NTL No. 2000-G16, “Guideline for General Lease 

Surety Bonds” and additional security under 30 CFR 256.53(d) and National NTL No. 2008-N07, “Supplemental 

Bond Procedures.”

G. Oil Spill Financial Responsibility (OSFR) 

Shell Offshore Inc., BOEM Operator Number 0689, has demonstrated oil spill financial responsibility for the 

activities proposed in this EP according to 30 CFR Parts 250 and 253 and NTL No. 2008-N05, “Guidelines for Oil 

Spill Financial Responsibility for Covered Facilities.”

H. Deepwater well control statement 

Shell Offshore Inc., BOEM Operator Number 0689, has the financial capability to drill a relief well and conduct other 

emergency well control operations if required. 

I. Suspension of Production 

Information regarding Suspension of Production is not included in this EP as such information is only necessary 

in the case of DOCDs. 

Page 22 Public Information Copy
J. Summary 

This Section 2j was prepared by Shell pursuant to the guidance provided in the BOEM’s NTL 2010-N06 with respect 

to blowout and worst case discharge (WCD) scenario descriptions. Shell intends to comply with all applicable laws, 

regulations, rules and Notices to Lessees. 

Shell focuses on an integrated, three-pronged approach to a blowout, including prevention, intervention, 

containment, and recovery. 

1. Shell believes that the best way to manage blowouts is to prevent them from happening. Significant 

effort goes into design and execution of wells and into building and maintaining staff competence. Shell 

continues to invest independently in R&D to improve safety and reliability of our well systems. 

2. Shell is a founding member of the MWCC, which provides robust well containment (shut-in and 

controlled flow) capabilities. Additionally, Shell is investing in R&D to improve containment systems. 

3. As outlined in Shell’s OSRP, and detailed in EP Section 9a (ii), Shell has contracts with OSROs to provide 

the resources necessary to respond to this WCD scenario. The capabilities for on-water recovery, aerial 

and subsea dispersant application, in-situ burning, and nighttime monitoring and tracking have been 

significantly increased. 

The WCD blowout scenario for this plan is calculated for the AT 18 Well A location penetration of the target interval 

and is based on the guidelines outlined in NTL 2010-N06 along with subsequent Frequently Asked Questions (FAQ). 

Shell’s Regional OSRP (April 2013/December 2014) is based on MC 811 Well 001 as the WCD well. In the unlikely 

event of a spill, Shell’s Regional OSRP is designed to contain and respond to a spill that exceeds this WCD. This WCD 

does not take into account potential flow mitigating factors such as well bridging, obstructions in wellbore, reservoir 

barriers, and early intervention including containment capabilities. 

Uncontrolled blowout (volume first day) 22,250 bbl. oil

Uncontrolled blowout rate (first 30-days average daily rate) 22,370 bopd 

Duration of flow (days) based on relief well 210 days

Total volume of spill (bbls) for 210 days 4.8 MMBO

Table 2.1. DeepSleep Worst Case Discharge Summary

The exploration prospect is located approximately 70 statute miles south-southeast of the nearest Louisiana 

shoreline in the Gulf of Mexico, in water depths of 4186-4708’ across the prospect. The prospect is a stratigraphic 

pinchout onto a salt high to the south and synclinally separated from the Vito and PowerNap wells. The objective 

interval for the proposed well with flow potential is the AT 18 location A well, expected to have the highest flow 

rates in the basis of its penetration point at the reservoir will encounter the thicker sand package and the higher 

pressure are expected, the rest of the locations planned for this EP are up dip from this well. 

1) Purpose 

Pursuant to 30 CFR 250.213(g), 250.219, 250.250, and NTL 2010-N06, this document provides a blowout scenario 

description, further information regarding any potential oil spill, the assumptions and calculations used to determine 

the WCD and the measures taken to 1) enhance the ability to prevent a blowout and 2) respond and manage a 

blowout scenario if it were to occur. These calculations are based on best technical estimates of subsurface 

parameters that are derived from the regional formation of offset well data and seismic data. These parameters are 

better than or consistent with the estimates used by Shell to justify the investment. Therefore, these assumed 

parameters were used to calculate the WCD. They do not reflect probabilistic estimates. 

Page 23 Public Information Copy
2) Background 

This attachment has been developed to document the additional information requirements for EPs as requested by 

NTL No. 2010-N06 in response to the explosion and sinking of the MODU Deepwater Horizon and the resulting 

subsea well blowout and recovery operations of the exploration well at the MC-252 Macondo location. 

3) Information Requirements 

a) Blowout scenario 

All well locations addressed in this EP were assessed for WCD. The AT-18 well from the A location represents the 

highest flow potential. The A well penetrates the Miocene objective interval as outlined in the Geological and 

Geophysical Information Section of the EP using a subsea wellhead system, conductor, surface and intermediate 

casing program, and using a DP MODU with a marine riser and subsea blowout preventer (BOP). A hydrocarbon 

influx and a well control event are modeled to occur from reservoirs in the objective interval. The modeled blowout 

results in unrestricted flow from the well at the seafloor, which represents the WCD (no restrictions in wellbore, 

failure/loss of the subsea BOP, and a blowout to the seabed). 

b) Estimated flow rate of the potential blowout 

Category EP 

Type of Activity Drilling 

Facility Location (area/block) AT 18 

Facility Designation MODU 

Distance to Nearest Shoreline (Statute miles) 70

Uncontrolled blowout (volume first day) 65,915 bbl. oil

Uncontrolled blowout rate (first 30-days average daily rate) 65,300 bopd

Table 2.2 Estimated Flow Rates of a Potential Blowout 

c) Total volume and maximum duration of the potential blowout 

Duration of flow (days) 210 days total duration to drill relief well 

(14 days rig demobilization, 6 days rig mobilization, 160 days spud 

to TD, 30 days ranging).

Total volume of spill (bbls) 12.96 MMBO based on 210 days flowing. 

Note: From GAP/Prosper/MBAL model

Table 2.3 Estimated Duration and Volume of a Potential Blowout 

There is usually a decline in the discharge rate as time proceeds, which is illustrated by the differences between the 

first 24-hour volume and 30-day average rate. The total volume calculated until a well is killed in a potential blowout 

further demonstrates this decline. At very short times, e.g. during the first 24 hours, the pressure profile in the 

reservoir changes from the moment when a well first starts flowing to a pseudo-steady state pressure profile with 

time, and as a result the rate declines. At somewhat longer time scales, effects such as reservoir voidage and the 

impact of boundaries can cause the rate to drop continuously with production. Simulation and material balance 

models can include these effects and form the basis of the NTL 2015-N01 calculations for 24-hour and 30-day rates 

as well as maximum duration volumes. 

Page 24 Public Information Copy
d) Assumptions and calculations used in determining the worst case discharge (Proprietary) 

e) Potential for the well to bridge over 

Mechanical failure/collapse of the borehole in a blowout scenario is influenced by several factors including in-situ 

stress, rock strength and fluid velocities at the sand base. Based on the nodal analysis and reservoir simulation 

models outlined above, a seabed blowout would create a high drawdown at the sand face. Given the substantial 

fluid velocities inherent in the worst case discharge, and the scenario as defined where the formation is not 

supported by a cased and cemented wellbore, it is possible that the borehole may fail/collapse/bridge over within 

the span of a few days, significantly reducing the outflow rates. However, this WCD scenario does not include any 

bridging. 

f) Likelihood for intervention to stop the blowout. 

Safety of operations is our top priority. Maintaining well control at all times to prevent a blowout is the key focus of 

our operations. Our safe drilling record is based on our robust standards, conservative well design, prudent 

operations practices, competency of personnel, and strong HSE focus. Collectively, these constitute a robust system 

making blowouts extremely rare events. 

Intervention Devices: Notwithstanding these facts, the main scenario for recovery from a blowout event is via 

intervention with the BOP attached to the well. There are built in redundancies in the BOP system to allow activation 

of selected components with the intent to seal off the well bore. As a minimum, the Shell contracted rig fleet in the 

GOM will have redundancies meeting the Interim Final Drilling Safety Rule with respect to Remotely Operated 

Vehicle (ROV) hot stab capabilities, a deadman system, and an autoshear system. 

The rig that will be used to drill the well will be equipped with BOP stack that complies with Shell and BSEE 

standards. 

Containment: The experience of gaining control over the Macondo well has resulted in a better understanding 

of the necessary equipment and systems for well containment. As a result, industry and government are better 

equipped and prepared today to contain an oil well blowout in deepwater. Shell is further analyzing these advances 

and incorporating them into its comprehensive approach to help prevent and, if needed, control another deepwater 

control incident. 

Pursuant to NTL 2010-N10 Shell will provide additional information regarding our containment capabilities in a 

subsequent filing. 

g) Availability of a rig to drill a relief well and rig package constraints 

Blowout intervention can be conducted from an ROV equipped vessel, the existing drilling rig or from another drilling 

rig. Shell has an active portfolio of well operations in the GOM which will be supported by a total of four to six MODU 

rigs in 2015 – 2020 timeframe. The dynamically positioned rigs under contract, the Noble Jim Day, Noble 

Globetrotter I, and the Noble Bully I will be the preferred rigs for blowout intervention work. However, moored rigs, 

like the Transocean Deepwater Nautilus, can also be used in some scenarios. Additionally, in the event of a blowout, 

there is the distinct possibility that other non-contracted rigs in the GOM could be utilized whether for increased 

expediency or better suitability. All efforts will be made at the time to secure the appropriate rig. Shell’s current 

contracted rigs capable of operating at DeepSleep water depths and reservoir depths without constraints are in the 

following table: 

Page 25 Public Information Copy
Rig Name Rig Type

Noble Jim Day Dynamically positioned semisubmersible

Noble Globetrotter I Dynamically positioned drillship

Noble Bully I Dynamically positioned drillship

Transocean Deepwater Nautilus Moored semisubmersible

Stena Ice Max Dynamically positioned drillship

Table 2.4 Shell contracted rigs capable at DeepSleep 

Future modifications may change the rig’s capability. Rig capabilities need to be assessed on a work scope specific 

basis. 

h) Time taken to contract a rig, move it onsite, and drill a relief well 

Relief well operations will immediately take priority and displace any activity from Shell’s contracted rig fleet. Table 

2.4 lists the Shell contracted rigs capable of operating at DeepSleep. It is expected to take an average of 14 days to 

safely secure the well that the rig is working on up to the point the rig departs location, and an additional 4 days 

transit to mobilize to the relief well site depending on distance to the site. The relief well will take approximately 160

days to drill down to the last casing string above the blowout zone, plus approximately 30 days for precision ranging 

activity to intersect the blowout well bore. The total time to mobilize and drill a relief well would be 210 days for the 

DeepSleep well. 

If a moored rig is chosen to conduct the relief well operations, anchor handlers would be prioritized to prepare 

mooring on the relief well site while the rig is being mobilized. This mooring activity is not expected to delay 

initiation of relief well drilling operations. Shell has deepwater anchor handlers on long term contract to support its 

moored rigs. 

It is not possible to drill relief wells from any existing platforms due to the distance to reach the sub-surface. 

i) Measures proposed to enhance ability to prevent blowout and to reduce likelihood of a blowout. 

Shell believes that the best way to manage blowouts is to prevent them from happening. Detailed below are the 

measures employed by Shell with the goal of no harm to people or the environment. The Macondo incident has 

highlighted the importance of these practices. The lessons learned from the investigation are, and will continue to 

be, incorporated into our operations. 

Standards: Shell’s well design and operations adhere to internal corporate standards, the Code of Federal 

Regulations, and industry standards. A robust management of change process is in place to handle un-defined or 

exception situations. Ingrained in the Shell standards for well control is the philosophy of multiple barriers in the well 

design and operations on the well. 

Risk Management: Shell believes that prevention of major incidents is best managed through the systematic 

identification and mitigation process (Safety Case). All Shell contracted rigs in the GOM have been operating with a 

Safety Case and will continue to do so. A Safety Case requires both the owner and contractors to systematically 

identify the risks in drilling operations and align plans to mitigate those risks; an alignment which is critical before 

drilling begins. 

Well Design Workflow: The Well Delivery Process (WDP) is a rigorous internal assurance process with defined 

decision gates. The WDP leverages functional experts (internal and external) to examine the well design at the 

conceptual and detailed design stages for robustness before making a recommendation to the management review 

board. Shell’s involvement in global deepwater drilling, starting in the GOM in the mid-1980’s, provides a significant 

depth and breadth of internal drilling and operational expertise. Third party vendors and rig contractors are involved 

Page 26 Public Information Copy
in all stages of the planning, providing their specific expertise. A Drill the Well on Paper (DWOP) exercise is 

conducted with rig personnel and vendors involved in execution of the well. This forum communicates the well plan, 

and solicits input as to the safety of the plan and procedures proposed. 

Well and rig equipment qualification, certification, and quality assurance: All rigs will meet all applicable 

rules, regulations, and Notice to Lessees. Shell works closely with rig contractors to ensure proper upkeep of all rig 

equipment, which meets or exceeds the strictest of Shell, industry, or regulatory requirements. Well tangibles are 

governed by our internal quality assurance/control standards and industry standards. 

MWD/LWD/PWD Tools: Shell intends to use these tools at DeepSleep. The MWD/LWD/PWD tools are run on the 

drill string so that data on subsurface zones can be collected as the well advances in real time instead of waiting 

until the drill string is pulled to run wireline logs. Data from the tools are monitored and interpreted real time against 

prognosis to provide early warning of abnormal pressures to allow measures to be taken to progress the well safely. 

Mud Logger: Mud-logging personnel continually monitor returning drilling fluids for indications of hydrocarbons, 

utilizing both a hot wire and a gas chromatograph. An abrupt increase in gas or oil carried in the returning fluid can 

be an indication of an impending kick. The mud logger also monitors drill cuttings returned to the surface in the 

drilling fluid for changes in lithology that can be an indicator that the well has penetrated or is about to penetrate a 

hydrocarbon-bearing interval. Mud logging instruments also monitor penetration rate to provide an early indication 

of drilling breaks that show the bit penetrating a zone that could contain hydrocarbons. The mud logging personnel 

are in close communication with both the offshore drilling foremen and onshore Shell representative(s) to report any 

observed anomalies so appropriate action can be taken.

Remote Monitoring: The Real Time Operating Center has been used by Shell to complement and support 

traditional rig-site monitoring since 2003. Well site operations are monitored 24/7 virtually by onshore teams 

consisting of geoscientists, petrophysicists, well engineers, and monitoring specialists. The same real time well 

control indicators monitored by the rig personnel are watched by the monitoring specialist for an added layer of 

redundancy. 

Competency and Behavior: A structured training program for Well Engineers and Foremen is practiced, which 

includes internal professional examinations to verify competency. Other industry training in well control, such as by 

International Association of Drilling Contractors (IADC) and International Well Control Forum (IWCF) are also 

mandated. Progressions have elements of competency and Shell continues to have comprehensive internal training 

programs. The best systems and processes can be defeated by lack of knowledge and/or improper values. We 

believe that a combination of HSE tools (e.g. stop work, pre-job analysis, behavior based safety, DWOPs, audits), 

management HSE involvement and enforcement (e.g. compliance to life saving rules) have created a strong safety 

culture in our operations. 

j) Measures to conduct effective and early intervention in the event of a blowout. 

The response to a blowout is contained in our Well Control Contingency Plan (WCCP) which is a specific requirement 

of our internal well control standards. The WCCP in turn is part of the wider emergency response framework within 

Shell that addresses the overall organization response to an emergency situation. Resources are dedicated to these 

systems and drills are run frequently to test preparedness (security, medical, oil spill, and hurricane). This same 

framework is activated and tested during hurricane evacuations, thereby maintaining a fresh and responsive team. 

The WCCP specifically addresses implementing actions at the emergency site that will ensure personnel safety, 

organizing personnel and their roles in the response, defining information requirements, establishing protocols to 

mobilize specialists, pre-selecting sources, and developing mobilization plans for personnel, material and services for 

well control procedures. The plan references individual activity checklists, a roster of equipment and services, initial 

information gathering forms, a generic description of relief well drilling, strategy and guidelines, intervention 

techniques and equipment, site safety management, exclusion zones, and re-boarding. 

As set forth in 3f of this document, Shell is currently analyzing recent advances in containment technology and 

equipment and will incorporate them as they become available. 

Page 27 Public Information Copy
k) Arrangements for drilling a relief well 

The size of the Shell contracted rig fleet in the GOM from 2015-2020 ensures that there is adequate well equipment 

(e.g. casing and wellhead) available for relief wells. Rigs and personnel will also be readily available within Shell, 

diverted from their active roles elsewhere. Resources from other operators can also be leveraged should the need 

arise. Generally, relief well plans will mirror the blowout well, incorporating any learning on well design based on 

root cause analysis of the blowout. A generic relief well description is outlined in the WCCP. 

l) Assumptions and calculations used in Regional OSRP 

All proposed DeepSleep locations were evaluated and Location A was determined to have the greatest WCD volume. 

Shell has designed a response program (Regional OSRP) based upon a regional capability of responding to a range 

of spill volumes, from small operational spills up to and including the WCD from a well blowout. Shell’s program is 

developed to fully satisfy federal oil spill planning regulations. The Regional OSRP presents specific information on 

the response program that includes a description of personnel and equipment mobilization, the incident 

management team organization and the strategies and tactics used to implement effective and sustained spill 

containment and recovery operations. 

Page 28 Public Information Copy
SECTION 3: GEOLOGICAL AND GEOPHYSICAL INFORMATION 

A. Geological description 

Proprietary 

B. Structure Contour Map(s) 

Proprietary 

C. Interpreted 2D and/or 3D Seismic line(s) 

Proprietary 

D. Geological Structure Cross-section(s) 

Proprietary 

E. Stratigraphic Column with Time vs Depth Table 

Proprietary 

F. Shallow Hazards Report 

The following report was used for our analysis: 

Gardline Surveys, Inc. “3D Geohazard Assessment, Gulf of Mexico, Atwater Valley, Blocks AT018 and AT019, 

Stromboli Prospect”, Report #9172, Dated August 3, 2012. Data: frequency enhanced 3-D seismic 

C&C Technologies, “Archaeological Assessment Report, Blocks 18 (OCS-G 33863) and 19 (OCS-G 32556), 

Atwater Valley Area, Gulf of Mexico”, Report No. 120015, Dated May 2012. Data: AUV Side Scan Sonar and 

Sub-bottom Profiler 

G. Shallow Hazards Assessment

Proprietary. See Section 6 for a detailed Shallow Hazards assessment of the wells proposed in this plan. 

H. Geochemical Information 

This information is not required for plans submitted in the GOM Region. 

I. Future G&G Activities 

This information is not required for plans submitted in the GOM Region. 

 

Page 29 Public Information Copy
SECTION 4: HYDROGEN SULFIDE (H2S) 

 Concentration 

<5 ppm

 Classification 

 

Based on 30 CFR 550.215, Shell requests that the Regional Supervisor, Field Operations, classify the area in the 

proposed drilling operations as H2S absent. 

 H2S Contingency Plan 

Shell is not required to provide an H2S Contingency Plan with the Application for Permit to Drill before conducting the 

proposed exploration activities. 

 Modeling Report 

We do not anticipate to encounter or handle H2S at concentrations greater than 500 parts per million (ppm) and 

therefore have not included modeling for H2S.

Page 30 Public Information Copy
SECTION 5: MINERAL RESOURCE CONSERVATION INFORMATION 

Information regarding Mineral Resource Conservation is not included in this EP as such information is only necessary in 

the case of DOCDs. 

Page 31 Public Information Copy
SECTION 6: BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION 

A. Chemosynthetic Communities Report 

Shallow Hazards Report and Data 

Gardline Surveys, Inc. “3D Geohazard Assessment, Gulf of Mexico, Atwater Valley, Blocks AT018 and AT019, 

Stromboli Prospect”, Report #9172, Dated August 3, 2012. Data: frequency enhanced 3-D seismic 

Proposed Locations and Coordinates: 

Proposed Location X Y Water Depth

AT 18, Proposed Location A 979379 10152357 4253’

AT 18, Proposed Location B 979365 10150705 4219’

AT 19, Proposed Location C 982700 10150332 4268’

AT 18, Proposed Location D 979650 10149569 4203’

AT 18, Proposed Location E 978388 10150803 4208’

AT 19, Proposed Location F 988371 10145621 4285’

AT 19, Proposed Location G 991219 10145526 4432’

Coordinates are in UTM 16, NAD27 

Atwater Valley 18, Proposed Location A 

Atwater Valley 18, Proposed Location A is located in a water depth of approximately 4253’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 18, Proposed Location A consists of: 

 Unit 1 (Seafloor – 612’ BML) - 612’ of soft hemipelagic silty muds with thin mud-rich mass transport 

deposits (MTD’s)

 Unit 2 (612’ – 1321’ BML) – 709’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

 Unit 3 – Blue Unit (1321’ – 2295’ BML) – 975’ of canyon margin rotated slides, interbedded with 

sands and muds 

 Unit 4 (2295’ – 2534’ BML) – 238’ of highly deformed stratigraphy, predominantly mud rocks

 Unit 5 is not present in this proposed wellsite 

 Unit 6a (2534’ – 3161’ BML) – 253’ of MTD’s, predominantly mud rocks, over 374’ of slope fan 

sequence of interbedded thin sands and mud rocks 

 Unit 6b (3161’ – 3622’ BML) – 461’ of muds with some silts and minor sands 

 Unit 7 (3622’ – 6776’ BML) – 3154’ of thin sands and muds in the upper part, muds in the middle and 

muds and thin sands in the lower part of the unit 

Shallow Water Flow Potential: 

 Low Potential – Seafloor – 612’ BML

 Moderately Low Potential – 612’ – 1321’ BML

 Moderately High Potential – 1321’ – 2295’ BML

 Moderately Low Potential – 2295’ – 2787’ BML

 Moderately High Potential – 2787’ – 3161’ BML

 Moderate Potential – 3161’ – 3622’ BML

 Moderately Low Potential – 3622’ – 6776’ BML

 

Shallow Gas Potential: 

 Low Potential – Seafloor – 1321’ BML

 Moderately Low Potential – 1321’ – 2295’ BML

Page 32 Public Information Copy
 Low Potential – 2295’ – 2787’ BML

 Moderately High Potential – 2787’ – 3161’ BML

 Moderately Low Potential – 3161’ – 6776’ BML

There are no amplitude anomalies identified within 250’ of AT 18, Proposed Location A.

AT 18, Proposed Location A will be positioned 728’ from BHP’s previously drilled AT 18-1 wellsite. Proposed 

Location A will not interfere with this previously drilled wellsite. 

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location A.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location A appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 18, proposed Location A (no anchors – DP Vessel) 

Atwater Valley 18, Proposed Location A is located in a water depth of approximately 4253’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 18, Proposed Location A will not disturb any high-density areas of benthic 

communities. 

The following table is a list of marine avoidance zones identified within 2000’ of AT 18, Proposed Location A: 

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc A

Direction from 

Prop Loc A

11 100’ 979907.25 10151893.00 703.10’ Southeast

12 100’ 979994.56 10151647.00 939.69’ Southeast

AT 18, Proposed Location A will be positioned 728’ from Anadarko’s previously drilled AT 18-1 wellsite. 

Proposed Location A will not interfere with this previously drilled wellsite. 

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location A.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location A appears suitable for the planned activity. 

Atwater Valley 18, Proposed Location B 

Atwater Valley 18, Proposed Location B is located in a water depth of approximately 4219’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 18, Proposed Location B consists of: 

 Unit 1 (Seafloor – 658’ BML) - 658’ of soft hemipelagic silty muds with thin mud-rich mass transport 

deposits (MTD’s)

 Unit 2 (658’ – 1214’ BML) – 556’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

 Unit 3 – Blue Unit (1214’ – 2090’ BML) – 876’ of canyon margin rotated slides, interbedded with 

sands and muds 

 Unit 4 (2090’ – 2352’ BML) – 262’ of highly deformed stratigraphy, predominantly mud rocks

 Unit 5 is not present in this proposed location 

 Unit 6a (2352’ – 3012’ BML) – 660’ slope fan sequence of interbedded thin sands and mud rocks 

 Unit 6b (3012’ – 3449’ BML) – 437’ of muds with some silts and minor sands

Page 33 Public Information Copy
 Unit 7 (3449’ – 6726’ BML) – 3277’ of thin sands and muds in the upper part, muds in the middle and 

muds and thin sands in the lower part of the unit 

Shallow Water Flow Potential: 

 Low Potential – Seafloor – 658’ BML

 Moderately Low Potential – 658’ – 1214’ BML

 Moderately High Potential – 1214’ – 2090’ BML

 Moderately Low Potential – 2090’ – 2352’ BML

 Moderately High Potential – 2352’ – 3012’ BML

 Moderate Potential – 3012’ – 3449’ BML

 Moderately Low Potential – 3449’ – 6726’ BML

 

Shallow Gas Potential: 

 Low Potential – Seafloor – 1214’ BML

 Moderately Low Potential – 1214’ – 2090’ BML

 Low Potential – 2090’ – 2352’ BML

 Moderately High Potential – 2352’ – 3012’ BML

 Moderately Low Potential – 3012’ – 6726’ BML

There are no amplitude anomalies identified within 250’ of AT 18, Proposed Location B.

AT 18, Proposed Location B will be positioned 1534’ from BHP’s previously drilled AT 18-1 wellsite. Proposed 

Location B will not interfere with this previously drilled wellsite. 

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location B.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location B appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 18, Proposed Location B (no anchors – DP Vessel) 

Atwater Valley 18, Proposed Location B is located in a water depth of approximately 4219’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 18, Proposed Location B will not disturb any high-density areas of benthic 

communities. 

The following table is a list of marine avoidance zones identified within 2000’ of AT 18, Proposed Location B: 

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc B

Direction from 

Prop Loc B

12 100’ 979994.56 10151647.00 1133.01’ Northeast

11 100’ 979907.25 10151893.00 1305.90’ Northeast

AT 18, Proposed Location B will be positioned 1534’ from Anadarko’s previously drilled AT 18-1 wellsite. 

Proposed Location B will not interfere with this previously drilled wellsite. 

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location B.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location B appears suitable for the planned activity. 

Page 34 Public Information Copy
Atwater Valley 19, Proposed Location C 

Atwater Valley 19, Proposed Location C is located in a water depth of approximately 4267.5’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 19, Proposed Location C consists of: 

 Unit 1 (Seafloor – 568.5’ BML) – 568.5’ of soft hemipelagic silty muds with thin mud-rich mass 

transport deposits (MTD’s)

 Unit 2 (568.5’ – 1164.5’ BML) – 596’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

 Unit 3 – Blue Unit (1164.5’ – 2100.5’ BML) – 936’ of canyon margin rotated slides, interbedded with 

sands and muds 

 Unit 4 (2100.5’ – 2436.5’ BML) – 336’ of highly deformed stratigraphy, predominantly mud rocks 

 Unit 5 is not present in this proposed wellsite 

 Unit 6a (2436.5’ – 3026.5’ BML) – 288’ of MTD’s, predominantly mud rocks, over 302’ of slope fan 

sequence of interbedded thin sands and mud rocks 

 Unit 6b (3026.5’ – 3481.5’ BML) – 455’ of muds with some silts and minor sands

 Unit 7 (3481.5’ – 6367.5’ BML) – 2886’ of thin sands and muds in the upper part, muds in the middle 

and muds and thin sands in the lower part of the unit 

Shallow Water Flow Potential: 

 Low Potential – Seafloor – 568.5’ BML

 Moderately Low Potential – 568.5’ – 1164.5’ BML

 Moderately High Potential – 1164.5’ – 2100.5’ BML

 Moderately Low Potential – 2100.5’ – 2724.5’ BML

 Moderately High Potential – 2724.5’ – 3026.5’ BML

 Moderate Potential – 3026.5’ – 3481.5’ BML

 Moderately Low Potential – 3481.5’ – 6367.5’ BML

Shallow Gas Potential: 

 Low Potential – Seafloor – 1164.5’ BML

 Moderately Low Potential – 1164.5’ – 2100.5’ BML

 Low Potential – 2100.5’ – 2724.5’ BML

 Moderately High Potential – 2724.5’ – 3026.5’ BML

 Moderately Low Potential – 3026.5’ – 6367.5’ BML

There are no amplitude anomalies identified within 250’ of AT 19, Proposed Location C.

There are no previously drilled wellsites within 2000’ of AT 19, Proposed Location C.

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 19, Proposed Location C.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 19, Proposed Location C appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 19, Proposed Location C (no anchors – DP Vessel) 

Atwater Valley 19, Proposed Location C is located in a water depth of approximately 4267.5’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 19, Proposed Location C will not disturb any high-density areas of benthic 

communities. 

Page 35 Public Information Copy
The following table is a list of marine avoidance zones identified within 2000’ of AT 19, Proposed Location C: 

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc C

Direction from 

Prop Loc C

19 100’ 982804.56 10148461.00 1873.92’ South

There are no previously drilled wellsites within 2000’ of AT 19, Proposed Location C.

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 19, Proposed Location C.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 19, Proposed Location C appears suitable for the planned activity. 

Atwater Valley 18, Proposed Location D 

Atwater Valley 18, Proposed Location D is located in a water depth of approximately 4203’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 18, Proposed Location D consists of: 

 Unit 1 (Seafloor – 667’ BML) - 667’ of soft hemipelagic silty muds with thin mud-rich mass transport 

deposits (MTD’s)

 Unit 2 (667’ – 1349’ BML) – 682’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

 Unit 3 – Blue Unit (1349’ – 1820’ BML) – 471’ of canyon margin rotated slides, interbedded with 

sands and muds 

 Unit 4 (1820’ – 2279’ BML) – 459’ of highly deformed stratigraphy, predominantly mud rocks 

 Unit 5 is not present in this proposed location 

 Unit 6a (2279’ – 2893’ BML) – 614’ slope fan sequence of interbedded thin sands and mud rocks

 Unit 6b (2893’ – 3357’ BML) – 464’ of muds with some silts and minor sands

 Unit 7 (3357’ – 6492’ BML) – 3135’ of thin sands and muds in the upper part, muds in the middle and 

muds and thin sands in the lower part of the unit 

Shallow Water Flow Potential: 

 Low Potential – Seafloor – 667’ BML

 Moderately Low Potential – 667’ – 1349’ BML

 Moderately High Potential – 1349’ – 1820’ BML

 Moderately Low Potential – 1820’ – 2279’ BML

 Moderately High Potential – 2279’ – 2893’ BML

 Moderate Potential – 2893’ – 3357’ BML

 Moderately Low Potential – 3357’ – 6492’ BML

 

Shallow Gas Potential: 

 Low Potential – Seafloor – 1349’ BML

 Moderately Low Potential – 1349’ – 1820’ BML

 Low Potential – 1820’ – 2279’ BML

 Moderately High Potential – 2279’ – 2893’ BML

 Moderately Low Potential – 2893’ – 6492’ BML

There are no amplitude anomalies identified within 250’ of AT 18, Proposed Location D. 

There are no previously wells located within 2000’ of AT 18, Proposed Location D.

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location D.

Page 36 Public Information Copy
Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location D appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 18, Proposed Location D (no anchors – DP Vessel) 

Atwater Valley 18, Proposed Location D is located in a water depth of approximately 4203’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 18, Proposed Location D will not disturb any high-density areas of benthic 

communities. 

The following table is a list of marine avoidance zones identified within 2000’ of AT 18, Proposed Location D: 

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc D

Direction from 

Prop Loc D

18 100’ 980653.88 10148709.00 1321.88’ Southeast

There are no previously wells located within 2000’ of AT 18, Proposed Location D.

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location D.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location D appears suitable for the planned activity. 

Atwater Valley 18, Proposed Location E 

Atwater Valley 18, Proposed Location E is located in a water depth of approximately 4208’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 18, Proposed Location E consists of: 

 Unit 1 (Seafloor – 704’ BML) - 704’ of soft hemipelagic silty muds with thin mud-rich mass transport 

deposits (MTD’s)

 Unit 2 (704’ – 1214’ BML) – 510’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

 Unit 3 – Blue Unit (1214’ – 1781’ BML) – 567’ of canyon margin rotated slides, interbedded with 

sands and muds 

 Unit 4 (1781’ – 2385’ BML) – 604’ of highly deformed stratigraphy, predominantly mud rocks

 Unit 5 is not present in this proposed location 

 Unit 6a (2385’ – 3025’ BML) – 640’ slope fan sequence of interbedded thin sands and mud rocks 

 Unit 6b (3025’ – 3606’ BML) – 581’ of muds with some silts and minor sands

 Unit 7 (3606’ – 6811’ BML) – 3205’ of thin sands and muds in the upper part, muds in the middle and 

muds and thin sands in the lower part of the unit

Shallow Water Flow Potential: 

 Low Potential – Seafloor – 704’ BML

 Moderately Low Potential – 704’ – 1214’ BML

 Moderately High Potential – 1214’ – 1781’ BML

 Moderately Low Potential – 1781’ – 2385’ BML

 Moderately High Potential – 2385’ – 3025’ BML

 Moderate Potential – 3025’ – 3606’ BML

 Moderately Low Potential – 3606’ – 6811’ BML

 

Shallow Gas Potential: 

 Low Potential – Seafloor – 1214’ BML

Page 37 Public Information Copy
 Moderately Low Potential – 1214’ – 1781’ BML

 Low Potential – 1781’ – 2385’ BML

 Moderately High Potential – 2385’ – 3025’ BML

 Moderately Low Potential – 3025’ – 6811’ BML

There are no amplitude anomalies identified within 250’ of AT 18, Proposed Location E.

There are no previously wells located within 2000’ of AT 18, Proposed Location E.

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location E.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location E appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 18, Proposed Location E (no anchors – DP Vessel) 

Atwater Valley 18, Proposed Location E is located in a water depth of approximately 4208’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 18, Proposed Location E will not disturb any high-density areas of benthic 

communities. 

The following table is a list of marine avoidance zones identified within 2000’ of AT 18, Proposed Location E:

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc E

Direction from 

Prop Loc E

12 100’ 979994.56 10151647.00 1814.76’ Northeast

11 100’ 979907.25 10151893.00 1869.82’ Northeast

13 100’ 976668.25 10151650.00 1917.02’ Northwest

There are no previously wells located within 2000’ of AT 18, Proposed Location E.

Currently, there are no existing flowlines or umbilicals within 2000’ of AT 18, Proposed Location E.

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 18, Proposed Location E appears suitable for the planned activity. 

Atwater Valley 19, Proposed Location F 

Atwater Valley 19, Proposed Location F is located in a water depth of approximately 4285’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 19, Proposed Location F consists of: 

• Unit 1 (Seafloor – 506’ BML) - 506’ of soft hemipelagic silty muds with thin mud-rich mass transport 

deposits (MTD’s)

• Unit 2 (506’ – 1450’ BML) – 944’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

• Unit 3 – Blue Unit (1450’ – 2030’ BML) – 580’ of canyon margin rotated slides, interbedded with 

sands and muds 

• Unit 4 (2030’ – 2359’ BML) – 329’ of highly deformed stratigraphy, predominantly mud rocks

• Unit 5 (2359’ – 2763’ BML) – 404’ of predominantly mud with some sand and silt

• Unit 6a and 6b (2763’ – 3806’ BML) – 1043’ of slope fan sequence of interbedded thin sands and 

mud rocks 

• Unit 7 (3806’ – 5405’ BML) – 1599’ of thin sands and muds in the upper part, muds in the middle and 

muds and thin sands in the lower part of the unit 

Page 38 Public Information Copy
Shallow Water Flow Potential: 

 Low Potential – Seafloor – 506’ BML

 Moderately Low Potential – 506’ – 1450’ BML

 Moderately High Potential – 1450’ – 2030’ BML

 Moderate Potential – 2030’ – 2359’ BML

 Low Potential – 2359’ – 2763’ BML

 Moderately High Potential – 2763’ – 3806’ BML

 Moderately Low Potential – 3806’ – 5405’ BML

 

Shallow Gas Potential: 

 Low Potential – Seafloor – 1450’ BML

 Moderately Low Potential – 1450’ – 2030’ BML

 Low Potential – 2030’ – 2763’ BML

 Moderately High Potential – 2763’ – 3806’ BML

 Moderately Low Potential – 3806’ – 5405’ BML

There are no amplitude anomalies identified within 250’ of AT 19, Proposed Location F.

There are no previously wells located within 2000’ of AT 19, Proposed Location F.

The Bennu flowline and umbilical are identified 330’ east of AT 19, Proposed Location F. Proposed Location F 

will not interfere with this flowline and umbilical. 

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 19, Proposed Location F appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 19, Proposed Location F (no anchors – DP Vessel) 

Atwater Valley 19, Proposed Location F is located in a water depth of approximately 4285’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 19, Proposed Location F will not disturb any high-density areas of benthic 

communities. 

The following table is a list of marine avoidance zones identified within 2000’ of AT 19, Proposed Location F:

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc F

Direction from 

Prop Loc F

21 100’ 986539.81 10145698.00 1832.81’ West

There are no previously wells located within 2000’ of AT 19, Proposed Location F.

The Bennu flowline and umbilical are identified 330’ east of AT 19, Proposed Location F. Proposed Location F 

will not interfere with this flowline and umbilical. 

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 19, Proposed Location F appears suitable for the planned activity. 

Page 39 Public Information Copy
Atwater Valley 19, Proposed Location G 

Atwater Valley 19, Proposed Location G is located in a water depth of approximately 4432’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. 

The stratigraphy at the site of AT 19, Proposed Location G consists of: 

 Unit 1 (Seafloor – 468’ BML) - 468’ of soft hemipelagic silty muds with thin mud-rich mass transport 

deposits (MTD’s)

 Unit 2 (468’ – 1304’ BML) – 836’ of canyon over-bank deposits and channel-fill of muds with 

interbedded sands and silts. 

