UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field 

Operations (MS 5231)

Public Information copy of Exploration Plan

Control # - R-05296

Type - Revised Exploration Plan

Lease(s) - OCS-G21447 Block - 919 Keathley Canyon Area

Operator - Exxon Mobil Corporation

Subsea Wells B, D, and E

DP SEMISUBMERSIBLE

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.

Karen Dunlap

Plan Coordinator

Description -

Rig Type -

Subject:

From:

October 28, 2011
REVISED EXPLORATION PLAN

KEATHLEY CANYON BLOCK 919, OCS-G 21447

EXXON MOBIL CORPORATION

Bryan.l.chapman@exxonmobil.com

Authored by: Bryan L. Chapman, Sr. Regulatory Specialist

Public Information Copy
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Table of Contents 

REVISIONS TABLE TO PUBLIC INFO COPY OF PLAN R-5296: .................................................................................... 1

SECTION 1: PLAN CONTENT ................................................................................................................................... 2

DESCRIPTION, OBJECTIVES & SCHEDULE ................................................................................................................... 2

LOCATION .................................................................................................................................................................. 2

RIG SAFETY AND POLLUTION FEATURES: .............................................................................................................................. 2

STORAGE TANKS - MAERSK DEVELOPER SEMISUBMERSIBLE .................................................................................................... 4

POLLUTION PREVENTION MEASURES .................................................................................................................................. 4

SECTION 2: GENERAL INFORMATION ................................................................................................................... 10

APPLICATION AND PERMITS ............................................................................................................................................10

DRILLING FLUIDS ..........................................................................................................................................................10

PRODUCTION...............................................................................................................................................................10

OIL CHARACTERISTICS....................................................................................................................................................10

NEW OR UNUSUAL TECHNOLOGY ....................................................................................................................................10

BONDING....................................................................................................................................................................10

OIL SPILL FINANCIAL RESPONSIBILITY (OSFR) ....................................................................................................................10

DEEPWATER WELL CONTROL STATEMENT...........................................................................................................................10

SUSPENSION OF PRODUCTION.........................................................................................................................................10

BLOWOUT SCENARIO.....................................................................................................................................................11

SUMMARY – PUBLIC INFORMATION VERSION ........................................................................................ 13

CHEMICAL PRODUCTS....................................................................................................................................................21

SECTION 3: GEOLOGICAL AND GEOPHYSICAL INFORMATION ............................................................................... 22

GEOLOGICAL DESCRIPTION..............................................................................................................................................22

STRUCTURE CONTOUR MAPS FOR WELL E .........................................................................................................................22

INTERPRETED 3D SEISMIC LINES – WELL E .........................................................................................................................22

GEOLOGICAL STRUCTURE CROSS SECTIONS ........................................................................................................................22

SHALLOW HAZARDS ASSESSMENT ....................................................................................................................................22

HIGH-RESOLUTION SEISMIC LINES....................................................................................................................................24

TIME VS DEPTH TABLE ...................................................................................................................................................24

STRATIGRAPHIC COLUMN...............................................................................................................................................24

GEOCHEMICAL INFORMATION .........................................................................................................................................24

FUTURE G&G ACTIVITIES...............................................................................................................................................24

SECTION 4: HYDROGEN SULFIDE .......................................................................................................................... 24

CONCENTRATION..........................................................................................................................................................24

CLASSIFICATION............................................................................................................................................................24

MODELING REPORT ......................................................................................................................................................24

SECTION 5: MINERAL RESOURCE CONSERVATION INFORMATION ..................................................................... 25

SECTION 6: BIOLOGICAL, PHYSICAL, AND SOCIOECONOMIC INFORMATION........................................................ 26

CHEMOSYNTHETIC COMMUNITIES REPORT ........................................................................................................................26

TOPOGRAPHIC FEATURES, LIVE BOTTOMS, (PINNACLE TREND) MAP, LIVE BOTTOMS (LOW RELIEF) ...................................27

REMOTELY OPERATED VEHICLE (ROV) MONITORING PLAN..................................................................................................27

THREATENED AND ENDANGERED SPECIES INFORMATION ......................................................................................................27

ARCHAEOLOGICAL REPORT .............................................................................................................................................29

AIR AND WATER QUALITY INFORMATION ..........................................................................................................................29

SOCIOECONOMIC INFORMATION......................................................................................................................................29

SECTION 7: WASTE AND DISCHARGE INFORMATION ........................................................................................... 30

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PROJECTED GENERATED WASTES.....................................................................................................................................30

PROJECTED OCEAN DISCHARGES......................................................................................................................................31

MODELING REPORT ......................................................................................................................................................31

SECTION 8: AIR EMISSIONS INFORMATION .......................................................................................................... 32

WORKSHEETS ..............................................................................................................................................................32

SECTION 9: OIL SPILL INFORMATION .................................................................................................................... 33

OIL SPILL RESPONSE PLANNING.......................................................................................................................................33

OIL SPILL RESPONSE DISCUSSION.....................................................................................................................................34

MODELING REPORT ......................................................................................................................................................34

SECTION 10: ENVIRONMENTAL MONITORING INFORMATION ............................................................................. 35

MONITORING SYSTEMS..................................................................................................................................................35

INCIDENTAL TAKES ........................................................................................................................................................35

FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY....................................................................................................35

SECTION 11: LEASE STIPULATIONS INFORMATION............................................................................................... 35

SECTION 12: ENVIRONMENTAL MITIGATION MEASURE INFORMATION .............................................................. 36

IMPACTS TO MARINE AND COASTAL ENVIRONMENTS...........................................................................................................36

INCIDENTAL TAKES ........................................................................................................................................................36

SECTION 13: RELATED FACILITIES AND OPERATIONS INFORMATION ................................................................... 36

SECTION 14: SUPPORT VESSELS AND AIRCRAFT INFORMATION ........................................................................... 37

GENERAL ....................................................................................................................................................................37

DIESEL OIL SUPPLY VESSELS............................................................................................................................................37

DRILLING FLUIDS TRANSPORTATION ................................................................................................................................. 37

SOLID AND LIQUID WASTES TRANSPORTATION ...................................................................................................................37

VICINITY MAP..............................................................................................................................................................37

SECTION 15: ONSHORE SUPPORT FACILITIES INFORMATION ............................................................................... 38

GENERAL ....................................................................................................................................................................38

SUPPORT BASE CONSTRUCTION OR EXPANSION..................................................................................................................38

SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE ..................................................................................................38

WASTE DISPOSAL .........................................................................................................................................................38

AIR EMISSIONS .............................................................................................................................................................38

UNUSUAL SOLID AND LIQUID WASTES................................................................................................................................38

SECTION 16: SULPHUR OPERATIONS INFORMATION ........................................................................................... 39

