Tolbert, Michael

From: Tolbert, Michael

Sent: Tuesday, February 22, 2011 1:56 PM

To: 'sylvia.bellone@shell.com'

Cc: Peuler, Elizabeth; Hill, Chiquita; Wetzel, Nick; Saucier, Michael

Subject: Supplemental Exploration Plan S-7445 for Lease OCS-G 7493 (GB 427)

Importance: High

Page 1 of 1

2/22/2011

This email is to notify you that the following Supplemental Exploration Plan received October 28, 2010, amended 

 November 19 and 30, December 3 and 9, 2010, and January 6, 21, 27, and February 18, 2011, has been 

deemed submitted in accordance with 30 CFR 250.231(a) and 232(d) as of February 22, 2011:

Control Number - S-7445

Type - Supplemental Exploration Plan

Operator – Shell Offshore Inc.

Lease(s) - OCS-G 7493 (Block 427, Garden Banks Area)

Activities Proposed – Add Wells O, P, and Q

Michael Tolbert 

Petroleum Engineer 

Office of Field Operations, Plans Section

Phone: (504) 736-2867 

email: Michael.Tolbert@boemre.gov 

 
Shell Offshore Inc

P. O. Box 61933

New Orleans, LA 70161-1933

United States of America

Tel +1 504 728 7215

Fax +1 504 728 6747

Email sylvia.bellone@shell.com

February 17, 2011 

Regional Supervisor 

Office of Field Operations 

Bureau of Ocean Energy Management 

Regulation & Enforcement 

1201 Elmwood Park Boulevard 

New Orleans, LA 70123-2394 

 

Attn: Plans Group 

 MS 5321 

SUBJECT: Amended Supplemental Exploration Plan 

 OCS-G 7493, Garden Banks Block 427 

 Garden Banks 471 Unit 

 Offshore, Louisiana 

 S-07445

 

Shell submitted subject Supplemental Exploration Plan on October 28, 2010. At this time we are requesting 

an amendment to the plan to include the information contained in the attachments to this letter. The

amendments include an update to our worst case discharge number, a change in our proposed anchor 

pattern, and an update to our proposed schedule. These amendments do not change the analysis and 

conclusions in the previously submitted EIA. All additional information in our original supplemental plan 

remains as previously submitted. 

The NTL 2010-06 Worst Case Blowout requirements for our Regional Oil Spill Response Plan highest 

exploration well, were previously submitted October 26, 2010 with our Supplemental Exploration Plan for 

Mississippi Canyon Blocks 391, 392 and 348, Plan Control No. R-05066. 

Should you require any additional information, please contact me as indicated above. 

Kind regards 

Sylvia A. Bellone 
 

U. S. Department of the Interior OMB Control Number: 1010-0051 

Minerals Management Service OMB Approval Expires: 12/31/2011

OCS PLAN INFORMATION FORM 

General Information 

Type of OCS Plan: X Exploration Plan (EP) Development Operations Coordination Document (DOCD) 

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

Address: P. O. Box 61933 Contact Person: Sylvia Bellone 

New Orleans, LA 70161-1933 Phone Number: (504) 728-7215 

E-Mail Address: sylvia.bellone@shell.com

Lease(s): OCS-G 7493 Area: Garden Banks Block(s): 427 Project Name (If Applicable): NA 

Objective(s): X Oil Gas Sulphur Salt Onshore Base: Fourchon & Amelia Distance to Closest Land (Miles): 130 

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) 

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 an MMS-designated high-probability archaeological area? X Yes No 

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

Tentative Schedule of Proposed Activities

Proposed Activity Start Date End Date No. of Days 

Preset anchors 3/7/11 4/7/11 30 

Drill O 4/7/11 9/14/11 160 

Drill P 4/7/12 9/14/12 160 

Drill Q 4/7/13 9/14/13 160 

 

Description of Drilling Rig Description of Production Platform

 Jackup Drillship Caisson Tension leg platform

 Gorilla Jackup Platform rig Well protector Compliant tower 

X Semisubmersible Submersible Fixed platform Guyed tower

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

Drilling Rig Name (If Known): Noble Jim Thompson Spar Other (Attach Description) 

Description of Lease Term Pipelines

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

N/A

 

 MMS MMS Form MMS-137 (December 2008 – Supersedes all previous editions of form MMS=137 which may not be used.) Page 1 of 4 

PUBLIC INFORMATION
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): O Subsea Completion 