 Unit 3 – Blue Unit (1304’ – 2140’ BML) – 836’ of canyon margin rotated slides, interbedded with 

sands and muds 

 Unit 4 (2140’ – 2404’ BML) – 264’ of highly deformed stratigraphy, predominantly mud rocks

 Unit 5 (2404’ – 2930’ BML) – 526’ of predominantly mud with some sand and silt

 Unit 6a and 6b (2930’ – 4060’ BML) – 1130’ of slope fan sequence of interbedded thin sands and 

mud rocks 

 Unit 7 (4060’ – 5291’ BML) – 1231’ of thin sands and muds in the upper part, muds in the middle and 

muds and thin sands in the lower part of the unit 

Shallow Water Flow Potential: 

 Low Potential – Seafloor – 468’ BML

 Moderately Low Potential – 468’ – 1304’ BML 

 Moderately High Potential – 1304’ – 2140’ BML

 Moderate Potential – 2140’ – 2404’ BML

 Low Potential – 2404’ – 2930’ BML

 Moderately High Potential – 2930’ – 4060’ BML

 Moderately Low Potential – 4060’ – 5291’ BML

 

Shallow Gas Potential: 

 Low Potential – Seafloor – 1304’ BML

 Moderately Low Potential – 1304’ – 2140’ BML

 Low Potential – 2140’ – 2930’ BML

 Moderately High Potential – 2930’ – 4060’ BML

 Moderately Low Potential – 4060’ – 5291’ BML

There are no amplitude anomalies identified within 250’ of AT 19, Proposed Location G. 

There are no previously wells located within 2000’ of AT 19, Proposed Location G.

The Bennu flowline and umbilical are identified 1850’ southwest of AT 19, Proposed Location G. Proposed 

Location G will not interfere with this flowline and umbilical. 

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 19, Proposed Location G appears suitable for the planned activity. 

Benthic/Anchor Assessment, AT 19, Proposed Location G (no anchors – DP Vessel) 

Atwater Valley 19, Proposed Location G is located in a water depth of approximately 4432’. There is no 

evidence of seafloor or near-surface faulting, amplitudes or fluid expulsion features in the vicinity of this 

proposed location. AT 19, Proposed Location G will not disturb any high-density areas of benthic 

communities. 

Page 40 Public Information Copy
The following table is a list of marine avoidance zones identified within 2000’ of AT 19, Proposed Location G:

Avoidance 

Zone Number Avoidance 

Target X

Coordinate

Target Y 

Coordinate

Distance from 

Prop Loc G

Direction from 

Prop Loc G

22 100’ 991408.38 10145337.00 267.56’ Southeast

There are no previously wells located within 2000’ of AT 19, Proposed Location G.

The Bennu flowline and umbilical are identified 1850’ southwest of AT 19, Proposed Location G. Proposed 

Location G will not interfere with this flowline and umbilical. 

Based on a high-resolution geophysical survey consisting of AUV Side Scan Sonar and Sub-bottom Profiler, 

frequency enhanced 3-D seismic, Enhanced Surface Renderings (ESR’s) and ESR’s with amplitudes applied, 

AT 19, Proposed Location G appears suitable for the planned activity. 

B. Topographic Features Map 

The proposed activities are not within 1,000' of a no-activity zone or within the 3-mile radius zone of an 

identified topographic feature. Therefore, no map is required per NTL No. 2008-G04. 

C. Topographic Features Statement (Shunting)

Shell does not plan to drill more than two wells from the same surface location within the Protective Zone of 

an identified topographic feature. Therefore, the topographic features statement required by NTL No. 2008-

G04 is not applicable. 

D. Live Bottoms (Pinnacle Trend) Map 

The activities proposed in this plan are not within 200' of any pinnacle trend feature with vertical relief equal 

to or greater than 8'. Therefore, no map is required per NTL No. 2008-G04. 

E. Live Bottoms (Low Relief) Map

The activities proposed in this plan are not within 100' of any live bottom low relief features. Therefore, no 

map is required per NTL No. 2008-G04. 

F. Potentially Sensitive Biological Features 

The activities proposed in this plan are not within 200' of any potentially sensitive biological features. 

Therefore, no map is required per NTL No. 2008-G04, extended by NTL 2014-G03. 

G. Remotely Operated Vehicle (ROV) Monitoring Plan 

In accordance with the provisions of NTL 2008-G06, Remotely Operated Vehicle Surveys in Deepwater, Atwater 

Valley 18 and 19 are located in Grid 13, which is considered an area that does have adequate ROV survey 

coverage; therefore we are not required to run the pre- and post-ROV survey in accordance with NTL 2008-G06. 

H. Threatened and Endangered Species Information 

Under Section 7 of the Endangered Species Act (ESA) all federal agencies must ensure that any actions they 

authorize, fund, or carry out are not likely to jeopardize the continued existence of a listed species, or destroy 

or adversely modify its designated critical habitat. 

In accordance with the 30 CFR 250, Subpart B, effective May 14, 2007 and further outlined in Notice to 

Lessees (NTL) 2008-G04, lessees/operators are required to address site-specific information on the presence 

of federally listed threatened or endangered species and critical habitat designated under the ESA and marine 

Page 41 Public Information Copy
mammals protected under the Marine Mammal Protection Act (MMPA) in the area of proposes activities under 

this plan. 

Currently there are no designated critical habitats for the listed species in the Gulf of Mexico Outer 

Continental Shelf; however, it is possible that one or more of these species could be seen in the area of our 

operations. The following table reflects the Federally-listed endangered and threatened species in the lease 

area and along the northern Gulf coast: 

Common Name Scientific Name T/E Status

Hawksbill Turtle Eretmochelys imbricata E

Green Turtle Chelonia mydas T/E

Kemp's Ridley Turtle Lepidochelys kempii E

Leatherback Turtle Dermochelys coriacea E

Loggerhead Turtle Caretta caretta T

Table 6.6 – Threatened and Endangered Sea Turtles 

The green sea turtle is threatened, except for the Florida breeding population, which is listed as endangered. 

There are 29 species of marine mammals that may be found in the Gulf of Mexico (see Table 6.7 below). Of 

the species listed as Endangered, only the Sperm whale is commonly found in the project area. No critical 

habitat for these species has been designated in the Gulf of Mexico. 

Common Name Scientific Name T/E Status

Atlantic Spotted Dolphin Stenella frontalis

Blainville's Beaked Whale Mesoplodon densirostris

Blue Whale Balaenoptera musculus E

Bottlenose Dolphin Tursiops truncatus

Bryde's Whale Balaenoptera edeni

Clymene Dolphin Stenella clymene

Cuvier's Beaked Whale Ziphius cavirostris

Dwarf Sperm Whale Kogia simus

False Killer Whale Pseudorca crassidens

Fin Whale Balaenoptera physalus E

Fraser's Dolphin Lagenodelphis hosei

Gervais' Beaked Whale Mesoplodon europaeus

Humpback Whale Megaptera novaeangliae E

Killer Whale Orcinus orca

Melon-headed Whale Peponocephala electra

Minke Whale Balaenoptera acutorostrata

North Atlantic Right Whale Eubalaena glacialis E

Pantropical Spotted Dolphin Stenella attenuata

Pygmy Killer Whale Feresa attenuata

Pygmy Sperm Whale Kogia breviceps

Risso's Dolphin Grampus griseus

Rough-toothed Dolphin Steno bredanensis

Sei Whale Balaenoptera borealis E

Short-finned Pilot Whale Globicephala macrorhynchus

Sowerby's Beaked Whale Mesoplodon bidens

Page 42 Public Information Copy
Sperm Whale Physeter macrocephalus E

Spinner Dolphin (Long-snouted) Stenella longirostris

Striped Dolphin Stenella coeruleoalba

Florida manatee Trichechus manatus E

Table 6.7 – Threatened and Endangered Marine Mammals 

The blue, fin, humpback, North Atlantic right and sei whales are rare or extralimital in the Gulf of Mexico and 

are unlikely to be present in the lease area. The Environmental Impact Analysis found in Section 18 

discusses potential impacts and mitigation measures related to threatened and endangered species. 

I. Archaeological Report 

The following reports were used in this analysis: 

C&C Technologies, “Archaeological Assessment Report, Blocks 18 (OCS-G 33863) and 19 (OCS-G 32556), 

Atwater Valley Area, Gulf of Mexico”, Report No. 120015, Dated May 2012. Data: AUV Side Scan Sonar and 

Sub-bottom Profiler 

Archaeological Analysis 

The Archaeological Assessment Survey revealed twenty-nine unidentified sonar contacts within the project 

area. All of the sonar contacts appear to be insignificant modern debris or natural in origin. No contacts are 

recommended for avoidance or investigation on the basis of archaeological potential. 

There is still a possibility that shipwreck remains could be undetected or unidentified within the survey area. 

If any material possibly related to a shipwreck are encountered during lease development, the BOEM 

archaeologists must be contacted within 48 hours for an assessment of any antiquities. Material indicating 

the presence of a historic shipwreck may include, but is not limited to, wooden ship beams, hull planking, 

rigging, anchors, ceramics, or other possible cultural material. In this event, no activities should be 

conducted near the area of discovery until advised by the appropriate BOEM personnel (Pre-Seabed 

Disturbance Survey Mitigation Document and NTL No. 2005-G07, Archaeological Resource Surveys and 

Reports). 

J. Air and Water Quality Information 

AT 18 and 19 are located 70 miles from the nearest shoreline. Drilling operations will produce air pollutant 

emissions, but as provided in the Air Emissions Spreadsheet (see Section 8 of this Plan), these operations are 

below the exemption levels. 

These drilling operations will result in the discharge of authorized effluents under the EPA Region VI General 

permit. Impacts of these discharges are expected to be minimal on water quality in the area. 

For specific information relating to air and water quality information please refer to Section 18. 

K. Socioeconomic Information 

1) Shell will utilize its existing shorebase located in Fourchon, Louisiana which is fully staffed and 

operational and does not expect to employ persons from within the State of Florida. 

2) Shell does not expect to purchase major supplies, services, energy, water or other resources from 

within the State of Florida for these operations. 

3) Shell does not expect to hire contractors or vendors from within the State of Florida. 

For specific information relating to socioeconomic information please refer to Section 18 in this Plan.

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SECTION 7: WASTE AND DISCHARGE INFORMATION 

A. Projected Ocean Discharges 

Note: Please specify if the amount reported is a total or per well amount DEEP SLEEP AT18-001

Type of Waste and Composition Composition Projected Amount /well Discharge rate/day/well Discharge Method Answer yes or no

Will drilling occur ? If yes, you should list muds and cuttings

EXAMPLE: Cuttings wetted with ynthetic based fluid 

Cuttings generated while using synthetic 

based drilling fluid. X bbl/well X bbl/day discharge pipe No

Water-based drilling fluid barite, additives, mud 94,049 bbls/well 17,604 bbls/day

Overboard and seafloor discharge prior to marine 

riser installation No

Cuttings wetted with water-based fluid

cuttings coated with water based drilling 

mud 3,304 bbls/well 469 bbls/day Sea bed during riserless drilling No

Cuttings wetted with synthetic-based fluid 

Cuttings generated while using synthetic 

based drilling fluid. 6,416 bbls/well 409 bbls/day Overboard discharge line below the water level No

Synthetic based drilling fluid adhering to washed drill 

cuttings

Synthetic based drilling fluid adhering to 

washed drill cuttings 1,265 bbls/well 15 bbs/day Overboard discharge line below the water level No

Will humans be there? If yes, expect conventional waste

EXAMPLE: Sanitary waste water X liter/person/day NA chlorinate and discharge No

Domestic waste (kitchen water, shower water) grey water 40,600 bbls/well 203 bbls/day

Grinded to less than 25 mm mesh size and 

discharge overboard No

Sanitary waste (toilet water) treated sanitary waste 6,000 bbls/well 30 bbls/day

Treated in the MSD** prior to discharge to meet 

NPDES limits No

Is there a deck? If yes, there will be Deck Drainage

Deck Drainage Wash and rainwater 4,000 bbls/well 20 bbls/day Drained overboard through deck scuppers No

Will you conduct well treatment, completion, or workover? 

well treatment fluids NA NA NA NA No

well completion fluids NA NA NA NA No

workover fluids NA NA NA NA No

Miscellaneous discharges. If yes, only fill in those associated with your activity. 

Chemical product waste Drilling additives added to well 1,000 bbls/well 5 bbls/day

Treated to meet NPDES limits and discharged 

overboard No

Desalinization unit discharge Rejected water from watermaker unit 76,000 bbls/well 380 bbls/day Discharged overboard below waterline No

Blowout prevent fluid Water based 400 bbls/well 2 bbls/day Disharge at seafloor No

Ballast water Uncontaminated seawater 400,000 bbls/well 2,000 bbls/day Discharged overboard Just above waterline No

Bilge water

Bilge and drainage water will be treated to 

MARPOL standards (< 15ppm oil in water). 400,000 bbls/well 2,000 bbls/day

Bilge and drainage water will be treated to 

MARPOL standards (< 15ppm oil in water). No

Excess cement at seafloor Cement slurry

1100 bbls/well (assume 

planned 100% excess is 

discharged) 1100 bbls/well

Discharged at the seafloor during riserless 

drilling No

Fire water Treated seawater 13,000 bbls/well 2,000 bbls / month Drained overboard through deck scuppers No

Cooling water Treated seawater 29,000,000 bbls/well 145,000 bbls/day Discharged overboard 40 feet below waterline No

Will you produce hydrocarbons? If yes fill in for produced water.

Produced water NA NA NA NA NA

Will you be covered by an individual or general NPDES permit ? GENERAL PERMIT GMG290103

TABLE 7A: WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR DISCHARGE TO THE GOM

Projected 

Downhole 

Projected generated waste Projected ocean discharges Disposal

Page 51 Public Information Copy
B. Projected Generated Wastes 

EXAMPLE: Oil-based drilling fluid or mud NA NA NA NA NA

Oil-based drilling fluid or mud NA NA NA NA NA

Synthetic-based drilling fluid or mud used SBF and additives Drums on barges

Newpark Environmental Services 

(Fourchon, La.) or US Liquids of 

Louisiana (Fourchon, La.) 2,500 bbls/well Recycled

Cuttings wetted with Water-based fluid NA NA NA NA NA

Cuttings wetted with Synthetic-based fluid 

Drill cuttings from synthetic 

based interval. storage tank on supply boat.

Newpark Environmental Services 

(Fourchon, La.) or US Liquids of 

Louisiana (Fourchon, La.) 300 bbls / well Recycled

Cuttings wetted with oil-based fluids NA NA NA NA NA

Will you produce hydrocarbons? If yes fill in for produced sand.

Produced sand NA NA NA NA NA

EXAMPLE: trash and debris cardboard, aluminum, barged in a storage bin shorebase z tons total recycle

Waste Oil Sludge

Waste Oil from MODU 

Machinery

N/A - Incinerated via onboard MODU 

Incinerator MODU Incinerator 12 m3/mont

Incinerate via onboard MODU that 

meets MARPOL 73/78, as 

amended, Annex VI, 

Regulation16(2), (a), / IMO 

Resolution MEPC. 76(40) amended 

by Resolution MEPC.93(45)

Trash and debris - recyclables trash and debris storage bins on supply boat

Omega Waste Management, W. 

Patterson, LA or ARC, New Iberia, LA 60 lbs/month recylce

Non-Hazardous trash and debris - nonrecyclables trash and debris storage bins on supply boatRepublic/BFI landfill, Sorrento, LA or 

the parish landfill, Avondale, LA. 118 lbs/month landfill

Hazardous waste

paints, solvents and unused 

chemicals drums on supply boat

Lamp Environmental, Hammond, LA

60 lbs/month recylce

Used oil & glycole

used oil, oily rags and pads, 

empty drums and cooking 

oil drums on supply boat

Omega Waste Management, W. 

Patterson, LA or ARC, New Iberia, LA 20 bbls/month recycle

Universal waste items

Batteries, lamps, glass and 

mercury-contaminated 

waste drums on supply boat Lamp Environmental, Hammond, LA 30 bbls/month landfill

NOTE: If you will not have a type of waste, enter NA in the row. 

Will you have additional wastes that are not permitted for discharge? If 

yes, fill in the appropriate rows. 

C. Modeling Report 

The proposed activities under this plan do not meet the U.S. Environmental Protection Agency requirements for an individual NPDES permit. Therefore, modeling 

report requirements per NTL No. 2008-G04 is not applicable to this EP. 

Page 52 Public Information Copy
SECTION 8: AIR EMISSIONS INFORMATION 

A. Emissions Worksheet and Screening Questions 

Screening Questions for EP’s Yes No

Is any calculated Complex Total (CT) Emission amount (in tons) associated with 

your proposed exploration activities more than 90% of the amounts calculated 

using the following formulas: CT = 3400D2/3 for CO and CT 33.3D for the 

other air pollutants (where D distance to shore in miles)?

x

Do your emission calculations include any emission reduction measures or modified 

emission factors? X*

Are your proposed exploration activities located east of 87.5° W longitude? x

Do you expect to encounter H2S at concentrations greater than 20 parts per million 

(ppm)? x

Do you propose to flare or vent natural gas for more than 48 continuous hours

From any proposed well? x

Do you propose to burn produced hydrocarbon liquids? x

 

*Note: The following AQR is using fuel limitations and Shell will perform fuel monitoring for 

this project. 

 If you answer no to all of the above screening questions from the appropriate table, provide: 

(1) Summary information regarding the peak year emissions for both Plan Emissions and Complex 

Total Emissions, if applicable. This information is compiled on the summary form of the two 

sets of worksheets. You can submit either these summary forms or use the format below. You 

do not need to include the entire set of worksheets. 

Air Pollutant

Plan Emission

Amounts 

(tons)

Calculated 

Exemption 

Amounts 

(tons)

Calculated

Complex Total 

Emission 

Amounts

(tons)

PM

SOx

NOx

VOC

CO

(2) Contact: Tracy Albert, 504.425.4652, tracy.albert@shell.com

B. Worksheets 

See attached worksheets. 

Page 53 Public Information Copy
Attachment 8A – Air Quality Report

Fuel Limit Basis for Drillships and DP Semi-subs

bm -13/05/2014

Purpose

Step 1 - Determine Typical Operating Loads

Scenario 1 – Riser less drilling (top hole) - Four engines online @ 35 to 45%

Scenario 2 - Riser less drilling Running casing/ cementing - Four Engines online @ 30 to 40 %

Scenario 3 - Transit (5 knot log speed) - Four engines online @ 65% . Not considered further 

Scenario 4 – Drilling ahead with BOP deployed - Four Engines online @ 40 to 50% 

 

Op Mode 1 Op Mode 2 Op Mode 3 Op Mode 4

45% 40% 50%

45% 40% 50%

45% 40% 50%

45% 40% 50%

0% 0% 0%

0% 0% 0%

30% 27% 33%

Step 2 - Identify Corresponding Fuel Levels

Value

74615

33%

25,000

5.00

Step 3 - Support Vessel Fuel Loads

Value

50%

10,943

5,471

6,260

939

1.26

Additional Notes

1 - Operating loads are campaign specific and may change in future AQRs depending on the future fuel usage tracking. Fuel levels 

depicted in this AQR does not restrict Shell from using a different value in future AQRs.

2 - If tracked fuel usage associated with this activity indicates emissions may exceed the approved emissions, Shell will submit 

revised AQR calculations.

PTE Fuel Use (gal/day) Crew Vessels are rated at 5400 hp. The PTE fuel use is then estimated using the 

AQR conversion factor of 0.0483 gal/hp-hr.

Campaign Average Daily Fuel Use 

(gal/day)

Calculated Value - PTE fuel use * Proposed Operating Load. Note that Crew 

Vessels are only in field 30% of campaign and daily average value has been 

adjusted accordingly. Total Vessel Activity

2015-2021 Fuel Limits MMGals Sum of (vessel daily fuel use * corresponding campaign days)

Crew Vessel

2015-2021 Fuel Limits MMGals Calculated Value - Campaign Average Daily Fuel Use * Campaign Days 

Description Notes

Proposed Operating Loads Shell policy restricts D/P to < 50% near rig. When in standby away from rig but 

within 25 miles load will be < 50% (conserve fuel). When transiting through field 

(25 nm), traveling at economical speeds. 

Offshore Support Vessels

 PTE Fuel Use (gal/day) Offshore Support Vessels are rated at 9440 hp. The PTE fuel use is then 

estimated using the AQR conversion factor of 0.0483 gal/hp-hr.

Campaign Average Daily Fuel Use 

(gal/day)

Calculated Value - PTE fuel use * Proposed Operating Load. 

PTE Fuel Use (gal/day) The Noble Don Taylor is equipped with 6 main engines at 10,728 hp each. The 

PTE fuel use is then estimated using the AQR conversion factor of 0.0483 gal/hphr.

Proposed Operating Load See Step 1 above.

Campaign Average Daily Fuel Use 

(gal/day)

Calculated Value - PTE fuel use * Proposed Operating Load and rounded up to 

nearest thousand (for additional conservatism).

Description Notes

Shell has reviewed engine information for its GOM fleet of Drillship and DP semi-sub MODUs. The single MODU with the largest 

power profile is the Noble Don Taylor, which has six main engines of 10,728 hp/engine. The projected fuel usages presented below 

would therefore be conservative across the fleet of Drillships and DP Semi-subs.

The Noble Don Taylor has six main engines. As confirmed by drillship owner, the below operating scenarios are considered 

representative for newbuild drilling rigs. Scenario 4 is selected as the conservative representation of typical engine loads. The 

highlighted cell indicates the highest power load scenario for this activity - Note Scenario 3 (transit) will be limited in duration and not 

considered representative for the full campaign. 

% Load

Engine

1

2

3

4

5

6

Average 

Page 54 Public Information Copy
COMPANY Shell Offshore Inc.

AREA Atwater

BLOCK 18 -19

LEASE OCS-G 33863 and OCS-G 32556 

PLATFORM DP MODU

WELL A, B, C, D, E, F, G

DISTANCE TO LAND 70

COMPANY CONTACT 504-206-5120

TELEPHONE NO. Bertrand Montchanin

REMARKS Deepsleep_AQR_Suppl EP_DP MODU Incin_12032014.xlsx

Page 55 Public Information Copy
Fuel Usage Conversion 

Factors

Natural Gas 

Turbines

Natural 

Gas 

Engines

Diesel 

Recip. 

Engine

REF. DATE

SCF/hp-hr 9.524 SCF/hphr 7.143 GAL/hphr 0.0483 AP42 3.2-1 4/76 & 8/84

Equipment/Emission Factors units PM SOx NOx VOC CO REF. DATE

NG Turbines gms/hp-hr 0.00247 1.3 0.01 0.83 AP42 3.2-1& 3.1-1 10/96

NG 2-cycle lean gms/hp-hr 0.00185 10.9 0.43 1.5 AP42 3.2-1 10/96

NG 4-cycle lean gms/hp-hr 0.00185 11.8 0.72 1.6 AP42 3.2-1 10/96

NG 4-cycle rich gms/hp-hr 0.00185 10 0.14 8.6 AP42 3.2-1 10/96

Diesel Recip. < 600 hp. gms/hp-hr 1 0.1835 14 1.12 3.03 AP42 3.3-1 10/96

Diesel Recip. > 600 hp. gms/hp-hr 0.32 0.1835 11 0.33 2.4 AP42 3.4-1 10/96

Diesel Boiler lbs/bbl 0.084 0.3025 0.84 0.008 0.21 AP42 1.3-12,14 9/98

NG Heaters/Boilers/Burners lbs/mmscf 7.6 0.593 100 5.5 84 AP42 1.4-1, 14-2, & 

14-3

7/98

NG Flares lbs/mmscf 0.593 71.4 60.3 388.5 AP42 11.5-1 9/91

Liquid Flaring lbs/bbl 0.42 6.83 2 0.01 0.21 AP42 1.3-1 & 1.3-3 9/98

Tank Vapors lbs/bbl 0.03 E&P Forum 1/93

Fugitives lbs/hr/comp. 0.0005 API Study 12/93

Glycol Dehydrator Vent lbs/mmscf 6.6 La. DEQ 1991

Gas Venting lbs/scf 0.0034

Sulphur Content Source Value Units

Fuel Gas 3.33 ppm

Diesel Fuel 0.05 % weight

Per 40 CFR 80.510(a)(1), Locomotive and Marine (LM) diesel fuels are limited to 500 ppm 

maximum sulfur, effective June 1, 2007.

Produced Gas( Flares) 3.33 ppm

Produced Oil (Liquid Flaring) 1 % weight

Page 56 Public Information Copy
Miscellaneous Constants and Conversions

365 days/yr - Follows FLAG 2010 Guidance

2000

lb/ton conversion 

factor

454 g/lb conversion factor

1000 SCF/MSCF conversion factor

1.341 hp/kW conversion 

factor

Page 57 Public Information Copy
COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

Shell Offshore Inc Atw ater 18 -19 OCS-G 33863 and OCS-G 32556 A,B, C, D, E, F, G 504-206-5120 Bertrand Montchanin Deepsleep_AQR_Suppl EP_DP MODU Incin_12032014.xlsx

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR ESTIMATED TONS

Diesel Engines HP GAL/HR GAL/D

Nat. Gas Engines HP SCF/HR SCF/D

Burners MMBTU/HR SCF/HR SCF/D HR/D DAYS P M SOx NOx VOC CO P M SOx NOx VOC CO

DP PRIME MOVER>600hp diesel 10728 518 24 200 7.56 4.34 259.93 7.80 56.71

PRIME MOVER>600hp diesel 10728 518 24 200 7.56 4.34 259.93 7.80 56.71

PRIME MOVER>600hp diesel 10728 518 24 200 7.56 4.34 259.93 7.80 56.71

PRIME MOVER>600hp diesel 10728 518 24 200 7.56 4.34 259.93 7.80 56.71

PRIME MOVER>600hp diesel 10728 518 24 200 7.56 4.34 259.93 7.80 56.71

PRIME MOVER>600hp diesel 10728 518 24 200 7.56 4.34 259.93 7.80 56.71

Energency Generator>600hp diesel 2547 123 1 200 1.80 1.03 61.71 1.85 13.46

Emergency Air Compressor< 600hp diesel 26 1 1 200 0.06 0.01 0.80 0.06 0.17

Incinerator 1.41 3.24 0.42 0.02 1.30 0.68 1.55 0.20 0.01 0.62

All other rig-equipment is electric (e.g cranes) or negligible in emissions potential (e.g. life boats, welding equipment, etc.)

Supply Vessel>600hp diesel (general support) 9440 456 5471 24 200 6.65 3.82 228.72 6.86 49.90 7.98 4.58 274.47 8.23 59.88

Supply Vessel>600hp diesel (riserless support) 9440 456 5471 24 10 6.65 3.82 228.72 6.86 49.90 0.40 0.23 13.72 0.41 2.99

Supply Vessel>600hp diesel (riserless support) 9440 456 5471 24 10 6.65 3.82 228.72 6.86 49.90 0.40 0.23 13.72 0.41 2.99

Crew Vessel>600hp diesel 5400 261 939 24 60 3.81 2.18 130.84 3.93 28.55 0.41 0.24 14.13 0.42 3.08

2015-2021 TOTAL 72.40 43.92 2439.51 73.23 533.47 46.35 27.75 1570.34 47.11 343.20

EXEMPTION 

CALCULATION

DISTANCE FROM LAND IN 

MILES 2331.00 2331.00 2331.00 2331.00 57748.97

70.0

25000 36.48 20.92 1254.09 37.62 273.62

Emissions estimated on separate worksheet tab.

Page 58 Public Information Copy
Emissions for Incinerator (Waste Oil Incineration)

Table 1 - Emission Calculation Inputs

Value

0.083

0.022

144

7

264.1721

2000

Table 2 - Incinerator Emission Factors (lb/1000 gal)

PM SOx NOx VOC

64A 147S 19 1

Factors per AP 42 tables 1.11-1, 1.11-2 and 1.11-3, where A and S are provided below

1.00 A = ash percentage (assumed value to be consistent with other GOM incinerator calculations)

1.00 S = sulfur percentage (assumed value to be consistent with other GOM incinerator calculations)

Table 3 - CO Emission Factor

Value

200

36

984

264.1721

453592.4

59.126

Table 4 - Hourly and Annual Emissions

PM SOx NOx VOC CO PM SOx NOx VOC CO

Waste Oil Burning 1.409 3.236 0.418 0.022 1.302 0.676 1.553 0.201 0.011 0.625

Waste Oil Feed Rate (1000 gal/hr) Calculated Value, based on Feed Rate (m3/hr) and Conversion Factor (gal/m3)

Parameter Notes

Waste Oil Feed rate (m3/hr) provided via e-mail by Stena IceMax, Rig Manager based on 1 m3 feed rate every 12 hours 

Operations (hours/month) Calculated Value, based on an estimated 12 m3/calendar month and typical feed rate.

Months of Operation Consistent with Exploration Plan schedule 

Conversion Factor (gal/m3)

Conversion Factor (lb/ton)

Emission Factor Discussion - The BOEM's AQR emission spreadsheets do not provide emission factors for incinerators. In absence of this data, 

emission factors from USEPA AP-42 publication on Waste Oil Combustion (Chapter 1.11) have been utilized. It should be noted that the majority of 

default emission factors utilized by BOEM in the AQR spreadsheets have been provided by USEPA AP-42 publications. 

CO Emission Factor Note - The incinerator has Certificate of Shipboard Incinerator that identifies CO emission factor of 200 mg/MJ (converts to 59.13 

lb/1000 gal) in the flue gas, which is greater than the 5 lb/1000 gal emission factors provided by USEPA AP-42. In order to provide conservative 

emission estimates, the higher emission factor is utilized to estimate emissions. See Table 3 for detail on the Incinerator certificate and conversion 

formulas.

Parameter Notes

Certificate Emission Factor (mg/MJ) Page 3 of the Certificate of Shipboard Incinerator identifies the CO emission factor as 200 

Waste Oil Heat Value (MJ/kg) Calorific Values are provided in Section A1.4 of ANNEX 8 - STANDARD SPECIFICATION FOR 

Waste Oil Density (kg/m3) Calculated Value, based on design flow in 82 kg/hr (vendor certificate) and typical feed rates 

MAXIMUM POUNDS PER HOUR ESTIMATED TONS/CALENDAR YEAR

Conversion Factor (gal/m3)

Conversion Factor (mg/lb)

Certificate Emission Factor (lb/1000 gal) Calculated Value, Certificate Emission Factor (mg/MJ) * Waste Oil Heat Value (MJ/kg) * 

Page 59 Public Information Copy
COMPANY AREA BLOCK LEASE PLATFORM WELL

Shell 

Offshore Inc.

Atwater 18 -19 OCS-G 33863 and OCS-G 32556 DP MODU A, B, C, D, 

E, F, G

Emitted Substance

Year

PM SOx NOx VOC CO

AQR Emissions if DP MODU(Semi-sub 

or Drillship) is Utilized

2015-

2021 47.03 29.30 1570.54 47.13 343.82

Allowable 2331.00 2331.00 2331.00 2331.00 57748.97

Notes

Emissions for DP MODU activities in 2015-2021 account for reduced fuel usage.

Page 60 Public Information Copy
SECTION 9: OIL SPILL INFORMATION 

A. Oil Spill Response Planning 

All the proposed activities in this EP will be covered by the Regional OSRP filed by Shell Offshore Inc. 

(0689) in accordance with 30 CFR 254.47 and NTL 2013-N02. Shell’s regional OSRP was approved by 

BSEE on April 11, 2013. A revision was submitted November 17, 2014 and approved by BSEE on 

December 30, 2014. 

Spill Response sites are as follows: 

Primary Response Equipment Locations Preplanned Staging Location(s) 

Venice, LA; Ft Jackson, LA; Harvey, LA; Stennis, 

MS; Pascagoula, MS

Venice, LA; Pacagouls, MS ; Mobile, AL

Table 9.1 – Response Equipment and Staging Areas 

The names of the OSRO’s under contract include Clean Gulf Associates (CGA), Marine Spill Response 

Company (MSRC), Clean Caribbean America (CCA) and OSRL/EARL. 

Category Regional OSRP EP

Type of Activity Exploratory Drilling Exploratory Drilling 

Facility Location (area/block) MC 812 AT 18

Facility Designation Subsea well B◊ Subsea well A

Distance to Nearest Shoreline (miles) 59 70

Volume

Storage tanks (total)

Flowlines (on facility)

Pipelines

Uncontrolled blowout (volume per day)

Total Volume

N/A

N/A

N/A

468,000* BOPD

468,000 Bbls

N/A

N/A

N/A

65,915** BOPD

65,915 Bbls

Type of Oil(s) - (crude oil, condensate, 

diesel)

Crude oil Crude oil

API Gravity(s) 31o 25o

Table 9.2 - Worst Case Scenario Determination 

 *24 hour rate (432,000 BOPD 30 day average) 

**24 hour rate (65,300 BOPD 30 day average) 

 ◊This number was accepted by BOEM in plan N-9840. 

Certification: Since Shell has the capability to response to the appropriate worst-case spill scenario included in 

its Regional OSRP, approved April 11, 2013. A revision was submitted November 17, 2014 and approved by BSEE 

on December 30, 2014. Since the number proposed in this EP does not exceed the number approved in our OSRP, 

I hereby certify that Shell has the capability to respond, to the maximum extent practicable, to a worst-case 

discharge, or a substantial threat of such a discharge, resulting from the activities proposed in our EP. 

Modeling: 

Shell did not model a potential oil or hazardous substance spill for operations proposed in this plan. 

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B. Oil Spill Response Discussion

1. Volume of the Worst Case Discharge 

Please refer to Section 2j and 9(iv) of this EP. 

2. Trajectory Analysis 

Trajectories of a spill and the probability of it impacting a land segment have been projected 

utilizing information in the BOEMRE Oil Spill Risk Analysis Model (OSRAM) for the Central and 

Western Gulf of Mexico available on the BSEE website using 30 day impact. Offshore areas along the 

trajectory between the source and land segment contact could be impacted. The land segment 

contact probabilities are shown in Table 9.C.1. 

Area/Block OCS-G

Launch

Area Land Segment Contact %

Exploratory

AT 18 & 19 60

Galveston, TX 1 

Jefferson, TX 1 

Cameron, LA 2

Vermillion, LA 1

Terrebonne, LA 2

LaFourche, LA 1

Plaquemines, LA 4

Table 9.C.1 Probability of Land Segment Impact 

C. Resource Identification

The locations identified in Table 9.C.1 are the highest probable land segments to be impacted using 

the BSEE Oil Spill Risk Analysis Model (OSRAM). The environmental sensitivities are identified using 

the appropriate National Oceanic and Atmospheric Administration (NOAA) Environmental Sensitivity 

Index (ESI) maps for the given land segment. ESI maps provide a concise summary of coastal 

resources that are at risk if an oil spill occurs nearby. Examples of at-risk resources include biological 

resources (such as birds and shellfish beds), sensitive shorelines (such as marshes and tidal flats), 

and human-use resources (such as public beaches and parks). 

In the event an oil spill occurs, ESI maps can help responders meet one of the main response 

objectives: reducing the environmental consequences of the spill and the cleanup efforts. 

Additionally, ESI maps can be used by planners to identify vulnerable locations, establish protection 

priorities, and identify cleanup strategies. 

The following is a list of resources of special economic or environmental importance that potentially 

could be impacted by the Atwater Valley18 WCD scenario. 

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Onshore/Nearshore: Plaquemines Parish has been identified as the most probable impacted 

Parish within the Gulf of Mexico for the Greater than 10 Mile Worst Case Discharge and the 

Exploratory Worst Case Discharge. Plaquemines Parish has a total area of 2,429 square miles of 

which, 845 square miles of it is land and 1,584 square miles is water. Plaquemines Parish includes 

two National Wildlife Refuges: Breton National Wildlife Refuge and Delta National Wildlife Refuge. 

This area is also a nesting ground for the brown pelican, an endangered species. Examples of 

Environmental Sensitivity maps for Plaquemines Parish are detailed in the following pages. Key ESI 

maps for Plaquemines Parish and the legend are shown in Figures 9.C.1 through 9.C.5. 

Offshore: An offshore spill may require an Essential Fishing Habitat (EFH) Assessment. This 

assessment would include a description of the spill, analysis of the potential adverse effects on EFH 

and the managed species; conclusions regarding the effects on the EFH; and proposed mitigation, if 

applicable. 

Significant pre-planning of joint response efforts was undertaken in response to provisions of the 

National Contingency Plan (NCP). Area Contingency Plans (ACPs) were developed to provide a well 

coordinated response to oil discharges and other hazardous releases. The One Gulf Plan is specific 

to the Gulf of Mexico to advance the unity of policy and effort in each of the Gulf Coast ACPs. 

Strategies used for the response to an oil spill regarding protection of identified resources are 

detailed in the One Gulf Plan and relevant Gulf Coast ACP. 

D. Worst Case Discharge Response 

Shell will make every effort to respond to the AT 18 Worst Case Discharge as effectively as possible. 

Below is a table outlining the applicable evaporation and surface dispersion quantity: 

Atwater Valley Block 18 & 19

Calculations

(BBLS)

i. TOTAL WCD (based on 30 day average per day) 65,300

ii. Approximate loss of volume of oil to natural surface dispersion and evaporation base 

(approximate bbls per day)*

(16% Natural surface evaporation and dispersion in 24 hrs)

-10,448

APPROXIMATE TOTAL REMAINING ~54,852

* As this scenario involves a surface blowout onboard the platform, an ADIOS 2 Model was ran to 

account for surface dispersion and evaporation. 

Table 9.D.1 Oil Remaining After Surface Dispersion 

Shell has contracted OSROs to provide equipment, personnel, materials and support vessels as well 

as temporary storage equipment to be considered in order to cope with a WCD spill. Under adverse 

weather conditions, major response vessels and Transrec skimmers are still effective and safe in sea 

states of 6-8 ft. If sea conditions prohibit safe mechanical recovery efforts, then natural dispersion 

and airborne chemical dispersant application (visibility & wind conditions permitting) may be the 

only safe and viable recovery option. 