SECTION 17: COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION ........................................................... 40

SECTION 18 - ENVIRONMENTAL IMPACT ANALYSIS (EIA) ................................................................................... 41

A. IMPACT-PRODUCING FACTORS ...................................................................................................................................41

B. ANALYSIS................................................................................................................................................................44

B.1.1 Designated Topographic Features ..........................................................................................................44

B.1.2 Pinnacle Trend Area Live Bottoms...........................................................................................................44

B.1.3 Eastern Gulf Live Bottoms .......................................................................................................................44

B.1.4 Chemosynthetic Communities .................................................................................................................44

B.1.5 Water Quality ..........................................................................................................................................44

B.1.6 Fisheries ..................................................................................................................................................45

B.1.7 Marine Mammals ....................................................................................................................................45

B.1.8 Sea Turtles ...............................................................................................................................................46

B.1.9 Air Quality ...............................................................................................................................................47

B.1.10 Shipwreck Sites (known or potential) ..................................................................................................48

B.1.11 Prehistoric Archaeological Sites ..........................................................................................................48

B.2.1 Essential Fish Habitat ..............................................................................................................................48

B.2.2 Marine and Pelagic Birds ........................................................................................................................49

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B.2.3 Public Health and Safety .........................................................................................................................50

B.3 COASTAL AND ONSHORE ...................................................................................................................................50

B.3.1 Beaches ...................................................................................................................................................50

B.3.2 Wetlands .................................................................................................................................................50

B.3.3 Shore Birds and Coastal Nesting Birds ....................................................................................................50

B.3.4 Coastal Wildlife Refuges .........................................................................................................................51

B.3.5 Wilderness Areas .....................................................................................................................................51

B.4.1 Non-Chemosynthetic Benthic Communities ............................................................................................51

B.4.2 Pelagic Communities ...............................................................................................................................52

C. IMPACTS ON PROPOSED ACTIVITIES .............................................................................................................................53

D. ALTERNATIVES.........................................................................................................................................................53

E. MITIGATION MEASURES ............................................................................................................................................53

F. CONSULTATION........................................................................................................................................................53

G. REFERENCES ...........................................................................................................................................................54

H. LIST OF PREPARERS ..................................................................................................................................................55

SECTION 19: ADMINISTRATIVE INFORMATION .................................................................................................... 56

EXEMPTED INFORMATION DESCRIPTION (PUBLIC INFORMATION COPIES ONLY) ........................................................................56

BIBLIOGRAPHY .............................................................................................................................................................56

Public Information Copy
REVISIONS TABLE TO PUBLIC INFO COPY OF PLAN R-5296: 

8/31/2011 submitted Plan to BOEM. 

9/13/2011 info request: 

1. Plan Form, verify distance to shore. 

2. Plan Form, verify well “B” 

3. Well Plat, add MD/TVD, Section 1 

4. Verify WCD blowout days, Section 2j 

5. Check well “B” in haz assessment, Section 3 

6. Chemo, check well B, Section 6 

7. OSRP, use numbers in original plan, Section 9 

8. OSRP, verify response time, Section 10 

9. Support vessels - remove anchor handling, Section 14 

10. EIA, provide list of preparers, Section 18 

Provided information on 9/16/2011 

9/20/2011 info request: 

1. Well “B” MD/TVD 

Provided information on 9/21/2011 

9/21/2011 info request 

1. Clarification data for Well B, Section 3 

Provided information 9/23/2011 

9/26/2011 

1. Additional clarification for Well B, Section 3 

2. Waste Table 7B, Section 7 

Provided information 9/27/2011 

10/17/2011 info request 

1. Provide full plans and CDs 

Provided information 10/18/2011 
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SECTION 1: PLAN CONTENT 

 DESCRIPTION, OBJECTIVES & SCHEDULE 

Lease OCS-G 21447, Keathley Canyon Block 919, was acquired by Exxon Mobil Corporation (Exxon Mobil) at the Gulf of 

Mexico Lease Sale No. 174 held August 25, 1999. The lease was issued with an effective date of December 1, 1999 

and a primary term ending November 30, 2009. The current lease operator and ownership are as follows: 

Area/Block

Lease Number

Operator Ownership

Keathley Canyon 

Block 919

OCS-G 21447

Exxon Mobil

Corporation

Exxon Mobil Corporation – 50%

Petrobras America, Inc. – 25% 

ENI Petroleum US LLC – 25%

The Initial EP for this lease was N-8115 for the drilling of the A & B wells. The “A” well was drilled in 2004. Plan S-7330 

was a supplemental EP to N-8115 that proposed the drilling of the C, D, E and F locations. This Plan was revised with 

Plan R-5106 (replaced Plan R-5016) for the drilling of the F (Hadrian 5) location in Keathley Canyon 919. Well F was 

drilled in 2011 and temporarily abandoned. 

This revised Plan will move the location of well “E” (Hadrian 6) greater than 500’. It will also include previously approved wells B 

and D which will be drilled (one well per year) beginning in 2013 and ending around 2014. The wells will be drilled and 

temporarily abandoned with rig on location. The completion of the wells will be performed under the development phase of 

the project. If a well is unsuccessful, it will be permanently plugged and abandoned in accordance with BOEM regulations. 

 LOCATION 

See attached BOEM forms and location plats. 

Rig Safety and Pollution Features: 

The Rig we plan to use (Maersk Developer or similar DP semi-submersible) 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 proposed wells will be drilled and temporarily abandoned utilizing the Maersk Developer, a DP semi-submersible. If 

another rig is selected, it will be a similar type rig and the rig information will be made part of the Application for Permit to 

Drill.

The Maersk Developer is a KFELS MSC Gusto DSS 2 design, dynamically positioned, semi-submersible vessel designed to drill 

to 40,000 feet in water depths up to 10,000 feet. The Developer has an overall length of 383 feet and width of 256 feet. The 

maximum variable load is 7,000 metric tons. The rig has been designed, built and classed in accordance with the American 

Bureau of Shipping (ABS), and has the classification designation of PDS-2, AMCUU, A1 Column Stabilized Drilling Unit. 

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Emergency Plan 

The Maersk Developer has written safety and emergency operations instructions to cover the foreseeable emergencies 

that may be encountered onboard the Developer. These instructions are provided in the rig’s Operating Manual and 

Emergency Response Manual. Additional rig safety equipment is described below. 

Safety Features 

The Maersk Developer is equipped with well control and personnel safety equipment as required to meet the codes, 

rules and regulations of SOLAS and IMO. A listing of key elements of the rig’s well control and personnel safety 

equipment are as follows. 