Anchor Radius (if applicable) in feet: Rectangle as defined by the following four points: NW corner 

X=1826637 Y=10009880; NE corner X=1840946Y=10009880; SE corner X=1840946 Y=9996040 and SW 

corner X=1826637 Y=9996040 

X Yes No 

Surface Location Bottom-Hole Location (For Wells) 

Lease No. OCS-G 7493 

Area Name Garden Banks 

Block No. 427 

Blockline 

Departures 

(in feet)

N/S Departure: 5965' FNL 

 E/W Departure: 1400' FEL 

Lambert X-Y 

coordinates 

X: 1,836,040 

 Y: 10,004,915 

Latitude/ 

Longitude

Latitude 

27.56962046 

Longitude 

-92.39596682 

TVD (Feet): MD (Feet): Water Depth (Feet): 2721’ 

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. 

Chapter 35) requires us to inform you that MMS collects this information as part of an applicant’s 

Exploration Plan or Development Operations Coordination Document submitted for MMS 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 250.196. 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. The use of this form is 

voluntary. 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 580 

hours per response, including the time for reviewing instructions, gathering and maintaining data, and 

completing and reviewing the form. Direct comments regarding the burden estimate or any other 

aspect of this form to the Information Collection Clearance Officer, Mail Stop 4230, Minerals 

Management Service, 1849 C Street, N.W., Washington, DC 20240.

 MMS Form MMS-137 (December 2008 – Supersedes all previous editions of form MMS=137 which may not be used.) 

 Page 2 of 4 PUBLIC INFORMATION 

 

 
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): P Subsea Completion 

Anchor Radius (if applicable) in feet: 4802’ Anchor Radius (if applicable) in feet: Rectangle as defined by 

the following four points: NW corner X=1826637 Y=10009880; NE corner X=1840946Y=10009880; SE 

corner X=1840946 Y=9996040 and SW corner X=1826637 Y=9996040 

X Yes No 

Surface Location Bottom-Hole Location (For Wells) 

Lease No. OCS-G 7493 

Area Name Garden Banks 

Block No. 427 

Blockline 

Departures 

(in feet)

N/S Departure: 5470' FNL 

 E/W Departure: 1920' FEL 

Lambert X-Y 

coordinates 

X: 1,835,520 

 Y: 10,005,410 

Latitude/ 

Longitude

Latitude 

27.57098950 

Longitude 

-92.39756494 

TVD (Feet): MD (Feet): Water Depth (Feet): 2721’ 

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. 

Chapter 35) requires us to inform you that MMS collects this information as part of an applicant’s 

Exploration Plan or Development Operations Coordination Document submitted for MMS 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 250.196. 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. The use of this form is 

voluntary. 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 580 

hours per response, including the time for reviewing instructions, gathering and maintaining data, and 

completing and reviewing the form. Direct comments regarding the burden estimate or any other 

aspect of this form to the Information Collection Clearance Officer, Mail Stop 4230, Minerals 

Management Service, 1849 C Street, N.W., Washington, DC 20240.

 MMS Form MMS-137 (December 2008 – Supersedes all previous editions of form MMS=137 which may not be used.) 

 Page 3 of 4 PUBLIC INFORMATION 

 
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): Q Subsea Completion 

Anchor Radius (if applicable) in feet: Rectangle as defined by the following four points: NW corner 

X=1826637 Y=10009880; NE corner X=1840946Y=10009880; SE corner X=1840946 Y=9996040 and SW 

corner X=1826637 Y=9996040 

X Yes No 

Surface Location Bottom-Hole Location (For Wells) 

Lease No. OCS-G 7493 

Area Name Garden Banks 

Block No. 427 

Blockline 

Departures 

(in feet)

N/S Departure: 6470' FNL 

 E/W Departure: 880' FEL 

Lambert X-Y 

coordinates 

X: 1,836,560 

 Y: 10,004,410 

Latitude/ 

Longitude

Latitude 

27.56822388 

Longitude 

-92.39436890 

TVD (Feet): MD (Feet): Water Depth (Feet): 2721’ 

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. 

Chapter 35) requires us to inform you that MMS collects this information as part of an applicant’s 

Exploration Plan or Development Operations Coordination Document submitted for MMS 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 250.196. 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. The use of this form is 

voluntary. 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 580 

hours per response, including the time for reviewing instructions, gathering and maintaining data, and 

completing and reviewing the form. Direct comments regarding the burden estimate or any other 

aspect of this form to the Information Collection Clearance Officer, Mail Stop 4230, Minerals 

Management Service, 1849 C Street, N.W., Washington, DC 20240.