MSRC OSRV 8 foot seas

VOSS System 4 foot seas

Expandi Boom 6 foot seas, 20 knot winds

Dispersants Winds more than 25 knots,

Visibility less than 3 nautical miles, or

Ceiling less than 1,000 feet.

Table 9.D.2 Operational Limitations of Response Equipment 

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Upon notification of the spill, Shell would request a partial or full mobilization of contracted 

resources, including, but not limited to, skimming vessels, oil storage vessels, dispersant aircraft, 

subsea dispersant, shoreline protection, wildlife protection, and containment equipment. Following 

is a list of the contracted resources including de-rated recovery capacity, personnel, and estimated 

response times (procurement, load out, travel time to the site, and deployment). The Incident 

Commander or designee may contact other service companies if the Unified Command deems such 

services necessary to the response efforts. 

Based on the anticipated worst case discharge scenario, Shell can be onsite with dedicated, 

contracted on water oil spill recovery equipment with adequate response capacity to contain and 

recover surface oil, and prevent land impact, within 18 hours (based on the equipment’s Estimated 

Daily Response Capacity (EDRC)). Shell will continue to ramp up additional on-water mechanical 

recovery resources as well as apply dispersants and in-situ burning as needed and as approved 

under the supervision of the USCG Captain of the Port (COTP) and the Regional Response Team 

(RRT). 

Subsea Control and Containment: Shell, as a founding member of the MWCC, will have access 

to the IRCS that can be rapidly deployed through the MWCC. The IRCS is designed to contain oil 

flow in the unlikely event of an underwater well blowout, and is designed, constructed, tested, and 

available for rapid response. Shell’s specific containment response for AT 18 will be addressed in 

Shell’s NTL 2010-N10 submission at the time the APD is submitted. 

 Table 9.D.9 Control, Containment, and Subsea Dispersant Package Activation List 

Mechanical Recovery (skimming): Response strategies include skimming utilizing available 

OSROs Oil Spill Response Vessels (OSRVs), Oil Spill Response Barges (OSRBs), ID Boats, and Quick 

Strike OSRVs. There is a combined de-rated recovery rate capability of approximately 134,400 

barrels/day. Temporary storage associated with the identified skimming and temporary storage 

equipment equals approximately 55,800 barrels. 

De-rated Recovery Rate

(bopd)

Storage

(bbls)

Offshore Recovery and 

Storage 4,769 49,799

Nearshore Recovery and 

Storage 129,636 6,070

Total 134,405 55,869

Table 9.D.3 Mechanical Recovery Combined De-Rated Capability 

 Table 9.D.4 Offshore On-Water Recovery and Storage Activation List 

 Table 9.D.5 Nearshore On-Water Recovery and Storage 5ctivation List 

Oil Storage: The strategy for transferring, storing and disposing of oil collected in these recovery 

zones is to utilize two 150,000-160,000 ton (dead weight) tankers mobilized by Shell (or any other 

tanker immediately available). The recovered oil would be transferred to Motiva’s Norco, LA storage 

and refining facility, or would be stored at Delta Commodities, Inc. Harvey, LA facility.

Aerial Surveillance: Aircraft can be mobilized to detect, monitor, and target response to oil spills. 

Aircraft and spotters can be mobilized within hours of an event. 

Table 9.D.6 Aerial Surveillance Activation List

Aerial Dispersant: Depending on proximity to shore and water depth, dispersants may be a viable 

response option. If appropriate and approved, 4 to 5 sorties from three DC-3’s can be made within 

the first 12 hour operating day of the response. These aerial systems could disperse approximately 

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7,704 to 9,630 barrels of oil per day. Additionally, 3 to 4 sorties from the BE90 King Air and 3 to 4 

sorties from the Hercules C-130A within the first 12 hour operating day of the response could 

disperse 4,600 to 6,100 barrels of oil per day. For continuing dispersant operations, the CCA’s Aerial 

Dispersant Delivery System (ADDS) would be mobilized. The ADDS has a dispersant spray capability 

of 5,000 gallons per sortie. 

 Table 9.D.7 Offshore Aerial Dispersant Activation List 

Vessel Dispersant: Vessel dispersant application is another available response option. If 

appropriate, vessel spray systems can be installed on offshore vessels of opportunity using inductor 

nozzles (installed on fire-water monitors), skid mounted systems, or purpose-built boom arm spray 

systems. Vessels can apply dispersant within the first 12-24 hours of the response and continually as 

directed. 

 Table 9.D.8 Offshore Boat Spray Dispersant Activation List 

Subsea Dispersant: Shell has contracted with Wild Well Control for a subsea dispersant package. 

Subsea dispersant application has been found to be highly effective at reducing the amount of oil 

reaching the surface. Additional data collection, laboratory tests and field tests will help in facilitating 

the optimal application rate and effectiveness numbers. For planning purposes, the system has the 

potential to disperse approximately 24,500 to 34,000 barrels of oil per day.

 Table 9.D.9 Control, Containment, and Subsea Dispersant Package Activation List 

In-Situ Burning: Open-water in-situ burning (ISB) also may be used as a response strategy, 

depending on the circumstances of the release. ISB services may be provided by the primary OSRO 

contractors. If appropriate conditions exist and approvals are granted, one or multiple ISB task 

forces could be deployed offshore. Task forces typically consist of two to four fire teams, each with 

two vessels capable of towing fire boom, guide boom or tow line with either a handheld or aeriallydeployed oil ignition system. At least one support/safety boat would be present during active 

burning operations to provide logistics, safety and monitoring support. Depending upon a number of 

factors, up to 4 burns per 12-hour day could be completed per ISB fire team. Most fire boom 

systems can be used for approximately 8-12 burns before being replaced. Fire intensity and weather 

will be the main determining factors for actual burns per system. Although the actual amount of oil 

that will be removed per burn is dependent on many factors, recent data suggests that a typical 

burn might eliminate approximately 750 barrels. For planning purposes and based on the above 

assumptions, a single task force of four fire teams with the appropriate weather and safety 

conditions could complete four burns per day and remove up to ~12,000 bbls/day. In-situ burning 

nearshore and along shorelines may be a possible option based on several conditions and with 

appropriate approvals, as outlined in Section 19, In-situ Burn Plan (OSRP). In-situ burning along 

certain types of shorelines may be used to minimize physical damage where access is limited or if it 

is determined that mechanical/manual removal may cause a substantial negative impact on the 

environment. All safety considerations will be evaluated. In addition, Shell will assess the situation 

and can make notification within 48 hours of the initial spill to begin ramping up fire boom 

production through contracted OSRO(s). There are potential limitations that need to be assessed 

prior to ISB operations. Some limitations include atmospheric and sea conditions; oil weathering; air 

quality impacts; safety of response workers; and risk of secondary fires. 

 Table 9.D.10 In-Situ Burn Equipment Activation List 

 Shoreline Protection: If the spill went unabated, shoreline impact in Plaquemines Parish, LA 

would depend upon existing environmental conditions. Nearshore response may include the 

deployment of shoreline boom on beach areas, or protection and sorbent boom on vegetated areas. 

Strategies would be based upon surveillance and real time trajectories provided by The Response 

Group that depict areas of potential impact given actual sea and weather conditions. Strategies from 

the New Orleans, Louisiana Area Contingency Plan, Unified Command would be consulted to ensure 

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that environmental and special economic resources would be correctly identified and prioritized to 

ensure optimal protection. Shell has access to shoreline response guides that depict the protection 

response modes applicable for oil spill clean-up operations. Each response mode is schematically 

represented to show optimum deployment and operation of the equipment in areas of 

environmental concern. Supervisory personnel have the option to modify the deployment and 

operation of equipment allowing a more effective response to site-specific circumstances. 

 Table 9.D.11 Shoreline Protection and Wildlife Support List 

Wildlife Protection: If wildlife is threatened due to a spill, the contracted OSRO’s have resources 

available to Shell, which can be utilized to protect and/or rehabilitate wildlife. The resources under 

contract for the protection and rehabilitation of affected wildlife are in Table 9.D.11. 

New or unusual technology in regards to spill, prevention, control and clean-up: 

Shell will use our normal well design and construction processes with multiple barrier approach as 

well as new stipulations mandated by NTL 2008-N05. Response techniques will utilize new learnings 

from Macondo response to include in-situ burning and subsea dispersant application. Mechanical 

recovery advancements are continuing to be made to incorporate utilization of Koseq arms outfitted 

on barges, conversion of Platform Support Vessels for Oil Spill Response, and inclusion of nighttime 

spill detection radar to improve tracking capabilities (X-Band radar, Infrared sensing, etc.). In 

addition, new response technologies/techniques are continuing to be considered by Shell and the 

appropriate government organizations for incorporation into our planned response. Any additional 

response technologies/techniques presented at the time of response will be used at the discretion of 

the Unified Command and USCG. 

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Figure 9.C.2 South Pass ESI Map 

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Figure 9.C.3 Garden Island Pass ESI Map 

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Figure 9.C.4 Pass a Loutre West ESI Map 

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Figure 9.C.5 Main Pass ESI Map 

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Table 9.D.4 Offshore On-Water Recovery Storage Activation List 

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Table 9.D.5 Nearshore On-Water Recovery Activation List 

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Table 9.D.5 Nearshore On-Water Recovery Activation List (continued) 

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Table 9.D.6 Aerial Surveillance Activation List 

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Table 9.D.7 Offshore Aerial Dispersant Activation List 

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Table 9.D.7 Offshore Aerial Dispersant Activation List (cont.) 

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Table 9.D.8 Offshore Boat Spray Dispersant Activation List 

Table 9.D.9 Subsea Control, Containment, and Subsea Dispersant Package Activation List 

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Table 9.D.10 In-Situ Burn Equipment Activation List 

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Table 9.D.10 In-Situ Burn Equipment Activation List (continued) 

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Table 9.D.10 In-Situ Burn Equipment Activation List (continued) 

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Table 9.D.10 In-Situ Burn Equipment Activation List (continued) 

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Table 9.D.10 In-Situ Burn Equipment Activation List (continued) 

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Table 9.D.11 Shoreline Protection and Wildlife Support List 

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Table 9.D.11 Shoreline Protection and Wildlife Support List (cont.) 

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Table 9.D.11 Shoreline Protection and Wildlife Support List (cont.) 

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Table 9.D.11 Shoreline Protection and Wildlife Support List (cont.) 

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Table 9.D.11 Shoreline Protection and Wildlife Support List (cont.) 

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SECTION 10: ENVIRONMENTAL MONITORING INFORMATION 

A. Monitoring Systems 

A rig based Acoustic Doppler Current Profiler (ADCP) is used to continuously monitor the current beneath 

the rig. Metocean conditions such as sea states, wind speed, ocean currents, etc. will also be continuously 

monitored. Shell will comply with NTL 2009-G02. 

B. Incidental Takes 

No incidental takes are anticipated. Although marine mammals may be seen in the area, Shell does not 

believe that its operations proposed under this EP will result Shell implements the mitigation measures and 

monitors for incidental takes of protected species according to the following notices to lessees and operators 

from the BOEM/BSEE: 

 NTL 2012-BSEE-G01 “Marine Trash and Debris Awareness and Elimination”

 NTL 2012-Joint-G01 “Vessel Strike Avoidance and Injured/Dead Protected Species Reporting”

 NTL 2012-Joint-G02 “Implementation of Seismic Survey Mitigation Measures & Protected Species 

Observer Program”

C. Flower Garden Banks National Marine Sanctuary 

The operations proposed in this EP will not be conducted within the Protective Zones of the Flower Garden 

Banks and Stetson Bank. 

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SECTION 11: LEASE STIPULATIONS INFORMATION 

Atwater Valley Block 18, OCS-G 33863 

This lease was acquired by BHP E&P Company LP in Lease Sale #213 on 3/17/2010 and has an expected 

expiration date of 6/30/2017. The lease is not a part of any Biological Sensitive Area, Military Warning Area, 

high Archeological probability area, or Shipping Fairway. Shell Offshore Inc. became lease operator on 

December 18, 2014. 

Lease Stipulation No. 8, Protected Species, is addressed in the following sections of this plan: 

Section 6h, Threatened or endangered species, critical habitat, and marine mammal information 

Section 10b, Environmental Monitoring Information, Incidental takes 

Section 12b, Environmental Mitigation Measures Information, Incidental takes 

Section 18, Environmental Impact Assessment 

Atwater Valley Block 19, OCS-G 32556 

This lease was acquired by ATP Oil & Gas Corporation in Lease Sale #206 on 3/19/2008 and has an expected 

expiration date of 7/31/2018. The lease is not a part of any Biological Sensitive Area, Military Warning Area, 

high Archeological probability area, or Shipping Fairway. Shell Offshore Inc. became lease operator on 

December 18, 2014. 

Lease Stipulation No. 8, Protected Species, is addressed in the following sections of this plan: 

Section 6h, Threatened or endangered species, critical habitat, and marine mammal information 

Section 10b, Environmental Monitoring Information, Incidental takes 

Section 12b, Environmental Mitigation Measures Information, Incidental takes 

Section 18, Environmental Impact Assessment 

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SECTION 12: ENVIRONMENTAL MITIGATION MEASURE INFORMATION 

A. Impacts to Marine and coastal environments 

The proposed action will implement mitigation measures required by laws and regulations, including all 

applicable Federal & State requirements concerning air emissions, discharges to water and solid waste disposal, 

as well as any additional permit requirements and Shell policies. Project activities will be conducted in 

accordance with the Regional OSRP. Section 18 of this plan discusses impacts and mitigation measures, 

including Coastal Habitats and Protected Areas. 

B. Incidental Takes 

We do not anticipate any incidental takes related to the proposed operations. Shell implements the mitigation 

measures and monitors for incidental takes of protected species according to the following notices to lessees 

and operators from the BOEM/BSEE: 

NTL 2012-BSEE-G01 “Marine Trash and Debris Awareness and Elimination”

NTL 2012-Joint-G01 “Vessel Strike Avoidance and Injured/Dead Protected Species Reporting”

NTL 2012-Joint-G02 “NTL 2012-Joint-G02 “Implementation of Seismic Survey Mitigation Measures &

Protected Species Observer Program”

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SECTION 13: RELATED FACILITIES AND OPERATIONS INFORMATION 

Information regarding Related Facilities and Operations Information, transportation systems & produced liquid 

hydrocarbon transportation vessels are not included in this EP as such information is only necessary in the case of 

DOCDs. 

 

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SECTION 14: SUPPORT VESSELS AND AIRCRAFT INFORMATION 

A. General 

Type Maximum Fuel Tank 

Storage Capacity (Gals)

Maximum No. In Area at 

Any Time

Trip Frequency or 

Duration

Crew Boats 8,000 1 Twice per week

Offshore Support Vessels 120,000 2 Twice per week

Helicopter 760 1 Once per day

B. Diesel Oil Supply Vessels 

Size of Fuel Supply 

Vessel

Capacity of Fuel Supply 

Vessel

Frequency of Fuel 

Transfers

Route Fuel Supply Vessel Will 

Take

280 foot length 100,000 gals. 1 week 6 miles from Port Fourchon to 

the mouth of Bayou Lafourche, 

then to DC 18

C. Drilling Fluids Transportation 

According to NTL 2008-G04, this information in only required when activities are proposed in the State 

of Florida. 

D. Solid and Liquid Wastes Transportation 

See Section 7, Table 7B. 

E. Vicinity Map 

See Attachment 14A for Vicinity Map. 

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Attachment 14A – Vicinity Map 

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SECTION 15: ONSHORE SUPPORT FACILITIES INFORMATION 

A. General 

Name Location Existing/New/Modified

Fourchon Port Fourchon, LA Existing

Boothville Heliport Boothville, LA Existing

The onshore support bases for water and air transportation will be the existing terminals in Boothville and 

Fourchon, Louisiana. The Fourchon boat facility is operated by Shell and is located on Bayou Lafourche, south 

of Leeville, LA approximately 3 miles from the Gulf of Mexico. The existing onshore air support base in 

Boothville, LA is located at 38963 Hwy. 23, Boothville, LA 70041. 

B. Support Base Construction or Expansion 

This does not apply to this EP as Shell does not plan to construct a new onshore support base or expand an 

existing one to accommodate the activities proposed in this EP. 

C. Support Base Construction or Expansion Timetable 

Since no onshore support base construction or expansion is planned for these activities, a timetable for land 

acquisition and construction or expansion is not applicable. 

D. Waste Disposal 

See Section 7, Tables 7A and 7B. 

E. Air emissions 

Not required by BOEM GOM. 

F. Unusual solid and liquid wastes 

Not required by BOEM GOM. 

SECTION 16: SULPHUR OPERATIONS INFORMATION 

Information regarding Sulphur Operations is not included in this EP as we are not proposing to conduct sulphur 

operations. 

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SECTION 17: COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION 

Louisiana and Mississipp’s CZM concurrences were obtained for these leases in plan N-9781 and are not 

required for Supplemental EP’s.

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SECTION 18: ENVIRONMENTAL IMPACT ANALYSIS (EIA) 

Environmental Impact Analysis 

SUPPLEMENTAL EXPLORATION PLAN 

Atwater Valley Blocks 18 and 19 (OCS-G 33863 and 32556)

Offshore Louisiana 

January 2015 

Prepared for:

Shell Offshore Inc. 

P.O. Box 61933 

New Orleans, Louisiana 70161 

Telephone: (504) 425-6021 

Prepared by:

CSA Ocean Sciences Inc. 

8502 SW Kansas Avenue 

Stuart, Florida 34997

Telephone: (772) 219-3000 

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Acronyms and Abbreviations 

ac acre 

AT Atwater Valley 

AUV autonomous underwater vehicle 

ADIOS Automated Data Inquiry for Oil Spills 

bbl barrel 

BOEM Bureau of Ocean Energy 

Management 

BOEMRE Bureau of Ocean Energy 

Management, Regulation and 

Enforcement 

BOP blowout preventer 

BOPD barrels of oil per day (bbl/d) 

BSEE Bureau of Safety and Environmental 

Enforcement 

C&C C&C Technologies, Inc. 

CFR Code of Federal Regulations 

CH4 methane 

CO carbon monoxide 

CO2 carbon dioxide 

dB decibel 

DP dynamically positioned 

DPS distinct population segment 

EFH Essential Fish Habitat 

EIA Environmental Impact Analysis 

EIS Environmental Impact Statement 

EP Exploration Plan 

ESA Endangered Species Act 

FAD fish-attracting device 

FR Federal Register 

Gardline Gardline Surveys Inc. 

GMFMC Gulf of Mexico Fishery Management 

Council 

H2S hydrogen sulfide 

ha hectare 

HAPC Habitat Area of Particular Concern 

Hz hertz 

IPF impact-producing factor 

MARPOL International Convention for the 

Prevention of Pollution from Ships 

MC Mississippi Canyon 

MMC Marine Mammal Commission 

MMPA Marine Mammal Protection Act 

MMS Minerals Management Service 

MWCC Marine Well Containment Company 

NAAQS National Ambient Air Quality 

Standards 

NEPA National Environmental Policy Act 

NMFS National Marine Fisheries Service 

NOAA National Oceanic and Atmospheric 

Administration 

NOx nitrogen oxides 

NPDES National Pollutant Discharge 

Elimination System 

NRC National Research Council 

NTL Notice to Lessees and Operators 

NWR National Wildlife Refuge 

OCS Outer Continental Shelf 

OCSLA Outer Continental Shelf Lands Act 

OSAT Operational Science Advisory Team 

OSRA Oil Spill Risk Analysis 

OSRP Oil Spill Response Plan 

PAH polycyclic aromatic hydrocarbon 

PM particulate matter 

ROV remotely operated vehicle 

SBM synthetic-based mud 

SEA Site-Specific Environmental 

Assessment 

Shell Shell Offshore Inc. 

SHL surface hole location 

SOx sulfur oxides 

UME Unusual Mortality Event 

USCG U.S. Coast Guard 

USDOI U.S. Department of the Interior 

USEPA U.S. Environmental Protection 

Agency 

USFWS U.S. Fish and Wildlife Service 

VOC volatile organic compound 

WCD worst case discharge 

WMA Wildlife Management Area 

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Introduction 

Project Summary

Shell Offshore Inc. (Shell) is submitting a Supplemental Exploration Plan (EP) for Atwater Valley 

Blocks 18 (AT 18) and 19 (AT 19) for seven (7) exploration wells to be drilled using either a 

dynamically positioned (DP) drillship or DP semisubmersible drilling rig. This EP is for proposed 

well locations A, B, C, D, E, F, and G. Surface hole locations (SHLs) for wells A, B, D, and E will 

be in AT 18, and wells C, F, and G will be in AT 19 in the Central Planning Area of the Gulf of 

Mexico. This Environmental Impact Analysis (EIA) provides information on potential impacts of 

Shell’s proposed activities based on the SHLs.

The lease area is 70 miles (111 km) from the nearest shoreline (Louisiana), 109 miles (175 km)

from the onshore support base at Port Fourchon, Louisiana, and 94 miles (153 km) from the 

helicopter base at Boothville, Louisiana. All miles in this EIA are statute miles. Water depth 

estimates at the proposed wellsites range from 4,203 to 4,432 ft (1,281 to 1,351 m). 

The following types of exploratory drilling rigs are available for this project: 

 Noble Don Taylor or a similar DP drillship; or 

 Noble Jim Day or similar DP semisubmersible drilling rig. 

The EIA is structured to address environmental impacts from both types of drilling rigs. 

Spudding for the proposed wells is scheduled for 2015, with an estimated timeline of 200 days 

per well and one well drilled each year. 

Purpose of the Environmental Impact Analysis

This EIA was prepared pursuant to the requirements of the Outer Continental Shelf Lands Act 

(OCSLA), 43 U.S.C. §§ 1331-1356, as well as regulations including 30 CFR 550.212(o) and 

550.227. The EIA is a project- and site-specific analysis of Shell’s planned activities under 

this EP1. 

The EIA presents data, analyses, and conclusions to support BOEM reviews as required by the 

National Environmental Policy Act (NEPA) and other relevant federal laws, including the 

Endangered Species Act (ESA) and Marine Mammal Protection Act (MMPA). It also identifies some 

of the mitigation measures Shell will implement in connection with the planned activities. 

The EIA is a project-specific analysis that focuses on the impacts of a specific plan. This EIA 

addresses the impact-producing factors (IPFs), resources, and impacts associated with the 

activities proposed in this EP. The EIA also analyzes the potential environmental impacts of the 

blowout scenario and worst case discharge (WCD) information. 

BOEM has performed numerous environmental evaluations of oil and gas activities on the Gulf of 

Mexico Outer Continental Shelf (OCS). Potential impacts were analyzed at a broader level in the 

 

1

 On October 1, 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) reorganized into two 

separate agencies: Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE). 

Shell understands that BOEM will review this EIA and prepare a Site-Specific Environmental Assessment (SEA) for the project. 

This EIA complies with guidance provided in existing Notices to Lessees and Operators (NTLs) issued by the former Minerals 

Management Service (MMS) and BOEMRE, including NTL 2008-G04 (recently extended by NTL 2014-G05). Throughout this EIA, 

when existing guidance and general agency activities are referred to, “BOEM” is meant to subsume the former agencies and to 

represent the continuous regulatory entity now called BOEM. The former agency names (MMS and BOEMRE) are used when 

referring to particular historical documents published under those names. In addition, until NTLs are reissued under BOEM or 

BSEE, the EIA will refer to the former BOEMRE as BOEM when addressing NTLs issued by BOEMRE or MMS. 

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Programmatic Environmental Impact Statements (EISs) for the OCS Oil and Gas Leasing Program 

(MMS, 2007a; BOEM 2012a) and in lease sale EISs for the Western and Central Gulf of Mexico 

Planning Areas (MMS, 2007b; BOEM, 2012b,c, 2013). 

These studies generated critical data and advanced the large body of existing knowledge on the 

Gulf of Mexico OCS. They analyze potential impacts on the natural environment, the 

socioeconomic effects of exploration and development activities, and other regional resources. 

Numerous technical studies address the likely trajectory of spilled oil, the effects of underwater 

noise on threatened and endangered species, and other IPFs. The studies inform agency 

decision-making on lease offerings, mitigation measures and lease stipulations, operational 

requirements, and permit restrictions. This substantial body of work, which in part, forms the 

basis for the evaluation presented here, will allow the BOEM and other regulatory agencies to 

evaluate Shell’s EP and ensure that oil and gas exploration activities are performed in an 

environmentally sound manner, with minimal impacts on the environment. Shell has incorporated 

these comprehensive environmental analyses by reference and built on them with project- and 

site-specific analyses, where applicable. 

OCS Regulatory Framework

The regulatory framework for OCS activities in the Gulf of Mexico was summarized in MMS (2010) 

and BOEM (2012b). Under the OCSLA, the U.S. Department of the Interior (USDOI) is responsible 

for the administration of mineral exploration and development of the OCS. Within the USDOI, 

BOEM and BSEE are charged with the responsibility of managing and regulating the development 

of OCS oil and gas resources in accordance with the provisions of the OCSLA. The BSEE offshore 

regulations are in 30 Code of Federal Regulations (CFR) Chapter II, Subchapter B. BOEM offshore 

regulations are in 30 CFR Chapter V, Subchapter B. 

In implementing its responsibilities under the OCSLA and NEPA, the BOEM consults numerous 

federal departments and agencies that have authority to govern and maintain ocean resources 

pursuant to other federal laws. Among these are the U.S. Coast Guard (USCG), 

U.S. Environmental Protection Agency (USEPA), U.S. Fish and Wildlife Service (USFWS), and the 

National Oceanic and Atmospheric Administration (NOAA) through the National Marine Fisheries 

Service (NMFS). Federal regulations establish consultation and coordination processes with 

federal, state, and local agencies (e.g., the ESA, MMPA, Coastal Zone Management Act of 1972, 

and the Magnuson-Stevens Fishery Conservation and Management Act). 

NTLs are formal documents issued by the BOEM and BSEE that provide clarification, description, 

or interpretation of a regulation or standard. Table 1 lists and summarizes the NTLs applicable to 

this EIA. 

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Table 1. Notices to Lessees and Operators (NTLs) that are applicable to this Environmental 

Impact Analysis (EIA). 

NTL Title Summary

2014-G04 Military Warning and Water Test 

Areas

Provides contact links to individual command headquarters for the 

military warning and water test areas in the Gulf of Mexico.

BOEM-2014-G05 Extension of Prior Notices to 

Lessees

Extends the effective date of NTLs 2008-G04 and 2008-G05 (and 

one other NTL) until December 31, 2014.

BSEE-2012-N06

Guidance to Owners and Operators 

of Offshore Facilities Seaward of the 

Coast Line Concerning Regional Oil 

Spill Response Plans

Provides clarification, guidance, and information for preparation of 

regional Oil Spill Response Plans. Recommends description of 

response strategy for WCD scenarios to ensure capability to 

respond to oil discharges is both efficient and effective.

2012-JOINT-G01

Vessel Strike Avoidance and 

Injured/Dead Protected Species 

Reporting

Recommends protected species identification training; recommends 

that vessel operators and crews maintain a vigilant watch for 

marine mammals and slow down or stop their vessel to avoid 

striking protected species; and requires operators to report 

sightings of any injured or dead protected species.

2012-BSEE-G01 Marine Trash and Debris Awareness 

and Elimination

Instructs operators to exercise caution in the handling and disposal 

of small items and packaging materials; requires the posting of 

placards at prominent locations on offshore vessels and structures; 

and mandates a yearly marine trash and debris awareness training 

and certification process.

2011-JOINT-G01

Revisions to the List of OCS Blocks 

Requiring Archaeological Resource 

Surveys and Reports

Provides new information on which OCS blocks require 

archaeological surveys and reports and line spacing required in each 

block. This NTL augments NTL 2005-G07.

2010-N10

Statement of Compliance with 

Applicable Regulations and 

Evaluation of Information 

Demonstrating Adequate Spill 

Response and Well Containment 

Resources

Informs operators using subsea blowout preventers (BOPs) or 

surface BOPs on floating facilities that applications for well permits 

must include a statement signed by an authorized company official 

stating that the operator will conduct all activities in compliance 

with all applicable regulations, including the increased safety 

measures regulations (75 Federal Register [FR] 63346). Informs 

operators that the BOEM will be evaluating whether each operator 

has submitted adequate information demonstrating that it has 

access to and can deploy containment resources to promptly 

respond to a blowout or other loss of well control.

2010-N06

Information Requirements for 

Exploration Plans, Development and 

Production Plans, and Development 

Operations Coordination Documents 

on the OCS

Rescinds the limitations set forth in NTL 2008-G04 regarding a 

blowout scenario and WCD scenario, and provides guidance 

regarding the information required in blowout scenario and 

WCD scenario descriptions.

2009-G40 Deepwater Benthic Communities

Guidance for avoiding and protecting high-density deepwater 

benthic communities (including chemosynthetic and deepwater 

coral communities) from damage caused by OCS oil and gas 

activities in water depths greater than 984 ft (300 m). Prescribes 

separation distances of 2,000 ft (610 m) from each mud and 

cuttings discharge location and 250 ft (76 m) from all other seafloor 

disturbances.

2009-G39 Biologically Sensitive Underwater 

Features and Areas

Guidance for avoiding and protecting biologically sensitive features 

and areas (i.e., topographic features, pinnacles, low-relief live 

bottom areas, and other potentially sensitive biological features) 

when conducting OCS operations in water depths less than 984 ft 

(300 m) in the Gulf of Mexico.

2009-N11 Air Quality Jurisdiction on the OCS Clarifies jurisdiction for regulation of air quality in the Gulf of Mexico 

Outer Continental Shelf. 

2008-G04

Information Requirements for 

Exploration Plans and Development 

Operations Coordination Documents

Guidance on the information requirements for OCS plans, including 

EIA requirements and information regarding compliance with the 

provisions of the ESA and MMPA.

2005-G07 Archaeological Resource Surveys 

and Reports

Provides guidance on regulations regarding archaeological 

discoveries, specifies requirements for archaeological resource 

surveys and reports, and outlines options for protecting 

archaeological resources.

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Oil Spill Prevention and Contingency Planning

Shell has an approved Gulf of Mexico Regional Oil Spill Response Plan (OSRP) as a fundamental 

component of the planned drilling program that certifies Shell’s capability to respond to the 

maximum extent practicable to a WCD (30 CFR 254.2) (see EP Section 9). The OSRP 

demonstrates Shell’s capabilities to rapidly and effectively manage oil spills that may result from 

drilling operations. Despite the extremely low likelihood of a large oil spill occurring during the 

project, Shell has designed its response program based upon a regional capability of responding 

to a range of spill volumes that increase from small operational spills to a WCD from a well 

blowout. Shell’s program is intended to meet the response planning requirements of the relevant 

coastal states and federal oil spill planning regulations. The OSRP includes information regarding 

Shell’s regional oil spill organization and dedicated response assets, potential spill risks, and local 

environmental sensitivities. The OSRP presents specific information on the response program that 

includes a description of personnel and equipment mobilization, the incident management team 

organization, and the strategies and tactics used to implement effective and sustained spill 

containment and recovery operations. 

EIA Organization

The EIA is organized into Sections A through I corresponding to the information required by 

NTL 2008-G04, which provides guidance regarding information required by 30 CFR Part 550 for 

EPs. The main impact-related discussions are in Section A (Impact-Producing Factors) and 

Section C (Impact Analysis). 

A. Impact-Producing Factors 

Table 2 is a matrix of IPFs and potentially affected environmental resources adapted from 

Form BOEM-142. An “X” indicates that an IPF could reasonably be expected to affect a certain 

resource, and a dash (--) indicates no impact or negligible impact is anticipated. Numbers in 

parentheses refer to the table footnotes on the following page. Where there may be an effect, an 

analysis is provided in Section C. Potential IPFs for the proposed activity are listed below and 

briefly discussed in the following subsections: 

 Drilling rig presence (including noise and lights); 

 Physical disturbance to the seafloor; 

 Air pollutant emissions; 

 Effluent discharges; 

 Water intake; 

 Onshore waste disposal; 

 Marine debris; 

 Support vessel and helicopter traffic; and 

 Accidents. 

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Table 2. Matrix of impact-producing factors and affected environmental resources. X = potential impact; dash (--) = no impact or negligible impact. 

Environmental Resources

Impact-producing Factors

Drilling Rig 

Presence (incl. 

noise & lights)

Physical 

Disturbance 

to Seafloor

Air 

Pollutant 

Emissions

Effluent 

Discharges

Water 

Intake

Onshore 

Waste 

Disposal

Marine 

Debris

Support 

Vessel/Helo 

Traffic

Accidents

Small Fuel 

Spill

Large Oil 

Spill

Physical/Chemical Environment

Air quality -- -- X(5) -- -- -- -- -- X(6) X(6)

Water quality -- -- -- X -- -- -- -- X(6) X(6)

Seafloor Habitats and Biota

Soft bottom benthic communities -- X -- X -- -- -- -- -- X(6)

High-density deepwater benthic communities -- --(4) -- --(4) -- -- -- -- -- X(6)

Designated topographic features -- --(1) -- --(1) -- -- -- -- -- --

Pinnacle trend area live bottoms -- --(2) -- --(2) -- -- -- -- -- --

Eastern Gulf live bottoms -- --(3) -- --(3) -- -- -- -- -- --

Threatened, Endangered, and Protected Species and Critical Habitat

Sperm whale (endangered) X(8) -- -- -- -- -- -- X(8) X(6,8) X(6,8)

West Indian manatee (endangered) -- -- -- -- -- -- -- X(8) -- X(6,8)

Non-endangered marine mammals (protected) X -- -- -- -- -- -- X X(6) X(6)

Sea turtles (endangered/threatened) X(8) -- -- -- -- -- -- X(8) X(6,8) X(6,8)

Piping Plover (threatened) -- -- -- -- -- -- -- -- -- X(6)

Whooping Crane (endangered) -- -- -- -- -- -- -- -- -- X(6)

Gulf sturgeon (threatened) -- -- -- -- -- -- -- -- -- X(6)

Beach mice (endangered) -- -- -- -- -- -- -- -- -- X(6)

Coastal and Marine Birds

Marine and pelagic birds X -- -- -- -- -- -- X X(6) X(6)

Shorebirds and coastal nesting birds -- -- -- -- -- -- -- X -- X(6)

Fisheries Resources

Pelagic communities and ichthyoplankton X -- -- X X -- -- -- X(6) X(6)

Essential Fish Habitat X -- -- X X -- -- -- X(6) X(6)

Archaeological Resources

Shipwreck sites -- --(7) -- -- -- -- -- -- -- X(6)

Prehistoric archaeological sites -- --(7) -- -- -- -- -- -- -- X(6)

Coastal Habitats and Protected Areas

Beaches -- -- -- -- -- -- -- -- -- X(6)

Wetlands and seagrass beds -- -- -- -- -- -- -- X -- X(6)

Coastal wildlife refuges and wilderness areas -- -- -- -- -- -- -- -- -- X(6)

Socioeconomic and Other Resources

Recreational and commercial fishing X -- -- -- -- -- -- -- X(6) X(6)

Public health and safety -- -- -- -- -- -- -- -- X(6) X(6)

Employment and infrastructure -- -- -- -- -- -- -- -- X(6) X(6)

Recreation and tourism -- -- -- -- -- -- -- -- X(6) X(6)

Land use -- -- -- -- -- -- -- -- -- X(6)

Other marine uses -- -- -- -- -- -- -- -- -- X(6)

Numbers in parentheses refer to table footnotes on the following page. Helo = helicopter. 

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Table 2 Footnotes and Applicability: 

(1) Activities that may affect a marine sanctuary or topographic feature. Specifically, if the well, platform site, or any 

anchors will be on the seafloor within the following: 

(a) 4-mile zone of the Flower Garden Banks, or the 3-mile zone of Stetson Bank; 

(b) 1,000-m, 1-mile, or 3-mile zone of any topographic feature (submarine bank) protected by the Topographic 

Features Stipulation attached to an Outer Continental Shelf (OCS) lease; 

(c) Essential Fish Habitat (EFH) criteria of 500 ft from any no-activity zone; or 

(d) Proximity of any submarine bank (500-ft buffer zone) with relief greater than 2 m that is not protected by 

the Topographic Features Stipulation attached to an OCS lease. 

 Not applicable. The lease is not within the given ranges (buffer zone) of any marine sanctuary, 

topographic feature, or no-activity zone. There are no submarine banks in the lease block. 

(2) Activities with any bottom disturbance within an OCS lease block protected through the Live Bottom 

(Pinnacle Trend) Stipulation attached to an OCS lease. 

 The Live Bottom (Pinnacle Trend) Stipulation is not applicable to the lease area. 

(3) Activities within any Eastern Gulf OCS block and portions of Pensacola and Destin Dome area blocks in the 

Central Planning Area where seafloor habitats are protected by the Live Bottom (Low-Relief) Stipulation attached 

to an OCS lease. 

 The Live Bottom (Low-Relief) Stipulation is not applicable to the lease area. 

(4) Activities on blocks designated by the BOEM as being in water depths 300 m or greater. 

 No impacts on high-density deepwater benthic communities are anticipated because no features indicative 

of high-density chemosynthetic communities or coral communities are located within 2,000 ft (610 m) of 

mud or cuttings discharge locations (Gardline Surveys Inc. [Gardline], 2012). 

(5) Exploration or production activities where hydrogen sulfide (H2S) concentrations greater than 500 ppm might be 

encountered. 

 EP Section 4 contains Shell’s request for classification as an area absent of H2S.

(6) All activities that could result in an accidental spill of produced liquid hydrocarbons or diesel fuel that you 

determine would impact these environmental resources. If the proposed action is located a sufficient distance 

from a resource that no impact would occur, the EIA can note that in a sentence or two. 