Well Control 

The Maersk Developer utilizes a Hydril 18-3/4 inch 15,000 psi working pressure guidelineless BOP system (suitable for 

H2S service) consisting of six (6) 15,000 psi ram preventers, two (2) 10,000 psi annular preventers and a Vetco SHD-H4 

15,000 psi wellhead connector. The marine riser system consists of a Aker Kvaener 19.25 inch ID riser, with 4 inch ID 

15,000 psi choke and kill lines. The rig choke manifold is suitable for H2S service, complete with four (4) choke and kill 

failsafe valves. 

Personal Safety 

The Maersk Developer is equipped with four (4) 90 person life boats and sufficient approved inflatable life rafts to 

accommodate all persons on board, life jackets for 560 persons or 300 percent of the vessels rated capacity, as well as 

other safety features to meet the requirements of ABS, the rig’s certifying authority. Safety of personnel and 

protection of the environment during the proposed operations is of primary concern with Exxon Mobil, and mandates 

regulatory compliance with the contractors and vendors associated with the proposed operations as follows: 

Bureau of Ocean Energy Management, Regulation & Enforcement (BOEMRE) mandates that the operations in this Plan 

comply with well control, pollution prevention, construction and welding procedures as described in Title 30 CFR Part 

250, Subparts C, D, E and O; and as further clarified by BOEMRE Notices to Lessees. 

The BOEMRE conducts periodic announced and unannounced onsite inspections of offshore facilities to confirm 

operators are complying with lease stipulations, operating regulations, approved plans, and other conditions; as well as 

to assure safety and pollution prevention requirements are being met. The National Potential Incident of 

Noncompliance (PINC) List serves as the baseline for these inspections. 

U. S. Coast Guard regulations contained in Title 33 CFR mandate the appropriate life rafts, life jackets, ring buoys, etc., 

be maintained on the facility at all times. 

U. S. Environmental Protection Agency regulations contained in the NPDES General Permit GMG290000 mandate that 

supervisory and certain designated personnel on-board the facility be familiar with the effluent limitations and 

guidelines for overboard discharges into the receiving waters. 

Pollution Plan 

Maersk is committed to the wellbeing of all employees and to the protection of the environment in which we operate 

and live. It is the clear intention of Exxon Mobil and Maersk to conduct all operations in a manner that will comply with 

all environmental laws, rules and regulations applicable to our operations. The Maersk Developer is designed and 

operated to meet or exceed acceptable environmental regulatory standards to ensure protection of human health and 

the environment. The vessel has been designed, built and classed in accordance with the rules of the International 

Maritime Organization (IMO) and complies with the regulations of the International Convention of the Prevention of 

Pollution from Ships (MARPOL). The vessel has also been designed and constructed in accordance with United States 

Coast Guard (USCG) rules and regulations pertaining to foreign flag vessels. 

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Storage Tanks - Maersk Developer Semisubmersible 

Type of 

Storage Tank

Type of 

Facility

Tank Capacity 

(bbls.)

Number of 

Tanks

Total 

Capacity (bbls)

Fluid Gravity 

(API)

Pontoon 

Fuel Oil Tank

DP Semi -

Submersible 8,207 2

 

16,414 Diesel

Pontoon 

Fuel Oil Tank

DP Semi -

Submersible 5,502 2

 

11,004 Diesel

Upper Hull 

Oil Tank 

DP Semi -

Submersible 305 1

 

305 Diesel

Upper Hull 

Oil Tank 

DP Semi -

Submersible 356 1

 

356 Diesel

Upper Hull 

Oil Tank 

DP Semi -

Submersible 213 1

 

213 Diesel

Upper Hull 

Oil Tank 

DP Semi -

Submersible 220 1

 

220 Diesel

 Pollution Prevention Measures 

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

the discharges of oils and greases from the Rig during rainfall or routine operations. ExxonMobil does not propose 

additional safety, pollution prevention, or early spill detection measures beyond those required by 30 CFR 250. 

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 a routine 

scheduled basis. 

 All pollution pans on Rig are inspected daily. 

 Containment dikes are installed around all oil containment, drum storage areas, fuel vents, fuel storage tanks. 

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

 Drains on the Rig are assigned a number on a checklist. The checklist is used 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 via boat. 

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 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. 

 

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

Minerals Management Service OMB Approval Expires: December 31, 2011 

OCS PLAN INFORMATION FORM 

General Information

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

Company Name: ExxonMobil Corporation MMS Operator Number: 0276

Address: P. O. Box 4368 Contact Person: Bryan Chapman

Houston, TX 77210-4358 Phone Number: 281.654.1941

E-Mail Address: bryan.l.chapman@exxonmobil.com

Lease(s): OCS-G 21447 Area: KC Block(s): 919 Project Name (If Applicable): 

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

216

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

X

No

Do you propose to use new or unusual technology to conduct your activities? Yes x

X

No

Do you propose any facility that will serve as a host facility for deepwater subsea development? Yes x

X

No

Do you propose any activities that may disturb an MMS-designated high-probability archaeological area? Yes x

X

No

Have all of the surface locations of your proposed activities been previously reviewed and approved by MMS?

(See below for SL clearance)*

Yes* x

X

No

Tentative Schedule of Proposed Activities

Proposed Activity Start Date End Date No. of Days

Drill E and suspend 05/01/2012 08/19/2012 110

Drill B (SL approved in Plan R-4192) and suspend* 01/01/2013 04/20/2013 110

Drill D (SL approved in Plan S-7330) and suspend* 01/01/2014 04/20/2014 110

Description of Drilling Rig Jackup Drillship Description of Production Platform 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): Maersk Developer 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

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

 

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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 

(SL approved in Plan R-4192)

Subsea Completion

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

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 21447

Area Name Keathley Canyon

Block No. 919

Blockline

Departures

(in feet)

N/S Departure: 4187’ FSL

E/W Departure: 3364’ FWL

Lambert X-Y 

coordinates

X: 1,951,684

Y: 9,460,667

Latitude/

Longitude

Latitude

26.069992

Longitude

-92.051475

TVD (Feet): MD (Feet): Water Depth (Feet): 7400’

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.)

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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

(SL approved in Plan S-7330)

Subsea Completion

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

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 21447

Area 

Name

Keathley Canyon

Block No. 919

Blockline

Departures

(in feet)

N/S Departure: 2228' FSL

E/W Departure: 905' FWL

Lambert X-Y 

coordinates

X: 1,949,225.10

Y: -9,458,708.12

Latitude/

Longitude

Latitude

26o 03' 52.73471"

Longitude

-92o 03' 32.39581"

TVD (Feet): MD (Feet): Water Depth (Feet): 7380’

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.)