 MMS Form MMS-137 (December 2008 – Supersedes all previous editions of form MMS=137 which may not be used.) 

 Page 4 of 4 PUBLIC INFORMATION
(2j) Blowout scenario

Summary 

This Section was prepared by Shell Offshore Inc. (Shell) pursuant to the guidance provided in the 

Bureau of Ocean Energy Management, Regulation and Enforcement’s (BOEMRE) Notice to 

Lessees (NTL) No. 2010-N06 with respect to blowout and worst case discharge scenario 

descriptions. 

Shell focuses on an integrated, three-pronged approach to a loss of well control event (blowout), 

including prevention, intervention /containment, and recovery. 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 with the goal of safe and 

environmentally sound well construction. Shell continues to invest independently in Research and 

Development (R&D) to improve safety and reliability of our well systems. Shell intends to comply 

with all applicable laws, regulations, rules and Notice to Lessees. 

 

Shell is a founding member of the Marine Well Containment Corporation (MWCC) and will have 

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 owns, manages, and provides 

fully trained crews to provide operational guidance of the subsea containment system during a 

response. The near term containment response capability will be addressed in Shell’s NTL10 

submission at the time an Application to Drill (APD) is submitted and will include lessons learned 

from the Macondo response. Shell is investing in R&D to improve containment systems. Also, 

Shell is a member of Clean Caribbean America (CCA), Marine Spill Response Corporation 

(MSRC), Clean Gulf Associates (CGA), and Oil Spill Response (OSR) to provide the resources 

necessary to respond to a spill as outlined in our Regional Oil Spill Response Plan. 

The Worst Case Discharge (WCD) blowout scenario for this EP is calculated for the GB 427 O 

location and based on the guidelines outlined in NTL No. 2010-N06 along with subsequent 

Frequently Asked Questions (FAQ). The WCD for GB 427 O falls below the WCD exploratory 

scenario (MC 391) included in our Regional OSRP. In the unlikely event of a spill, Shell’s Regional 

OSRP (October 2010) is designed to contain and respond to a spill that meets or exceeds this WCD. 

The WCD does not take into account potential flow mitigating factors such as well bridging, 

obstructions in wellbore, reservoir barriers, or early intervention. 

Uncontrolled blowout (volume first day) 184,000 bbl 

Uncontrolled blowout rate (first 30-days average daily rate) 166,000 bopd 

Duration of flow (days) based on relief well 109 days 

Total volume of spill (bbls) for 109 days 14.4 MMBO

Table 1 Worst Case Discharge Summary 

 
Shell is submitting a Supplemental Exploration Plan for GB 427 (OCS-G 7493) to appraise its 

recent Cardamom discovery. While the Cardamom discovery comprises multiple reservoirs, this 

Supplemental EP and NTL-06 documentation pertain to appraising one reservoir – the U sand. 

Three wells, each with unique surface and U sand bottom hole locations, are described in the 

Supplemental EP. The WCD forecast in this document pertains to the well location that, in the 

event of loss of well control, discharges the largest volume before containment. 

The GB 427-2 will be the first well drilled with a surface location in GB Block 427; however, 17 

exploratory and development wells drilled by Shell have targeted objectives in GB Block 427. 

Consequently, the fundamental geology of the block is well understood. 

For this appraisal, Shell plans to submit in Q4 2010 an APD for drilling a new blue water well. 

Given success, the well will be secured for later completion in ~Q2 2012.

Subsurface Description: 

Omitted from public information copies 

Blowout Scenario 

1) Purpose 

Pursuant to 30 CFR 250.213(g), 250.219, 250.250, and NTL No. 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 firstly enhance 

the ability to prevent a blowout and secondly to 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 offset wells and seismic. 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. 