 Accidental hydrocarbon spills could affect the resources marked (X) in the matrix, and impacts are analyzed 

in Section C. 

(7) All activities that involve seafloor disturbances, including anchor emplacements, in any OCS block designated by 

the BOEM as having high-probability for the occurrence of shipwrecks or prehistoric sites, including such blocks 

that will be affected that are adjacent to the lease block in which your planned activity will occur. If the 

proposed activities are located a sufficient distance from a shipwreck or prehistoric site that no impact would 

occur, the EIA can note that in a sentence or two. 

 No impacts on archaeological resources are expected. The lease area is not on the list of archaeology survey 

blocks (BOEM, 2012d), and the archaeological surveys did not detect any sonar targets or identify any 

archaeological avoidance areas within 2,000 ft (610 m) of the wellsites (C&C Technologies, Inc., 2012). The 

lease area is beyond the 60-m (197-ft) depth contour; therefore, prehistoric archaeological sites are not 

likely. A dynamically positioned (DP) drillship or DP semisubmersible drilling rig will be used; therefore, no 

seafloor disturbances due to anchoring will occur. 

(8) All activities that you determine might have an adverse effect on endangered or threatened marine mammals or 

sea turtles or their critical habitats. 

 IPFs that may affect marine mammals or sea turtles include drilling rig presence and emissions, support 

vessel and helicopter traffic, and accidents. See Section C. 

(9) Production activities that involve transportation of produced fluids to shore using shuttle tankers or barges. 

 Not applicable.

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A.1 Drilling Rig Presence (including noise and lights)

The wells will be drilled using either a DP drillship or DP semisubmersible drilling rig that will be 

on site for an estimated 200 days per well. DP drillships and DP semisubmersible drilling rigs are 

self-propelled and maintain position using a global positioning system, specific computer 

software, and sensors in conjunction with a series of thrusters. Offshore support vessels will be 

used during the drilling program. Potential impacts to marine resources from the drilling rig 

include the physical presence of the drilling rig in the ocean, increased light from working and 

safety lighting on the vessel, and noise audible above and below the water surface. 

The physical presence of a DP drillship or DP semisubmersible drilling rig in the ocean can attract 

pelagic fishes and other marine life, as discussed in Section C.5.1. The DP drillship or 

DP semisubmersible drilling rig will maintain exterior lighting for working at night and 

navigational and aviation safety in accordance with federal regulations. Artificial lighting may 

attract and directly or indirectly impact natural resources, particularly birds, as discussed in 

Section C.4. 

Drilling operations produce noise that includes strong tonal components at low frequencies, 

including infrasonic frequencies in at least some cases (MMS, 2000). DP drillships and 

DP semisubmersible drilling rigs can be expected to produce noise from both drilling and 

maintenance operations. Potential impacts of noise produced during drilling operations and vessel 

positioning are discussed in Section C.3 (threatened, endangered, and protected species) and 

Section C.4 (coastal and marine birds). 

Underwater marine sounds associated with drilling operations are not particularly intense and 

include strong tonal components at low frequencies (averaging 10 to 500 hertz [Hz]) and 

infrasonic frequencies in at least some cases (Richardson et al., 1995; MMS, 2000). Sound and 

vibration associated with drilling operations are transmitted to the water either through the air or 

through the risers (MMS, 2000). Marine sounds emitted by drilling rigs were found to be 

dominated by a mix of tones believed to be related to the drill string rotation rate. When drilling, 

the drill string represents a long vertical sound source (McCauley, 1998). The DP thrusters add 

another component to the marine sound signature from a DP drillship or DP semisubmersible 

drilling rig. DP thrusters can produce intermittent or continuous marine sound that varies 

depending on thruster type, operating efficiency, ship size, engine load, duty cycle, and weather 

or current conditions. 

The response of marine mammals, sea turtles, and fishes to a perceived marine sound depends 

on a range of factors, including: 1) the sound pressure level, frequency, duration, and novelty of 

the sound; 2) the physical and behavioral state of the animal at the time of perception; and 

3) the ambient acoustic features of the environment (Hildebrand, 2004). 

A.2 Physical Disturbance to the Seafloor

The wells will be drilled using either a DP drillship or DP semisubmersible drilling rig, which will 

not use anchors. There will be minimal disturbance to the seafloor and soft bottom communities 

during positioning of the wellbore and blowout preventers. Physical disturbance of the seafloor 

will be limited to the proximal area where the wellbore penetrates the substrate and where mud 

and drill cuttings will be deposited. 

A.3 Air Pollutant Emissions

Estimates of air pollutant emissions are provided in EP Section 8. Offshore air pollutant 

emissions will result from operations of the DP drillship or DP semisubmersible drilling rig as well 

as service vessels and helicopters. These emissions occur mainly from combustion of diesel fuel. 

Primary air pollutants typically associated with OCS activities are suspended particulate matter 

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(PM), sulfur oxides (SOx), nitrogen oxides (NOx), volatile organic compounds (VOCs), and carbon 

monoxide (CO). 

AT 18 and 19 are located westward of 87.5° W longitude; thus, air quality is under BOEM 

jurisdiction, as explained in NTL 2009-N11. The BOEM implementing regulations are provided in 

30 CFR 550 Subpart C. The Air Quality Emissions Report (see EP Section 8) prepared in 

accordance with BOEM requirements shows that the projected emissions from emission sources 

associated with the proposed activities meet the BOEM exemption criteria and are therefore 

exempt from further air quality review pursuant to 30 CFR 550.303(d). Based on calculated 

emissions and the wells’ locations relative to shore, it can be concluded that project emissions 

will not significantly affect onshore air quality for any of the criteria pollutants. No further analysis 

or control measures are required. 

A.4 Effluent Discharges

Effluent discharges from the DP drillship or DP semisubmersible drilling rig are summarized in 

EP Section 7. Discharges from the DP drillship or DP semisubmersible drilling rig are required to 

be in compliance with the National Pollutant Discharge Elimination System (NPDES) General 

Permit for oil and gas activities (GMG290000). Support vessel discharges are expected to be in 

accordance with USCG regulations and, therefore, they are not expected to cause significant 

impacts on water quality. 

Water-based drilling muds and cuttings will be released at the seafloor during the initial well 

intervals before the marine riser is set, which allows their return to the surface vessel. Excess 

cement slurry will also be released at the seafloor during casing installation for the riserless 

portion of the drilling operations. 

A synthetic-based mud (SBM) system will be used for drilling activities after the marine riser is 

installed that allows recirculation of the SBM fluids and cuttings. Unused or residual SBM will be 

collected and transported to Port Fourchon, Louisiana, for recycling. Drill cuttings will be 

discharged overboard via a downpipe below the water surface, after treatment that complies with 

the NPDES permit limits for synthetic fluid retained on cuttings. The estimated volume of drill 

cuttings to be discharged is provided in EP Section 7. 

Other effluent discharges from the DP drillship or DP semisubmersible drilling rig and support 

vessel are expected to include excess cement slurry, non-contact cooling water, treated sanitary 

and domestic wastes, deck drainage, desalination unit brine, uncontaminated fire water, and 

ballast water. The DP drillship or DP semisubmersible drilling rig and support vessel discharges 

are expected to be in accordance with NPDES permit and USCG regulations, as applicable, and 

therefore are not expected to cause significant impacts on water quality. 

A.5 Water Intake

Seawater will be drawn from several meters below the ocean surface for various services, 

including firewater and once-through non-contact cooling of machinery on the DP drillship or 

DP semisubmersible drilling rig (EP Table 7a).

Section 316(b) of the Clean Water Act requires NPDES permits to ensure that the location, 

design, construction, and capacity of cooling water intake structures reflect the best technology 

available to minimize adverse environmental impact from impingement and entrainment of 

aquatic organisms. The NPDES General Permit No. GMG290000 specifies requirements for new 

facilities for which construction commenced after July 17, 2006, with a cooling water intake 

structure having a design intake capacity of greater than 2 million gallons of water per day, of 

which at least 25% is used for cooling purposes. 

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The wells will be drilled using a DP drillship or DP semisubmersible drilling rig. If the DP drillship 

or DP semisubmersible drilling rig selected for this project meets the described applicability for 

new facilities, the vessel’s water intakes are expected to be in compliance with the design, 

monitoring, and recordkeeping requirements of the NPDES permit. 

A.6 Onshore Waste Disposal

Wastes generated during exploration activities are tabulated in EP Section 7. Non-hazardous 

trash and debris and non-recyclable waste will be generated during the proposed project and will 

be transported to the Republic/BFI landfill in Sorrento, Louisiana, to the parish landfill in 

Avondale, Louisiana, or to a similarly permitted facility. Recyclable trash and debris will be 

generated during the proposed project and will be recycled at Omega Waste Management in 

Patterson, Louisiana, at ARC of New Iberia, Louisiana, or at a similarly permitted facility. Used oil 

will be sent to Omega Waste Management in Patterson, Louisiana, to ARC of New Iberia, 

Louisiana, or to a similarly permitted facility. Hazardous waste will be sent to Lamp 

Environmental Services in Port Fourchon, Louisiana, or to a similarly permitted facility. At the 

respective onshore facilities, wastes will be recycled or disposed of according to applicable 

regulations. 

A.7 Marine Debris

Trash and debris released into the marine environment can harm marine animals through 

entanglement and ingestion. Shell will adhere to the International Convention for the Prevention 

of Pollution from Ships (MARPOL 73/78) Annex V requirements, USEPA and USCG regulations, 

and BSEE regulations and NTLs regarding solid wastes. BSEE regulations at 30 CFR 250.300(a) 

and (b)(6) prohibit operators from deliberately discharging containers and other similar materials 

(e.g., trash and debris) into the marine environment, and 30 CFR 250.300(c) requires durable 

identification markings on equipment, tools and containers (especially drums), and other 

material. USCG and USEPA regulations require operators to become proactive in avoiding 

accidental loss of solid waste items by developing waste management plans, posting 

informational placards, manifesting trash sent to shore, and using special precautions such as 

covering outside trash bins to prevent accidental loss of solid waste. Shell complies with NTL 

2012-BSEE-G01, which instructs operators to exercise caution in the handling and disposal of 

small items and packaging materials, requires the posting of placards at prominent locations on 

offshore vessels and structures, and mandates a yearly marine trash and debris awareness 

training and certification process. Shell’s compliance with applicable laws, regulations, and NTL 

2012-BSEE-G01 will avoid significant impacts on the environment. 

A.8 Support Vessel and Helicopter Traffic

Shell will use existing shore-based facilities at Port Fourchon and Boothville, Louisiana, for 

onshore support for water and air transportation, respectively. No terminal expansion or 

construction is planned at either location. 

The supply base at Port Fourchon is operated by Shell and located on Bayou Lafourche, 

approximately 3 miles (5 km) from the Gulf of Mexico. There will likely be at least one support 

vessel in the field at all times during drilling activities. The supply vessels will normally move to 

the project area via the most direct route from the shorebase. Helicopters transporting personnel 

and small supplies will normally take the most direct route of travel between the helicopter base 

in Boothville and the lease area when air traffic and weather conditions permit. Helicopters 

typically maintain a minimum altitude of 700 ft (213 m) while in transit offshore; 1,000 ft (305 m) 

over unpopulated areas or across coastlines; and 2,000 ft (610 m) over populated areas and 

sensitive habitats such as wildlife refuges and park properties. Additional guidelines and 

regulations specify that helicopters maintain an altitude of 1,000 ft (305 m) within 300 ft (91 m) 

of marine mammals (BOEM, 2012a). 

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Vessel noise is one of the main contributors to overall noise in the sea (National Research Council 

[NRC], 2003a; Jasny et al., 2005). Offshore supply and service vessels associated with the 

proposed project would contribute to the overall noise environment by transmitting noise through 

both air and water. Vessel noise is a combination of narrow-band (tonal) and broadband sound 

(Richardson et al., 1995). Tones typically dominate up to about 50 Hz, whereas broadband 

sounds may extend to 100 kHz. The primary sources of vessel noise are propeller cavitation, 

propeller singing, and propulsion; other sources include auxiliary engine noise, flow noise from 

water dragging along the hull, and bubbles breaking in the vessel’s wake while moving through 

the water (Richardson et al., 1995). Propeller cavitation is usually the dominant underwater noise 

source. The intensity of noise from service vessels is roughly related to ship size and speed. 

Broadband source levels for smaller boats (a category that would include supply and other 

service vessels) are in the range of 150 to 170 decibels [dB] re 1 μPa at 1 m (Richardson et al., 

1995). 

Helicopters used for offshore oil and gas operation support are a potential source of noise to the 

marine environment. Helicopter noise is generated from their jet turbine engines, airframe, and 

rotors. The dominant tones for helicopters are generally below 500 Hz (Richardson et al., 1995). 

Richardson et al. (1995) reported received sound pressure levels in water of 109 dB re 1 μPa 

from a Bell 212 helicopter flying at an altitude of 152 m (500 ft). Penetration of aircraft noise 

below the sea surface is greatest directly below the aircraft; at angles greater than 13 degrees 

from vertical, much of the sound is reflected from the sea surface and so does not penetrate into 

the water (Richardson et al., 1995). The duration of underwater sound from passing aircraft is 

much shorter in water than air; for example, a helicopter passing at an altitude of 152 m (500 ft) 

that is audible in air for 4 minutes may be detectable under water for only 38 seconds at 3 m 

(10 ft) depth and for 11 seconds at 18 m (59 ft) depth (Richardson et al., 1995). 

A.9 Accidents

A.9.1 Types of Accidents Evaluated

The analysis in this EIA focuses on two types of potential accidents: 

 a small fuel spill, which is the most likely type of spill during OCS exploration activities; 

and 

 an oil spill resulting from an uncontrolled blowout. A blowout resulting in a large oil spill 

is an extremely rare event, and the probability of such an event will be minimized by 

Shell’s well control and blowout prevention measures detailed in EP Section 2j. 

The following subsections summarize assumptions about the sizes and fates of these spills as 

well as Shell’s spill response plans. Impacts are analyzed in Section C. 

Lease sale EISs (MMS, 2007b; BOEM, 2012b,c, 2013) analyzed other types of accidents, including 

chemical spills, vessel collisions, and loss of well control. These accidents are discussed briefly in 

Section A.9.4. 

A.9.2 Small Fuel Spill

Spill Size. According to the analysis in BOEM (2012b), the most likely type of small spill 

(<1,000 barrels [bbl]) as a result of OCS activities is a minor diesel fuel spill. Historically, most 

diesel spills have been <1 bbl, and this size is predicted to be the most common in ongoing and 

future OCS activities in the Western and Central Gulf of Mexico Planning Areas (BOEM, 2012b). 

The median size for spills <1 bbl is 0.024 bbl, and the median size for spills of 1 to 10 bbl is 3 bbl 

(BOEM, 2012b). For this analysis, a small diesel fuel spill of 3 bbl is assumed. Operational 

experience suggests that the most likely cause of such a spill would be a hose rupture resulting 

in the loss of the contents of a fuel transfer hose, which is less than 3 bbl.

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Spill Fate. The fate of a small fuel spill in the lease area would depend on meteorological and 

oceanographic conditions at the time of the spill, as well as the effectiveness of spill response 

activities. However, given the open ocean location of the lease area and the short duration of a 

small spill, it is expected that the opportunity for impacts to occur would be very brief. 

The water-soluble fractions of diesel are dominated by two- and three-ringed polycyclic aromatic 

hydrocarbons (PAHs), which are moderately volatile (NRC, 2003b). The constituents of these oils 

are light to intermediate in molecular weight and can be readily degraded by aerobic microbial 

oxidation. Diesel density is such that it will not sink to the seafloor. Diesel dispersed in the water 

column can adhere to suspended sediments, but this generally occurs only in coastal areas with 

high-suspended solids loads (NRC, 2003b) and would not be expected to occur to any 

appreciable degree in offshore waters of the Gulf of Mexico. Diesel oil is readily and completely 

degraded by naturally occurring microbes (NOAA, 2006). 

The fate of a small diesel fuel spill was estimated using NOAA’s Automated Data Inquiry for Oil 

Spills (ADIOS) 2 model. This model uses the physical properties of oils in its database to predict 

the rate of evaporation and dispersion over time, as well as changes in the density, viscosity, and 

water content of the product spilled. It is estimated that more than 90% of a small diesel spill 

would be evaporated or naturally dispersed within 24 hours. The area of diesel fuel on the sea 

surface would range from 1.2 to 12 acres (ac) (0.5 to 5 hectares [ha]), depending on sea state 

and weather conditions. 

The ADIOS 2 results, coupled with spill trajectory information discussed in the next section for a 

large spill, indicate that a small fuel spill would not affect coastal or shoreline resources. The 

lease area is 70 miles (111 km) from the nearest shoreline (Louisiana). Modeling results indicate 

that a surface spill in the lease area would have a 4% probability of contacting the nearest 

Louisiana shorelines within 30 days after a spill. Slicks from spills are expected to persist for 

relatively short periods of time ranging from minutes (<1 bbl) to hours (<10 bbl) to a few days 

(10 to 1,000 bbl) and rapidly spread out, evaporate, and disperse into the water column 

(BOEM, 2012b). Because of the distance of these potential spills on the OCS and their lack of 

persistence, it is unlikely that a small diesel spill would make landfall prior to dissipation 

(BOEM, 2012b). 

Spill Response. In the unlikely event of a fuel spill, response equipment and trained personnel 

would be available to ensure that spill effects are localized and would result only in short-term, 

localized environmental consequences. EP Section 9b provides a detailed discussion of Shell’s 

response to a spill. 

A.9.3 Large Oil Spill

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures detailed in 

EP Section 2j. Blowouts are rare events and most do not result in oil spills (BOEM, 2012a). 

Spill Size. Shell has calculated the WCD for this EP using the requirements prescribed by 

NTL 2015-N01 as 65,915 barrels of oil per day (BOPD). The detailed analysis of this calculation 

can be found in EP Section 2j. The WCD scenario for this EP has a low probability of being 

realized. Some of the factors that are likely to reduce rates and volumes, which are not included 

in the WCD calculation, include, but are not limited to, obstructions or equipment in the wellbore, 

well bridging, and early intervention such as containment. 

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Shell has a robust system in place to prevent blowouts. Included in EP Sections 2j and 9b is 

Shell’s response to NTL 2010-N06, which includes descriptions of measures to prevent a blowout, 

reduce the likelihood of a blowout, and conduct effective and early intervention in the event of a 

blowout. Shell will also comply with NTL 2010-N10 and the Final Drilling Safety Rule, which 

specify additional safety measures for OCS activities. 

Spill Trajectory. The fate of a large oil spill in the lease area would depend on meteorological and 

oceanographic conditions at the time. The Oil Spill Risk Analysis (OSRA) model is a computer 

simulation of oil spill transport that uses realistic data for winds and currents to predict spill fate. 

The OSRA report by Ji et al. (2004) provides conditional contact probabilities for shoreline 

segments. 

The results for Launch Area C060 (the launch area nearest to the lease area) are presented in 

Table 3. The model predicts no shoreline contact within the first 3 days following a spill. After 

10 days, there is a 1% probability of contact with Plaquemines Parish, Louisiana. After 30 days, 

shoreline segments of two Texas counties and five Louisiana parishes have a probability of 1% to 

4% of being contacted. Plaquemines Parish, Louisiana, has the highest probability of shoreline 

contact, with a 4% chance within 30 days. Other parishes and counties ranging from Galveston 

County, Texas, to LaFourche Parish, Louisiana, have a 1% to 2% probability of shoreline contact 

after 30 days. 

Table 3. Conditional probabilities of a spill in the lease area contacting shoreline segments based 

on a 30-day Oil Spill Risk Analysis (OSRA) (From: Ji et al., 2004). Values are conditional 

probabilities that a hypothetical spill in the lease area (represented by OSRA Launch 

Area C060) could contact shoreline segments within 3, 10, or 30 days. 

Shoreline 

Segment County or Parish, State Conditional Probability of Contact1

(%)

3 Days 10 Days 30 Days

C10 Galveston, TX -- -- 1

C12 Jefferson, TX -- -- 1

C13 Cameron, LA -- -- 2

C14 Vermilion, LA -- -- 1

C17 Terrebonne, LA -- -- 2

C18 LaFourche, LA -- -- 1

C20 Plaquemines, LA -- 1 4

1

 Conditional probability refers to the probability of contact within the stated time period, assuming that a spill has 

occurred. -- indicates less than 0.5% probability of contact. 

The OSRA model does not evaluate the fate of a spill over time periods longer than 30 days, nor 

does it predict the fate of a release that continues over a period of weeks or months. Also as 

noted in Ji et al. (2004), the OSRA model does not take into account the chemical composition or 

biological weathering of oil spills, the spreading and splitting of oil spills, or spill response 

activities. The model does not assume a particular spill size but has generally been used by 

BOEM to evaluate contact probabilities for spills greater than 1,000 bbl. OSRA is a preliminary risk 

assessment model. In the event of an actual oil spill, trajectory modeling would be conducted 

using the location and estimated amount of spilled oil, as well as current and wind data. 

Weathering. Following an oil spill, several physical, chemical, and biological processes, collectively 

called weathering, interact to change the physical and chemical properties of the oil, and thereby 

influence its harmful effects on marine organisms and ecosystems. The most important 

weathering processes include spreading, evaporation, dissolution, dispersion into the water 

column, formation of water-in-oil emulsions, photochemical oxidation, microbial degradation, 

adsorption to suspended PM, and stranding on shore or sedimentation to the seafloor (NRC, 

2003b). 

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Weathering decreases the concentration of oil and produces changes in its chemical composition, 

physical properties, and toxicity. The more toxic, light aromatic and aliphatic hydrocarbons are 

lost rapidly by evaporation and dissolution from the slick on the water surface. Evaporated 

hydrocarbons are degraded rapidly by sunlight. Biodegradation of oil on the water surface and in 

the water column by marine bacteria removes first the n-alkanes and then the light aromatics 

from the oil. Other petroleum components are biodegraded more slowly. Photooxidation attacks 

mainly the medium and high molecular weight PAHs in the oil on the water surface. 

Spill Response. Shell is a founding member of the Marine Well Containment Company (MWCC) 

and has access to an integrated subsea well control and containment system that can be rapidly 

deployed through the MWCC. The MWCC is a non-profit organization that assists with the subsea 

containment system during a response. The near-term containment response capability will be 

specifically addressed in Shell’s NTL 2010-N10 submission at the time an Application for Permit to 

Drill is submitted and will include equipment and services available to Shell through MWCC’s 

development of near-term capability and other industry sources. Shell is a member of Clean 

Caribbean & Americas, Marine Spill Response Corporation, Clean Gulf Associates, and Oil Spill 

Response Limited, organizations that are committed to providing the resources necessary to 

respond to a spill as outlined in Shell’s OSRP.

Mechanical recovery capabilities are addressed in the OSRP. The mechanical recovery response 

equipment that could be mobilized to the spill location in normal and adverse weather conditions 

is included in the Offshore On-Water Recovery Activation List in the OSRP. 

Chemical dispersion capabilities are also readily available from resources identified in the OSRP. 

Available equipment for surface and subsea application of dispersants, response times, and 

support resources are identified in the OSRP. 

Open-water in situ burning may also be used as a response strategy, depending on the 

circumstances of the release. If appropriate conditions exist and approval from the Unified 

Command is received, one or multiple in situ burning task forces could be deployed offshore. 

See EP Section 9b for a detailed description of spill response measures. 

A.9.4 Other Accidents Not Analyzed in Detail

The lease sale EISs (BOEM, 2012b,c, 2013) discuss four other types of accidents: chemical spills, 

pipeline failures, vessel collisions, and loss of well control. Three of these types of accidents 

considered relevant to this EP are briefly discussed in this section. Other than the presence of 

hydrogen sulfide (H2S), which is addressed below, no other site-specific issues have been 

identified for this EP. The analysis in the lease sale EISs for these topics is incorporated by 

reference. 

Chemical Spill. Chemicals are used in drilling and producing operations to achieve technical goals 

in the drilling process, improve the efficiency and safety of drilling, and protect associated 

equipment. Chemicals used during drilling include surfactants, bentonite clays, olefins, inorganic 

salts, glycols, polymers, barite, and calcium carbonate. Supplies are renewed on a regular basis 

by transfer in containers from supply boats (Boehm et al., 2001). In addition to chemicals used in 

drilling fluids, the following chemicals are likely to be used on the DP drillship or 

DP semisubmersible drilling rig: ethylene glycol (blowout prevention control fluid, used in closed 

cooling loops for crane and main engines and brake coolers), cement (used to cement casing in 

place), solvents (used in painting operations), hydraulic fluids (used in cranes and other hydraulic 

rig equipment), lubricating oil and grease (used in reciprocating and electrical equipment), and 

sodium hypochlorite (dilute, used as laundry bleach and disinfectant). 

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A study of environmental risks of chemical products used in OCS activities determined that only 

two chemicals could potentially affect the marine environment in the concentrations typically 

used: zinc bromide and ammonium chloride (Boehm et al., 2001). The project addressed by this 

EP does not anticipate the use of either zinc bromide or ammonium chloride. Most other 

chemicals are either nontoxic or used in small quantities (BOEM, 2012b,c, 2013). No significant 

impacts are expected from chemical spills. 

Vessel Collisions. As summarized in MMS (2007b) and BOEM (2012b,c, 2013), vessel collisions 

occasionally occur during routine operations. Most collision mishaps are the result of service 

vessels colliding with platforms or vessel collisions with pipeline risers. About 10% of these 

collisions have caused spills of diesel fuel or chemicals (BOEM, 2012b,c). Shell will comply with 

USCG- and BOEM-mandated safety requirements to minimize the potential for vessel collisions. 

Loss of Well Control. A loss of well control is the uncontrolled flow of a reservoir fluid that may 

result in the release of gas, condensate, oil, drilling fluids, sand, or water. Loss of well control is a 

broad term that includes minor to serious well control incidents, while blowouts, discussed in 

Section A.9.3, are considered to be a more serious subset of loss of well control incidents with 

greater risk of oil spill or human injury (MMS, 2007b). Not all loss of well control events result in 

blowouts (BOEM, 2012b,c, 2013). In addition to the potential release of gas, condensate, oil, 

sand, or water, the loss of well control can also resuspend and disperse bottom sediments 

(BOEM, 2012b). BOEM (2012b,c, 2013) noted that most OCS blowouts have resulted in the 

release of gas. 

Shell has a robust system in place to prevent loss of well control. Included in this EP is Shell’s 

response to NTL 2010-N06, which includes descriptions of measures to prevent a blowout, 

reduce the likelihood of a blowout, and conduct effective and early intervention in the event of a 

blowout. Shell will also comply with NTL 2010-N10 and the Final Drilling Safety Rule, which 

specify additional safety measures for OCS activities. See EP Sections 2j and 9b for further 

information. 

H2S Release. EP Section 4 contains Shell’s request for classification as an area absent of H2S.

B. Affected Environment 

The lease area is in the central Gulf of Mexico, 70 miles (111 km) from the nearest shoreline, 

109 miles (175 km) from the onshore support base at Port Fourchon, Louisiana, and 94 miles 

(153 km) from the helicopter base at Boothville, Louisiana. 

Water depth estimates at the proposed wellsites range from 4,203 to 4,432 ft 

(1,281 to 1,351 m). 

There is no evidence of seafloor or near-surface faulting, amplitudes, or fluid expulsion in the 

vicinity of the proposed well locations. The side-scan sonar survey confirmed the presence of 

previously drilled wells in the lease area, with one within 2,000 ft (610 m) of two of the proposed 

wellsites. AT 18-A and 18-B are within 2,000 ft (610 m) from Anadarko’s previously drilled AT 18-

1 wellsite. The previously drilled well will not interfere with the proposed wellsites. There is one 

flowline and umbilical in the vicinity of the proposed wells AT 19-F and 19-G (Gardline, 2012). 

The proposed wells will not interfere with the Bennu flowline and umbilical. 

A detailed description of the regional affected environment is provided in MMS (2007b) and 

BOEM (2012b,c), including meteorology, oceanography, geology, air and water quality, benthic 

communities, threatened and endangered species, biologically sensitive resources, archaeological 

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resources, socioeconomic conditions, and other marine uses. These regional descriptions are 

based on extensive literature reviews and are incorporated by reference. General background 

information is presented in the following sections, and brief descriptions of each potentially 

affected resource are presented in Section C, including site-specific and/or new information if 

available. 

The local environment in the lease area is not known to be unique with respect to 

physical/chemical, biological, or socioeconomic conditions. The baseline environmental conditions 

in the lease area are expected to be consistent with the regional description of the locations 

evaluated in MMS (2007b) and BOEM (2012b,c). 

C. Impact Analysis 

This section analyzes the potential direct and indirect impacts of routine activities and accidents; 

cumulative impacts are discussed in Section C.9. 

Impacts have been analyzed extensively in lease sale EISs for the Western and Central Gulf of 

Mexico Planning Areas (MMS, 2007b; BOEM, 2012b,c, 2013). Site-specific issues are addressed in 

this section as appropriate. 

C.1 Physical/Chemical Environment

C.1.1 Air Quality

Due to the distance from shore-based pollution sources, offshore air quality is expected to be 

good. The attainment status of federal OCS waters is unclassified because there is no provision in 

the Clean Air Act for classification of areas outside state waters (MMS, 2007b). 

In general, ambient air quality on coastal counties along the Gulf of Mexico is relatively good 

(BOEM, 2012a). As of July 2, 2014, Louisiana, Mississippi, and Alabama coastal counties and 

parishes are in attainment of the National Ambient Air Quality Standards (NAAQS) for all criteria 

pollutants. One coastal metropolitan area in Texas (Houston-Galveston-Brazoria) is a 

nonattainment area for 8-hour ozone. One coastal metropolitan area in Florida (Tampa) is a 

nonattainment area for lead based on the 2008 Standard (USEPA, 2014). 

Winds in the region are driven by the clockwise circulation around the Bermuda High 

(BOEM, 2012b). The Gulf of Mexico is located to the southwest of this center of circulation, 

resulting in a prevailing southeasterly to southerly flow, which is conducive to transporting 

emissions toward shore. However, circulation is also affected by tropical cyclones (hurricanes) 

during summer and fall and by extratropical cyclones (cold fronts) during winter. 

IPFs that could potentially affect air quality are air pollutant emissions and two types of accidents 

– a small fuel spill and a large oil spill. 

Impacts of Air Pollutant Emissions

Air pollutant emissions are the only routine IPF anticipated to affect air quality. Offshore air 

pollutant emissions will result from the operation of the DP drillship or DP semisubmersible 

drilling rig as well as helicopters and service vessels as described in Section A.3. These 

emissions occur mainly from combustion or burning of diesel fuel. Primary air pollutants typically 

associated with OCS activities are suspended PM, SOx, NOx, VOCs, and CO. 

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Due to the distance from shore, routine operations in the project area are not expected to impact 

air quality along the coast. As noted in the lease sale EISs (MMS, 2007b; BOEM, 2012b,c, 2013), 

emissions of air pollutants from routine activities in the Gulf of Mexico Central Planning Area are 

projected to have minimal impacts on onshore air quality because of the prevailing atmospheric 

conditions, emission heights, emission rates, and the distance of these emissions from the 

coastline. 

AT 18 and 19 are located west of 87.5° W longitude; thus, air quality is under BOEM jurisdiction 

as explained in NTL 2009-N11. The BOEM-implementing regulations are provided in 

30 CFR 550 Subpart C. The Air Quality Emissions Report (see EP Section 8) prepared in 

accordance with BOEM requirements shows that the projected emissions from emission sources 

associated with the proposed activities meet the BOEM exemption criteria. This EP is therefore 

exempt from further air quality review pursuant to 30 CFR 550.303(d). 

The Breton Wilderness Area, which is part of the Breton National Wildlife Refuge (NWR), is 

designated under the Clean Air Act as a Prevention of Significant Deterioration Class I air quality 

area. The BOEM coordinates with the USFWS if emissions from proposed projects may affect the 

Breton Class I area. The lease area is approximately 103 miles (166 km) from the Breton 

Wilderness Area. Shell will comply with emissions requirements as directed by the BOEM. 

Carbon dioxide (CO2) and methane (CH4) emissions from the project would constitute a negligible 

contribution to greenhouse gas emissions from all OCS activities. According to Programmatic and 

OCS lease sale EISs (BOEM, 2012a,b), estimated CO2 emissions from OCS oil and gas sources are 

0.4% of the U.S. total. OCS activities in the Central and Western Planning Areas contribute 

approximately 0.005% to total global CO2 emissions (BOEM 2012b). Greenhouse gas emissions 

from this proposed project represent a negligible contribution to the total greenhouse gas 

emissions from reasonably foreseeable activities in the Gulf of Mexico area and would not 

significantly alter any of the climate change impacts evaluated in the Programmatic EIS 

(BOEM, 2012a). 

Impacts of a Small Fuel Spill

Potential impacts of a small spill on air quality are expected to be consistent with those analyzed 

and discussed in MMS (2007b) and BOEM (2012b,c, 2013). The probability of a small spill would 

be minimized by Shell’s preventative measures during routine operations, including fuel transfer. 

In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

impacts. EP Section 9b provides detail on spill response measures. Given the open ocean 

location of the lease area, the extent and duration of air quality impacts from a small spill would 

not be significant. 

A small fuel spill would likely affect air quality near the spill site by introducing VOCs through 

evaporation. The ADIOS 2 model (see Section A.9.2) indicates that more than 90% of a small 

diesel spill would be evaporated or dispersed within 24 hours. The area of diesel fuel on the sea 

surface would range from 1.2 to 12 ac (0.5 to 5 ha), depending on sea state and weather 

conditions. 

A small fuel spill would not affect coastal air quality because the spill would not be expected to 

make landfall or reach coastal waters prior to breaking up (see Section A.9.2).

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Impacts of a Large Oil Spill

Potential impacts of a large oil spill on air quality are expected to be consistent with those 

analyzed and discussed in MMS (2007b) and BOEM (2012b,c, 2013). 

A large oil spill would likely affect air quality by introducing VOCs through evaporation from the 

slick. The extent and persistence of impacts would depend on the meteorological and 

oceanographic conditions at the time and the effectiveness of spill response measures. Additional 

air quality impacts could occur if response measures approved by the Unified Command included 

in situ burning of the floating oil. In situ burning would generate a plume of black smoke offshore 

and result in emissions of NOx, SOx, CO, and PM, as well as greenhouse gases. 

Due to the lease area location (70 miles [111 km] from the nearest shoreline), most air quality 

impacts would occur in offshore waters. Depending on the spill trajectory and the effectiveness of 

spill response measures, coastal air quality could also be affected. Based on the OSRA modeling 

predictions (Table 3), Plaquemines Parish, Louisiana, is the coastal area most likely to be 

affected (4% probability after 30 days). All other coastal areas have a 1% to 2% or lower 

probability of shoreline oil contact 30 days after a spill. A blowout resulting in a large oil spill is an 

extremely rare event, and the probability of such an event will be minimized by Shell’s well 

control and blowout prevention measures as detailed in EP Section 2j. In the unlikely event of a 

spill, implementation of Shell’s OSRP will mitigate and reduce the impacts. EP Section 9b

provides detail on spill response measures. Therefore, no significant spill impacts on air quality 

are expected. 

C.1.2 Water Quality

IPFs that could potentially affect water quality are effluent discharges and two types of accidents 

– a small fuel spill and a large oil spill. 

Impacts of Effluent Discharges

As described in Section A.4, NPDES General Permit GMG290000 establishes permit limits and 

monitoring requirements for effluent discharges from the DP drillship or DP semisubmersible 

drilling rig. After discharge, SBM retained on cuttings would be expected to adhere to the cuttings 

particles and, consequently, would not produce much turbidity as the cuttings sink through the 

water column (Neff et al., 2000). Recent EISs have concluded that the discharge of treated 

SBM cuttings will not cause persistent impacts on water quality in the lease area (BOEM 2012b,c, 

2013). NPDES permit limits and requirements are expected to be met, and little or no impact on 

water quality is anticipated. 

Treated sanitary and domestic wastes may have a transient effect on water quality in the 

immediate vicinity of these discharges. NPDES permit limits and requirements are expected to be 

met, and little or no impact on water quality is anticipated. 

Deck drainage includes effluents resulting from rain, deck washings, and runoff from curbs, 

gutters, and drains, including drip pans in work areas. Rainwater that falls on uncontaminated 

areas of the DP drillship or DP semisubmersible drilling rig will flow overboard without treatment. 

However, rainwater that falls on the DP drillship or DP semisubmersible drilling rig deck and other 

areas such as chemical storage areas and places where equipment is exposed is required to be 

collected and oil and water separated to meet NPDES permit requirements. Negligible impact on 

water quality is anticipated. 

Other discharges from the proposed DP drillship or DP semisubmersible drilling rig are required to 

be in accordance with the NPDES permit. Discharges include desalination unit brine and 

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uncontaminated cooling water, fire water, and ballast water and are expected to be diluted 

rapidly and have little or no impact on water quality. 

Support vessels will discharge treated sanitary and domestic wastes in accordance with 

regulations. These will have a transient effect on water quality in the immediate vicinity of the 

discharges. Support vessel discharges are subject to USCG regulations and therefore are not 

expected to cause significant impacts on water quality. 

Impacts of a Small Fuel Spill

Potential impacts of a small spill on water quality are expected to be consistent with those 

analyzed and discussed in MMS (2007b) and BOEM (2012b,c, 2013). The probability of a small 

spill would be minimized by Shell’s preventative measures during routine operations, including 

fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Given the open 

ocean location of the lease area, the extent and duration of water quality impacts from a small 

spill would not be significant. 