 

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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 x Yes X No

Surface Location Bottom-Hole Location (For Wells)

Lease No. OCS-G 21447

Area Name Keathley Canyon

Block No. 919

Blockline

Departures

(in feet)

N/S Departure: 4997' FNL

E/W Departure: 3966’' FWL

Lambert X-Y 

coordinates

X: 1,952,264.96

Y: 9,467,968.33

Latitude/

Longitude

Latitude

26.088600

Longitude

-92.049535

TVD (Feet): MD (Feet): Water Depth (Feet): 7380’

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.)

 

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-7240

-7220

-7300

-7300

-7020

-7240

-7240

-7320

-7260

-7280

-7340

-7360

-7000

92°3'0"W92°2'0"W

26°6'0"N

26°5'0"N

26°4'0"N

1,950,0001,955,0001,960,000

9,455,000

9,460,000

9,465,000

9,470,000

0 1,000 2,000 500 Feet

0 250 500 125 Meters

Chart scale 1" = 2,000'

Bathymetry Plat Figure 11

(Hadrian-6)

Hadrian-6

Easting 1,952,286.38

Northing 9,467,322.54

FWL KC 919 3,966.38

FNL KC 919 4,997.48

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SECTION 2: GENERAL INFORMATION 

Application and Permits 

There are no individual or site-specific permits other than general NPDES Permit and rig move notification that need to 

be obtained. 

Drilling Fluids 

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

Production 

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

Oil Characteristics 

Information regarding Oil Characteristics is not included in this REP as such information is only necessary in the case of 

DOCDs. 

New or Unusual Technology 

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

activities in this REP. 

Bonding 

The bond requirement for the activities proposed in this REP 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 National NTL No. 2008-N07, “Supplemental Bond Procedures.”

Oil Spill Financial Responsibility (OSFR) 

Exxon Mobil Corporation (ExxonMobil) BOEM Operator Number 0276 has demonstrated oil spill financial responsibility 

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

Financial Responsibility for Covered Facilities.”

Deepwater well control statement 

Exxon Mobil Corporation (ExxonMobil) BOEM Operator Number 0276 has the financial capability to drill a relief well 

and conduct other emergency well control operations. 

Suspension of Production 

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

case of DOCDs. 

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Blowout scenario 

Summary 

This Section was prepared by ExxonMobil 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. ExxonMobil intends to comply with all applicable laws, regulations, rules and 

Notices to Lessees. 

The WCD blowout scenario is calculated for the KC 919 E location and based on the guidelines outlined in NTL 2010-

N06 along with subsequent Frequently Asked Questions (FAQ). The WCD for KC 919 E location falls below the WCD 

exploratory scenario (KC 919 F) included in our Regional OSRP. In ExxonMobil’s Regional OSRP (July 2011) response 

capabilities are based on the first 30-day average daily rate; thus in the unlikely event of a spill, ExxonMobil’s Regional OSRP 

(July 2011) is designed to contain and respond to a spill that meets or exceeds this WCD. 

The WCD scenario, in terms of both initial and the sustained rates, has a low probability of being realized. Some of the 

factors that are likely to reduce rates and volumes, and 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 capabilities. 

Uncontrolled blowout (volume first day) 204,331 bbl 

Uncontrolled blowout rate (first 30-days average daily rate) 204,331 bopd 

Duration of flow (days) based on relief well 120 days

Total volume of spill (bbls) for 120 days 24.5 MMBO

Table 1 Worst Case Discharge Summary 

Blowout Scenario 

1) Purpose 

Pursuant with 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 offset wells, and seismic. These parameters are better than or consistent with the estimates used by 

ExxonMobil 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 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. 

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3) Information Requirements 

Blowout scenario 

All locations of the proposed KC 919 Revised EP were assessed for Worst Case Discharge. The KC 919 E location is 

drilled to the target sands, 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 target Sands 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). 

 Estimated flow rate of the potential blowout 

Category EP

Type of Activity Drilling 

Facility Location (area/block) KC 919

Facility Designation MODU

Distance to Nearest Shoreline (miles) 216 miles

Uncontrolled blowout (volume first day) 204,331 bopd

Uncontrolled blowout rate (first 30-days average 

daily rate) 204,331 bopd 

Table 2 Estimated Flow Rates of a Potential Blowout 

 Total volume and maximum duration of the potential blowout 

Duration of flow (days) 120 days total duration 

(14 days to secure present well, 3 

days to mob, 82 days to drill well and 

21 days to range.)

Total volume of spill (bbls) 24.5 MMBO 

Table 3 - Estimated Duration and Volume of a Potential Blowout 

ExxonMobil estimates 110 days to drill the initial well. However, the total days to drill the relief well from spud 

is 103 days (82 drilling days and 21 ranging days). The remaining difference is due to few logging days for a relief 

well versus an exploration well.

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SUMMARY – PUBLIC INFORMATION VERSION

ExxonMobil’s calculation of the Worst Case Discharge flow rate for the Hadrian-6 well results in a rate of 204,331 barrels 

of oil per day. The main factors controlling this rate include oil viscosity, net pay thickness, reservoir permeability, and 

reservoir pressure. The values chosen for all input parameters are best estimates based on available data in the area. The 

daily production rate was modeled for a period of 120 days, representing the maximum anticipated time to mobilize a rig and 

drill a relief well. 

Regional OSRP Information 

ExxonMobil’s primary provider for Oil Spill Response (“OSR”) equipment is Clean Gulf Associates (CGA), an industry 

cooperative owning an inventory of oil spill clean-up equipment. CGA is supported by the Marine Spill Response 

Corporation (MSRC), which is responsible for storing, inspecting, maintaining and dispatching CGA’s equipment. The MSRC 

STARS network provides for the closest available personnel, as well as MSRC supervision to operate the equipment. 

Spill Response Sites 

The following locations will be used in the event an oil spill occurs as a result of the proposed activities: 

Primary Response 

Equipment Location

Pre-Planning Staging 

Location(s)

Additional locations

Houma, LA Houma or Fourchon, LA See currently approved OSRP

OSRO Information 

ExxonMobil’s primary equipment provider for equipment is Clean Gulf Associates (CGA), an industry cooperative 

owning an inventory of oil spill clean-up equipment. CGA is supported by the Marine Spill Response Corporation (MSRC), 

which is responsible for storing, inspecting, maintaining and dispatching CGA’s equipment. The MSRC STARS network 

provides for the closest available personnel, as well as an MSRC supervisor to operate the equipment. 