2) Background 

This attachment has been developed to document the additional information requirements for 

Exploration Plans as requested by NTL No. 2010-N06 in response to the explosion and sinking of 

the Mobile Offshore Drilling Unit (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 

The GB 427-2 well is drilled to the U sand, as outlined in the Geological and Geophysical 

Information Section of the approved Supplemental EP and described above, using a subsea 

wellhead system, conductor, surface and intermediate casing program, and using a MODU 

rig with a marine riser and subsea blowout preventer (BOP). A hydrocarbon influx and a 

well control event are modeled to occur from the U Sand during a trip out of the hole. The 

simulated blowout modeled 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 Initial EP 

Type of Activity Drilling 

Facility Location (area/block) GB-427 

Facility Designation MODU 

Distance to Nearest Shoreline (miles) 130 miles 

Uncontrolled blowout (volume first day) 184,000 bbl 

Uncontrolled blowout rate (first 30-days average daily rate) 166,000 bopd 

Table 2 Estimated Flow Rates of a Potential Blowout

c) Total volume and maximum duration of the potential blowout 

Duration of flow (days) 109 days total duration 

(14 days to contract/mob rig 95 

days to drill relief well) 

Total volume of spill (bbls) 14.4 MMBO 

Note: based on MBAL Material 

balance reservoir model * 

* Note: The U sand model was constructed using observations from analogue fields in the 

area which indicate that moderate aquifer support is likely. Model and model outputs can be 

provided to the BOEMRE in electronic form upon request. 

Table 3 Estimated Duration and Volume of a Potential Blowout 

d) Assumptions and calculations used in determining the worst case discharge 

Information omitted from public information copies.

The NTL 2010-06 Worst Case Blowout requirements for our Regional Oil Spill Response Plan 

highest exploration well, were previously submitted October 26, 2010 with our Supplemental 

Exploration Plan for Mississippi Canyon Blocks 391, 392 and 348, Plan Control No. R-5066.

 
 (3f) Shallow Hazards Assessment

SITE SPECIFIC COMMENTS

History

Shell’s Auger TLP is centered in GB426 at X = 1,820,750 Y= 9,996,240. The anchors for the TLP 

extend into blocks 426 and 427. Two of the lateral mooring anchors are within the requested 

anchor pattern radius. None of the Auger Platform wells have surface locations in block 427. Shell 

now seeks approval to use the anchored vessel Noble Jim Thompson or similar rig within a 

rectangle with coordinates of: NW corner X=1826637 Y=10009880; NE corner 

X=1840946Y=10009880; SE corner X=1840946 Y=9996040 and SW corner X=1826637 

Y=9996040 with a 1000’ buffer to perform its planned operations on proposed locations O, P, and 

Q. Within this area there are two Auger Lateral mooring system lines: 

C1A-L1 is located at X = 1,826,623 Y = 10,003,220 

C1A-L2 is located at X = 1,829,722 Y = 9,997,196 

 

Flowlines flank the Auger dome on all sides. Existing pipelines surround and cross the proposed 

radius. Shell will maintain a buffer of at least 500’ when setting anchors. Shell will not set anchors 

at the intersection of the pipelines. 

To assess the proposed anchor radius and surrounding area, Shell used the following data: 

- Fugro-McClelland Anchoring Report Proposed Tension Leg Platform and M/V George 

Richardson for GB 426, 427, 470 and 471 dated February 22, 1990 

- Fugro’s Archeological Assessment Garden Banks Block 427 Report 2410-1061 dated May 

2010 (based on Fugro report No. 0201-0526) 

- Chance’s Hazard Study of GB 426, 427, 470, and 471 dated September 1985, 

- C& C Technologies Engineering and Hazard Study for 10” x 6” Pipeline Route in GB 341 

to 426, Report No. 3566-3662 dated March 2003 

- C& C Technologies Engineering and Hazard Study for 12” x 8” Pipeline Route in GB 341 

to 426, Report No. 3567-3663 dated June 2003 

- Shell’s high resolution 3-D surveys 

Well Locations Information

The proposed locations will use a 4,802’ (plus 1000’ buffer) radius. The rig center will be 

X = 1,836,144 Y = 10,004,512 

The well centers are: 

Proposed Location O: X = 1836040 Y = 10004915 

Proposed Location P: X = 1835520 Y = 10005410 

Proposed Location Q: X = 1836560 Y = 10004410 

Based on a high-resolution geophysical survey consisting of frequency enhanced 3-D seismic, 

Enhanced Surface Renderings, and Enhanced Surface Renderings with amplitudes applied, deeptow data, Archeological Assessment, side scan sonar, and Subbottom profiler data, the planned 

anchoring operations for GB 427 are suitable for the planned activities. 

David Garner Vernessa Bradford 

Staff Geological Engineer Shallow Hazards Interpreter

 
6 Biological, Physical, and Socioeconomic Information

(6a) Chemosynthetic Communities Report

ANCHOR CLEARANCE AND CHEMOSYNTHETIC 

ORGANISMS COMMENTS

History 

Shell located the Auger TLP in GB426. The anchors for the TLP extend into blocks 426 and 427. 