A small fuel spill in offshore waters would increase the concentrations of petroleum hydrocarbons 

and their degradation products. The extent and persistence of impacts would depend on the 

meteorological and oceanographic conditions at the time and the effectiveness of spill response 

measures. However, it is estimated that more than 90% of a small diesel spill would be 

evaporated or dispersed within 24 hours (see Section A.9.2). The area of diesel fuel on the sea 

surface would range from 1.2 to 12 ac (0.5 to 5 ha), depending on sea state and weather 

conditions. 

The water-soluble fractions of diesel are dominated by two- and three-ringed PAHs, which are 

moderately volatile (NRC, 2003b). The constituents of these oils are light to intermediate in 

molecular weight and can be readily degraded by aerobic microbial oxidation. Diesel fuel density 

is such that it will not sink and pool on the seafloor. Diesel fuel dispersed in the water column 

can adhere to suspended sediments, but this generally occurs only in coastal areas with high 

suspended solids loads (NRC, 2003b) and would not be expected to occur to any appreciable 

degree in offshore waters of the Gulf of Mexico. Diesel oil is readily and completely degraded by 

naturally occurring microbes (NOAA, 2006). 

A small fuel spill would not affect coastal water quality because the spill would not be expected 

to make landfall or reach coastal waters prior to breaking up (see Section A.9.2).

Impacts of a Large Oil Spill

Potential impacts of a large oil spill on water quality are expected to be consistent with those 

analyzed and discussed in MMS (2007b) and BOEM (2012b,c, 2013). A large spill would likely 

affect water quality by producing a slick on the water surface and increasing the concentrations 

of petroleum hydrocarbons and their degradation products. The extent and persistence of 

impacts would depend on the meteorological and oceanographic conditions at the time of the 

spill, as well as the effectiveness of spill response measures. Most of the oil would be expected to 

form a slick at the surface, although observations following the Macondo spill indicate that 

plumes of submerged oil droplets can be produced when subsea dispersants are applied at the 

wellhead (Camilli et al., 2010; Hazen et al., 2010; Joint Analysis Group, 2010a,b,c). Recent 

analyses of the full set of samples associated with the Macondo spill have confirmed that the 

application of subsurface dispersants resulted in subsurface hydrocarbon plumes (Spier et al., 

2013). A report by Kujawinski et al. (2011) indicates that chemical components of subsea 

dispersants used during the Macondo spill persisted for up to 2 months and were detectable up 

to 186 miles (300 km) from the wellsite at a water depth of 3,280 to 3,937 ft (1,000 to 1,200 m). 

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While dispersants were detectable in 353 of the 4,114 total water samples, concentrations in the 

samples were significantly below the chronic screening level for dispersants (BOEM, 2012c). 

Once oil enters the ocean, a variety of physical, chemical, and biological processes act to disperse 

the oil slick. These processes include spreading, evaporation of the more volatile constituents, 

dissolution into the water column, emulsification of small droplets, agglomeration sinking, 

microbial modification, photochemical modification, and biological ingestion and excretion (NRC, 

2003b). Marine water quality would be temporarily affected by the dissolved components and 

small oil droplets that do not rise to the surface or are mixed down by surface turbulence. 

Dispersion by currents and microbial degradation removes the oil from the water column or 

dilutes the constituents to background levels. 

A large oil spill could result in a release of gaseous hydrocarbons that could affect water quality. 

During the Macondo spill, large volumes of CH4 were released, causing localized oxygen depletion 

as methanotrophic bacteria rapidly metabolized the hydrocarbons (Joye et al., 2011; Kessler et 

al., 2011). However, a broader study of the deepwater Gulf of Mexico found that although some 

stations showed slight depression of dissolved oxygen concentrations relative to climatological 

background values, the findings were not indicative of hypoxia (<2.0 mg/L) (Operational Science 

Advisory Team [OSAT], 2010). Stations revisited around the Macondo wellhead in October 2010 

showed no measurable oxygen depressions (OSAT, 2010). 

Due to the lease area location, most water quality impacts would occur in offshore waters. 

Depending on the spill trajectory and the effectiveness of spill response measures, coastal water 

quality could be affected. Based on the OSRA modeling predictions (Table 3), the nearshore 

waters and embayments of Plaquemines Parish, Louisiana, is the coastal area most likely to be 

affected, with a 4% probability of shoreline contact within 30 days. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on water quality are expected. 

C.2 Seafloor Habitats and Biota

Water depth estimates at the proposed well surface locations range from 4,203 to 4,432 ft (1,281 

to 1,351 m). See EP Section 6a for further information. 

According to BOEM (2012b,c, 2013), existing information for the deepwater Gulf of Mexico 

indicates that the seafloor is composed primarily of soft sediments; hard bottom communities are 

rare. In accordance with the guidance of NTL 2008-G04, a remotely operated vehicle (ROV) 

Monitoring Survey Plan is one of several requirements to accompany the EP when there is a 

potential to disturb seafloor areas in deep water (>400 m). The specific requirements of the ROV 

Survey Plan are detailed in NTL 2008-G06. BOEM (2011) has subdivided the Gulf of Mexico 

Region (Western Planning Area, Central Planning Area, and parts of Eastern Planning Area) into 

grids. AT 18 and 19 have adequate ROV coverage of the seafloor to characterize the area (BOEM, 

2011), and as such an ROV Monitoring Survey Plan is not necessary to accompany the EP. Highresolution geophysical surveys, including frequency enhanced three-dimensional seismic, 

enhanced surface renderings, ROV, and autonomous underwater vehicle (AUV) data, have been 

conducted in the project area as part of the assessment of archaeological resources and shallow 

hazards (Gardline Surveys Inc. [Gardline], 2012; C&C Technologies, Inc. [C&C], 2012). Based on 

these surveys, features or areas that could support high-density chemosynthetic or other benthic 

communities are not anticipated within 2,000 ft (610 m) of the proposed mud and cuttings 

discharge locations. 

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C.2.1 Soft Bottom Benthic Communities

Data from the Northern Gulf of Mexico Continental Slope Habitats and Benthic Ecology study 

(Wei, 2006; Rowe and Kennicutt, 2009) can be used to describe typical benthic communities that 

could be present in vicinity of the wellsites. Table 4 summarizes data from two nearby stations 

in similar water depths to the proposed wells. Sediments at these two stations were similar, 

predominantly clay (45.5% at Station MT4 and 52.6% at Station MT3) and silt (45.5% at MT4 

and 41.5% at MT3) (Rowe and Kennicutt, 2009). 

Table 4. Benthic community data from stations nearest to the lease area in similar water depths 

sampled during the Northern Gulf of Mexico Continental Slope Habitats and Benthic 

Ecology Study (From: Wei, 2006; Rowe and Kennicutt, 2009). 

Station Location Relative 

to Lease Area

Water Depth

(m)

Abundance

Meiofauna

(individuals/m2)

Macroinfauna

(individuals/m2)

Megafauna

(individuals/ha)

MT4 16 km SW 1,401 246,058 3,262 1,548

MT3 53 km NE 990 885,995 4,924 1,034

Meiofaunal and megafaunal abundance from Rowe and Kennicutt (2009); macroinfaunal 

abundance from Wei (2006). 

-- Indicates data not available. 

Densities of meiofauna (animals that pass through a 0.5-mm sieve but are retained on a 

0.062-mm sieve) in sediments collected at water depths representative of the lease area typically 

range from about 246,000 to 886,000 individuals/m2 (Rowe and Kennicutt, 2009). Nematodes, 

nauplii, and harpacticoid copepods were the three dominant groups in the meiofauna, accounting 

for about 90% of total abundance. 

The benthic macroinfauna is characterized by small mean individual sizes and low densities, both 

of which are a reflection of the meager primary production in Gulf of Mexico surface waters (Wei, 

2006). Densities decrease exponentially with water depth. Based on an equation presented by 

Wei (2006), macroinfaunal densities in the water depth of the wellsites are expected to be about 

278 individuals/m2; however, actual densities at the proposed wellsites are unknown and often 

highly variable.

Polychaetes are typically the most abundant macroinfaunal group on the northern Gulf of Mexico 

continental slope, followed by amphipods, tanaids, bivalves, and isopods. Wei (2006) recognized 

four depth-dependent faunal zones (1 through 4), two of which are divided horizontally. The 

lease area is located in Zone 2E, which covers one station in the mid Texas-Louisiana Slope, the 

west flank of the Mississippi Fan, the mid Mississippi Canyon, and the head of the DeSoto 

Canyon. The five most abundant species in Zone 2E were the polychaetes Aricidea suecica, 

Exogone sp. A, Levinsenia uncinata, Paralacydonia paradoxa, and Tharyx annulosus (Wei, 2006). 

Megafaunal density from nearby station MT4 was 1,548 individuals/ha, and 1,034 individuals/ha 

from station MT3 (Table 4). Common megafauna included motile groups such as decapods, 

ophiuroids, holothurians, and demersal fishes as well as sessile groups such as sponges and 

anemones. 

Bacteria are the foundation of deep-sea chemosynthetic communities (Ross et al., 2012) and are 

an important component in terms of biomass and cycling of organic carbon (Cruz-Kaegi, 1998). 

Bacterial biomass at the depth range of the lease area typically is about 1.3 to 1.4 grams of 

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carbon per square meter (g C m−

2

) in the top 6 in. (15 cm) of sediments (Rowe and Kennicutt, 

2009). 

IPFs that could potentially affect benthic communities are physical disturbance, effluent 

discharges (drilling mud and cuttings), and a large oil spill resulting from a well blowout at the 

seafloor. A small fuel spill would not affect benthic communities because the diesel fuel would 

float and dissipate on the sea surface.

Impacts of Physical Disturbance to the Seafloor

In water depths such as those that are encountered in the lease area, DP drillships and 

DP semisubmersibles disturb the seafloor only around the wellbore (SHL) where the bottom 

template and blowout preventer are located. Depending upon the specific well configuration, this 

area is generally about 0.62 ac (0.25 ha) per well (BOEM, 2012b). 

The areal extent of these impacts from the DP drillship or DP semisubmersible drilling rig will be 

small compared to the lease area itself. Soft bottom communities are ubiquitous along the 

northern Gulf of Mexico continental slope (Gallaway et al., 2003; Rowe and Kennicutt, 2009). 

Physical disturbance to the seafloor during this project will have no significant impact on soft 

bottom benthic communities on a regional basis. 

Impacts of Effluent Discharges

Drilling mud and cuttings are the only effluents likely to affect these soft bottom benthic 

communities that could be present in vicinity of the wellsites. During initial well interval(s) before 

the marine riser is set, cuttings and seawater-based “spud mud” will be released at the seafloor. 

Excess cement slurry will also be released at the seafloor during casing installation for the 

riserless portion of the drilling operations. Cement slurry components typically include cement 

mix and some of the same chemicals used in water-based drilling mud (Boehm et al., 2001). The 

main impacts will be burial and smothering of benthic organisms within several meters to tens of 

meters around the wellbore. Soft bottom sediments disturbed by cuttings, drilling mud, and 

cement slurry will eventually be recolonized through larval settlement and migration from 

adjacent areas. Because some deep-sea biota grow and reproduce slowly, recovery may require 

several years. 

Discharges of treated SBM cuttings from the DP drillship or DP semisubmersible drilling rig may 

affect benthic communities, primarily within several hundred meters of the wellsites. The fate 

and effects of SBM cuttings have been reviewed by Neff et al. (2000), and monitoring studies 

have been conducted in the Gulf of Mexico by Continental Shelf Associates, Inc. (2004, 2006). 

In general, cuttings with adhering SBM tend to clump together and form thick cuttings piles close 

to the drillsite. Areas of SBM cuttings deposition may develop elevated organic carbon 

concentrations and anoxic conditions (Continental Shelf Associates, Inc., 2006). Where SBM 

cuttings accumulate and concentrations exceed approximately 1,000 mg/kg, benthic infaunal 

communities may be adversely affected due to both the toxicity of the base fluid and organic 

enrichment (with resulting anoxia) (Neff et al., 2000). Infaunal numbers may increase and 

diversity may decrease as opportunistic species that tolerate low oxygen and high H2S 

predominate (Continental Shelf Associates, Inc., 2006). As the base synthetic fluid is decomposed 

by microbes, the area will gradually return to pre-drilling conditions. Disturbed sediments will be 

recolonized through larval settlement and migration from adjacent areas. 

The areal extent of impacts from drilling discharges will be small; the typical effect radius is 

approximately 1,640 ft (500 m) around each wellsite. For the nine surface locations in this 

exploration drilling program, the total impact area would be 1,737 ac (702 ha). In light of the 

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proximity of the proposed wells to each other, the overall impact area could be reduced. Soft 

bottom benthic communities are ubiquitous along the northern Gulf of Mexico continental slope 

(Gallaway, 1988; Gallaway et al., 2003; Rowe and Kennicutt, 2009), and thus impacts from 

drilling discharges during this project will have no significant impact on soft bottom benthic 

communities on a regional basis. 

Impacts of a Large Oil Spill

Potential impacts of a large oil spill on the benthic community are expected to be consistent with 

those analyzed and discussed in MMS (2007b) and BOEM (2012b,c, 2013). Likely impacts from a 

subsea blowout include smothering and exposure to toxic hydrocarbons from oiled sediment 

settling to the seafloor. The most likely effects of a subsea blowout on benthic communities 

would be within a few hundred meters of the wellsites. The MMS (2007b) estimates that a severe 

subsurface blowout could resuspend and disperse sediments within a 984-ft (300-m) radius. 

While coarse sediments (sands) would probably settle at a rapid rate within 1,312 ft (400 m) 

from the blowout site, fine sediments (silts and clays) could be resuspended for more than 30 

days and dispersed over a much wider area. A previous study characterized surface sediments in 

the vicinity of the site as approximately clay (45.5% at Station MT4 and 52.6% at Station MT3) 

and silt (45.5% at MT4 and 41.5% at MT3) (Rowe and Kennicutt, 2009). 

Previous analyses (MMS, 2007a, 2008) concluded that oil spills would be unlikely to affect benthic 

communities beyond the immediate vicinity of the wellhead (i.e., due to physical impacts of a 

blowout) because the oil would rise quickly to the sea surface directly over the spill location. 

However, during the Macondo spill, subsurface plumes were reported at a water depth of about 

3,600 ft (1,100 m), extending at least 22 miles (35 km) from the wellsite and persisting for more 

than a month (Camilli et al., 2010). The subsurface plumes apparently resulted from the use of 

dispersants at the wellhead (Joint Analysis Group, 2010c; Spier et al., 2013). Chemical 

components of subsea dispersants used during the Macondo spill persisted for up to 2 months 

and were detected up to 186 miles (300 km) from the wellsite at a water depth of 3,280 to 

3,937 ft (1,000 to 1,200 m) (Kujawinski et al., 2011). However, estimated dispersant 

concentrations in the subsea plume were below levels known to be toxic to marine life. While the 

behavior and impacts of subsurface plumes are not well known, a subsurface plume could 

contact the seafloor and affect benthic communities beyond the 984-ft (300-m) radius estimated 

in MMS (2007a, 2008), depending on its extent, trajectory, and persistence (Spier et al., 2013). 

This contact could result in smothering and/or toxicity to benthic organisms. The affected area 

would be recolonized by benthic organisms over a period of months to years (NRC, 2003b). 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on soft bottom communities are expected. 

C.2.2 High-Density Deepwater Benthic Communities

As defined in NTL 2009-G40, high-density deepwater benthic communities are features or areas 

that could support high-density chemosynthetic communities, high-density deepwater corals, or 

other associated high-density hard bottom communities. Chemosynthetic communities were 

discovered in the central Gulf of Mexico in 1984 and have been studied extensively 

(MacDonald, 2002). Deepwater coral communities are also known from numerous locations in the 

Gulf of Mexico (Brooke and Schroeder, 2007; CSA International, Inc., 2007; Brooks et al., 2012). 

These communities occur almost exclusively on authigenic carbonates created by chemosynthetic 

communities, and on shipwrecks. 

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Monitoring programs on the Gulf of Mexico continental slope have shown that benthic impacts 

from drilling discharges typically are concentrated within about 1,640 ft (500 m) of the wellsites, 

although detectable deposits may extend beyond this distance (Continental Shelf Associates, Inc., 

2004, 2006; Neff et al., 2005). Nearby high-density deepwater benthic communities include those 

in Mississippi Canyon (MC) 969. The community in MC 969, located approximately 50 miles (80 

km) from the project area, includes vesicomyid or lucinid clams (BOEM, n.d.). 

High-resolution geophysical surveys, including frequency enhanced three-dimensional seismic, 

enhanced surface renderings, ROV, and AUV data, have been conducted in the project area as 

part of the assessment of archaeological resources and shallow hazards (Gardline, 2012; 

C&C, 2012). Based on these surveys, features or areas that could support high-density 

chemosynthetic or other benthic communities are not anticipated within 2,000 ft (610 m) of the 

proposed mud and cuttings discharge locations. 

The only IPF identified for this project that could potentially affect high-density deepwater 

benthic communities is a large oil spill from a well blowout at the seafloor. Physical disturbance 

and effluent discharge are not likely to affect high-density deepwater benthic communities since 

these are generally limited to localized impacts and the geophysical surveys. Gardline (2012) did 

not identify any features that could support high-density deepwater benthic communities within 

2,000 ft (610 m) of the proposed drilling mud/cuttings discharge locations. A small fuel spill 

would not affect benthic communities because the diesel fuel would float and dissipate on the 

sea surface. 

Impacts of a Large Oil Spill

BOEM (2012a) concluded that oil spills would be unlikely to affect benthic communities beyond 

the immediate vicinity of the wellhead (i.e., due to physical impacts of a blowout) because the oil 

would rise quickly to the sea surface directly over the spill location. However, subsea oil plumes 

resulting from a seafloor blowout could affect sensitive deepwater communities 

(BOEM, 2014a,b). During the Macondo spill, subsurface plumes were reported at a water depth 

of about 3,600 ft (1,100 m), extending at least 22 miles (35 km) from the wellsite and persisting 

for more than a month (Camilli et al., 2010). The subsurface plumes apparently resulted from the 

use of subsea dispersants at the wellhead (Joint Analysis Group, 2010c). Chemical components of 

subsea dispersants used during the Macondo spill persisted for up to 2 months and were 

detectable up to 186 miles (300 km) from the wellsite at a water depth of 3,280 to 3,937 ft 

(1,000 to 1,200 m) (Kujawinski et al., 2011). However, estimated dispersant concentrations in 

the subsea plume were below levels known to be toxic to marine life. While the behavior and 

impacts of subsurface plumes are not well known, a subsurface plume could have the potential to 

contact high-density deepwater benthic communities beyond the 984-ft (300-m) radius estimated 

in BOEM (2012a), depending on its extent, trajectory, and persistence (Spier et al., 2013). 

Potential impacts on sensitive resources would be an integral part of the decision and approval 

process for the use of dispersants. 

Oil plumes that directly contact localized patches of sensitive benthic communities before 

degrading could potentially impact the resource. However, the potential impacts would be 

localized due to the directional movement of oil plumes by the water currents and because the 

sensitive habitats have a scattered, patchy distribution. The more likely result would be exposure 

to widely dispersed, biodegraded particles that “rain” down from a passing oil plume. While a few 

patches of habitats may be affected, the Gulf-wide ecosystem of live bottom communities would 

be expected to suffer no significant effects (BOEM, 2014a,b). 

The geophysical surveys (Gardline, 2012; C&C, 2012) did not identify high-density deepwater 

benthic communities within 2,000 ft (610 m) of the proposed drilling mud/cuttings discharge 

locations. Potential impacts of oil on high-density deepwater benthic communities are discussed 

in MMS (2007b) and BOEM (2012b). 

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Although chemosynthetic communities live among hydrocarbon seeps, natural seepage occurs at 

a relatively constant low rate compared with the potential rates of oil release from a blowout. In 

addition, seep organisms require unrestricted access to oxygenated water at the same time as 

exposure to hydrocarbon energy sources (MacDonald, 2002). Oil droplets or oiled sediment 

particles could come into contact with chemosynthetic organisms. As discussed in MMS (2007b), 

impacts could include loss of habitat and biodiversity; destruction of hard substrate; change in 

sediment characteristics; and reduction or loss of one or more commercial and recreational 

fishery habitats. 

Sublethal effects are possible for communities that receive a lower level of impact and could be 

temporary (e.g., lack of feeding and loss of tissue mass) or long lasting and affect the resilience 

of coral colonies to natural disturbances (e.g., elevated water temperature and diseases) (BOEM, 

2012c; 2014a,b). 

The potential for a spill to affect deepwater corals was observed during an October 2010 survey 

of deepwater coral habitats in water depths of 4,600 ft (1,400 m) approximately 7 miles (11 km) 

southwest of the Macondo wellhead. Much of the soft coral observed in a location measuring 

about 50 by 130 ft (15 by 40 m) was covered by a brown flocculent material (BOEMRE, 2010) 

with signs of stress, including varying degrees of tissue loss and excess mucous production 

(White et al., 2012a,b). Researchers concluded, based on hopanoid petroleum biomarker analysis 

of the flocculent material, that it contained oil from the Macondo spill. The injured and dead 

corals were in an area in which a subsea plume of oil had been documented during the spill in 

June 2010. The deepwater coral at this location showed signs of tissue damage that was not 

observed elsewhere during these surveys or in previous deepwater coral studies in the Gulf of 

Mexico. The team of researchers concluded that the observed coral injuries likely resulted from 

exposure to the subsurface oil plume (White et al., 2012a,b). 

Although no known deepwater coral communities are likely to be impacted by a subsurface 

plume, previously unidentified communities may be encountered if a large subsurface oil spill 

occurs. However, because of the scarcity of deepwater hard bottoms, their comparatively low 

surface area, and the distancing requirements set by BOEM in NTL 2009-G40, it is unlikely that a 

sensitive habitat would be located adjacent to a seafloor blowout or that concentrated oil would 

contact the site (BOEM, 2014a,b). 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Potential impacts 

on sensitive resources would be an integral part of the decision and approval process for the use 

of dispersants. Therefore, no significant spill impacts on deepwater benthic communities are 

expected. 

C.2.3 Designated Topographic Features

The block is not within or near a designated topographic feature or a no-activity zone as 

identified in NTL 2009-G39. The nearest designated topographic feature stipulation block is West 

Delta Block 147, located 51 miles (83 km) northwest of the lease area. There are no IPFs 

associated with either routine operations or accidents that could cause impacts to designated 

topographic features due to the distance from the lease area. 

C.2.4 Pinnacle Trend Area Live Bottoms

The lease area is not covered by the Live Bottom (Pinnacle Trend) Stipulation. As defined in 

NTL 2009-G39, the nearest pinnacle trend blocks are located about 92 miles (148 km) north, 

northeast of the lease area in Main Pass Block 290. 

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There are no IPFs associated with either routine operations or accidents that could cause impacts 

to pinnacle trend area live bottoms due to the distance from the lease area. 

C.2.5 Eastern Gulf Live Bottoms

The lease area is not covered by the Live Bottom (Low-Relief) Stipulation, which pertains to 

seagrass communities and low-relief hard-bottom reef within the Gulf of Mexico Eastern Planning 

Area blocks in water depths of 328 ft (100 m) or less and portions of Pensacola and Destin Dome 

Area Blocks in the Central Planning Area. The nearest block covered by the Live Bottom 

Stipulation, as defined in NTL 2009-G39, is Destin Dome Block 573, located approximately 122 

miles (197 km) northeast of the project area. 

There are no IPFs associated with either routine operations or accidents that could cause impacts 

to eastern Gulf of Mexico live bottom areas due to the distance from the lease area. 

C.3 Threatened, Endangered, and Protected Species and Critical Habitat

This section discusses species listed as endangered or threatened under the ESA. In addition, it 

includes marine mammal species in the region that are protected under the MMPA. 

Endangered, threatened, or species of concern that may occur in the project area and/or along 

the northern and eastern Gulf Coast are listed in Table 5. The table also indicates the location of 

designated critical habitat in the Gulf of Mexico. Critical habitat is defined as (1) specific areas 

within the geographical area occupied by the species at the time of listing, if they contain 

physical or biological features essential to conservation, and those features may require special 

management considerations or protection; and (2) specific areas outside the geographical area 

occupied by the species if the agency determines that the area itself is essential for conservation. 

The NMFS has jurisdiction over ESA-listed cetaceans and fishes in the Gulf of Mexico. The USFWS 

has jurisdiction over ESA-listed birds and the West Indian manatee. These two agencies share 

federal jurisdiction over sea turtles, with NMFS having lead responsibility at sea and USFWS on 

nesting beaches. 

Coastal endangered or threatened species that may occur along the northern or eastern Gulf 

coast include the West Indian manatee, Piping Plover, Whooping Crane, Gulf sturgeon, and 

four subspecies of beach mouse. Critical habitat has been designated for all of these species as 

indicated in Table 5 and discussed in individual sections. 

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Table 5. Listed endangered and threatened species in the lease area and along the northern and 

eastern Gulf Coast.

Species Scientific Name Status

Potential Presence Critical Habitat 

Designated in Gulf of 

Mexico

Lease 

Area Coastal

Marine Mammals

Sperm whale Physeter 

macrocephalus

E X -- None

West Indian manatee Trichechus manatus 

latirostris

E -- X Florida (Peninsular)

Sea Turtles

Loggerhead turtle Caretta caretta T,EaX X

Offshore Texas and 

Louisiana; coastal 

Mississippi, Alabama, 

and parts of Florida. 

Parts of offshore 

Mississippi, Alabama, 

and Floridab

Green turtle Chelonia mydas T, EcX X None

Leatherback turtle Dermochelys coriacea E X X None

Hawksbill turtle Eretmochelys 

imbricata

E X X None

Kemp’s ridley turtle Lepidochelys kempii E X X None

Birds

Piping Plover Charadrius melodus T -- X

Coastal Texas, 

Louisiana, Mississippi, 

Alabama, and Florida 

(Panhandle)

Whooping Crane Grus americana E -- X

Coastal Texas (Aransas 

National Wildlife 

Refuge)

Fishes

Gulf sturgeon Acipenser oxyrinchus 

desotoi

T -- X

Coastal Louisiana, 

Mississippi, Alabama, 

and Florida (Panhandle)

Terrestrial Mammals

Beach mice 

(subspecies: Alabama, 

Choctawhatchee, 

Perdido Key, 

St. Andrew)

Peromyscus polionotus E -- X

Alabama and Florida 

(Panhandle) beaches

Abbreviations: E = Endangered; T = Threatened. 

a The loggerhead turtle is composed of nine distinct population segments (DPS) that are considered “species.” The 

only DPS that may occur in the project area (Northwest Atlantic DPS) is listed as threatened (76 Federal Register 

[FR] 58868; September 22, 2011).

b Effective August 11, 2014, NMFS has designated marine areas shown in Figure 1 as critical habitat for the 

Northwest Atlantic Ocean DPS of the loggerhead sea turtle.

c The green sea turtle is threatened, except for the Florida breeding population, which is listed as endangered.

Two other coastal bird species (Bald Eagle and Brown Pelican) discussed in MMS (2007b) and 

BOEM (2012b) are no longer federally listed as endangered or threatened; these are discussed in 

Section C.4.2. 

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Five sea turtle species and one marine mammal species known to occur within OCS and slope 

waters of the Gulf of Mexico are currently listed as endangered and threatened by the ESA. The 

listed sea turtles include the leatherback turtle, Kemp's ridley turtle, hawksbill turtle, loggerhead 

turtle, and green turtle. Listed marine mammal species include one odontocete (sperm whale) 

which is known to occur in the Gulf of Mexico (Pritchard, 1997). Five endangered mysticete 

whales (blue whale, fin whale, humpback whale, North Atlantic right whale, and sei whale) have 

been reported from the Gulf of Mexico but are considered rare or extralimital and therefore are 

not considered further in this EIA (BOEM, 2012b). 

The sperm whale and five species of sea turtles are the only endangered or threatened species 

likely to occur at or near the lease area. Effective August 11, 2014, NMFS has designated marine 

areas shown in Figure 1 as critical habitat for the northwest Atlantic distinct population segment 

(DPS) of the loggerhead sea turtle. These areas cover one of more of the following habitat types 

deemed critical for the loggerhead sea turtle: nearshore reproductive habitat, winter area, 

breeding areas, constricted migratory corridors, and/or Sargassum habitat. In the Gulf of Mexico, 

nearshore reproductive habitat has been identified in parts of coastal Mississippi, Alabama, and 

Florida; breeding habitat has been identified surrounding the Florida Keys; and Sargassum 

habitat has been identified to include most of the Western and Central Gulf of Mexico and parts 

of the southern portion of the Eastern Planning Area (NMFS, 2014). No critical habitat has been 

designated in the Gulf of Mexico for the leatherback turtle, Kemp's ridley turtle, hawksbill turtle, 

green turtle, or the sperm whale. 

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Figure 1. Location of loggerhead turtle designated critical habitat in relation to the lease area. 

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There are no other endangered animals or plants in the Gulf of Mexico that are reasonably likely 

to be affected by either routine or accidental events. Other species occurring at certain locations 

in the Gulf of Mexico such as the smalltooth sawfish (Pristis pectinata), elkhorn coral 

(Acropora palmata), staghorn coral (Acropora cervicornis), and Florida salt marsh vole 

(Microtus pennsylvanicus dukecampbelli) are remote from the lease area and highly unlikely to be 

affected. 

C.3.1 Sperm Whale (Endangered)

The only endangered marine mammal likely to be present at or near the project area is the 

sperm whale (Physeter macrocephalus). Resident populations of sperm whales occur within the 

Gulf of Mexico. A species description is presented in MMS (2007b). Gulf of Mexico sperm whales 

are classified as an endangered species and a “strategic stock” by NOAA Fisheries (Waring et al., 

2013). A “strategic stock” is defined by the MMPA as a marine mammal stock that meets the 

following criteria: 

 The level of direct human-caused mortality exceeds the potential biological removal level; 

 Based on the best available scientific information, is in decline and is likely to be listed as 

a threatened species under the ESA within the foreseeable future; or 

 Is listed as a threatened or endangered species under the ESA, or is designated as 

depleted under the MMPA. 

According to the recovery plan, the main threats to sperm whale populations include collisions 

with vessels, direct harvest, loss of prey base because of climate change, disturbance from 

anthropogenic noise, and possibly competition for resources (NMFS, 2010a). No critical habitat 

for the sperm whale has been designated in the Gulf of Mexico. 

The distribution of sperm whales in the Gulf of Mexico is correlated with mesoscale physical 

features such as eddies associated with the Loop Current (Jochens et al., 2008). Sperm whale 

populations in the north-central Gulf of Mexico are present there throughout the year 

(Davis et al., 2000). Results of a multi-year tracking study show female sperm whales typically 

concentrated along the upper continental slope between the 656- and 3,280-ft (200- and 

1,000-m) depth contours (Jochens et al., 2008). Male sperm whales were more variable in their 

movements and were documented in water depths greater than 9,843 ft (3,000 m). Generally, 

groups of sperm whales sighted in the Gulf of Mexico during the MMS-funded Sperm Whale 

Seismic Study consisted of mixed-sex groups comprising adult females and immatures, and 

groups of bachelor males. Typical group size for mixed groups was 10 individuals (Jochens et al., 

2008). A review of sighting reports from seismic mitigation surveys in the Gulf of Mexico 

conducted over a 6-year period found a mean group size for sperm whales of 2.5 individuals 

(Barkaszi et al., 2012). 

In these mitigation surveys, sperm whales were the most common cetacean encountered 

(Barkaszi et al., 2012). Results of the Sperm Whale Seismic Study showed that sperm whales 

transit through the vicinity of the lease area. Movements of satellite-tracked individuals suggest 

that this area of the Gulf continental slope is within the home range of the Gulf of Mexico 

population (within the 95% utilization distribution) (Jochens et al., 2008). 

Current threats to sperm whale populations worldwide are discussed in a final recovery plan for 

the sperm whale published by NOAA (NMFS, 2010a). Threats are defined as “any factor that 

could represent an impediment to recovery,” and include fisheries interactions, anthropogenic 

noise, vessel interactions, contaminants and pollutants, disease, injury from marine debris, 

research, predation and natural mortality, direct harvest, competition for resources, loss of prey 

base due to climate change and ecosystem change, and cable laying. In the Gulf of Mexico, the 

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impacts from many of these threats are identified as either low or unknown (BOEMRE, 2011; 

BOEM, 2012c). 

IPFs that could potentially affect sperm whales include drilling rig presence, noise, and lights; 

support vessel and helicopter traffic noise; support vessel strikes; and two types of accidents –

a small fuel spill and a large oil spill. Effluent discharges are likely to have negligible impacts on 

sperm whales due to rapid dispersion, the small area of ocean affected, the intermittent nature of 

the discharges, and the mobility of these marine mammals. Compliance with NTL 2012-BSEE-G01 

will minimize the potential for marine debris-related impacts on sperm whales. 

Impacts of Drilling Rig Presence, Noise, and Lights

Some sounds produced by the drilling rig may be emitted at levels that could potentially disturb 

individual whales or mask the sounds animals would normally produce or hear. Noise associated 

with drilling is relatively weak in intensity, and an individual animal’s noise exposure would be 

transient. As discussed in Section A.1, the bandwidth of sounds generated by the drilling rig is 

approximately 10 to 500 Hz. 

Sperm whales appear to have good low-frequency hearing, with variable responses to 

anthropogenic noise (Jochens et al., 2008). The sperm whale may possess better low-frequency 

hearing than some of the other odontocetes, although not as low as many baleen whale species 

that produce sounds within a bandwidth between 30 Hz and greater than 5 kHz (Wartzok and 

Ketten, 1999). Southall et al. (2007) lists sperm whales in the same hearing group 

(i.e., mid-frequency cetaceans) as dolphins, toothed whales, beaked whales, and bottlenose 

whales (estimated hearing range from 150 Hz to 160 kHz). Generally, most of the acoustic 

energy from sperm whales is present at frequencies below 4 kHz, although diffuse energy up to 

and past 20 kHz has been reported, with source levels up to 236 dB re 1 μPa at 1 m. Other 

studies indicate sperm whales’ wideband clicks contain energy between 0.1 and 20 kHz (Weilgart 

and Whitehead, 1993; Goold and Jones, 1995). Most observations of behavioral responses of 

marine mammals to anthropogenic sounds, in general, have been limited to short-term 

behavioral responses, which included the cessation of feeding, resting, or social interactions 

(NMFS, 2009a). 

Observations of sperm whales near offshore oil and gas operations suggest an inconsistent 

response to anthropogenic marine sound (Jochens et al., 2008). Sounds produced during drilling 

operations are generally constant (rather than pulsed or intermittent) and at levels that may be 

louder than, and of a similar frequency to, the auditory signal received by sperm whales. Animals 

can determine the direction from which a sound arrives based on cues, such as difference in 

arrival times, sound levels, and phases at the two ears. Thus, an animal’s directional hearing 

capabilities have a bearing on its vulnerability to masking (NRC, 2003a). Behavioral changes for 

marine mammals such as the sperm whale to auditory masking sounds may include producing 

more calls, longer calls, or shifting the frequency of the calls (NMFS, 2009a; Holt et al., 2009). 

In addition, there are other OCS facilities and activities near the lease area, and the region as a 

whole has a large number of similar sound sources. Drilling-related noise associated with this 

project will contribute to increases in the ambient noise environment of the Gulf of Mexico, but it 

is not expected in amplitudes sufficient enough to cause either hearing or behavioral effects to 

sperm whales. 

The DP drillship or DP semisubmersible drilling rig will be located within a deepwater, open ocean 

environment and will use DP to maintain position during drilling operations. Sounds generated by 

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drilling operations will be generally continuous with some variability in sound level. This analysis 

assumes that the continuous nature of sounds produced by the drilling rig will provide individual 

whales with cues relative to the direction and relative distance (sound intensity) of the sound 

source, and the fixed position of the drilling rig will provide multiple options for active avoidance 

of potential physical impacts. 

NMFS analyzed the potential for impacts of drilling-related noise on sperm whales in its Biological 

Opinion for the Five-Year Oil and Gas Leasing Program in the Central and Western Planning Areas 

of the Gulf of Mexico (NMFS, 2007). The analysis noted that drilling rigs show low sound source 

levels and concluded that drilling is not expected to produce amplitudes sufficient to cause 

hearing or behavioral effects in sperm whales; therefore, these effects are insignificant (NMFS, 

2007). 

Although offshore lighting and presence of drilling rigs and OCS vessels were considered potential 

factors affecting sperm whales, NMFS’s 2007 Biological Opinion and lease sale EISs (MMS, 

2007b; BOEM, 2012b,c, 2013) did not identify these as IPFs for sperm whales. Therefore, no 

significant impacts are expected. 

Impacts of Support Vessel and Helicopter Traffic

Support vessel traffic has the potential to disturb sperm whales. There is also a risk of vessel 

strikes, which are identified as a threat in the recovery plan for this species (NMFS, 2010a). Data 

concerning the frequency of vessel strikes are presented in the lease sale EIS (MMS, 2007b). 

To reduce the potential for vessel strikes, the BOEM has issued NTL 2012-JOINT-G01, which 

recommends protected species identification training and that vessel operators and crews 

maintain a vigilant watch for marine mammals and slow down or stop their vessel to avoid 

striking protected species, and requires operators to report sightings of any injured or dead 

protected species. When whales are sighted, vessel operators and crews are required to attempt 

to maintain a distance of 300 ft (91 m) or greater whenever possible. Vessel operators are 

required to reduce vessel speed to 10 knots or less, when safety permits, when mother/calf pairs, 

pods, or large assemblages of cetaceans are observed near an underway vessel. Compliance with 

this NTL will minimize the likelihood of vessel strikes as well as reduce the chance for disturbing 

sperm whales. 