Worst Case Discharge Scenario Comparison 

Category Regional OSRP WCDS EP WCDS

Type of Activity Exploratory Drilling Exploratory Drilling

Facility Location (Area/Block) KC 919 KC 919

Facility Designation

Distance to Nearest Shoreline 

(miles)

216 216

Volume 

Storage tanks (total)

Flowlines (on facility)

Lease term pipelines

Uncontrolled blowout 

 (volume/day)

Total Volume 252,000 252,000

Type of Oil(s)

(crude, condensate, diesel) Crude Oil Crude Oil

API Gravity 21.6° 21.6°

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Since ExxonMobil has the capability to respond to the worst-case spill scenario included in its Revised Regional OSRP 

(Appendix H – KC 919), submitted on 07/18/2011, and since the worst-case scenario determined for our EP does not 

replace the worst-case scenario in our Regional OSRP, I hereby certify that ExxonMobil 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. 

WORST CASE DISCHARGE SCENARIO RATES AND VOLUMES

WCD Hole Section 

The blowout model assumes uncontrolled flow from all reservoirs encountered in the 12-1/4" hole section, with no drill 

pipe in the hole. Following conventional safe drilling practices, this is an unlikely situation. 

Production profile 

The Miocene reservoirs expected to be encountered in the Hadrian-6 well are expected to have large aquifers that will 

provide strong water drive support and maintain reservoir pressure. Therefore the flow rate would not be expected to 

decline over the duration of a blowout and we have assumed a constant flow rate of 204,331 bopd. 

Total Potential Spill Volume 

We have evaluated two potential scenarios to kill a blowout, seafloor intervention and a relief well. Under seafloor 

intervention we would expect to kill the well in 21 days which would result in a total discharge volume of 4,290,951 barrels 

of oil. With a relief well we estimate 120 days to kill the well which would result in a total discharge volume of 24,519,720 

barrels of oil. 

DOCUMENTATION OF ASSUMPTIONS AND CALCULATIONS 

Uncertainties in this type of model in an appraisal well involve the characterization of the reservoir and fluids using 

nearby data for calibration. With respect to the reservoir, best estimate parameters are determined from logs and cores in 

other Hadrian wells. The values used for thickness, porosity, and permeability are assumed to be homogeneous throughout 

the reservoir. Following is a discussion of the basis for each parameter involved in the discharge rate calculation. 

a. Reservoir characteristics; 

b. Reservoir pressure and temperature

c. Reservoir drive mechanisms

d. Reservoir drainage area and depletion rates; 

e. Wellbore completion configurations:

f. Casing and open-hole sizes; In the worst case discharge scenario, the well would flow into a 12.25" open 

hole, and then up casing with 12.375" ID to the seafloor with no restrictions at the wellhead. 

g. Casing and open-hole roughness; In the open hole section, wells in the area have been drilled with very 

smooth holes showing very little deviation in the caliper logs, therefore the open hole section is assumed 

to have a roughness of 0.25 inches. For pipe roughness, there are many sources of information available 

that indicate a wide range for new steel pipe from 0.002 to 0.0008 inches with a preponderance of values 

around 0.0018 inches (for example, see Binder 1973). Therefore we have assumed a pipe roughness of 

0.0018 inches. 

h. Production history; the planned well is an exploratory appraisal well and there is no historical production 

from any of these reservoirs. 

i. Static and flowing pressures and temperatures; Available deepwater data was used to estimate the 

temperature at the mudline of 40 °F. The flowing pressures and temperatures in the worst case discharge 

scenario are shown in the table below. All depths in this table are referenced to the mudline. 

j. Skin damage; For all zones, the skin is set to zero to model no drilling induced near well bore formation 

damage or stimulation. There are assumed to be no non-Darcy effects since gas zones are not expected. 

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k. Water intrusion; At this well location we expect all hydrocarbon-bearing sands to be saturated with 

hydrocarbons to the base of the sand with no penetration of the water leg, therefore water intrusion is 

not assumed to occur during the worst case discharge. Since strong water drive is expected, depending 

on the duration of a blowout, encroachment of water could occur and water could begin flowing along 

with hydrocarbons, but this effect is ignored at this time. 

l. Coning; No increase in water or gas saturation in the wellbore due to coning is assumed to occur within 

the calculation period. 

m. Formation sloughing; The formations that would produce in the worst case discharge are highly 

unconsolidated and therefore will require sand control completions during production operations. This 

results in the expectation that sloughing would be likely to occur, but sloughing is assumed not to occur in 

the discharge calculation. Hole size is assumed to be constant at the drilled radius during the discharge. 

n. Bridging; The formations that would produce in the worst case discharge are highly unconsolidated and 

therefore will require sand control completions. This results in the expectation that massive sand 

production would occur along with heaving shales due to the pressure drawdown during a blowout and 

bridging is therefore likely to occur, however, no bridging is assumed in the discharge calculation. 

o. Pressure-volume-temperature characteristics of the fluid; Uncertainty with respect to the fluid 

characterization exists since we have not penetrated this fault block previously. Fluid characteristics are 

shown above in Table 1. 

p. Hydrostatic pressure; For modeling the discharge scenario, it was assumed that at the sea floor (7100 ft 

water depth), the only back pressure is from the water column at 0.445 psi/ft, resulting in a backpressure 

of 3160 psig. In other words, there would be no restriction to flow from the wellhead/BOP stack. This 

assumption represents an extremely unlikely situation based on our historical drilling performance, but is 

the assumption used in the worst case discharge calculation. 

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DRILLING OPERATIONS AND WELL CONTROL 

Blowout prevention while drilling and operating wells relies on a number of interrelated processes and procedures as 

described below. Drilling and completion fluids will provide primary well control during drilling and workover operations. 

The fluids are designed to exert hydrostatic pressure on the wellbore. The hydrostatic pressure exerted will exceed the pore 

pressures within the subsurface formations, preventing undesired fluid flow into the wellbore. Subsea-mounted blowout 

prevention equipment (BOPE), as described later in this section, will provide secondary well control during drilling or 

workover operations. In the event that primary well control is lost, the BOPE will contain the influx of formation fluid and 

then allow safe circulation of the influx out of the wellbore. 

Well Control Planning 

Well Planning

• Extensive offset well data used in well planning

– Casing points chosen to enable overbalanced drilling

– Well data and continuous well logging while drilling will be used to define casing setting points

– Casing and wellhead designed to be stronger than the formation to be drilled

• Rig BOPE will ensure the rig can manage high pressure drilling

– 15,000psi working pressure BOP stack on location

– Mud storage volume maintained for control and manage problems

• Experience and training is key to drilling Gulf of Mexico

– All ExxonMobil rig supervisors and engineers are certified in well control

– Experienced rig supervisors, operations superintendent, engineering manager and field drilling 

manager

– Crews will be trained to identify warning signs of hazards and to avoid escalation

– On the job proficiency drills are routinely conducted to ensure a kick can be detected in 10bbls 

or less 

• Specialized onsite teams and tools will supplement regular rig team during key drilling phases

– Engineers and geologists will monitor drilling parameters to pickup casing points and maintain 

well control

– Logging (LWD) and pressure while drilling (PWD) tools will be used to provide real time data

Well control will begin during the well planning phase. ExxonMobil has developed an Integrated Pore Pressure 

Prediction (IP3) Team consisting of geophysicists, geologists, drilling engineers, and computer modelers. The IP3 Team will 

analyze seismic data, well data from analogous wells, and regional models to predict pore pressure and fracture gradients, 

and to develop a detailed understanding of the reservoir. The use of advanced technology will enhance the prediction of 

formation behavior as wells are drilled, and allows the engineer to plan a well that minimizes the risk of a well control 

incident. 