None of the Auger Platform wells have a surface location in block 427. Shell now seeks approval to 

use the anchored vessel Noble Jim Thompson in Garden Banks Block 427 within a rectangle with 

coordinates of: NW corner X=1826637 Y=10009880; NE corner X=1840946Y=10009880; SE 

corner X=1840946 Y=9996040 and SW corner X=1826637 Y=9996040 with a 1000’ buffer as 

required by NTL 2009-G40 to perform the planned operations on proposed locations O, P, and Q. 

To assess the proposed archeological status, well locations, anchor radius and surrounding area, 

Shell used the following data: 

 - Fugro-McClelland Anchoring Report Proposed Tension Leg Platform and M/V George 

 Richardson for GB 426, 427, 470 and 471 dated February 22, 1990 

 - Fugro’s Archeological Assessment Garden Banks Block 427 Report 2410-1061 dated May 

 2010 (based on Fugro report No. 0201-0526) 

 - Chance’s Hazard Study of GB 426, 427, 470, and 471 dated September 1985, 

 - C& C Technologies Engineering and Hazard Study for 10” x 6” Pipeline Route in GB 341 

 to 426, Report No. 3566-3662 dated March 2003 

 - C& C Technologies Engineering and Hazard Study for 12” x 8” Pipeline Route in GB 341 

 to 426, Report No. 3567-3663 dated June 2003 

 - Shell’s high resolution 3-D surveys 

Flowlines flank the Auger dome on all sides. 

Chemosynthetic Community Statement 

Per NTL No. 2009-G40, Deepwater Benthic Communities, Attachment A 

ASSOCIATED ANCHORS – NO ANCHOR DISTURBANCES WITHIN 250 FEET OF 

CHEMOSYNTHETIC COMMUNITIES 

For the three proposed locations O, P, Q and the associated anchor radius: 

Shell will observe the following separation distances from high-density deepwater benthic communities:

1. At least 2,000 feet from each proposed muds and cuttings discharge location; 

2. At least 250 feet from the location of all other proposed seafloor disturbances (including those 

caused by anchors, anchor chains, wire ropes, seafloor template installation, and pipeline 

construction). Seafloor disturbances include all “temporary” disturbances caused during mooring 

operations (e.g., anchor deployment, setting, and retrieval) as well as those caused by anchoring 

activities conducted prior to a MODU arriving on location (e.g., pre-installation of suction piles 

and cables; where seafloor impacts are much greater while the cables are located on the seafloor 

prior to being pulled taut and attached to the MODU). 

` 
Anchor Pattern Analysis 

The proposed rectangular “radius” has the following coordinates: NW corner X=1826637 

Y=10009880; NE corner X=1840946 Y=10009880; SE corner X=1840946 Y=9996040 and SW 

corner X=1826637 Y=9996040. 

The center of the rig will be X = 1,836,144 Y = 10,004,512. 

The proposed well centers are: 

Proposed Location O: X = 1836040 Y = 10004915 

Proposed Location P: X = 1835520 Y = 10005410 

Proposed Location Q: X = 1836560 Y = 10004410 

The seafloor east of the diapir is relatively smooth. The proposed locations are east of the base of 

the Auger diaper in GB427. There are four amplitudes and fluid expulsion features on its crest. 

From left to right, their center coordinates are: 

1 X = 1828115.61 Y = 10001005.83 

2 X = 1829096.38 Y = 10001119.85 

3 X = 1830134.70 Y = 10002291.81 

4 X = 1830808.04 Y = 10002577.53 

Shell has designated a 250’ avoidance zone around each fluid expulsion feature. Outside these 

avoidance zones, the subsurface has a dark reflectivity, interpreted as authigenic. The Auger dome 

has numerous seafloor faults that radiate from its crest. The faults also curve 

around the perimeter of the dome. These faults are usually small displacements affecting the 

shallow sediments and the seafloor. Vertical displacement of the subsurface reflectors was generally 

less than 10 feet and seafloor displacement is less than 5 feet. Because of these conditions, the 

placement of the suction anchors will be optimized. The suction anchors will be located to 

minimize penetration of shallow seafloor faults on the eastern side of the dome. 

Shell will set the anchors using ROV to survey the area before installation. 