NMFS (2007) analyzed the potential for vessel strikes and harassment of sperm whales in its 

Biological Opinion for the Five-Year Oil and Gas Leasing Program in the Central and Western 

Planning Areas of the Gulf of Mexico (NMFS, 2007). With implementation of the mitigation 

measures in NTL 2012-JOINT-G01, NMFS concluded that the likelihood of collisions between 

vessels and sperm whales would be reduced to insignificant levels. NMFS concluded that the 

observed avoidance of passing vessels by sperm whales is an advantageous response to avoid a 

potential threat and is not expected to result in any significant effect on migration, breathing, 

nursing, breeding, feeding, or sheltering to individuals, or have any consequences at the level of 

the population. With implementation of the vessel strike avoidance measures requirement to 

maintain a distance of 295 ft (90 m) from sperm whales, NMFS concluded that the potential for 

harassment of sperm whales would be reduced to discountable levels. 

Helicopter traffic also has the potential to disturb sperm whales. Smultea et al. (2008) 

documented responses of sperm whales offshore Hawaii to fixed wing aircraft flying at an altitude 

of 800 ft (245 m). A reaction to the initial pass of the aircraft was observed during 3 (12%) of 

24 sightings. All three reactions consisted of a hasty dive and occurred at less than 1,180 ft 

(360 m) lateral distance from the aircraft. Additional reactions were seen when aircraft circled 

certain whales to make further observations. Based on other studies of cetacean responses to 

sound, the authors concluded that the observed reactions to brief overflights by the aircraft were 

short-term and probably of no long-term biological significance. 

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Helicopters maintain altitudes above 700 ft (213 m) during transit to and from the offshore 

working area. In the event that a whale is seen during transit, the helicopter will not approach or 

circle the animal(s). In addition, guidelines and regulations specify that helicopters maintain an 

altitude of 1,000 ft (305 m) within 300 ft (91 m) of marine mammals (BOEM, 2012a,b). Although 

whales may respond to helicopters (Smultea et al., 2008), NMFS (2007) and BOEM (2012a) 

concluded that this altitude would minimize the potential for disturbing sperm whales. Therefore, 

no significant impacts are expected. 

Impacts of a Small Fuel Spill

Potential spill impacts on marine mammals including sperm whales are discussed in MMS (2007b) 

and BOEM (2012b,c, 2013) and the Biological Opinion for the Five-Year Oil and Gas Leasing 

Program in the Central and Western Planning Areas of the Gulf of Mexico (NMFS, 2007). Oil 

impacts on marine mammals are discussed by Geraci and St. Aubin (1990). For this EP, there are 

no unique site-specific issues with respect to spill impacts on these animals. 

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP 

will mitigate and reduce the potential for impacts on sperm whales. EP Section 9b provides 

detail on spill response measures. Given the open ocean location of the lease area and the 

duration of a small spill, the opportunity for impacts to occur would be very brief. 

A small fuel spill in offshore waters would produce a slick on the water surface and increase the 

concentrations of petroleum hydrocarbons and their degradation products. The extent and 

persistence of impacts would depend on the meteorological and oceanographic conditions at the 

time of the spill, as well as the effectiveness of spill response measures. Section A.9.2 discusses 

the likely fate of a small fuel spill and indicates that more than 90% would be evaporated or 

dispersed naturally within 24 hours. The area of diesel fuel on the sea surface would range from 

1.2 to 12 ac (0.5 to 5 ha), depending on sea state and weather conditions. 

Direct physical and physiological effects of exposure to diesel fuel could include skin irritation, 

inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; inhalation of 

toxic fumes; ingestion of oil directly or via contaminated prey; and stress from the activities and 

noise of response vessels and aircraft (Marine Mammal Commission [MMC], 2011). However, due 

to the limited areal extent and short duration of water quality impacts from a small fuel spill, as 

well as the mobility of sperm whales, no significant impacts are expected. 

Impacts of a Large Oil Spill

Potential spill impacts on marine mammals including sperm whales are discussed in 

MMS (2007b), BOEM (2012a,b,d, 2013), and in NMFS (2007). Oil impacts on marine mammals 

are discussed by Geraci and St. Aubin (1990). For this EP, there are no unique site-specific issues 

with respect to spill impacts on these animals. 

Impacts of oil spills on sperm whales can include direct impacts from oil exposure, as well as 

indirect impacts due to response activities and materials (e.g., vessel traffic, noise, and 

dispersants) (MMC, 2011). Direct physical and physiological effects can include skin irritation, 

inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; inhalation of 

toxic fumes; ingestion of oil (and dispersants) directly or via contaminated prey; and stress from 

the activities and noise of response vessels and aircraft. The level of impact of oil exposure 

depends on the amount, frequency, and duration of exposure; route of exposure; and type or 

condition of petroleum compounds or chemical dispersants (Waring et al., 2013). Complications 

of the above may lead to dysfunction of immune and reproductive systems, physiological stress, 

declining physical condition, and death. Behavioral responses can include displacement of 

animals from prime habitat, disruption of social structure, changing prey availability and foraging 

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distribution and/or patterns, changing reproductive behavior/productivity, and changing 

movement patterns or migration (MMC, 2011). In the event of a large spill, the level of vessel 

and aircraft activity associated with spill response could disturb sperm whales and potentially 

result in vessel strikes, entanglement, or other injury or stress. Response vessels would operate 

in accordance with NTL 2012-JOINT-G01 to reduce the potential for striking or disturbing these 

animals. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on sperm whales are expected. 

C.3.2 West Indian Manatee (Endangered)

Most of the Gulf of Mexico manatee population is located in peninsular Florida (USFWS, 2001). 

Manatees regularly migrate farther west of Florida in the warmer months (Wilson, 2003) into 

Alabama and Louisiana coastal environs, with some individuals traveling as far west as Texas 

(Fertl et al., 2005). A species description is presented in MMS (2007b) and in the recovery plan 

for this species (USFWS, 2001). 

IPFs that could potentially affect manatees include support vessel and helicopter traffic and a 

large oil spill. A small fuel spill in the lease area would be unlikely to affect manatees, as the 

lease area is approximately 70 miles (111 km) from the nearest shoreline (Louisiana). 

As explained in Section A.9.2, a small fuel spill would not be expected to make landfall or reach 

coastal waters prior to breaking up. Compliance with NTL 2012-BSEE-G01 will minimize the 

potential for marine debris-related impacts on manatees. Consistent with the analysis in 

BOEM (2012a), impacts of routine project-related activities on the manatee would be negligible. 

Impacts of Support Vessel and Helicopter Traffic

Support vessel traffic has the potential to disturb manatees, and there is also a risk of vessel 

strikes, which are identified as a threat in the recovery plan for this species (USFWS, 2001). 

To reduce the potential for vessel strikes, the BOEM has issued NTL 2012-JOINT-G01, which 

recommends protected species identification training and that vessel operators and crews 

maintain a vigilant watch for marine mammals and slow down or stop their vessel to avoid 

striking protected species, and requires operators to report sightings of any injured or dead 

protected species. Compliance with NTL 2012-JOINT-G01 will minimize the likelihood of vessel 

strikes, and no significant impacts on manatees are expected. 

Helicopter traffic, if present, also has the potential to disturb manatees. Rathbun (1988) reported 

that manatees were disturbed more by helicopters than by fixed-wing aircraft; however, the 

helicopter was flown at relatively low altitudes of 66 to 525 ft (20 to 160 m). Helicopters used in 

support operations maintain a minimum altitude of 700 ft (213 m) while in transit offshore, 1,000 

ft (305 m) over unpopulated areas or across coastlines, and 2,000 ft (610 m) over populated 

areas and sensitive habitats such as wildlife refuges and park properties. In addition, guidelines 

and regulations specify that helicopters maintain an altitude of 1,000 ft (305 m) within 300 ft (91 

m) of marine mammals (BOEM, 2012a,b). This mitigation measure will minimize the potential for 

disturbing manatees, and no significant impacts are expected. 

Impacts of a Large Oil Spill

The OSRA results summarized in Table 3 predict that Texas and Louisiana shorelines could be 

contacted by a large oil spill within 30 days. There is no critical habitat designated in these areas, 

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and the number of manatees potentially present is a small fraction of the population in peninsular 

Florida. 

In the event that manatees were exposed to oil, effects could include direct impacts from oil 

exposure, as well as indirect impacts due to response activities and materials (e.g., vessel traffic, 

noise, and dispersants) (MMC, 2011). Direct physical and physiological effects can include skin 

irritation, inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; 

inhalation of toxic fumes; ingestion of oil (and dispersants) directly or via contaminated prey 

(or contaminated vegetation, in the case of manatees); and stress from the activities and noise 

of response vessels and aircraft. Complications of the above may lead to dysfunction of immune 

and reproductive systems, physiological stress, declining physical condition, and death. 

Behavioral responses can include displacement of animals from prime habitat, disruption of social 

structure, changing prey availability and foraging distribution and/or patterns, changing 

reproductive behavior/productivity, and changing movement patterns or migration (MMC, 2011). 

In the event that a large spill reached coastal waters where manatees were present, the level of 

vessel and aircraft activity associated with spill response could disturb manatees and potentially 

result in vessel strikes, entanglement, or other injury or stress. Response vessels would operate 

in accordance with NTL 2012-JOINT-G01 to reduce the potential for striking or disturbing these 

animals, and therefore no significant impacts are expected. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on manatees are expected. 

C.3.3 Non-Endangered Marine Mammals (Protected)

In addition to the seven endangered species that were cited previously in Section C.3, 

21 additional species of marine mammals may be found in the Gulf of Mexico, including 1 species 

of mysticete whale, the dwarf and pygmy sperm whales, 4 species of beaked whales, and 

14 species of delphinids (see EP Section 6h). The minke whale (Balaenoptera acutorostrata) is 

considered rare in the Gulf of Mexico, and is therefore not considered further in this EIA (BOEM, 

2012b). All marine mammals are protected species under the MMPA. The most common 

non-endangered cetaceans in the deepwater environment are odontocetes such as the 

pantropical spotted dolphin, spinner dolphin, and Clymene dolphin. A brief summary is presented 

in this section, and additional information on these groups is presented in MMS (2007b) and 

BOEM (2012a,b,d, 2013). 

Mysticete whales. One species of non-endangered mysticete whale is known from the Gulf of 

Mexico: the Bryde’s whale (Balaenoptera edeni) and minke whale (Balaenoptera acutorostrata). 

The Bryde’s whale (Balaenoptera edeni) has been sighted most frequently along the 328-ft 

(100-m) isobath (Davis and Fargion, 1996; Davis et al., 2000). Most sightings have been made in 

the DeSoto Canyon region and off western Florida, although there have been some in the 

west-central portion of the northeastern Gulf. Based on the available data, it is possible that 

Bryde’s whales could occur in the lease area.

Dwarf and pygmy sperm whales. At sea, it is difficult to differentiate dwarf sperm whales 

(Kogia sima) from pygmy sperm whales (Kogia breviceps), and sightings are often grouped 

together as “Kogia spp.” Both species have a worldwide distribution in temperate to tropical 

waters. In the Gulf of Mexico, both species occur primarily along the continental shelf edge and 

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in deeper waters off the continental shelf (Mullin et al., 1991; Mullin, 2007; Waring et al., 2013). 

Either species could occur in the lease area. 

Beaked whales. Four species of beaked whales are known from the Gulf of Mexico. They are 

Blainville’s beaked whale (Mesoplodon densirostris), Cuvier’s beaked whale (Ziphius cavirostris), 

Sowerby’s beaked whale (Mesoplodon bidens), and Gervais’ beaked whale 

(Mesoplodon europaeus). Stranding records in the Gulf of Mexico suggest that Gervais’ beaked 

whale is the most common, and Sowerby’s beaked whale is extralimital. Due to the difficulties of 

at-sea identification, beaked whales in the Gulf of Mexico are identified either as Cuvier’s beaked 

whales or are grouped into an undifferentiated complex (Mesoplodon spp. and Ziphius spp.). 

In the northern Gulf of Mexico, they are broadly distributed in waters greater than 3,281 ft 

(1,000 m) over lower slope and abyssal landscapes (Davis et al., 2000). Any of these species 

could occur in the lease area (Waring et al., 2013). 

Delphinids. Fourteen species of delphinids are known from the Gulf of Mexico, including Atlantic 

spotted dolphin (Stenella frontalis), bottlenose dolphin (Tursiops truncatus), Clymene dolphin 

(Stenella clymene), false killer whale (Pseudorca crassidens), Fraser’s dolphin (Lagenodelphis 

hosei), killer whale (Orcinus orca), melon-headed whale (Peponocephala electra), pantropical 

spotted dolphin (Stenella attenuata), pygmy killer whale (Feresa attenuata), short-finned pilot 

whale (Globicephala macrorhynchus), Risso’s dolphin (Grampus griseus), rough-toothed dolphin 

(Steno bredanensis), spinner dolphin (Stenella longirostris), and striped dolphin 

(Stenella coeruleoalba). The most common non-endangered cetaceans in the deepwater 

environment are the pantropical spotted dolphin, spinner dolphin, and Clymene dolphin. 

However, any of these species could occur in the lease area (Waring et al., 2013). 

The bottlenose dolphin (Tursiops truncatus) is a common inhabitant of the northern Gulf of 

Mexico, particularly within continental shelf waters. There are two ecotypes of bottlenose 

dolphins, a coastal form and an offshore form, which are genetically isolated from each other 

(Waring et al., 2013). The offshore form of the bottlenose dolphin may occur within the lease 

area. Inshore populations of coastal bottlenose dolphins in the northern Gulf of Mexico are 

separated by the NMFS into 37 geographically distinct population units, or stocks, for 

management purposes (Waring et al., 2013). NMFS (2013) has proposed to classify the Gulf of 

Mexico Northern Coastal Stock, Western Coastal Stock, and all 32 of the Bay, Sound, and 

Estuarine Stocks as strategic stocks. 

The strategic stock designation in this case was based primarily on the occurrence of an “Unusual 

Mortality Event” (UME) of unprecedented size and duration that has affected these stock areas. 

This UME began in February 2010 and, as of December 2014, the event was still considered to be 

ongoing (NOAA, 2014; Waring et al., 2013). Carmichael et al. (2012) hypothesized that the 

unusual number of bottlenose dolphin strandings in the northern Gulf of Mexico during this time 

may have been associated with environmental perturbations, including sustained cold weather 

and the Macondo spill in 2010, as well as large volumes of cold freshwater discharge in the early 

months of 2011. Schwacke et al. (2014) reported that one year after the Macondo spill, dolphins 

in Barataria Bay, Louisiana, showed evidence of disease conditions associated with petroleum 

exposure and toxicity. 

IPFs that could potentially affect non-endangered marine mammals include drilling rig presence, 

noise, and lights; support vessel and helicopter traffic; and two types of accidents (a small fuel 

spill and a large oil spill). Effluent discharges are likely to have negligible impacts on marine 

mammals due to rapid dispersion, the small area of ocean affected, the intermittent nature of the 

discharges, and the mobility of marine mammals. Compliance with NTL 2012-BSEE-G01 will 

minimize the potential for marine debris-related impacts on marine mammals. 

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Impacts of Drilling Rig Presence, Noise, and Lights

Noise from routine drilling activities has the potential to disturb marine mammals. Most 

odontocetes (toothed whales and dolphins) use higher frequency sounds than those produced by 

OCS drilling activities (Richardson et al., 1995). Noise associated with drilling is relatively weak in 

intensity, and an individual animal’s noise exposure would be transient. Stronger noise levels will 

occur during thruster use in dynamic positioning. Thruster noise impacts would be expected at 

greater distances than vessel noise alone (LGL Ecological Research Associates, Ltd., 2006) but 

are dependent on variables relating to thruster type and usage. It is expected that marine 

mammals within or near the lease area would be able to detect the presence of the drilling rig 

and avoid exposure to higher energy sounds, particularly within an open ocean environment. 

Some odontocetes have shown increased feeding activity around lighted platforms at night (Todd 

et al., 2009). Even temporary drilling rigs present an attraction to pelagic food sources that may 

attract cetaceans (and sea turtles). Therefore, prey congregation could pose an attraction to 

protected species that exposes them to higher levels or longer durations of noise that might 

otherwise be avoided. 

There are other OCS facilities and activities near the lease area, and the region as a whole has a 

large number of similar sources. Due to the limited scope, timing, and geographic extent of 

drilling activities, this project would represent a small temporary contribution to the overall noise 

regime, and any short-term impacts are not expected to be biologically significant to marine 

mammal populations. 

Drilling rig lighting and presence are not identified as IPFs for marine mammals in MMS (2007b) 

or BOEM (2012a,b,c, 2013). Therefore, no significant impacts are expected. 

Impacts of Support Vessel and Helicopter Traffic

Support vessel traffic has the potential to disturb marine mammals, and there is also a risk of 

vessel strikes. Data concerning the frequency of vessel strikes are presented in the lease sale 

EIS (MMS, 2007b). To reduce the potential for vessel strikes, the BOEM and BSEE have issued 

NTL 2012-JOINT-G01, which recommends protected species identification training and that 

vessel operators and crews maintain a vigilant watch for marine mammals and slow down or stop 

their vessel to avoid striking protected species, and requires operators to report sightings of any 

injured or dead protected species. Vessel operators and crews are required to attempt to 

maintain a distance of 300 ft (91 m) or greater when whales are sighted and 150 ft (45 m) when 

small cetaceans are sighted. When cetaceans are sighted while a vessel is underway, vessels 

must attempt to remain parallel to the animal’s course and avoid excessive speed or abrupt 

changes in direction until the cetacean has left the area. Vessel operators are required to reduce 

vessel speed to 10 knots or less when mother/calf pairs, pods, or large assemblages of cetaceans 

are observed near an underway vessel, when safety permits. Compliance with this NTL will 

minimize the likelihood of vessel strikes as well as reduce the chance for disturbing marine 

mammals, and therefore no significant impacts are expected. 

Aircraft traffic also has the potential to disturb marine mammals (Würsig et al., 1998). However, 

while flying offshore, helicopters maintain altitudes above 700 ft (213 m) during transit to and 

from the working area. In addition, guidelines and regulations specify that helicopters maintain 

an altitude of 1,000 ft (305 m) within 300 ft (91 m) of marine mammals (BOEM, 2012a,b). This 

altitude will minimize the potential for disturbing marine mammals, and no significant impacts are 

expected (BOEM, 2012a,b). 

Impacts of a Small Fuel Spill

Potential spill impacts on marine mammals are discussed in MMS (2007b) and BOEM (2012a,b,d, 

2013), and oil impacts on marine mammals in general are discussed in Geraci and St. Aubin 

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(1990). For this EP, there are no unique site-specific issues with respect to spill impacts on these 

animals. 

The probability of a fuel spill will be minimized by Shell’s preventative measures, including fuel 

transfer. In the unlikely event of a spill, implementation of Shell’s OSRP is expected to mitigate 

and reduce the potential for impacts on marine mammals. EP Section 9b provides detail on spill 

response measures. Given the open ocean location of the lease area and the duration of a small 

spill, the opportunity for impacts to occur would be very brief. 

A small fuel spill in offshore waters would produce a slick on the water surface and increase the 

concentrations of petroleum hydrocarbons and their degradation products. The extent and 

persistence of impacts would depend on the meteorological and oceanographic conditions at the 

time and the effectiveness of spill response measures. Section A.9.2 discusses the likely fate of 

a small fuel spill and indicates that over 90% would be evaporated or dispersed naturally within 

24 hours. The area of diesel fuel on the sea surface would range from 1.2 to 12 ac (0.5 to 5 ha), 

depending on sea state and weather conditions. 

Direct physical and physiological effects of exposure to diesel fuel could include skin irritation, 

inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; inhalation of 

toxic fumes; ingestion of oil directly or via contaminated prey; and stress from the activities and 

noise of response vessels and aircraft (MMC, 2011). However, due to the limited areal extent and 

short duration of water quality impacts from a small fuel spill, as well as the mobility of marine 

mammals, no significant impacts would be expected. 

Impacts of a Large Oil Spill

Potential spill impacts on marine mammals are discussed in MMS (2007b), BOEM (2012a,b,d, 

2013), and in Geraci and St. Aubin (1990). For this EP, there are no unique site-specific issues. 

Impacts of oil spills on marine mammals can include direct impacts from oil exposure, as well as 

indirect impacts due to response activities and materials (e.g., vessel traffic, noise, and 

dispersants) (MMC, 2011). Direct physical and physiological effects can include skin irritation, 

inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; inhalation of 

toxic fumes; ingestion of oil (and dispersants) directly or via contaminated prey (or contaminated 

vegetation, in the case of manatees); and stress from the activities and noise of response vessels 

and aircraft. Complications of the above may lead to dysfunction of immune and reproductive 

systems, physiological stress, declining physical condition, and death. Behavioral responses can 

include displacement of animals from prime habitat; disruption of social structure; changing prey 

availability and foraging distribution and/or patterns; changing reproductive 

behavior/productivity; and changing movement patterns or migration (MMC, 2011). 

In the event of a large spill, the level of vessel and aircraft activity associated with spill response 

could disturb marine mammals and potentially result in vessel strikes, entanglement, or other 

injury or stress. Response vessels would operate in accordance with NTL 2012-JOINT-G01 to 

reduce the potential for striking or disturbing these animals, and therefore no significant impacts 

are expected. A blowout resulting in a large oil spill is an extremely rare event, and the 

probability of such an event will be minimized by Shell’s well control and blowout prevention 

measures as detailed in EP Section 2j. In the unlikely event of a spill, implementation of 

Shell’s OSRP will mitigate and reduce the impacts. EP Section 9b provides detail on spill 

response measures. Therefore, no significant spill impacts on marine mammals are expected. 

C.3.4 Sea Turtles (Endangered/Threatened)

As listed in EP Section 6h, five species of endangered or threatened sea turtles may be found 

near the lease area. Endangered species are the leatherback (Dermochelys coriacea), 

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Kemp's ridley (Lepidochelys kempii), and hawksbill (Eretmochelys imbricata) turtles. The DPS of 

loggerhead turtle (Caretta caretta) that occurs in the Gulf of Mexico is listed as threatened, 

although other DPSs are endangered. The green turtle (Chelonia mydas) is listed as threatened, 

except for the Florida breeding population, which is listed as endangered. Species descriptions 

are presented in (BOEM, 2012c, 2013). 

The DPS of loggerhead turtle (Caretta caretta) that occurs in the Gulf of Mexico is listed as 

threatened, although other DPSs are endangered. In March 2013, the USFWS proposed to 

designate critical habitat for this DPS including beaches in Jackson County, Mississippi; Baldwin 

County, Alabama; and Bay, Gulf, and Franklin Counties in the Florida Panhandle, as well as 

several counties in southwest Florida and the Florida Keys (78 Federal Register [FR] 18000). 

NMFS issued a ruling (effective August 11, 2014) outlining critical habitat for the Northwest 

Atlantic DPS of the loggerhead sea turtle in the Gulf of Mexico. The nearest designated nearshore 

reproductive critical habitat for loggerhead sea turtles is approximately 156 miles (251 km) north 

of the lease area (Figure 1).

Leatherbacks and loggerheads are the species most likely to be present near the lease area as 

adults. Green, hawksbill, and Kemp’s ridley turtles are typically inner shelf and nearshore species, 

unlikely to occur near the lease area as adults. Hatchlings or juveniles of any of the sea turtles 

may be present in deepwater areas, including the lease area, where they may be associated with 

Sargassum and other flotsam. 

All five sea turtle species in the Gulf of Mexico are migratory and use different marine habitats 

according to their life stage. These habitats include high-energy beaches for nesting females and 

emerging hatchlings and pelagic convergence zones for hatchling and juvenile turtles. As adults, 

green, hawksbill, and loggerhead turtles forage primarily in shallow, benthic habitats. 

Leatherbacks are the most pelagic of the sea turtles, feeding primarily on jellyfish. 

Sea turtle nesting in the northern Gulf of Mexico can be summarized by species as follows: 

 Loggerhead turtles – Loggerhead turtles nest in significant numbers along the Florida 

Panhandle (Florida Fish and Wildlife Conservation Commission, 2014a) and, to a lesser 

extent, from Texas through Alabama (NMFS and USFWS, 2008). The nearest significant 

nesting area of loggerhead turtles is found in Louisiana, on beaches within the Breton 

NWR; 

 Green and leatherback turtles – Green and leatherback turtles infrequently nest on 

Florida Panhandle beaches (Florida Fish and Wildlife Conservation Commission, 2014b,c); 

 Kemp’s ridley turtles – The main nesting site of the Kemp’s ridley turtle is Rancho Nuevo 

beach, Tamaulipas, Mexico (NMFS et al., 2011). Approximately 209 Kemp’s ridley turtles 

nested on Texas beaches in 2012 (Sea Turtle Restoration Project, 2013). Kemp’s ridley 

turtles typically do not nest anywhere near the project area, although there have been 

occasional reports of nesting in Alabama (Share the Beach, 2014); and 

 Hawksbill turtles – Hawksbill turtles typically do not nest anywhere near the project area 

(USFWS, 2013). 

IPFs that could potentially affect sea turtles include drilling rig presence, noise, and lights; 

support vessel and helicopter traffic; and two types of accidents – a small fuel spill and a large oil 

spill. Effluent discharges are likely to have negligible impacts on sea turtles due to rapid 

dispersion, the small area of ocean affected, and the intermittent nature of the discharges. 

Compliance with NTL 2012-BSEE-G01 will minimize the potential for marine debris-related 

impacts on sea turtles. 

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Impacts of Drilling Rig Presence, Noise, and Lights

Offshore drilling activities produce a broad array of sounds at frequencies and intensities that 

may be detected by sea turtles (Geraci and St. Aubin, 1987). Potential impacts may include 

behavioral disruption and temporary or permanent displacement from the area near the sound 

source. Certain sea turtles, especially loggerheads, may be attracted to offshore structures 

(Lohoefener et al., 1990) and, thus, may be more susceptible to impacts from sounds produced 

during routine operations. Helicopters and service vessels may also affect sea turtles due to 

machinery noise and/or visual disturbances. The most likely impacts would be short-term 

behavioral changes such as diving and evasive swimming, disruption of activities, or departure 

from the area. Due to the limited scope, timing, and geographic extent of drilling activities, these 

short-term impacts are not expected to be biologically significant to sea turtle populations. 

Artificial lighting can disrupt the nocturnal orientation of sea turtle hatchlings (Witherington, 

1997; Tuxbury and Salmon, 2005). However, hatchlings may rely less on light cues when they 

are offshore than when they are emerging on the beach (Salmon and Wyneken, 1990). 

NMFS (2007) concluded that the effects of lighting from offshore structures on sea turtles are 

insignificant. Therefore, no significant impacts are expected. 

Impacts of Support Vessel and Helicopter Traffic

Support vessel traffic has the potential to disturb sea turtles, and there is also a risk of vessel 

strikes. Data show that vessel traffic is one cause of sea turtle mortality in the Gulf of Mexico 

(Lutcavage et al., 1997). While adult sea turtles are visible at the surface during the day and in 

clear weather, they can be difficult to spot from a moving vessel when resting below the water 

surface, during nighttime, or during periods of inclement weather. To reduce the potential for 

vessel strikes, the BOEM and BSEE have issued NTL 2012-JOINT-G01, which recommends 

protected species identification training and that vessel operators and crews maintain a vigilant 

watch for sea turtles and slow down or stop their vessel to avoid striking protected species, and 

requires operators to report sightings of any injured or dead protected species. When sea turtles 

are sighted, vessel operators and crews are required to attempt to maintain a distance of 150 ft 

(45 m) or greater whenever possible. Compliance with this NTL will minimize the likelihood of 

vessel strikes as well as reduce the chance for disturbing sea turtles (NMFS, 2007). Therefore, no 

significant impacts are expected. 

Helicopter traffic also has the potential to disturb sea turtles. However, while flying offshore, 

helicopters maintain altitudes above 700 ft (213 m) during transit to and from the working area. 

This altitude will minimize the potential for disturbing sea turtles, and no significant impacts are 

expected. 

Impacts of a Small Fuel Spill

Potential spill impacts on sea turtles are discussed in MMS (2007b), BOEM (2012b,c, 2013), and 

in NMFS (2007) in its Biological Opinion for the Five-Year Oil and Gas Leasing Program in the 

Central and Western Planning Areas of the Gulf of Mexico. For this EP, there are no unique 

site-specific issues with respect to spill impacts on these animals.

The probability of a fuel spill will be minimized by Shell’s preventative measures, including fuel 

transfer. In the unlikely event of a spill, implementation of Shell’s OSRP is expected to mitigate 

and reduce the potential for impacts on sea turtles. EP Section 9b provides detail on spill 

response measures. Given the open ocean location of the lease area, the duration of a small spill 

and opportunity for impacts to occur would be very brief. 

A small fuel spill in offshore waters would produce a slick on the water surface and increase the 

concentrations of petroleum hydrocarbons and their degradation products. The extent and 

persistence of impacts would depend on the meteorological and oceanographic conditions at the 

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time of the spill, as well as the effectiveness of spill response measures. Section A.9.2 discusses 

the likely fate of a small fuel spill and indicates that more than 90% would be evaporated or 

dispersed naturally within 24 hours. The area of diesel fuel on the sea surface would range from 

1.2 to 12 ac (0.5 to 5 ha), depending on sea state and weather conditions. 

Direct physical and physiological effects of exposure to diesel fuel could include skin irritation, 

inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; inhalation of 

toxic fumes; ingestion of oil directly or via contaminated prey; and stress from the activities and 

noise of response vessels and aircraft (MMS, 2007b; NMFS, 2010b; BOEM, 2012b,c, 2013). 

However, due to the limited areal extent and short duration of water quality impacts from a small 

fuel spill, no significant impacts would be expected. 

Effects of a small spill on Sargassum critical habitat for loggerhead turtles would be limited to the 

small area (0.5 to 5 ha [1.2 to 12 ac]) likely to be impacted by a small spill. A 5-ha (12-ac) 

impact would represent a negligible portion of the 151,214 mi2 (391,642 km2) designated 

Sargassum critical habitat for loggerhead turtles in the northern Gulf of Mexico. 

A small fuel spill in the lease area would be unlikely to affect sea turtle nesting beaches because 

the lease area is 70 miles (111 km) from the nearest shoreline (Louisiana) and 156 miles 

(251 km) from the nearest designated nearshore reproductive critical habitat. As explained in 

Section A.9.2, a small fuel spill would not be expected to make landfall or reach coastal waters 

prior to breaking up. 

Impacts of a Large Oil Spill

Impacts of oil spills on sea turtles can include direct impacts from oil exposure, as well as indirect 

impacts due to response activities and materials (e.g., vessel traffic, noise, dispersants, and 

beach cleanup activities). Direct physical and physiological effects can include skin irritation, 

inflammation, or necrosis; chemical burns of skin, eyes, and mucous membranes; inhalation of 

toxic fumes and smoke (e.g., from in situ burning of oil); ingestion of oil (and dispersants) 

directly or via contaminated food; and stress from the activities and noise of response vessels 

and aircraft. Complications of the above may lead to dysfunction of immune and reproductive 

systems, physiological stress, declining physical condition, and death. Behavioral responses can 

include displacement of animals from prime habitat, disruption of social structure, changing food 

availability and foraging distribution and/or patterns, changing reproductive 

behavior/productivity, and changing movement patterns or migration (MMS, 2007b; 

NMFS, 2010c). In the unlikely event of a spill, implementation of Shell’s OSRP is expected to 

mitigate and reduce the potential for these types of impacts on sea turtles. EP Section 9b

provides detail on spill response measures. 

Studies of oil effects on loggerheads in a controlled setting (Lutcavage et al., 1995) suggest that 

sea turtles show no avoidance behavior when they encounter an oil slick, and any sea turtle in an 

affected area would be expected to be exposed. Sea turtles’ diving behaviors also put them at 

risk. Sea turtles rapidly inhale a large volume of air before diving and continually resurface over 

time, which may result in repeated exposure to volatile vapors and oiling (NMFS, 2007). 

The OSRA results summarized in Table 3 predict that Texas and Louisiana shorelines that 

support sea turtle nesting could be contacted within 30 days (1% to 4% conditional 

probabilities). The nearest significant nesting area of loggerhead turtles is found on beaches 

within the Breton NWR. Spilled oil reaching sea turtle nesting beaches could have effects on 

nesting sea turtles and egg development (NMFS, 2007). An oiled beach could affect nest site 

selection or result in no nesting at all (e.g., false crawls). Upon hatching and successfully 

reaching the water, hatchlings are subject to the same types of oil spill exposure hazards as 

adults. Hatchlings that contact oil residues while crossing a beach can exhibit a range of effects, 

from acute toxicity to impaired movement and normal bodily functions (NMFS, 2007). 

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The lease area is within the loggerhead turtle critical habitat designated as Sargassum habitat, 

which includes most of the Western and Central Planning Areas in the Gulf of Mexico and parts of 

the southern portion of the Eastern Planning Area (Figure 1) (NMFS, 2014). In the event of a 

large spill, parts of the Sargassum habitat would likely come into contact with spilled oil. Because 

Sargassum is a floating and pelagic species, it would only be affected by impacts that occur near 

the surface. 

Due to the large area covered by the designated Sargassum habitat for loggerhead turtles, a 

large spill could result in a substantial part of the Sargassum habitat in the northern Gulf of 

Mexico being oiled. However, even a significant spill in 2010 affected only about one third of the 

Sargassum habitat in the northern Gulf of Mexico (BOEM, 2014a,b). It is extremely unlikely that 

the entire Sargassum critical habitat would be affected by a large spill. 

The effects of oiling on Sargassum vary with severity, but moderate to heavy oiling that could 

occur during a large spill could cause complete mortality to Sargassum and its associated 

communities (BOEM, 2014a,b). Lower levels of oiling may cause sublethal affects, including 

reduced growth, productivity, and recruitment of organisms associated with Sargassum. The 

Sargassum algae itself could be less impacted by light to moderate oiling than associated 

organisms because of a waxy outer layer that might help protect it from oiling (BOEM, 2014a,b). 

Sargassum has a yearly seasonal cycle of growth and a yearly cycle of migration from the Gulf of 

Mexico to the western Atlantic. A large spill could affect a large portion of the annual crop of the 

algae; however, because of its ubiquitous distribution and seasonal cycle, recovery of the 

Sargassum community would be expected to occur within 1 to 2 years (BOEM, 2014a,b). 

Impacts to sea turtles from a large oil spill and associated cleanup activities would be dependent 

upon spill extent, duration, and season (relative to turtle nesting season); the amount of oil 

reaching the shore; the importance of specific beaches to sea turtle nesting; and the level of 

cleanup vessel and beach crew activity required. A blowout resulting in a large oil spill is an 

extremely rare event, and the probability of such an event will be minimized by Shell’s well 

control and blowout prevention measures as detailed in EP Section 2j. In the unlikely event of a 

spill, implementation of Shell’s OSRP would mitigate and reduce direct and indirect impacts to 

turtles from oil exposure and response activities and materials. EP Section 9b provides detail on 

spill response measures. 

C.3.5 Piping Plover (Threatened)

The Piping Plover (Charadrius melodus) is a migratory shorebird that overwinters along the 

southeastern U.S. and Gulf of Mexico coasts. This threatened species is in decline as a result of 

hunting, habitat loss and modification, predation, and disease (USFWS, 2003). Critical 

overwintering habitat has been designated, including beaches in Texas, Louisiana, Mississippi, 

Alabama, and Florida (Figure 2). Piping Plovers inhabit coastal sandy beaches and mudflats, 

feeding by probing for invertebrates at or just below the surface. They use beaches adjacent to 

foraging areas for roosting and preening (USFWS, 2010a). A species description is presented in 

MMS (2007b). 

A large oil spill is the only IPF that could potentially affect Piping Plovers. There are no IPFs 

associated with routine project activities that could affect these birds. A small fuel spill in the 

lease area would be unlikely to affect Piping Plovers because a small fuel spill would not be 

expected to make landfall or reach coastal waters prior to breaking up (see explanation in 

Section A.9.2).

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Impacts of a Large Oil Spill

The lease area is 71 miles (114 km) from the nearest shoreline inhabited by Piping Plovers. The 

OSRA results summarized in Table 3 predict that Texas and Louisiana shorelines designated as 

critical habitats for the wintering Piping Plover could be contacted by a spill within 30 days. 

Plaquemines Parish, Louisiana, which has the highest probability of contact within 30 days (4%), 

includes critical habitat of Piping Plovers. 

Plovers could become externally oiled while foraging on oiled shores or be exposed internally 

through ingestion of oiled intertidal sediments and prey (MMS, 2007b). Plovers congregate and 

feed along tidally exposed banks and shorelines, following the tide out and foraging at the 

water’s edge. It is possible that some deaths of Piping Plovers could occur, especially if spills 

occur during winter months when plovers are most common along the coastal Gulf or if spills 

contacted critical habitat. Impacts could also occur from vehicular traffic on beaches and other 

activities associated with spill cleanup. Shell has extensive resources available to protect and 

rehabilitate wildlife in the event of a spill reaching the shoreline, as detailed in the OSRP. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on Piping Plovers are expected. 

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Figure 2. Location of selected environmental features in relation to the lease area. (EFH = Essential Fish Habitat; HAPC = Habitat Area of 

Particular Concern.) 

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C.3.6 Whooping Crane (Endangered)

The Whooping Crane (Grus americana) is an omnivorous wading bird and an endangered 

species. There are three wild populations in North America (National Wildlife Federation, 2012). 

One population winters along the Texas coast at Aransas NWR and summers at Wood Buffalo 

National Park in Canada. This population represents the majority of the world’s population of

free-ranging Whooping Cranes and reached a record population of 278 at Aransas/Wood Buffalo 

National Park in August 2011 (Whooping Crane Eastern Partnership, 2013). A non-migrating 

population has been reintroduced in central Florida, and another reintroduced population 

summers in Wisconsin and migrates to the southeastern U.S. for the winter. Whooping Cranes 

breed, migrate, winter, and forage in a variety of habitats, including coastal marshes and 

estuaries, inland marshes, lakes, ponds, wet meadows and rivers, and agricultural fields 

(USFWS, 2007). About 22,240 ac (9,000 ha) of salt flats on Aransas NWR and adjacent islands 

comprise the principal wintering grounds of the Whooping Crane. Aransas NWR is designated as 

critical habitat for the species (Figure 2). A species description is presented in MMS (2007b) and 

BOEM (2012b,c). 