Engineers will use the pore pressure predictions to design a drilling mud program with sufficient hydrostatic head to 

overbalance the formation pressures from surface to total well depth. Other factors influencing the mud weight design are 

shale conditions, fractures, lost circulation zones, under-pressured formations, and stuck-pipe prevention. The well casing 

program is designed to allow for containment and circulation of formation fluid influx out of the wellbore without fracturing 

open formations. Casing is designed to contain the maximum anticipated pressures during a well control event. 

Well Planning conforms to 30 CFR 250 requirements. ExxonMobil standards and recommended practices are, at a 

minimum, equivalent to BOEMRE regulations. 

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Well Control Training 

ExxonMobil requires certified well control training for drilling supervisors, operations superintendents, drilling 

engineers, contractor rig drillers, tool pushers, assistant drillers, derrickmen, and other appropriate personnel through an 

operations training program with a professional organization and in accordance with BOEMRE requirements. The 

curriculum consists of training in blowout prevention technology and well control. Successful completion results in 

participant certification. 

WELL CONTROL DURING DRILLING 

Inspection of Well Control Equipment 

Prior to rig acceptance, there will be a comprehensive inspection and testing program performed on the drill rig that meets 

or exceeds 30 CFR 250 requirements. Routine functional and pressure testing during future drilling operations will be 

conducted in compliance with ExxonMobil and BOEMRE requirements. 

Well Control During Riserless Hole Drilling 

ExxonMobil conducts a shallow drilling hazards evaluation to identify and delineate shallow drilling hazards at all 

proposed wells from the mudline down to the surface casing setting depth. Surface locations are chosen to avoid potential 

shallow drilling hazards, including shallow hydrocarbon bearing intervals and shallow water flow zones, with a thorough 

analysis of seismic data (seismic facies determination, amplitude analysis, and geological structure mapping) and the 

integration of relevant offset well information. 

ExxonMobil will have contingency plans in place to address shallow flows while drilling the riserless sections of any 

well. Shallow hole drilling plans and contingencies will be described in greater detail in the application for permit to drill. 

All plans will meet the requirements of 30 CFR 250, subpart D. 

Well Control While Drilling Below the Surface Hole 

The subsea BOPE to be used by ExxonMobil exceeds the standards as defined in regulation 30 CFR 250.442-446. The 

BOPE will be installed before drilling below the surface hole. The surface casing is the first string of casing after drilling out 

from underneath the conductor or structural casing. 

The primary well control barrier will be the hydrostatic pressure of the drilling or completion fluid. During drilling 

operations below the surface hole, the full BOP stack will be necessary because of potential for an influx from any 

hydrocarbon zones. Should an influx occur, the BOP will be used to close in the well and provide a barrier against release of 

formation fluids. 

Once installed, the BOPE will be tested according to BOEMRE requirements. 

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Well Control Monitoring and Procedures 

Primary Means of Well Control

 Exxon Mobil operating philosophy is to maintain a minimum of two well control 

systems

– Drilling fluid system provides primary means of well control with blowout 

preventer equipment as a second system

– If a barrier is lost, it must be restored before drilling further (i.e. raise mud 

weight in well control event)

 Drilling will be performed using an overbalanced mud weight to control the well

– The pressure exerted by the mud column will exceed formation pressure at any 

point in the well

– Mud properties will be monitored and maintained to ensure consistency

 Systems and processes in place for early kick detection

– Rig and mudlogger PVT and Flo-Sho alarms to be set to lowest practical limits

– Standpipe pressure will be closely monitored for pressure reduction

– PWD will be closely monitored for pressure reduction below mud weight 

hydrostatic

– Gas monitoring systems to be fully functional and operating

Automatic and manual monitoring equipment will be installed to detect abnormal variation in the mud system volumes 

and drilling parameters. If an influx of formation fluid into the wellbore occurs, the BOPE will be used to immediately shut in 

the well. 

Each well will be drilled according to a location-specific, detailed well plan. While drilling, the well will constantly be 

monitored for pressure control. The mud weight (the primary well control mechanism) will be monitored and adjusted to 

meet actual wellbore requirements. Too low of a mud weight could under-balance the well, and may result in an influx of 

formation fluids. Too high of a mud weight may result in lost circulation to a weak formation, which could then lead to a 

drop in fluid level and an under-balanced condition. A range of mud weights will be used as the well is drilled to provide the 

proper well control for the formation conditions encountered. 

Secondary Means of Well Control 

If an influx of formation fluid (kick) occurs, secondary well control methods will be employed. Constant monitoring of 

the total fluid circulating volume and other drilling parameters will ensure that a kick is quickly detected. The well annulus 

will be shut in using the BOPE. The drill pipe will be shut in by a downhole check valve near the bit and a surface-mounted 

valve. This will contain the influx and any associated build-up of surface pressure. It will also prevent further influx of 

formation fluid into the wellbore. Surface pressures will be allowed to stabilize and will then be measured. The pressure 

readings will enable the calculation of the new kill-weight mud density needed to regain primary well control. A standard 

well-kill procedure will be implemented to circulate the kill-weight mud and safely remove formation fluids from the hole. 

Mud-gas separators and degassers will be used to remove gas from the mud as it is circulated out of the hole. After this 

procedure is completed, the kill effectiveness will be confirmed and the well will be opened up and the fluid levels 

monitored. Drilling operations will resume when conditions are normal. 

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BOP drills will be performed on a frequent basis to ensure the well can be shut in quickly and properly. Certified 

training of Gulf of Mexico personnel will include hands-on simulator practice at recognizing kicks, well shut-in, and 

circulating the kicks out of the wellbore. Well specific shut in procedures will be posted on the rig. 

Potential Blowout Duration 

Hadrian wells are designed to maximize the ability to shut in the well at the seafloor in the event of a blowout. All casing 

strings are designed to withstand the maximum shut-in pressure in a well control situation. The wellhead, subsea BOPE and 

associated connectors are designed for maximum anticipated pressures and tensions in a well control event. 