 

The Auger Lateral Mooring System has two lines within the proposed area. The coordinates are: 

Auger Lateral Line 3: X = 1826896.33 Y = 10003502.30 

Auger Lateral Line 4: X = 1830117.92 Y = 9997246.92

Shell will observe an anchor/suction buffer of 500’ from these lines. 

Archeological Assessment 

Per the archeological report, there are items of modern drilling debris such as drill pipe on the 

seafloor. One item is an unidentified contact measuring 25’ long by 25’ wide. This contact is a mud 

mat associated with former construction, shipping, or fishing activities. Its location is 

approximately X = 1822600; Y = 9995240. Previously drilled GB 471 Well # 1 is located at 

X = 1823472; Y = 9994628. The mud mat and the well are outside the proposed radius. 

There are no landforms or identified features that might be high probability prehistoric sites, such as 

natural levees or point bar deposits. The regional probability for historic shipwrecks in this area is

low. 
Within the study area, a modern day shipwreck, the shrimp boat Saint Mary sunk in 1990. Its 

coordinates are X = 1821348; Y = 10000919. The boat has a 750’ avoidance radius around it. A 

500’ avoidance buffer has been place along each existing pipeline. 

Slope Stability 

Shell conducted a detailed study on the Auger Dome to assess the surface stability for anchoring. A 

determination of sediment run out in case of slope failure was calculated. The anchor placement 

took this sediment run out into consideration. A slope stability factor of safety of 1.3 or greater is

deemed stable. Per Shell’s assessment, the sediment on the dome meets this requirement. 

Shell used the following methods to do the assessment: 3-D seismic data for seafloor bathymetric 

profiles upslope from proposed manifold locations, towards salt dome high Deep geotechnical 

borings at Auger for generalized soil conditions (stratigraphy and mechanical 

properties). 

Slope Conclusions and Recommendations 

• Based on infinite slope results with Auger soil data, the study profiles are in the “stable” 

range (i.e., FoS ~ 1.3-1.5 at zones of maximum slope). 

• Based on debris flow simulations of possible “seafloor failure zones,” Proposed Location O 

is ~200’ outside of the maximum run-out predicted with Auger soil data, while Proposed 

Locations P and Q are ~400’ to 750’ inside the maximum predicted runout, respectively. 

• Collective results indicate that risk to proposed manifold locations is low to moderate 

(increasing to the south). 

• Moving the proposed manifold locations to 500’ outside the maximum predicted run-out 

carries minimal risk. 

Overview 

NTL Numbers 2009-G40, 2009-G39, 2008-G20 and 2008-G05: Shell evaluated the seafloor and 

archeological data on GB Blocks 426, 427, 471, and 472. The anchor will be designed to minimize 

impact on areas of potential fluid expulsion and seafloor faults. Per BOEMRE regulations, Shell’s 

anchors will remain at least 250’ from potential fluid expulsion features and amplitudes. 

Based on a high-resolution geophysical survey consisting of frequency enhanced 3-D seismic, 

Enhanced Surface Renderings, and Enhanced Surface Renderings with amplitudes applied, deeptow data, Archeological Assessment, side scan sonar, and Subbottom profiler data, the planned 

anchoring operations for GB 427 is suitable for the planned activities. 

Vernessa Bradford 

Shallow Hazards Coordinator 

 

Supplemental Exploration Plan 

OCS-G 7493, Garden Banks Block 427 

Garden Banks 471 Unit 

Offshore, Louisiana 

8 AIR EMISSIONS INFORMATION

(8a) 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

(8b) 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 

Emission1 

Amounts 

(tons) 

Calculated 

Exemption2

Amounts 

(tons) 

Calculated

Complex Total 

Emission 

Amounts3

(tons) 

PM 17.36 4329 17.36

SOx 98.91 4329 98.91 

NOx 742.18 4329 742.18

VOC 23.44 4329 23.44

CO 161.89 87251.82 161.89

1

 For activities proposed in your EP or DOCD, list the projected emissions calculated from the worksheets. 

2

 List the exemption amounts for your proposed activities calculated by using the formulas in 30 CFR 250.303(d). 

3

 List the complex total emissions associated with your proposed activities calculated from the worksheets 

 (2) Contact: Sylvia Bellone, (504) 728-7215, Sylvia.Bellone@ shell.com

(1) Worksheets

Because the answers to all the questions set forth above is “no”, further worksheets are not required.