A large oil spill is the only IPF that could potentially affect Whooping Cranes due to the distance 

from Aransas NWR. 

Impacts of a Large Oil Spill

A large oil spill has a low probability of affecting Whooping Cranes because the lease area is 

approximately 450 miles (724 km) from its critical habitat (Aransas NWR, Texas), and the 

likelihood of contact with the habitat is extremely low (BOEM, 2012b). 

In the event of oil exposure, Whooping Cranes could become externally oiled while foraging in 

oiled areas or internally exposed to oil through ingestion of contaminated shellfish, frogs, and 

fishes. It is possible that some death of Whooping Cranes could occur. Shell has extensive 

resources available to protect and rehabilitate wildlife in the event of a spill reaching the 

shoreline, as detailed in the OSRP. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on Whooping Cranes are expected. 

C.3.7 Gulf Sturgeon (Threatened)

The Gulf sturgeon (Acipenser oxyrinchus desotoi) is a threatened fish species that inhabits major 

rivers and inner shelf waters from the Mississippi River to the Suwannee River, Florida (Barkuloo, 

1988; Wakeford, 2001). An anadromous fish that migrates from the sea upstream into coastal 

rivers to spawn in freshwater, it historically ranged from the Mississippi River to Charlotte Harbor, 

Florida (Wakeford, 2001). Today, this range has contracted to encompass major rivers and inner 

shelf waters from the Mississippi River to the Suwannee River, Florida. Populations have been 

depleted or even extirpated throughout this range by fishing, shoreline development, dam 

construction, water quality changes, and other factors (Barkuloo, 1988; Wakeford, 2001). These 

declines prompted the listing of the Gulf sturgeon as a threatened species in 1991. The best 

known populations occur in the Apalachicola and Suwannee Rivers in Florida (Carr, 1996; Sulak 

and Clugston, 1998), the Choctawhatchee River in Alabama (Fox et al., 2000), and the Pearl 

River in Mississippi/Louisiana (Morrow et al., 1998). Critical habitat in the Gulf extends from Lake 

Borgne, Louisiana (St. Bernard Parish), to Suwannee Sound, Florida (Levy County) (NMFS, 

2010d) (Figure 2). A species description is presented in MMS (2007b) and in the recovery plan 

for this species (USFWS and Gulf States Marine Fisheries Commission, 1995). 

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A large oil spill is the only IPF that could potentially affect Gulf sturgeon. There are no IPFs 

associated with routine project activities that could affect this species. A small fuel spill in the 

lease area would be unlikely to affect Gulf sturgeon, because a small fuel spill would not be 

expected to make landfall or reach coastal waters prior to breaking up (see explanation in 

Section A.9.2). 

Impacts of a Large Oil Spill

Potential spill impacts on Gulf sturgeon are discussed in MMS (2007b), BOEM (2012b,c, 2013), 

and in NMFS (2007) in its Biological Opinion for the Five-Year Oil and Gas Leasing Program in the 

Central and Western Planning Areas of the Gulf of Mexico. For this EP, there are no unique 

site-specific issues with respect to this species. 

The lease area is approximately 153 miles (246 km) from the nearest Gulf sturgeon critical 

habitat. OSRA modeling (Table 3) predicts that a spill in the lease area would have less than 

0.5% probability of contacting Gulf sturgeon critical habitat within 30 days. In the event of oil 

reaching Gulf sturgeon habitat, the fish could be affected by direct ingestion, ingestion of oiled 

prey, or the absorption of dissolved petroleum products through the gills. Based on the life 

history of this species, subadult and adult Gulf sturgeon would be most vulnerable to a marine oil 

spill, and would be vulnerable only during winter months (from September 1 through April 30) 

when this species is foraging in estuarine and marine habitats (NMFS, 2007). 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. Shell has extensive resources available to protect coastal and estuarine 

wildlife and habitats in the event of a spill reaching the shoreline, as detailed in the OSRP. 

EP Section 9b provides detail on spill response measures. Therefore, no significant spill impacts 

on Gulf sturgeon are expected. 

C.3.8 Beach Mice (Endangered)

Four subspecies of endangered beach mouse (Peromyscus polionotus) occur on the barrier 

islands of Alabama and the Florida Panhandle. They are the Alabama, Choctawhatchee, 

Perdido Key, and St. Andrew beach mouse. Critical habitat has been designated for all four 

subspecies; Figure 2 shows the critical habitat combined for all four subspecies. Species 

descriptions are provided in MMS (2007b). 

A large oil spill is the only IPF that could potentially affect subspecies of beach mouse. There are 

no IPFs associated with routine project activities that could affect these animals due to the 

distance from shore and the lack of onshore support activities near their habitat. 

Impacts of a Large Oil Spill

Potential spill impacts on beach mice are discussed in MMS (2007b) and BOEM (2012b,c, 2013). 

For this EP, there are no unique site-specific issues with respect to these species. 

The lease area is about 166 miles (267 km) from the nearest beach mouse critical habitat. 

OSRA modeling predicts that a spill in the lease area would have less than 0.5% chance of 

contacting beach mouse critical habitat within 30 days. In the event of oil contacting these 

beaches, beach mice could experience several types of direct and indirect impacts. Contact with 

spilled oil could cause skin and eye irritation and subsequent infection; matting of fur; irritation of 

sweat glands, ear tissues, and throat tissues; disruption of sight and hearing; asphyxiation from 

inhalation of fumes; and toxicity from ingestion of oil and contaminated food. Indirect impacts 

could include reduction of food supply, destruction of habitat, and fouling of nests. Impacts could 

also occur from vehicular traffic and other activities associated with spill cleanup. 

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A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on beach mice are expected. 

C.4 Coastal and Marine Birds

C.4.1 Marine and Pelagic Birds

A variety of seabirds may occur in the pelagic environment of the project areas 

(Clapp et al., 1982a,b, 1983; Peake, 1996; Hess and Ribic, 2000). Seabirds spend much of their 

lives offshore over the open ocean, except during breeding season when they nest along the 

coast. In addition, other birds such as waterfowl, marsh birds, and shorebirds may occasionally 

be present over open ocean areas. No endangered or threatened bird species are likely to occur 

at the project area due to the distance from shore. For a discussion of shorebirds and coastal 

nesting birds, see Section C.4.2. 

Seabirds of the northern Gulf of Mexico were surveyed from ships during the GulfCet II program. 

Hess and Ribic (2000) reported that terns, storm-petrels, shearwaters, and jaegers were the 

most frequently sighted seabirds in the deepwater area. From these surveys, four ecological 

categories of seabirds were documented in the deepwater areas of the Gulf: summer migrants 

(shearwaters, storm petrels, boobies); summer residents that breed in the Gulf (Sooty Tern, 

Least Tern, Sandwich Tern, Magnificent Frigatebird); winter residents (gannets, gulls, jaegers); 

and permanent resident species (Laughing Gull, Royal Tern, Bridled Tern) (Hess and Ribic, 2000). 

Common seabird species include Wilson’s Storm-Petrel (Oceanites oceanicus), Magnificent 

Frigatebird (Fregata magnificens), Northern Gannet (Morus bassanus), Masked Booby 

(Sula dactylatra), Brown Booby (Sula leucogaster), Cory’s Shearwater (Calonectris diomedea), 

Greater Shearwater (Puffinus gravis), and Audubon Shearwater (Puffinus lherminieri). Seabirds 

are distributed Gulf-wide and are not specifically associated with the lease area. 

Relationships with hydrographic features were found for several seabird species, possibly due to 

effects of hydrography on nutrient levels and productivity of surface waters where birds forage. 

GulfCet II did not estimate bird densities; however, Powers (1987) indicates that seabird 

densities over the open ocean typically are <10 birds/km2. 

Trans-Gulf migrant birds including shorebirds, wading birds, and terrestrial birds may also be 

present in the lease area. Migrant birds may use offshore structures and platforms for resting, 

feeding, or as temporary shelter from inclement weather (Russell, 2005). Some birds may be 

attracted to offshore structures because of the lights and the fish populations that aggregate 

around these structures. 

IPFs that could potentially affect marine and pelagic birds include drilling rig presence, noise, and 

lights; support vessel and helicopter traffic; and two types of accidents – a small fuel spill and a 

large oil spill. Effluent discharges permitted under the NPDES general permit are likely to have 

negligible impacts on the birds due to rapid dispersion, the small area of ocean affected, the 

intermittent nature of the discharges, and the mobility of these animals. Compliance with 

NTL 2012-BSEE-G01 will minimize the potential for marine debris-related impacts on birds. 

Impacts of Drilling Rig Presence, Noise, and Lights

Birds that frequent platforms may be exposed to contaminants including air pollutants and 

routine discharges, but significant impacts are unlikely due to rapid dispersion of effluents and air 

pollutants. Birds migrating over water have been known to strike offshore structures, resulting in 

death or injury (Wiese et al., 2001; Russell, 2005). Mortality of migrant birds at tall towers and 

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other land-based structures has been reviewed extensively, and the mechanisms involved in 

platform collisions appear to be similar. In some cases, migrants simply do not see a part of the 

platform until it is too late. In other cases, navigation may be disrupted by noise (Russell, 2005). 

Conversely, offshore structures are suitable stopover habitats for most trans-Gulf migrant 

species, and most of the migrants that stop over on platforms probably benefit from their stay, 

particularly in spring (Russell, 2005). 

Overall, potential negative impacts to birds from drilling rig lighting, potential collisions, or other 

adverse effects are highly localized, relatively short term and temporary in nature, and may be 

expected to affect only individual birds during migration periods. Therefore, these potential 

impacts are not expected to affect birds at the population or species level and are not significant 

(BOEM, 2012b, 2013). 

Impacts of Support Vessel and Helicopter Traffic

Support vessels and helicopters are unlikely to significantly disturb pelagic birds in open, offshore 

waters. It is likely that individual birds would experience, at most, only short-term behavioral 

disruption, and the impact would not be significant. 

Impacts of a Small Fuel Spill

Potential spill impacts on marine birds are discussed in MMS (2007b) and BOEM (2012b,c, 2013). 

For this EP, there are no unique site-specific issues with respect to spill impacts on these animals. 

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP 

will mitigate and reduce the potential for impacts on marine and pelagic birds. EP Section 9b

provides detail on spill response measures. Given the open ocean location of the lease area and 

the short duration of a small spill, the potential exposure for pelagic marine birds would be brief. 

A small fuel spill in offshore waters would produce a slick on the water surface and increase the 

concentrations of petroleum hydrocarbons and their degradation products. The extent and 

persistence of impacts would depend on the meteorological and oceanographic conditions at the 

time and the effectiveness of spill response measures. Section A.9.2 discusses the likely fate of 

a small fuel spill and indicates that more than 90% would be evaporated or dispersed naturally 

within 24 hours. The area of diesel fuel on the sea surface would range from 1.2 to 12 ac 

(0.5 to 5 ha), depending on sea state and weather conditions. 

Birds exposed to oil on the sea surface could experience direct physical and physiological effects 

including skin irritation; chemical burns of skin, eyes, and mucous membranes; and inhalation of 

VOCs. Because of the limited areal extent and short duration of water quality impacts from a 

small fuel spill, secondary impacts due to ingestion of oil via contaminated prey or reductions in 

prey abundance are unlikely. Due to the low densities of birds in open ocean areas, the small 

area affected, and the brief duration of the surface slick, no significant impacts on marine and 

pelagic birds would be expected. 

Impacts of a Large Oil Spill

Potential spill impacts on marine and pelagic birds are discussed in MMS (2007b) and 

BOEM (2012b,c, 2013). For this EP, there are no unique site-specific issues with respect to spill 

impacts on these animals. 

Pelagic seabirds could be exposed to oil from a spill at the project area. Hess and Ribic (2000) 

reported that terns, storm-petrels, shearwaters, and jaegers were the most frequently sighted 

seabirds in the deepwater Gulf of Mexico (>656 ft [>200 m]). Powers (1987) indicates that 

seabird densities over the open ocean typically are <10 birds/km2. The number of pelagic birds 

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that could be affected in open, offshore waters would depend on the extent and persistence of 

the oil slick. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on marine and pelagic birds are expected. 

C.4.2 Shorebirds and Coastal Nesting Birds

Threatened and endangered bird species (Piping Plover and Whooping Crane) are discussed in 

Section C.3. Various species of non-endangered birds are also found along the northern Gulf 

Coast, including diving birds, shorebirds, marsh birds, wading birds, and waterfowl. Gulf Coast 

marshes and beaches also provide important feeding grounds and nesting habitats. Species that 

nest on beaches, flats, dunes, bars, barrier islands, and similar coastal and nearshore habitats 

include the Sandwich Tern, Wilson’s Plover, Black Skimmer, Forster’s Tern, Gull-Billed Tern, 

Laughing Gull, Least Tern, and Royal Tern (USFWS, 2010b). Additional information is presented 

in MMS (2007b) and BOEM (2012b). 

The Brown Pelican (Pelecanus occidentalis) was delisted from federal endangered status in 2009 

(USFWS, 2010c). However, this species remains listed as endangered by the State of Louisiana 

(State of Louisiana Department of Wildlife and Fisheries, 2013), is listed as a species of greatest 

conservation need by the State of Mississippi (Mississippi Department of Wildlife, Fisheries and 

Parks, 2005), and is designated as a species of special concern by the State of Florida 

(Florida Fish and Wildlife Conservation Commission, 2014d). Brown Pelicans inhabit coastal 

habitats and forage within both coastal waters and waters of the inner continental shelf. Aerial 

and shipboard surveys, including GulfCet and GulfCet II, indicate that Brown Pelicans do not 

occur over deep offshore waters (Fritts and Reynolds, 1981; Peake, 1996; Hess and Ribic, 2000). 

Nearly half the southeastern population of Brown Pelicans lives in the northern Gulf Coast, 

generally nesting on protected islands (USFWS, 2010b). 

The Southern Bald Eagle (Haliaeetus leucocephalus) was delisted from its threatened status in 

the lower 48 states in June of 2007 (BOEM, 2014 a,b; USFWS, 2014). However, this species is 

listed as a state species of conservation concern in Louisiana (State of Louisiana Department of 

Wildlife and Fisheries, 2014) and as threatened in Texas (Texas Parks and Wildlife Department, 

2014). The Bald Eagle still receives protection under the Migratory Bird Treaty Act of 1918 and 

the Bald and Golden Eagle Protection Act of 1940 (USFWS, 2014). The Bald Eagle is a terrestrial 

raptor widely distributed across the southern U.S., including coastal habitats along the Gulf of 

Mexico. The Gulf coast is inhabited by both wintering migrant and resident Bald Eagles 

(Johnsgard, 1990; Ehrlich et al., 1992). 

IPFs that could potentially affect shorebirds and coastal nesting birds include support vessel and 

helicopter traffic and a large oil spill. As explained in Section A.9.2, a small fuel spill would not 

be expected to make landfall or reach coastal waters prior to breaking up. Compliance with 

NTL 2012-BSEE-G01 will minimize the potential for marine debris-related impacts on shorebirds. 

Impacts of Support Vessel and Helicopter Traffic

Support vessels and helicopters will transit coastal areas near Port Fourchon and Boothville, 

Louisiana, where shorebirds and coastal nesting birds may be found. These activities could 

periodically disturb individuals or groups of birds within sensitive coastal habitats (e.g., wetlands 

that may support feeding, resting, or breeding birds). 

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Vessel traffic may disturb some foraging and resting birds. Flushing distances vary among species 

and individuals (Rodgers and Schwikert, 2002). The disturbances will be limited to flushing birds 

away from vessel pathways; known distances are from 65 to 160 ft (20 to 49 m) for personal 

watercraft and 75 to 190 ft (23 to 58 m) for outboard-powered boats (Rodgers and Schwikert, 

2002). Flushing distances may be similar or less for the support vessels to be used for Shell’s 

project, and some species such as gulls are attracted to boats. Support vessels will not approach 

nesting or breeding areas on the shoreline, so nesting birds, eggs, and chicks will not be 

disturbed. Vessel operators will use designated navigation channels and comply with posted 

speed and wake restrictions while transiting sensitive inland waterways. Due to the limited scope, 

duration, and geographic extent of drilling activities, any short-term impacts are not expected to 

be significant to coastal bird populations. 

Aircraft traffic can cause some disturbance to birds on shore and off shore. Responses are highly 

dependent on the type of aircraft, bird species, activities that animals were previously engaged 

in, and previous exposures to overflights (Efroymson et al., 2000). Helicopters seem to cause the 

most intense responses over other human disturbances for some species (Bélanger and Bédard, 

1989). However, Federal Aviation Administration Advisory Circular No. 91-36D recommends that 

pilots maintain a minimum altitude of 2,000 ft (610 m) when flying over noise-sensitive areas 

such as wildlife refuges, parks, and areas with wilderness characteristics. This is greater than the 

distance (slant range) at which aircraft overflights have been reported to cause behavioral effects 

on most species of birds studied in Efroymson et al. (2000). With these guidelines in effect, it is 

likely that individual birds would experience, at most, only short-term behavioral disruption. The 

potential impacts are not expected to be significant to bird populations or species in the project 

area. 

Impacts of Large Oil Spill

Coastal birds can be exposed to oil as they float on the water surface, dive during foraging, or 

wade in oiled coastal waters. The Brown Pelican and Southern Bald Eagle could be impacted by 

the ingestion of contaminated fish or birds (BOEM, 2014a,b). In the event of a large oil spill 

reaching coastal habitats, clean up personnel and equipment could create short term 

disturbances to coastal birds and indirect effects could occur from restoration efforts due to 

habitat loss, alteration, or fragmentation (BOEM, 2014a,b). The OSRA results summarized in 

Table 3 predict that shorelines of Texas and Louisiana that include habitat for shorebirds and 

coastal nesting birds could be affected within 30 days. 

Studies concerning the Macondo spill provide additional information regarding impacts on 

shorebirds and coastal nesting birds that may be affected in the event that a large oil spill 

reaches coastal habitats. Although the Macondo spill had direct and indirect impacts to coastal 

and marine birds, it is premature to conclude impacts over a long period (BOEM, 2012b, 2014). 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on shorebirds and coastal nesting birds are expected. 

C.5 Fisheries Resources

C.5.1 Pelagic Communities and Ichthyoplankton

Biggs and Ressler (2000) reviewed the biology of pelagic communities in the deepwater 

environment of the northern Gulf of Mexico. The biological oceanography of the region is 

dominated by the influence of the Loop Current, whose surface waters are among the most 

oligotrophic in the world’s oceans. Superimposed on this low-productivity condition are productive 

“hot spots” associated with entrainment of nutrient-rich Mississippi River water and mesoscale 

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oceanographic features. Anticyclonic and cyclonic hydrographic features play an important role in 

determining biogeographic patterns and controlling primary productivity in the northern Gulf of 

Mexico (Biggs and Ressler, 2000). 

Most fishes inhabiting shelf or oceanic waters of the Gulf of Mexico have planktonic eggs and 

larvae (Ditty, 1986; Ditty et al., 1988; Richards et al., 1989, 1993). Pelagic eggs and larvae 

become part of the planktonic community for various lengths of time (10 to 100 days, depending 

on the species) (MMS, 2007b). A study by Ross et al. (2012) on midwater fauna to characterize 

vertical distribution of mesopelagic fishes in selected deepwater areas in the Gulf of Mexico 

substantiated high species richness, but general domination by relatively few families and 

species. 

IPFs that could potentially affect pelagic communities and ichthyoplankton include drilling rig 

presence, noise, and lights; effluent discharges; water intakes; and two types of accidents –

a small fuel spill and a large oil spill. 

Impacts of Drilling Rig Presence, Noise, and Lights

The drilling rig, as a floating structure in the deepwater environment, will act as a fish-attracting 

device (FAD). In oceanic waters, the FAD effect would be most pronounced for epipelagic fishes 

such as tunas, dolphin, billfishes, and jacks, which are commonly attracted to fixed and drifting 

surface structures (Holland et al., 1990; Higashi, 1994; Relini et al., 1994). This FAD effect could 

possibly enhance the feeding of epipelagic predators by attracting and concentrating smaller fish 

species. Because the drilling rig is a single, temporary structure, impacts on fish populations, 

whether beneficial or adverse, are considered minor. 

Impacts of Effluent Discharges

Discharges of treated SBM cuttings will produce temporary, localized increases in suspended 

solids in the water column around the drilling rig. In general, turbid water can be expected to 

extend between a few hundred meters and several kilometers down current from the discharge 

point (NRC, 1983; Neff, 1987). NPDES permit limits and requirements are expected to be met. 

Treated sanitary and domestic wastes may have a slight effect on the pelagic environment in the 

immediate vicinity of these discharges. These wastes may have elevated levels of nutrients, 

organic matter, and chlorine, but will be diluted rapidly to undetectable levels within tens to 

hundreds of meters from the source. Minimal impacts on water quality, plankton, and nekton are 

anticipated. 

Deck drainage may have a slight effect on the pelagic environment in the immediate vicinity of 

these discharges. Deck drainage from contaminated areas will be passed through an oil and 

water separator prior to release, and discharges will be monitored for visible sheen. The 

discharges may have slightly elevated levels of hydrocarbons but will be diluted rapidly to 

undetectable levels within tens to hundreds of meters from the source. Minimal impacts on water 

quality, plankton, and nekton are anticipated. 

Other discharges in accordance with the NPDES permit, such as desalination unit brine and 

uncontaminated cooling water, fire water, and ballast water, are expected to be diluted rapidly 

and have little or no impact on water column biota. 

Impacts of Water Intakes

Seawater will be drawn from several meters below the ocean surface for various services 

including firewater and once-through non-contact cooling of machinery on the drilling rig 

(EP Table 7a). Section 316(b) of the Clean Water Act requires NPDES permits to ensure that the 

location, design, construction, and capacity of cooling water intake structures reflect the best 

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technology available to minimize adverse environmental impact from impingement and 

entrainment of aquatic organisms. The current general NPDES Permit No. GMG290000 specifies 

requirements for new facilities for which construction commenced after July 17, 2006 with a 

cooling water intake structure having a design intake capacity of greater than two million gallons 

of water per day, of which at least 25% is used for cooling purposes. 

The wells will be drilled using a DP drillship or DP semisubmersible drilling rig. If the DP drillship 

or DP semisubmersible drilling rig selected for this project meets the described applicability for 

new facilities, the vessel’s water intakes are expected to be in compliance with the design, 

monitoring, and recordkeeping requirements of the NPDES permit. 

Impacts of a Small Fuel Spill

Potential spill impacts on fisheries resources are discussed in MMS (2007b) and 

BOEM (2012a,b,d). For this EP, there are no unique site-specific issues with respect to 

spill impacts. 

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP 

will mitigate and reduce the potential for impacts on pelagic communities, including 

ichthyoplankton. EP Section 9b provides detail on spill response measures. Given the open 

ocean location of the lease area, the duration of a small spill and opportunity for impacts to occur 

would be very brief. 

A small fuel spill in offshore waters would produce a slick on the water surface and increase the 

concentrations of petroleum hydrocarbons and their degradation products. The extent and 

persistence of impacts would depend on the meteorological and oceanographic conditions at the 

time and the effectiveness of spill response measures. Section A.9.2 discusses the likely fate of 

a small fuel spill and indicates that more than 90% would be evaporated or dispersed naturally 

within 24 hours. The area of diesel fuel on the sea surface would range from 1.2 to 12 ac 

(0.5 to 5 ha), depending on sea state and weather conditions. 

A small fuel spill could have localized impacts on phytoplankton, zooplankton, ichthyoplankton, 

and nekton. Due to the limited areal extent and short duration of water quality impacts, a small 

fuel spill would be unlikely to produce detectable impacts on pelagic communities. 

Impacts of a Large Oil Spill

Potential spill impacts on pelagic communities and ichthyoplankton are discussed in 

BOEM (2012a,b,d, 2013). For this EP, there are no unique site-specific issues. 

A large oil spill could affect water column biota including phytoplankton, zooplankton, 

ichthyoplankton, and nekton. A large spill that persisted for weeks or months would be more 

likely to affect these communities. While adult and juvenile fishes may actively avoid a large spill, 

planktonic eggs and larvae would be unable to avoid contact. Eggs and larvae of fishes in the 

upper layers of the water column are especially vulnerable to oiling; certain toxic fractions of 

spilled oil may be lethal to these life stages. Impacts would be potentially greater if local scale 

currents retained planktonic larval assemblages (and the floating oil slick) within the same water 

mass. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on pelagic communities and ichthyoplankton are expected. 

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C.5.2 Essential Fish Habitat

Essential Fish Habitat (EFH) is defined as those waters and substrate necessary to fish for 

spawning, breeding, feeding, and growth to maturity. Under the Magnuson-Stevens Fishery 

Conservation and Management Act, as amended, federal agencies are required to consult on 

activities that may adversely affect EFH designated in Fishery Management Plans developed by 

the regional Fishery Management Councils. 

The Gulf of Mexico Fishery Management Council (GMFMC) has prepared Fishery Management 

Plans for corals and coral reefs, shrimps, spiny lobster, reef fishes, coastal migratory pelagic 

fishes, and red drum. In 2005, the EFH for these managed species was redefined in Generic 

Amendment No. 3 to the various Fishery Management Plans (GMFMC, 2005). The EFH for most 

of these GMFMC-managed species is on the continental shelf in waters shallower than 600 ft 

(183 m). The shelf edge is the outer boundary for coastal migratory pelagic fishes, reef fishes, 

and shrimps. EFH for corals and coral reefs includes some shelf-edge topographic features on the 

Texas-Louisiana OCS, the nearest of which is located 54 miles (87 km) northwest of the lease 

area. 

EFH has been identified in the deepwater Gulf of Mexico for highly migratory pelagic fishes, 

which occur as transients in the lease area. Species in this group, including tunas, swordfishes, 

billfishes, and sharks, are managed by NMFS. Highly migratory species with EFH at or near the 

lease area include the following (NMFS, 2009b): 

 Bigeye thresher shark (all) 

 Atlantic bigeye tuna (juveniles, 

adults) 

 Atlantic bluefin tuna (spawning, 

eggs, larvae, adults) 

 Atlantic skipjack tuna (spawning, 

adults) 

 Atlantic swordfish (larvae, 

juveniles, adults) 

 Atlantic yellowfin tuna (spawning, juvenile, 

adults) 

 Blue marlin (juveniles, adults) 

 Longbill spearfish (juveniles, adults) 

 Longfin mako shark (all) 

 Oceanic whitetip shark (all) 

 Sailfish (juvenile, adult) 

 Silky Shark (all) 

 White marlin (juveniles, adults) 

Research indicates the central and western Gulf of Mexico may be important spawning habitat for 

Atlantic bluefin tuna, and NMFS (2009b) has designated a Habitat Area of Particular Concern 

(HAPC) for this species. The HAPC covers much of the deepwater Gulf of Mexico, including the 

lease area (Figure 2). The areal extent of the HAPC is approximately 115,830 mi2 (300,000 km2). 

The prevailing assumption is that Atlantic bluefin tuna follow an annual cycle of foraging in 

June through March off the eastern United States and Canadian coasts, followed by migration to 

the Gulf of Mexico to spawn in April, May, and June (NMFS, 2009b). 

Other HAPCs have been identified in the Gulf of Mexico by the GMFMC (2005), including the 

Florida Middle Grounds, Madison-Swanson Marine Reserve, Tortugas North and South Ecological 

Reserves, Pulley Ridge, and several individual reefs and banks of the northwestern Gulf of Mexico 

(Figure 2). The nearest of these is Jakkula Bank, located 151 miles (243 km) west of the lease 

area. 

Routine IPFs that could potentially affect EFH and fisheries resources include drilling rig presence, 

noise, and lights; effluent discharges; and water intakes. In addition, two types of accidents – a 

small fuel spill and a large oil spill may potentially affect EFH and fisheries resources. 

Impacts of Drilling Rig Presence, Noise, and Lights

The drilling rig, as a floating structure in the deepwater environment, will act as an FAD. 

In oceanic waters, the FAD effect would be most pronounced for epipelagic fishes such as tunas, 

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dolphin, billfishes, and jacks, which are commonly attracted to fixed and drifting surface 

structures (Holland et al., 1990; Higashi, 1994; Relini et al., 1994). This FAD effect would 

possibly enhance feeding of epipelagic predators by attracting and concentrating smaller fish 

species. Any impacts on EFH for highly migratory pelagic fishes are considered minor. 

Impacts of Effluent Discharges

Other effluent discharges affecting EFH by diminishing ambient water quality include drilling mud 

and cuttings, treated sanitary and domestic wastes, deck drainage, and miscellaneous discharges 

such as desalination unit brine and uncontaminated cooling water, fire water, and ballast water. 

Impacts on EFH from effluent discharges are anticipated to be similar to those described in 

Section C.5.1 for pelagic communities. No significant impacts on EFH for highly migratory 

pelagic fishes are expected from these discharges. 

Impacts of Water Intakes

As noted previously, cooling water intake will cause entrainment and impingement of plankton, 

including fish eggs and larvae (ichthyoplankton). Due to the limited scope, timing, and 

geographic extent of drilling activities, any short-term impacts on EFH for highly migratory 

pelagic fishes are not expected to be biologically significant. 

Impacts of a Small Fuel Spill

Potential spill impacts on EFH are discussed in MMS (2007b) and BOEM (2012a,b,d, 2013). For 

this EP, there are no unique site-specific issues with respect to spill impacts. 

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP 

will mitigate and reduce the potential for impacts on EFH. EP Section 9b provides detail on spill 

response measures. Given the open ocean location of the lease area, the duration of a small spill 

and opportunity for impacts to occur would be very brief. 

A small fuel spill in offshore waters would produce a slick on the water surface and increase the 

concentrations of petroleum hydrocarbons and their degradation products. The extent and 

persistence of impacts would depend on the meteorological and oceanographic conditions at the 

time and the effectiveness of spill response measures. Section A.9.2 discusses the likely fate of 

a small fuel spill and indicates that more than 90% would be evaporated or dispersed naturally 

within 24 hours. The area of diesel fuel on the sea surface would range from 1.2 to 12 ac 

(0.5 to 5 ha), depending on sea state and weather conditions. 

A small fuel spill could have localized impacts on EFH for highly migratory pelagic fishes, 

including tunas, swordfishes, billfishes, and sharks. These species occur as transients in the lease 

area. A spill would also produce short-term impact on water quality in the HAPC for spawning 

Atlantic bluefin tuna, which covers much of the deepwater Gulf of Mexico. The affected area 

would represent a negligible portion of the HAPC, which covers approximately 115,830 mi2 

(300,000 km2) of the Gulf of Mexico. Therefore, no significant spill impacts on EFH for highly 

migratory pelagic fishes are expected. 

A small fuel spill would not affect EFH for corals and coral reefs; the nearest coral EFH is located 

54 miles (87 km) northwest of the lease area. A small fuel spill would float and dissipate on the 

sea surface and would not contact these features. Therefore, no significant spill impacts on EFH 

for corals and coral reefs are expected.

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Impacts of a Large Oil Spill

Potential spill impacts on EFH are discussed in MMS (2007b) and BOEM (2012a,b,d). For this EP, 

there are no unique site-specific issues with respect to EFH. 

An oil spill in offshore waters would temporarily increase hydrocarbon concentrations on the 

water surface and potentially the subsurface as well. Given the extent of EFH designations in the 

Gulf of Mexico (GMFMC, 2005; NMFS, 2009b), some impact on EFH would be unavoidable. 

A large spill could affect the EFH for many managed species including shrimps, stone crab, spiny 

lobster, corals and coral reefs, reef fishes, coastal migratory pelagic fishes, red drum, and highly 

migratory pelagic fishes. It would result in adverse impacts on water quality and water column 

biota including phytoplankton, zooplankton, ichthyoplankton, and nekton. In coastal waters, 

sediments could be contaminated and result in persistent degradation of the seafloor habitat for 

managed demersal fish and invertebrates. 

The lease area is within the HAPC for spawning Atlantic bluefin tuna (NMFS, 2009b). A large spill 

could temporarily degrade the HAPC due to increased hydrocarbon concentrations in the water 

column, with the potential for lethal or sublethal impacts on spawning tuna and their offspring. 

Potential impacts would depend in part on the timing of a spill, as this species migrates to the 

Gulf of Mexico to spawn in April, May, and June (NMFS, 2009b). 

The nearest feature designated as EFH for corals is located 54 miles (87 km) northwest of the 

lease area. An accidental spill would be unlikely to reach or affect this feature. Near-bottom 

currents in the region are expected to flow along the isobaths (Nowlin et al., 2001) and typically 

would not carry a plume up onto the continental shelf edge. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on EFH are expected. 

C.6 Archaeological Resources

C.6.1 Shipwreck Sites

AT 18 and 19 are not on the list of archaeological survey blocks determined to have a high 

potential for containing archaeological properties (BOEM, 2012d). The archaeological surveys 

detected 29 sonar targets that were all identified to be modern debris or natural in origin with no 

archaeological avoidance areas within 2,000 ft (610 m) of the proposed wellsites (C&C, 2012). 

Because there are no historic shipwreck sites in the lease area (see EP Section 6), there are no 

routine IPFs that are likely to affect these resources. A small fuel spill would not affect 

shipwrecks in adjoining blocks because the oil would float and dissipate on the sea surface. The 

impact of a large oil spill that could contact shipwrecks in other areas is the only IPF considered. 

Impacts of a Large Oil Spill

Previous analyses (MMS, 2007a, 2008) concluded that oil spills would be unlikely to affect 

archaeological sites beyond the immediate vicinity of the wellhead (i.e., due to physical impacts 

of a blowout) because the oil would rise quickly to the sea surface directly over the spill location. 

However, during the Macondo spill, subsurface plumes were reported at a water depth of about 

3,600 ft (1,100 m), extending at least 22 miles (35 km) from the wellsite and persisting for more 

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than a month (Camilli et al., 2010). The subsurface plumes apparently resulted from the use of 

dispersants at the wellhead (Joint Analysis Group, 2010c). While the behavior and impacts of 

subsurface plumes are not well known, a subsurface plume could contact shipwreck sites beyond 

the 984-ft (300-m) radius estimated by MMS (2007a, 2008), depending on its extent, trajectory, 

and persistence (Spier et al., 2013). 

BOEM (2012b) reexamined the analyses for archaeological resources presented in MMS (2007a, 

2008) based on additional information available since the publication of these two documents 

and in consideration of the Macondo oil spill. New information that alters the initial impact 

conclusion for archaeological resources has come to light as a result of BOEM-sponsored studies 

and industry surveys. Specifically, evidence of damage to significant cultural resources 

(i.e., historic shipwrecks) has been shown to have occurred because of an incomplete knowledge 

of seafloor conditions in lease areas >200 m (>656 ft) deep that have been exempted from highresolution surveys. Since significant historic shipwrecks have been recently discovered outside 

the previously designated high-probability areas (some of which show evidence of impacts from 

permitted activities prior to their discovery), BOEM now requires that operators submit an 

archaeological survey for exploration and development projects. An archaeological survey was 

performed by C&C in 2012, and no areas of archaeological concern were identified. 

There are no known historic shipwrecks in the lease area. A spill entering shallow coastal waters 

could conceivably contaminate undiscovered or known historic shipwreck sites. The OSRA 

modeling summarized in Table 3 predicts that Texas and Louisiana shorelines could be 

contacted by a spill within 30 days. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on historic shipwrecks are expected. Also as noted in MMS (2007b), 

should an oil spill contact a coastal historic site, such as a fort or a lighthouse, the major impact 

would be a temporary, reversible visual impact from oil contact and contamination of the site and 

its environment. However, more recent studies suggest that the impacts could be longer term 

and not easily reversible (BOEM, 2012b,c). 

C.6.2 Prehistoric Archaeological Sites

With water depth estimates ranging from 4,203 to 4,432 ft (1,281 to 1,351 m), the wellsites are 

well beyond the 60-m (197-ft) depth contour used by the BOEM as the seaward extent for 

prehistoric archaeological site potential in the Gulf of Mexico. The archaeological surveys 

detected 29 sonar targets that were all deemed to be modern debris or natural in origin, with no 

archaeological avoidance areas within 2,000 ft (610 m) of the proposed wellsites (C&C, 2012). 

Because prehistoric archaeological sites are not found in the lease area, the only relevant IPF is a 

large oil spill that would reach coastal waters within the 60-m (197-ft) depth contour. 

Impacts of a Large Oil Spill

Because prehistoric archaeological sites are not found in the lease area, they would not be 

affected by the physical effects of a subsea blowout. MMS (2007b) estimates that a severe 

subsurface blowout could resuspend and disperse sediments within a 984-ft (300-m) radius. 

Along the northern Gulf Coast, prehistoric sites occur frequently along the barrier islands and 

mainland coast and along the margins of bays and bayous (MMS, 2007b). The OSRA modeling 

summarized in Table 3 predicts that Texas and Louisiana shorelines could be contacted by a spill 

within 30 days. A spill reaching a prehistoric site along these shorelines could coat fragile artifacts 

or site features and compromise the potential for radiocarbon dating organic materials in a site 

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(although other dating methods are available and it is possible to decontaminate an oiled sample 

for radiocarbon dating). Coastal prehistoric sites could also be damaged by spill cleanup 

operations (e.g., by destroying fragile artifacts and disturbing the provenance of artifacts and site 

features). BOEM (2012b) notes that some unavoidable direct and indirect impacts on coastal 

historic resources could occur, resulting in the loss of information. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an 

event will be minimized by Shell’s well control and blowout prevention measures as detailed in 

EP Section 2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and 

reduce the impacts. EP Section 9b provides detail on spill response measures. Therefore, no 

significant spill impacts on archaeological resources are expected. 