The BOPE utilized will be in compliance with the requirements of 30 CFR 250. These requirements for dynamically 

positioned rigs include both a deadman system to shut in the well in the event of complete loss of communication to the 

subsea BOPE and an auto-shear system to shut in the well in the event of an accidental disconnect. ROV hot stabs will be in 

place and function tested to ensure that they close one pipe ram, close the blind shear ram, and unlatch the LMRP. 

Given the well and BOPE design, there is a high probability that a well could be shut in at the sea floor. In the event the 

BOP cannot be shut-in using the rig controls at the surface, an ROV would be deployed to attempt to close the BOP and seal 

the well using the hot stabs. This operation could take 1-3 days. If the well could not be shut-in using the ROV, a second 

BOP stack would be mobilized to connect to either the well head or the BOP stack. The riser would be removed to allow 

connecting the capping stack to the wellhead or BOP. This operation would take approximately 21 days. 

ExxonMobil is a charter member of the Marine Well Containment Company (MWCC). MWCC provides subsea containment 

equipment including a capping stack that meets the requirements of NTL No. 2010-N10. ExxonMobil will have an 

agreement in place with MWCC to provide subsea containment resources for the Hadrian 6 well. 

Relief well planning and execution activities would progress in parallel with the subsea containment efforts. In the event a 

relief well is required, a deepwater rig currently located in the GOM would be contracted to drill the relief well. As of July 

2011, there are approximately 20 rigs in the GOM capable of drilling a Hadrian relief well. The rig must be capable of 

drilling to a depth of ~21,000’ in a water depth of 7,400’. 

Well Control Training Proficiency Drills

Goal: Train personnel to react quickly to abnormalities and manage well control

 Trip Drills

– Unannounced

– Purpose is to reduce time for driller to detect and react during trip

– Standard is to detect 10 bbl gain within 1 minute and shut well in an additional 2 

minutes

 Pit Drills

– Unannounced

– Purpose is to reduce time for driller , drill crew and mud loggers to detect and react to 

pit level changes

– Standard is to detect 10 bbl gain within 2 minutes and shut well in an additional 2

minutes

 Power Choke Drills

– After setting casing, perform power choke drill

– Conduct crew training using the power choke and manual back-up (i.e. practice bringing 

on pumps and getting feel for choke)

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There are no platforms in the vicinity for drilling a relief well. The Hadrian 5 well (OCS G21447 No. 3) is approximately 4500 

feet northwest of the planned Hadrian 6 location. In the event of an actual emergency, this wellbore could potential be 

used for a relief well. A detailed evaluation of this option would occur in parallel with other relief well planning and 

execution activities. 

In the event of a blowout, up to 120 days may be necessary to secure a rig, mobilize to the location, drill the relief well and 

kill the blowout well. ExxonMobil has a mutual aid agreement in place with other GOM operators to facilitate faster 

mobilization in the event of an emergency. 

NTL No. 2010-N06 REQUIREMENTS AND ASSUMPTIONS 

NTL No. 2010-N06 (“NTL-N06”) seeks to impose on OCS lessees and operators a series of new and substantive obligations 

that alter or exceed existing regulatory requirements. By submitting this filing in an effort to comply with NTL-N06, 

ExxonMobil does not waive and expressly reserves the right to challenge NTL-N06 for any reason. 

More specifically, ExxonMobil believes that the assumption of no BOP stack on the well and no drill pipe in the hole does 

not reflect a likely potential blowout scenario. The wellhead/BOP/riser system is designed such that the weak point is at 

the surface. This design ensures that the structural casing, wellhead, BOP and associated connectors will remain intact in 

the event of a catastrophic loss of stationkeeping. 

Additionally, given the redundant control systems and ability to intervene with an ROV on the seafloor, it is unlikely that 

blind shear rams would not be able to close on the open hole. A more likely scenario for shear ram failure is an object 

across the rams that cannot be sheared (i.e. a drill pipe tool joint or drill collar). 

ExxonMobil believes that the following assumptions regarding hole conditions more accurately represent the resulting hole 

conditions of the Hadrian-6 well in the event a blowout occurs: 

 5-7/8" drill pipe is in the hole with drill bit at TD of the 12-1/4" hole section 

 BOP stack is in place with LMRP disconnected and the blind shear rams closed against a tool joint with 7" OD inside 18-

3/4" BOP cavity 

 Drill pipe is plugged and flow is up the annulus outside of the drill pipe 

 Discharge is at the top of the BOP stack 44 ft above the mudline 

Under this set of assumptions, ExxonMobil’s calculation of the Worst Case Discharge flow rate for the Hadrian-6 well results 

in a rate of 154,963 barrels of oil per day. Additionally, the presence of an intact BOP stack would more readily permit 

ExxonMobil to conduct a seafloor intervention, which could significantly decrease the duration of any discharge to 

approximately 21 days. More detailed information regarding this secondary calculation is available upon request. 

Software description 

In order to model the behavior of a blow out at the Hadrian-6 well location, ExxonMobil used the commercially available 

PROSPER software, version 11.5 (Petroleum Experts Ltd, Edinburgh, Scotland, UK). PROSPER is well suited for this purpose, as it 

is designed to calculate production rates considering the entire flow system including the reservoir, the near-well-bore region, 

the well bore, and the wellhead. 

PROSPER has a full PVT module which calculates hydrocarbon and water properties based on the input data. For the 

saturated oil and gas predicted, the Standing's correlations were used for oil properties and Petrosky for viscosity. Both 

correlations were matched to the actual laboratory data from Hadrian-5, -3 ST, and Lucius wells. 

A number of correlations are available within the software to govern the flow from the sand face through the well bore to 

the mud line. For this vertical flow situation, the OLGAS 2P correlation was selected due to its robustness and general 

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acceptance within industry for all multi-phase flow regimes. A vertical lift performance (VLP) curve (shown below) was then 

calculated using the best estimate parameters. 

The main software limitation involves the inability to handle heterogeneity in the reservoir. Full-scale reservoir simulations 

are generally not constructed until adequate calibration data is acquired through the drilling of exploration and appraisal wells. 

In general, the use of heterogeneity would degrade the reservoir inflow performance. Thus, the method used is inherently 

conservative and results in a higher rate. 

The blowout rate calculation is based on the expected reservoir thickness, permeability, temperature, and pressure at the 

well location. PROSPER was run using isotropic Darcy radial flow: 

q = 0.00708 keff h (Pe - Pw) / [μ B (ln(re/rw) + s)] 

Where: 

 q = flow rate, stbopd 

 keff = effective permeability, md 

 h = reservoir thickness, ft 

Pe = reservoir pressure, psi

Pw = wellbore pressure, psi

 = viscosity, cp

B = formation volume factor, rb/stb

 re = reservoir radius, ft 

 rw = wellbore radius, ft 

 s = skin damage, dimensionless 

The reservoir is assumed to be a horizontal three dimensional layer with constant properties (thickness and permeability). 