 
Supplemental Exploration Plan 

OCS-G 7493, Garden Banks Block 427 

Garden Banks 471 Unit 

Offshore, Louisiana 

9 OIL SPILLS INFORMATION

 (9a) Oil Spill Response Planning

(i) All the proposed activities and facilities in this EP will be covered by the Regional OSRP filed by Shell 

Offshore Inc (0689) in accordance with 30 CFR 250. An update to the Regional OSRP was filed with the 

BOEMRE October 26, 2010 and is pending approval. An OSRP Certification in accordance with 30 CFR 

254.2 was submitted and accepted by the BOEMRE on December 3, 2010. 

 (ii) Spill Response Sites: 

Primary Response Equipment Locations Preplanned Staging Location(s) 

Fourchon, LA; Cameron, LA; Houma, LA; Lake 

Charles, LA 

Lake Charles, LA ; Cameron, LA ; Fourchon ; LA 

(iii) The names of the oil spill removal organizations (OSRO’s) under contract include Clean Gulf Associates 

(CGA), Marine Spill Response Company (MSRC), Clean Caribbean America (CCA), and OSRL/EARL. 

(iv) Worst Case Scenario Determination 

Category Regional OSRP EP 

Type of Activity1 Drilling Rig Drilling Rig 

Facility Location (area/block) MC 391 GB 427 

Facility Designation2 C O 

Distance to Nearest Shoreline (miles) 72 137 

Volume3

Storage tanks (total) 

Flowlines (on facility) 

Pipelines 

Uncontrolled blowout (volume per day) 

Total Volume 

N/A 

N/A 

N/A 

405,000 BOPD 

405,000 Bbls 

N/A 

N/A 

N/A 

184,000* BOPD 

184,000 Bbls 

Type of Oil(s) - (crude oil, condensate, diesel) Crude oil Crude oil 

API Gravity(s)437.5o 24o 

*24 hour rate (166,000 BOPD 30 day average) 

Footnotes: 

1. Types of activities include pipeline, platform, caisson, subsea completion or manifold, and mobile drilling rig. 

2. E.g., Well No. 2, Platform JA, Pipeline Segment No. 6373. 

3. Your regional OSRP worst-case scenario volume must be taken from the appropriate section of your regional OSRP. 

For EP’s, the worst-case scenario volume must be determined by using the daily worst-case discharge volume 

determined using the guidance at 30 CFR 254.47(b). For DOCD’s, the daily worst-case discharge volume must be 

determined by using the guidance at 30 CFR 254.47 (a) and/or (b), as appropriate. 

4. Provide API gravity of all oils given under “Type of Oil(s)” above. Estimate for EP’s. 

Since Shell Offshore Inc has the capability to respond to the appropriate worst-case spill scenario included in its regional 

OSRP, submitted October 26, 2010, and since the worst-case scenario determined for our SEP does not replace the 

appropriate worst-case scenario in our regional OSRP, I hereby certify that Shell Offshore Inc 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 SEP. 

 
(9b) Oil Spill Response Discussion

A. Volume of the Worst Case Discharge 

Please refer to Section 2j of this EP 

B. 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 BOEMRE 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 

GB 427 20 

Kleberg, TX 

Nueces, TX 

Aransas, TX 

Calhoun, TX 

Matagorda, TX 

Brazoria, TX 

Galveston, TX 

Jefferson, TX 

Cameron, LA 

Vermillion, LA 

Iberia, LA 

Terrebonne, LA 

Plaquemines, LA 

1% 

1% 

1% 

1% 

3% 

2% 

6% 

4% 

9% 

3% 

1% 

2% 

1% 

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 

BOEMRE 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 Cardamom WCD scenario. 

Onshore/Nearshore: Cameron Parish is identified as the most probable impacted Parish within the Gulf of 

Mexico for the Exploratory WCD. Cameron Parish is located in the southwest corner of Louisiana and has a 

total area of 1,932 square miles of which, 1,313 square miles of it is land and 619 square miles is water. 

Cameron Parish includes four National Wildlife Refuges including the Cameron Prairie National Wildlife

Refuge, East Cove National Wildlife Refuge, Sabine National Wildlife Refuge and part of the Lacassine 

National Wildlife Refuge. 

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 

ACPs. 

D. Worst Case Discharge Response 

Shell will make every effort to respond to the Cardamom WCD as effectively as possible. 