C.7 Coastal Habitats and Protected Areas

Coastal habitats in the northern Gulf of Mexico that may be affected by oil and gas activities are 

described in previous EISs (MMS, 2007b; BOEM, 2012a,b,d, 2013) and in a literature review by 

Collard and Way (1997). Sensitive coastal habitats are also tabulated in the OSRP. Coastal 

habitats inshore of the project area include barrier beaches and dunes, wetlands, and submerged 

seagrass beds. Generally, most of the northern Gulf is fringed by barrier beaches, with wetlands 

and/or submerged seagrass beds occurring in sheltered areas behind the barrier islands and in 

estuaries. 

Due to the distance from shore, there are no IPFs associated with routine activities occurring in 

the lease area that are likely to affect beaches and dunes, wetlands, seagrass beds, coastal 

wildlife refuges, wilderness areas, or any other managed or protected coastal area. The support 

bases at Port Fourchon and Boothville, Louisiana, are not located in a wildlife refuge or a 

wilderness area. Potential impacts of support vessel traffic are briefly addressed in this section. 

A small fuel spill in the lease area would be unlikely to affect coastal habitats, because it would 

not be expected to make landfall or reach coastal waters prior to breaking up (see explanation in 

Section A.9.2).

Impacts of Support Vessel Traffic

For OCS activities in general, support operations, including the crew boat and supply boats, may 

have a minor incremental impact on coastal habitats. Over time with a large number of vessel 

trips, vessel wakes can erode shorelines along inlets, channels, and harbors. Support operations, 

including the crew boat and supply boats as detailed in EP Section 14, may have a minor 

incremental impact on coastal habitats, seagrass beds, wetlands, or protected areas. Impacts will 

be minimized by following the speed and wake restrictions in harbors and channels. 

Impacts of a Large Oil Spill

Potential spill impacts on coastal habitats are discussed in MMS (2007b) and BOEM 

(2012a,b,d, 2013). Coastal habitats inshore of the project area include barrier beaches and 

dunes, wetlands, and submerged seagrass beds. For this EP, there are no unique site-specific 

issues with respect to coastal habitats. 

The OSRA results summarized in Table 3 predict that shorelines of Texas and Louisiana could be 

affected within 30 days. Nearshore waters and embayments of Plaquemines Parish, Louisiana, 

have the highest probability of contact after 30 days. After 30 days, 7 counties or parishes could 

be contacted in Texas and Louisiana (1% to 4% probability). 

The shorelines within the geographic range predicted by the OSRA modeling include extensive 

barrier beaches and wetlands, with submerged seagrass beds occurring in sheltered areas behind 

the barrier islands and in estuaries. 

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NWRs and other protected areas such as Wildlife Management Areas (WMAs) along the coast are 

discussed in the lease sale EISs (MMS, 2007b; BOEM, 2012b) and Shell’s OSRP. Coastal wildlife 

refuges, wilderness areas, and state and national parks within the geographic range of the 

potential shoreline contacts after 30 days include the following: 

 Anahuac NWR 

 Apffel Park 

 Atchafalaya Delta WMA 

 Atkinson Island WMA 

 Atkinson Island WMA 

 Brazoria NWR 

 Breton NWR 

 Cameron Prairie NWR 

 Candy Abshier WMA 

 Delta NWR 

 Ft. Anahuac Park 

 Galveston Island State Park 

 Isles Dernieres Barrier Islands Refuge 

 J.D. Murphree WMA 

 Jean Lafitte National Historical Park 

 LaCassine NWR 

 Little Pecan Island Preserve 

 Lower Neches WMA 

 Mandalay NWR 

 McFaddin NWR 

 Old Fort Travis Park 

 Pass a Loutre WMA 

 Paul J. Rainey WMA 

 Peveto Woods Sanctuary 

 Pointe Au Chien WMA 

 Rockefeller State Wildlife Refuge and 

Game Preserve 

 Sabine NWR 

 Salvador WMA 

 Sea Rim State Park 

 Seawolf Park 

 St. Bernard State Park 

 Texas Point NWR 

 Wisner WMA 

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The OSRA results in Table 3 include only shoreline segments with contact probabilities greater than 

0.5% within 30 days; other coastal areas could be affected at lower contact probabilities within 

30 days, or beyond 30 days from the spill. Additional NWRs and managed wildlife areas occur along 

the Gulf Coast. These areas include habitats such as barrier beach and dune systems, wetlands, and 

submerged seagrass beds that support diverse wildlife, including endangered or threatened species. 

The level of impacts from oil spills on coastal habitats depends on many factors, including the oil 

characteristics, the geographic location of the landfall, and the weather and oceanographic conditions 

at the time (MMS, 2007b). Oil that makes it to beaches may be either liquid weathered oil, an oil-andwater mousse, or tarballs (MMS, 2007b). Oil is generally deposited on beaches in lines defined by 

wave action at the time of landfall. Oil that remains on the beach will thicken as its volatile 

components are lost. Thickened oil may form tarballs or aggregations that incorporate sand, shell, and 

other materials into its mass. Tar may be buried to varying depths under the sand. On warm days, 

both exposed and buried tarballs may liquefy and ooze. Oozing may also serve to expand the size of a 

mass as it incorporates beach materials. Oil on beaches may be cleaned up manually, mechanically, or 

both. Some oil can remain on the beach at varying depths and may persist for several years as it 

slowly biodegrades and volatilizes. 

Coastal wetlands are highly sensitive to oiling and can be significantly impacted because of the 

inherent toxicity of hydrocarbon and non-hydrocarbon components of the spilled substances 

(Mendelssohn, 2012). The MMS (2007b) predicted that for every 50 bbl of oil contacting wetlands, 

approximately 6.7 ac (2.7 ha) of wetland vegetation will experience dieback. Thirty percent of these 

damaged wetlands are assumed to recover within 4 years, and 85% within 10 years. About 15% of 

the contacted wetlands are expected to be converted permanently to open-water habitat. The critical 

concentration of oil is that concentration above which impacts to wetlands will be long term and 

recovery will take longer than two growing seasons, and which causes plant mortality and some 

permanent wetland loss. Critical concentrations of various oils are expected to vary broadly for 

wetland types and wetland plant species. Louisiana wetlands are assumed to be more sensitive to oil 

contact than elsewhere in the Gulf because of high cumulative stress (MMS, 2007b). In addition to the 

direct impacts of oil, cleanup activities in marshes may accelerate rates of erosion and retard recovery 

rates (MMS, 2007b). 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an event 

will be minimized by Shell’s well control and blowout prevention measures as detailed in EP Section 

2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

impacts. EP Section 9b provides detail on spill response measures. Therefore, no significant spill 

impacts on coastal habitats are expected. 

C.8 Socioeconomic and Other Resources

C.8.1 Recreational and Commercial Fishing

BOEM has reexamined the analysis for recreational and commercial fishing presented in MMS (2007b, 

2008) based on additional information and in consideration of the Macondo spill. No new information 

was found that would alter the potential impacts on commercial fishing (BOEMRE, 2011; BOEM, 

2012c). The main commercial fishing activity in deep waters of the northern Gulf of Mexico is pelagic 

longlining for tunas, swordfishes, and other billfishes (Continental Shelf Associates, Inc., 2002). 

Pelagic longlining has occurred historically in the project area, primarily during spring and summer. 

It is unlikely that any commercial fishing activity other than longlining occurs at or near the project 

area. Benthic species targeted by commercial fishers occur on the upper continental slope, well 

inshore of the project area. Royal red shrimp (Pleoticus robustus) are caught by trawlers in water 

depths of about 820 to 1,804 ft (250 to 550 m). Tilefishes (primarily Lophalotilus chamaeleonticeps) 

are caught by bottom longlining in water depths from about 540 to 1,476 ft (165 to 450 m) 

(Continental Shelf Associates, Inc., 2002). The proposed project is in 4,203 to 4,432 ft (1,281 to 

1,351 m) of water. No conflict with commercial fishing activity other than longlining is expected to 

occur. 

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Most recreational fishing activity in the region occurs in water depths less than 656 ft (200 m) 

(Continental Shelf Associates, Inc., 1997, 2002). In deeper water, the main attraction to recreational 

fishers would be petroleum platforms in offshore waters of Texas and Louisiana. 

The only routine IPF that could potentially affect fisheries is drilling rig presence (including noise and 

lights). Two types of potential accidents are also addressed in this section – a small fuel spill and a 

large oil spill. 

Impacts of Drilling Rig Presence

There is a slight possibility of pelagic longlines becoming entangled in the drilling rig. For example, in 

January 1999, a portion of a pelagic longline snagged on the acoustic Doppler current profiler of a 

drillship working in the Gulf of Mexico (Continental Shelf Associates, Inc., 2002). The line was 

removed without incident. Generally, longline fishers use radar and are aware of offshore structures 

and ships when placing their sets. Therefore, little or no impact on pelagic longlining is expected. 

No adverse impacts on fishing activities are anticipated. Other factors such as effluent discharges are 

likely to have negligible impacts on commercial or recreational fisheries due to rapid dispersion, the 

small area of ocean affected, and the intermittent nature of the discharges. 

Impacts of a Small Fuel Spill

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP will 

mitigate and reduce the potential for impacts. EP Section 9b provides detail on spill response 

measures. Given the open ocean location of the lease area, the duration of a small spill and 

opportunity for impacts to occur would be very brief. 

Pelagic longlining activities in the lease area, if any, could be interrupted in the event of a small fuel 

spill. The area of diesel fuel on the sea surface would range from 1.2 to 12 ac (0.5 to 5 ha), 

depending on sea state and weather conditions. Fishing activities could be interrupted due to the 

activities of response vessels operating in the lease area. A small fuel spill would not affect coastal 

water quality because the spill would not be expected to make landfall or reach coastal waters prior to 

breaking up (see Section A.9.2).

Impacts of a Large Oil Spill

Potential spill impacts on fishing activities are discussed in MMS (2007b) and BOEM (2012b,c, 2013). 

For this EP, there are no unique site-specific issues with respect to this activity. 

Pelagic longlining activities in the lease area and other fishing activities in the northern Gulf of Mexico 

could be interrupted in the event of a large oil spill. A spill may or may not result in fishery closures, 

depending on the duration of the spill, the oceanographic and meteorological conditions at the time, 

and the effectiveness of spill response measures. A blowout resulting in a large oil spill is an extremely 

rare event, and the probability of such an event will be minimized by Shell’s well control and blowout 

prevention measures as detailed in EP Section 2j. In the unlikely event of a spill, implementation of 

Shell’s OSRP will mitigate and reduce the impacts. EP Section 9b provides detail on spill response 

measures. According to BOEM (2012a), the potential impacts on commercial and recreational fishing 

activities from an accidental oil spill are anticipated to be minimal because the potential for oil spills is 

very low, the most typical events are small and of short duration, and the effects are so localized that 

fishes are typically able to avoid the affected area. Fish populations may be affected by an oil spill 

event should it occur, but they would be primarily affected if the oil reaches the productive shelf and 

estuarine areas where many fishes spend a portion of their life cycle (BOEM, 2012a). Therefore, no 

significant spill impacts on fishing activities are expected. 

C.8.2 Public Health and Safety

There are no IPFs associated with routine operations that are expected to affect public health and 

safety. Impacts of a small fuel spill and a large oil spill are addressed in this section. 

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Impacts of a Small Fuel Spill

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP will 

mitigate and reduce the potential for impacts. EP Section 9b provides detail on spill response 

measures. 

A small fuel spill would not have impacts on public health and safety because it would likely affect only 

a small area of the open ocean 70 miles (111 km) from the nearest shoreline, and nearly all of the 

diesel fuel would evaporate or disperse naturally within 24 hours. Response crews would be equipped 

with appropriate safety equipment to avoid injury and health effects. A small fuel spill would not be 

expected to make landfall or reach coastal waters prior to breaking up (see Section A.9.2).

Impacts of a Large Oil Spill

In the event of a large spill from a blowout, the main safety and health concerns are those of the 

offshore personnel involved in the incident and those responding to the spill. The proposed activities 

will be covered by the OSRP, and, in addition, the DP drillship or DP semisubmersible drilling rig 

maintains a Shipboard Oil Pollution Emergency Plan as required under MARPOL 73/78. 

Depending on the spill rate and duration, the physical/chemical characteristics of the oil, the 

meteorological and oceanographic conditions at the time, and the effectiveness of spill response 

measures, the public could be exposed to oil on the water and along the shoreline, through skin 

contact or inhalation of VOCs. Crude oil is a highly flammable material, and any smoke or vapors from 

a crude oil fire can cause irritation. Exposure to large quantities of crude oil may pose a health hazard. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an event 

will be minimized by Shell’s well control and blowout prevention measures as detailed in EP Section 

2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

impacts. EP Section 9b provides detail on spill response measures. Therefore, no significant spill 

impacts on public health and safety are expected. 

C.8.3 Employment and Infrastructure

There are no IPFs associated with routine operations that are expected to affect employment and 

infrastructure. The project involves drilling with support from existing shore-based facilities in 

Louisiana. No new or expanded facilities will be constructed, and no new employees are expected to 

move permanently into the area. The project will have a negligible impact on socioeconomic 

conditions such as local employment, existing offshore and coastal infrastructure (including major 

sources of supplies, services, energy, and water), and minority and lower income groups. Impacts of a 

small fuel spill and a large oil spill are addressed in this section. 

Impacts of a Small Fuel Spill

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP will 

mitigate and reduce the potential for impacts. EP Section 9b provides detail on spill response 

measures. Given the open ocean location of the lease area and the duration of a small spill, the 

opportunity for impacts to occur would be very brief. 

A small fuel spill that is dissipated within a few days would have little or no economic impact, as the 

spill response would use existing facilities, resources, and personnel. 

Impacts of a Large Oil Spill

Potential socioeconomic impacts of an oil spill are discussed in MMS (2007b) and BOEM (2012b,c, 

2013). For this EP, there are no unique site-specific issues with respect to employment and coastal 

infrastructure. A large spill could cause several types of economic impacts: extensive fishery closures 

could put fishermen out of work; temporary employment could increase as part of the response effort; 

adverse publicity could reduce employment in coastal recreation and tourism industries; and OCS 

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drilling activities, including service and support operations that are an important part of local 

economies, could be suspended. 

The lease area is 70 miles (111 km) from the nearest shoreline. Based on the OSRA modeling 

predictions (Table 3), coastal areas of Texas and Louisiana are the most likely to be contacted by a 

spill. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an event 

will be minimized by Shell’s well control and blowout prevention measures as detailed in EP Section 

2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

impacts. EP Section 9b provides detail on spill response measures. Considering that a large spill is 

unlikely, no significant spill impacts on employment and infrastructure are expected. 

C.8.4 Recreation and Tourism

BOEM has reexamined the analyses for recreation and tourism presented in MMS (2007b, 2008) based 

on additional information and in consideration of the Macondo oil spill event. No new information was 

found that would alter the potential impacts on recreation and tourism (BOEMRE, 2011; BOEM, 

2012c).

There are no known recreational uses of the lease area. Recreational resources and tourism in coastal 

areas would not be affected by routine activities due to the distance from shore. Compliance with NTL 

2012-BSEE-G01 will minimize the chance of trash or debris being lost overboard from the drilling rig 

and subsequently washing up on beaches. 

Impacts of a Small Fuel Spill

The probability of a fuel spill will be minimized by Shell’s preventative measures during routine 

operations, including fuel transfer. In the unlikely event of a spill, implementation of Shell’s OSRP will 

mitigate and reduce the potential for impacts. EP Section 9b provides detail on spill response 

measures. Given the open ocean location of the lease area, the duration of a small spill and 

opportunity for impacts to occur would be very brief. 

A small fuel spill in the lease area would be unlikely to affect recreation and tourism. There are no 

known recreational or tourism activities occurring in the lease area, and as explained in 

Section A.9.2, a small fuel spill would not be expected to make landfall or reach coastal waters prior 

to breaking up. 

Impacts of a Large Oil Spill

Potential impacts of an oil spill on recreation and tourism are discussed in MMS (2007b) and BOEM 

(2012a,b,d, 2013). For this EP, there are no unique site-specific issues with respect to these impacts. 

Impacts on recreation and tourism would vary depending on the duration of the spill and its fate 

including the effectiveness of response measures. A large spill that reached coastal waters and 

shorelines could adversely affect recreation and tourism by contaminating beaches and wetlands, 

resulting in negative publicity that encourages people to stay away. The OSRA results summarized in 

Table 3 predict that shorelines of Texas and Louisiana could be affected within 30 days. Nearshore 

waters and embayments of Plaquemines Parish, Louisiana, have the highest probability of contact 

within 30 days (4% probability). 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an event 

will be minimized by Shell’s well control and blowout prevention measures as detailed in EP Section 

2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

impacts. EP Section 9b provides detail on spill response measures. Therefore, no significant spill 

impacts on recreation and tourism are expected. 

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C.8.5 Land Use

Land use along the northern Gulf Coast is discussed in MMS (2007b) and BOEM (2012b,c, 2013). 

There are no routine IPFs potentially affecting land use. The project will use existing onshore support 

facilities in Louisiana. The land use at the existing shorebase sites is industrial. The project will not 

involve new construction or changes to existing land use and, therefore, will not have any impacts. 

Levels of boat and helicopter traffic, as well as demand for goods and services, including scarce 

coastal resources, will represent a small fraction of the level of activity occurring at the shorebases. 

A large oil spill is the only relevant accident IPF. A small fuel spill would not have impacts on land use, 

as the response would be staged out of existing shorebases and facilities. 

Impacts of a Large Oil Spill

The initial response for a large oil spill would be staged out of existing facilities, with no effect on land 

use. A large spill could have limited temporary impacts on land use along the coast if additional 

staging areas were needed. For example, during the Macondo spill, 25 temporary staging areas were 

established in Louisiana, Mississippi, Alabama, and Florida for spill response and cleanup efforts 

(BOEM, 2012b). In the event of a large spill in the lease area, similar temporary staging areas could 

be needed. These areas would eventually return to their original use as the response is demobilized. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an event 

will be minimized by Shell’s well control and blowout prevention measures as detailed in EP Section 

2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

impacts. EP Section 9b provides detail on spill response measures. Therefore, no significant spill 

impacts on land use are expected. 

C.8.6 Other Marine Uses

The lease area is not located within any USCG-designated fairway or shipping lane, and AT 18 and 19 

are not in a designated Military Warning Area. Shell will comply with BOEM requirements and lease 

stipulations to avoid impacts on uses of the area by military vessels and aircraft. There is one flowline 

and umbilical within the vicinity of the proposed wellsites AT 19-F and 19-G; the wellsites will not 

interfere with the flowline or umbilical (Gardline, 2012; C&C, 2012). 

The archaeological survey detected 29 sonar targets that were all deemed to be modern debris or 

natural in origin, with no archaeological avoidance areas within 2,000 ft (610 m) of the proposed 

wellsites (C&C, 2012). 

There are no IPFs from routine project activities that are likely to affect shipping or other marine uses. 

A large oil spill is the only relevant accident IPF. A small fuel spill would not have impacts on other 

marine uses, as the spill and response activities would be mainly within the lease area, and the 

duration would be brief. 

Impacts of a Large Oil Spill

An accidental spill would be unlikely to significantly affect shipping or other marine uses. The block is 

not located within any USCG-designated fairway or shipping lane. In the event of a large spill requiring 

numerous response vessels, coordination would be required to manage the vessel traffic for safe 

operations. Shell will comply with BOEM requirements and lease stipulations to avoid impacts on uses 

of the area by military vessels and aircraft. 

A blowout resulting in a large oil spill is an extremely rare event, and the probability of such an event 

will be minimized by Shell’s well control and blowout prevention measures as detailed in EP Section 

2j. In the unlikely event of a spill, implementation of Shell’s OSRP will mitigate and reduce the 

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impacts. EP Section 9b provides detail on spill response measures. Therefore, no significant spill 

impacts on other marine uses are expected. 

C.9 Cumulative Impacts

For purposes of NEPA, cumulative impact is defined as “the impact on the environment which results 

from the incremental impact of the action when added to other past, present, and reasonably 

foreseeable future actions regardless of what agency (federal or non-federal) or person undertakes 

such other actions” (40 CFR 1508.7). Any single activity or action may have a negligible impact(s) by 

itself, but when combined with impacts from other activities in the same area and/or time period, 

substantial impacts may result. 

Prior Studies. Prior to the lease sales, MMS prepared a multi-sale EIS in which it analyzed the 

environmental impact of activities that might occur in the multi-lease sale area. The MMS also recently 

analyzed the cumulative impacts of OCS exploration activities similar to those planned in this EP in 

several documents. The level and types of activities planned in Shell's EP are within the range of 

activities described and evaluated in the Final EIS for Gulf of Mexico OCS Oil and Gas Lease Sales 

2007-2012 (MMS, 2007b), as updated by a 2012 Final EIS for Gulf of Mexico OCS Oil and Gas Lease 

Sales 2012-2017 (BOEM, 2012b), the Final Supplemental EIS for Gulf of Mexico Lease Sale OCS Oil 

and Gas Sale: 2012 (BOEM, 2012c), and the Final Supplemental EIS for Gulf of Mexico OCS Oil and 

Gas Lease Sales 2013-2014 (BOEM, 2013). 

Past, present, and reasonably foreseeable activities were identified in the cumulative effects scenario 

of these documents, which are incorporated by reference. The proposed action will not result in any 

additional impacts beyond those evaluated in the multi-sale and Final EISs (MMS, 2007b; BOEM, 

2012b,c, 2013). 

Description of Activities Reasonably Expected to Occur in the Vicinity of Project Area. Other 

exploration and development activities may occur in the vicinity of lease blocks AT 18 and 19. Shell 

does not anticipate other projects in the vicinity of the project area beyond the types of projects 

analyzed in the lease sale and Supplemental EISs (MMS, 2007b, 2008; BOEMRE, 2011; 

BOEM, 2012b,c, 2013). 

Cumulative Impacts of Activities in the EP. The MMS (2007b) lease sale EIS and BOEM (2012b,c, 

2013) Final EISs included a lengthy discussion of cumulative impacts, which analyzed the 

environmental and socioeconomic impacts from the incremental impact of the 11 proposed lease 

sales, in addition to all activities (including non-OCS activities) projected to occur from past, proposed, 

and future lease sales during the 40-year period of 2007 to 2046 (see MMS, 2007b; BOEM, 2012b). 

The EISs considered exploration, delineation, and development wells; platform installation; service 

vessel trips; and oil spills. The EISs examined the potential cumulative effects on each specific 

resource for the entire Gulf of Mexico. 

The level and type of activity proposed in Shell’s EP are within the range of activities described and 

evaluated in the recent lease sale EISs. This EIA incorporates and builds on these analyses by 

examining the potential impacts on physical, biological, and socioeconomic resources from the work 

planned in this EP, in conjunction with the other reasonably foreseeable activities expected to occur in 

the Gulf of Mexico. Thus, for all impacts, the incremental contribution of Shell’s proposed actions to 

the cumulative impacts analysis in these prior analyses is not significant. 

C.9.1 Cumulative Impacts to Physical/Chemical Resources

The work planned in this EP is limited in geographic scope and duration, and the impacts on the 

physical/chemical environment will be correspondingly limited. 

Air Quality. Emissions from pollutants into the atmosphere from activities are not projected to have 

significant effects on onshore air quality because of the prevailing atmospheric conditions, emission 

rates and heights, and resulting pollutant concentrations. As BOEM found in the multi-lease sale EISs, 

the incremental contribution of activities similar to Shell’s proposed activities to the cumulative impacts 

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is not significant and will not cause or contribute to a violation of NAAQS (MMS, 2007b; 

BOEM, 2012b,c, 2013). In addition, the cumulative contribution to visibility impairment is also very 

small (MMS, 2007b; BOEM, 2012b,c, 2013). As mentioned in previous sections, projected emissions 

meet the BOEM exemption criteria and would not contribute to cumulative impacts on air quality. 

Climate Change. CO2 and CH4 emissions from the project would constitute a negligible contribution to 

greenhouse gas emissions from all OCS activities. According to BOEM (2013), greenhouse gas 

emissions from all OCS oil and gas activities make up a very small portion of national CO2 emissions 

and BOEM does not believe that emissions directly attributable to OCS activities are a significant 

contributor to global greenhouse gas levels. Greenhouse gas emissions identified in the EP represent a 

negligible contribution to the total greenhouse gas emissions from reasonably foreseeable activities in 

the Gulf of Mexico area and would not significantly alter any of the climate change impacts evaluated 

in the previous EISs. Globally, Shell is taking action in four areas: producing more natural gas, the 

cleanest burning fossil fuel; helping to develop technologies to capture and store CO2; producing lowcarbon biofuel; and working to improve the energy efficiency of our operations (Shell, 2012). 

Water Quality. Shell’s project may result in some minor water quality impacts due to the 

NPDES-permitted discharge of SBM cuttings, treated sanitary and domestic wastes, excess cement 

slurry, non-contact cooling water, deck drainage, desalination unit brine, uncontaminated fire water 

and ballast water. These effects are expected to be minor (localized to the area within a few hundred 

meters of the drilling rig), and temporary (lasting only hours longer than the disturbance or 

discharge). Any cumulative effects to water quality are expected to be negligible. 

Archaeological Resources. AT 18 and 19 are not on the list of archaeology survey blocks 

(BOEM, 2012d). The archaeological surveys detected 29 sonar targets that were deemed as modern 

debris or natural in origin, with no archaeological avoidance areas within 2,000 ft (610 m) of the 

proposed wellsites (C&C, 2012). Also, the lease area is well beyond the 60-m (197-ft) depth contour 

used by the BOEM as the seaward extent for prehistoric archaeological site potential in the Gulf of 

Mexico. Therefore, Shell’s operations will have no cumulative impacts on historic shipwrecks or 

prehistoric archaeological resources. 

New Information. New information included in the most recent Programmatic, Supplemental, and Final 

EISs (BOEM, 2012a,b,d, 2013) has been incorporated into the EIA, where applicable. 

C.9.2 Cumulative Impacts to Biological Resources

The work planned in this EP is limited in geographic scope and duration, and the impacts on biological 

resources will be correspondingly limited. 

Seafloor Habitats and Biota. Effects on seafloor habitats and biota from discharges of drilling mud and 

cuttings are expected to be minor and limited to a small area. As described previously, the geophysical 

surveys did not identify any features that could support high-density deepwater benthic communities 

within 2,000 ft (610 m) of the proposed drilling mud/cuttings discharge locations (Gardline, 2012; 

C&C, 2012). 

Areas that may support high-density deepwater benthic communities will be avoided as required by 

NTL 2009-G40. Soft bottom communities are ubiquitous along the northern Gulf of Mexico continental 

slope, and the extent of benthic impacts during this project is insignificant regionally. As noted in the 

multi-lease sale EISs, the incremental contributions of activities similar to Shell’s proposed activities to 

the cumulative impacts is not significant (MMS, 2007b; BOEM, 2012b,c, 2013). 

Threatened, Endangered, and Protected Species. Threatened, endangered, and protected species 

reasonably likely to occur in the lease area include the sperm whale and five species of sea turtles. 

Potential impact sources include drilling rig presence including noise and lights, marine debris, and 

support vessel and aircraft traffic. Potential effects for these species would be limited and temporary 

and would be reduced by Shell’s compliance with BOEM-required mitigation measures, including 

NTLs 2012-BSEE-G01 and 2012-JOINT-G01. No significant cumulative impacts are expected. 

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Coastal and Marine Birds. Birds may be exposed to contaminants, including air pollutants and routine 

discharges, but significant impacts are unlikely due to rapid dispersion. Shell’s compliance with 

NTL 2012-BSEE-G01 will minimize the likelihood of debris-related impacts on birds. Support vessel and 

helicopter traffic may disturb some foraging and resting birds; however, it is likely that individual birds 

would experience, at most, only short-term behavioral disruption. 

Due to the limited scope, timing, and geographic extent of drilling activities, collisions or other adverse 

effects are unlikely, and no significant cumulative impacts are expected. 

Fisheries Resources. Exploration and production structures occur in the vicinity of the lease area. The 

additional effect of the proposed drilling activity would be negligible. 

Coastal Habitats. Due to the distance of the wellsites from shore, routine activities are not expected to 

have any impacts on beaches and dunes, wetlands, seagrass beds, coastal wildlife refuges, wilderness 

areas, or any other managed or protected coastal area. The support bases at Port Fourchon and 

Boothville, Louisiana, are not in wildlife refuge or wilderness areas. Support operations, including the 

crew boat and supply boats, may have a minor incremental impact on coastal habitats. Over time with 

a large number of vessel trips, vessel wakes can erode shorelines along inlets, channels, and harbors. 

Impacts will be minimized by following the speed and wake restrictions in harbors and channels. 

New Information. New information included in the most recent Programmatic, Supplemental, and Final 

EISs (BOEM, 2012a,b,c, 2013) has been incorporated into the EIA, where applicable. 

C.9.3 Cumulative Impacts to Socioeconomic Resources

The work planned in this EP is limited in geographic scope and duration, and the impacts on 

socioeconomic resources will be correspondingly limited. 

The multi-lease sale and Supplemental and Final EISs analyzed the cumulative impacts of oil and gas 

exploration and development in the lease area, in combination with other impact-producing activities, 

on commercial fishing, recreational fishing, recreational resources, historical and archaeological 

resources, land use and coastal infrastructure, demographics, and environmental justice (MMS, 2007b; 

BOEM, 2012b,c, 2013). BOEM also analyzed the economic impact of oil and gas activities on the Gulf 

States, finding only minor impacts in most of Texas, Mississippi, Alabama, and Florida, more significant 

impacts in parts of Texas, and substantial impacts on Louisiana. 

Shell’s proposed activities will have negligible cumulative impacts on socioeconomic resources. There 

are no IPFs associated with routine operations that are expected to affect public health and safety, 

employment and infrastructure, recreation and tourism, land use, or other marine uses. Due to the 

distance from shore, it is unlikely that any recreational fishing activity is occurring in the project area, 

and it is unlikely that any commercial fishing activity other than longlining occurs at or near the project 

area. The project will have negligible impacts on fishing activities. 

New Information. New information included in the most recent Programmatic, Supplemental, and Final 

EISs (BOEM, 2012a,b,c, 2013) has been incorporated into the EIA, where applicable. 

D. Environmental Hazards 

D.1 Geologic Hazards

Based on the results of high-resolution geophysical surveys consisting of frequency-enhanced threedimensional seismic, enhanced surface renderings, and ROV and AUV high-resolution data, the 

proposed wellsite locations appear suitable for the planned activities (Gardline, 2012; C&C, 2012). 

There are no seafloor or near-surface hydrocarbon-charged sediments associated with surface 

faulting, acoustic void zones associated with surface faulting, mounds, knolls, gas seeps, oil seeps, or 

hard bottom within 2,000 ft (610 m) of the proposed wells. There was one previously drilled well in 

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the vicinity of the proposed well locations AT 18-A and 18-B within 2,000 ft (600m), but the proposed 

wells will not interfere with the previous wellsite (Gardline, 2012). 

See EP Section 6a for supporting geological and geophysical information. 

D.2 Severe Weather

Under most circumstances, weather is not expected to have any effect on the proposed activities. 

Extreme weather, including high winds, strong currents, and large waves, was considered in the 

design criteria for the drilling rig. High winds and limited visibility during a severe storm could disrupt 

communication and support activities (vessel and helicopter traffic) and make it necessary to suspend 

some activities on the drilling rig for safety reasons until the storm or weather event passes. In the 

event of a hurricane, procedures in Shell’s Hurricane Evacuation Plan would be followed.

D.3 Currents and Waves

A rig-based acoustic Doppler current profiler will be used to continuously monitor the current beneath 

the rig. Metocean conditions such as sea states, wind speed, ocean currents, etc., will also be 

continuously monitored. Under most circumstances, physical oceanographic conditions are not 

expected to have any effect on the proposed activities. Strong currents (caused by Loop Current 

eddies and intrusions) and large waves were considered in the design criteria for the drilling rig. High 

waves during a severe storm could disrupt support activities (i.e., vessel and helicopter traffic) and 

make it necessary to suspend some activities on the drilling rig for safety reasons until the storm or 

weather event passes. 

E. Alternatives 

No formal alternatives were evaluated in this EIA. However, various technical and operational options, 

including the location of the wellsites and the selection of a drilling unit, were considered by Shell in 

developing the proposed action. There are no other reasonable alternatives to accomplish the goals of 

this project. 

F. Mitigation Measures 

The proposed action includes numerous mitigation measures required by laws, regulations, and BOEM 

lease stipulations and NTLs. The project will comply with applicable federal, state, and local 

requirements concerning air pollutant emissions, discharges to water, and solid waste disposal. Project 

activities will be conducted under Shell’s OSRP and will include the measures described in 

EP Section 2f. 

G. Consultation 

No persons or agencies were consulted regarding potential impacts associated with the proposed 

activities during the preparation of this EIA. 

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H. Preparers 

This EIA was prepared for Shell Offshore Inc. by its contractor, CSA Ocean Sciences Inc. Contributors 

included the following: 

 Tracy Albert (Regulatory Specialist, Regulatory Compliance Consultants of LA, LLC); 

 Jeffrey McMenis (Environmental Engineer, Shell Exploration & Production Co.); 

 Bertrand Montchanin (Sr Environmental Engineer, Shell Exploration & Production Co.) 

 Casimiro Griborio Lopez (Reservoir Engineer, Shell Exploration & Production Co.); 

 Neal Phillips, Ph.D. (Senior Scientist, CSA Ocean Sciences Inc.); 

 Cindy Chandool, Ph.D. (Senior Scientist, CSA Ocean Sciences Inc.); 

 Deborah Fawcett (Project Scientist III, CSA Ocean Sciences Inc.); 

 Heidi Etter (Project Scientist I, CSA Ocean Sciences Inc.); 

 John Tiggelaar (Project Scientist I, CSA Ocean Sciences Inc.); 

 Jodi Harney, Ph.D. (Senior Scientist, CSA Ocean Sciences Inc.); 

 Keith VanGraafeiland (GIS/Remote Sensing Specialist, CSA Ocean Sciences Inc.); and 

 LeslieAnn Weekes (Technical Editor, CSA Ocean Sciences Inc.). 

I. References 

Ackleh, A., G.E. Loup, J.W. Loup, B. Ma, J.J. Newcomb, N. Pal, N.A. Sidorovskaia, and C. Tiemann. 2012. Assessing the 

Deepwater Horizon oil spill impact on marine mammal population through acoustics: Endangered sperm whales. J. 

Acoust. Soc. Am. 131(3): 2306-2314. 

Barkuloo, J.M. 1988. Report on the conservation status of the Gulf of Mexico sturgeon, Acipenser oxyrinchus desotoi. 

U.S. Department of the Interior, U.S. Fish Wildlife Service, Panama City, FL. 33 pp. 

Barkaszi, M.J., M. Butler, R. Compton, A. Unietis, and B. Bennet. 2012. Seismic survey mitigation measures and marine 

mammal observer reports. U.S. Dept. of the Interior, Bureau of Ocean Energy Management, Gulf of Mexico OCS 

Region, New Orleans, LA. OCS Study BOEM 2012-015. 53 pp. 

Bélanger, L. and J. Bédard. 1989. Responses of Staging Greater Snow Geese to Human Disturbance. Journal of Wildlife 

Management 53:713-719. 

Biggs, D.C. and P.H. Ressler. 2000. Water column biology, pp. 141-187. In: Continental Shelf Associates, Inc. Deepwater 

Program: Gulf of Mexico Deepwater Information Resources Data Search and Literature Synthesis. Volume I: 

Narrative Report. U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New 

Orleans, LA. OCS Study MMS 2000-049. 

Boehm, P., D. Turton, A. Raval, D. Caudle, D. French, N. Rabalais, R. Spies, and J. Johnson. 2001. Deepwater program: 

Literature review, environmental risks of chemical products used in Gulf of Mexico deepwater oil and gas 

operations. Volume I: Technical report. U.S. Department of the Interior, Minerals Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Study MMS 2001-011. 326 pp. 

Brooke, S., and W.W. Schroeder. 2007. State of deep coral ecosystems in the Gulf of Mexico region: Texas to the Florida 

Straits, pp. 271-306. In: S.E. Lumsden, T.F. Hourigan, A.W. Bruckner, and G. Dorr (eds.), The State of Deep Coral 

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SECTION 19: ADMINISTRATIVE INFORMATION 

A. Exempted Information Description (Public Information Copies Only) 

The following attachments were excluded from the public information copies of this plan: 

Section 1B OCS Plan Information form – Bottom hole locations & proposed total depth 

Section 2J Blowout Scenario – confidential information for NTL 2010 N06 calculation 

Section 3A Geologic Description 

Section 3B Structure Contour Maps 

Section 3C Interpreted 2D or 3D seismic line(s)

Section 3D Cross Section(s) 

Section 3E Stratigraphic Column with Time vs. depth table 

Section 3G High-Resolution Seismic Lines & Top Hole Progs 

B. Bibliography 

CSA Environmental Impact Analysis – January 2015 

Shell’s Regional OSRP (2013/2014) 

Gardline Surveys, Inc. “3D Geohazard Assessment, Gulf of Mexico, Atwater Valley, Blocks AT018 and AT019, 

Stromboli Prospect”, Report #9172, Dated August 3, 2012. Data: frequency enhanced 3-D seismic 

C&C Technologies, “Archaeological Assessment Report, Blocks 18 (OCS-G 33863) and 19 (OCS-G 32556), 

Atwater Valley Area, Gulf of Mexico”, Report No. 120015, Dated May 2012. Data: AUV Side Scan Sonar and 

Sub-bottom Profiler 

Anadarko Petroleum Corporation Initial Exploration Plan N-9781, 2014 

Page 175 Public Information Copy