Applied Science Associates (ASA) conducted a deepwater blowout simulation to better determine subsurface 

and surface evaporation and dispersion rates. Below is a table outlining the estimated applicable evaporation 

and dispersion quantities: 

Garden Banks 427 

Calculations 

(BBLS) 

i. 30 Day Average WCD = 166,000 bbls 

ii. Subsurface dispersion – 25% (Water Depth = ~2,700) -41,500 bbls 

iii. REMAINING WCD AFTER SUBSURFACE DISPERSION 124,500 bbls 

iv. Surface dispersion and evaporation – 25% -31,200 bbls 

TOTAL REMAINING ~93,300 bbls 

Table 9.D.1 Oil Remaining After Subsurface and 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 respond to 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 

Upon notification of the spill, Shell would request a full mobilization of contracted resources, including, but 

not limited to: MWCCs IRCS, skimming vessels, oil storage vessels, dispersant aircraft, subsea dispersant, insitu burn teams, 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 regional or global response resources and service companies if the Unified Command deems

such services necessary to the response efforts. 

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 Cardamom will be addressed in Shell’s NTL10 submission at the 

time the APD is submitted. 

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 865,000 barrels/day. Temporary 

storage associated with the identified skimming and temporary storage equipment equals approximately 

836,000 barrels. 

 

De-rated Recovery Rate 

(bopd) 

Storage 

(bbls) 

Offshore Recovery 476,000 273,400 

Offshore Storage 211,500 

Nearshore Recovery 106,000 17,000 

Total 583,000 502,000 

Table 9.D.3 Mechanical Recovery Combined De-Rated Capability 

 Table 9.D.4 Offshore On-Water Recovery Activation List 

Table 9.D.5 Offshore On-Water Storage Activation List 

 Table 9.D.6 Nearshore On-Water Recovery Activation 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.7 Arial 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 7,700 to 9,600 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.8 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.9 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.10 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 aerially-deployed 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 600 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 ~10,000 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.11 In-Situ Burn Equipment Activation List 

Shoreline Protection: If the spill went unabated, shoreline impact in St. Bernard or 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, The Response Group and Unified Command would be consulted to ensure that environmental and special 

economic resources would be correctly identified and prioritized to ensure optimal protection. The Response 

Group shoreline response guides 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.12 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 the following table: 

 Table 9.D.12 Shoreline Protection and Wildlife Support List 

 
1

 Table 9.D.12 Shoreline Protection and Wildlife Support List 

Figure 9.C.1 Environmental Sensitivity Index Map Legend 
2

Figure 9.C.2 Texas Point ESI Map 
3

Figure 9.C.3 Smith Bayou ESI Map 
4

. 

Figure 9.C.4 Johnsons ESI Map 
5

Figure 9.C.5 Peveto Beach ESI Map 
6

Figure 9.C.6 Holly Beach ESI Map 
7

Figure 9.C.7 Cameron ESI Map 
8

Figure 9.C.8 Grand Bayou ESI Map 
9

Figure 9.C.9 Creole ESI Map 
10

Figure 9.C.10 Hackberry Beach ESI Map 
11

Table 9.D.4 Offshore On-Water Recovery Activation List 
12

Table 9.D.4 Offshore On-Water Recovery Activation List (continued) 
13

Table 9.D.4 Offshore On-Water Recovery Activation List (continued) 
14

Table 9.D.4 Offshore On-Water Recovery Activation List (continued) 
15

Table 9.D.5 Offshore On-Water Storage Activation List 
16

 Table 9.D.6 Nearshore On-Water Recovery Activation List 
17

Table 9.D.6 Nearshore On-Water Recovery Activation List (continued) 
18

Table 9.D.6 Nearshore On-Water Recovery Activation List (continued) 
19

Table 9.D.6 Nearshore On-Water Recovery Activation List (continued) 
20

Table 9.D.6 Nearshore On-Water Recovery Activation List (continued) 
21

Table 9.D.7 Aerial Surveillance Activation List 
22

Table 9.D.8 Offshore Aerial Dispersant Activation List 
23

Table 9.D.9 Offshore Boat Spray Dispersant Activation List 
24

Table 9.D.10 Subsea Dispersant Package Activation List 
25

Table 9.D.11 In-Situ Burn Equipment Activation List 
26

Table 9.D.11 In-Situ Burn Equipment Activation List (continued) 
27

Table 9.D.12 Shoreline Protection and Wildlife Support List 
18. Environmental Impact Analysis (EIA)

The updated worst case discharge number of 184,000 BOPD, change in proposed anchor pattern, and 

update to the proposed schedule addressed in this amended Exploration Plan do not change the 

conclusions reached in the EIA submitted as part of the Exploration Plan on October 28, 2010.