The wellbore is assumed to be centered in a square drainage area. The calculations are based on stabilized flow into the well 

bore with the entire reservoir interval open. 

 

Chemical Products 

Information regarding chemical products is not included in this REP as such information is not required by BOEMRE 

GOMR. 

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SECTION 3: GEOLOGICAL AND GEOPHYSICAL INFORMATION 

 Geological description 

Proprietary data. 

Structure Contour Maps for Well E

Proprietary data. 

Interpreted 3D Seismic lines – Well E 

Proprietary data. 

Geological Structure Cross sections 

Proprietary data. 

Shallow Hazards Assessment 

Shallow Hazards Statement KC919-B, KC919-D, and KC919-E 

This section addresses seafloor and shallow geologic conditions that may impact exploratory drilling operations within 

2000 ft of the proposed wellsite. All anticipated geophysical and geotechnical work preparatory to initiation of exploratory 

drilling operations has been completed. The database for the shallow hazard report includes geophysical 3D seismic, 

seabed piston cores, and regional well information. The high quality 3D seismic data was reprocessed as 3D Short Offset 

(3DSO) data. The 3D seismic data set was specially reprocessed as a resolute (2ms processing sample rate) short-offset 3-

fold cube with a CDP interval of 41.0ft (12.5m) and an interpolated inline spacing of 65.6ft (20.0m). These data were 

processed to preserve true amplitude for shallow hydrocarbon recognition. Four piston cores, with soil sample recoveries 

ranging from 17.0-20.3ft (5.2-6.2m), were acquired at various locations within the study area. Existing seabed wells within 

the study area include ExxonMobil KC919-001, KC919-002, and KC919-003. 

The geohazards report generated in June 2011 by Gardline Surveys Inc. covers a 4x4 mile area including blocks KC874, 

875, 918, and 919. To aid identification of seafloor hydrocarbon seeps and to assess foundation conditions, all data 

described herein were used in support of Exploration Plans for the ExxonMobil Hadrian locations KC919-B (OCS-G-21447), 

KC919-D (OCS-G-21447), and KC919-E (OCS-G-21447). 

Proposed KC919-B Location 

Block 919, Keathley Canyon Area 

OCS-G-21147 

SL: 4187’ FSL & 3364’ FWL; x: 1,951,684, y: 9,460,667 

Shallow Hazards Summary 

This section prepared by Heather McCarren, Operations Geologist for ExxonMobil. 

No hazards are predicted at the seabed. The nearest potential high density deepwater benthic community is located 

3,900ft west of the proposed well. 

Seafloor to Top Salt (Unit A): This uppermost interval is interpreted to comprise very soft to soft clays passing down into 

soft clays and silts with a normal compaction profile. No drilling hazards or problems are predicted through this interval.

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No shallow gas or abnormally pressured water sands are predicted at the proposed KC919-B well location.

Proposed KC919-D Location 

Block 919, Keathley Canyon Area 

OCS-G-21147 

SL 2228’ FSL & 905’ FWL; x: 1,949,225.10, y: 9,458,708.12

Shallow Hazards Summary 

No hazards are predicted at the seabed. The nearest potential high density deepwater benthic community is located 

5,750ft to the southeast of the proposed well. Thin coarser-grained interbeds just below the seabed may affect jetting of 

the seabed casing. 

Unit D 

A low probability of solution gas is assigned to the level of the <15ft sand interbed at 1,029ft below seabed (-8,409ft below 

sea surface). Drilling should proceed cautiously at this level to allow any vaporizing shallow gas to be circulated out of the 

drilling system. 

Unit E

Minor drilling fluid circulation problems may occur if pressures over hydrostatic are exerted by the drilling fluid column at 

the level of a fault at 1,538ft below seabed (-8,918ft below sea surface). 

A low probability of solution gas and a low probability of encountering abnormally pressured water-bearing sand is assigned 

to the interval from 1,944ft to 2,328ft below seabed (-9,324ft to -9,708ft below sea surface). Drilling should proceed 

cautiously at this level to allow any vaporizing shallow gas to be circulated out of the drilling system. Appropriate drilling 

methods should be applied to contain a non-persistent, low volume flow event.

Unit F

A low probability of solution gas is assigned to the level of the <15ft sand interbed at 3,329ft below seabed (-10,709ft below 

sea surface). Drilling should proceed cautiously at this level to allow any vaporizing shallow gas to be circulated out of the 

drilling system. 

Proposed KC919-E Location 

Block 919, Keathley Canyon Area, OCS-G-21147 

SL: 4997’ FNL & 3966’ FWL; x: 1,952,264.96, y: 9,467,968.33

Shallow Hazards Summary 

No hazards are predicted at the seabed. The nearest potential high density deepwater benthic community is located 

5,875ft to the southeast of the proposed well. Thin, coarser-grained interbeds immediately below the seabed may affect 

jetting of the seabed casing. 

Unit B 

Minor wellbore and drilling fluid circulation problems are assigned within Unit B from 641ft to 1,016ft below seabed (-

7,765ft to -8,140ft below sea surface). 

Unit E 

Minor wellbore and drilling fluid circulation problems may occur within the intervals from 1,564ft to 1,967ft below seabed 

(-8,688ft to -9,091ft below sea surface) and from 1,967ft to 2,332ft below seabed (-9,091ft to -9,456ft below sea surface). 

Additionally, a low probability of encountering abnormally pressured water-bearing sand is assigned from 1,967ft to 2,332ft 

below seabed (-9,091ft to -9,456ft below sea surface). Appropriate drilling methods should be applied to contain a nonpersistent, low volume flow event. 

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Unit F 

A vertical borehole will penetrate a fault at 2,686ft below seabed (-9,810ft below sea surface). Minor drilling fluid 

circulation problems are possible at the level of the fault if pressures over hydrostatic are exerted by the drilling fluid 

column. 

High-Resolution Seismic Lines 

Proprietary data. 

Time vs Depth Table 

Proprietary data. 

Stratigraphic Column

Proprietary data. 

Geochemical Information 

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

Future G&G Activities 

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

 

SECTION 4: Hydrogen Sulfide 

Concentration 

Proprietary data. 

Classification 

 

Based on CFR 250.490(c), ExxonMobil requests that the Regional Supervisor, Field Operations, determine the zones in the 

proposed drilling operations in this plan to be classified as an area where the absence of H2S has been confirmed. 

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.

 

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SECTION 5: Mineral Resource Conservation Information 

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

the case of DOCDs 

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SECTION 6: Biological, Physical, and Socioeconomic Information 

Chemosynthetic Communities Report 

ANCHOR CLEARANCE AND CHEMOSYNTHETIC 

ORGANISMS COMMENTS 

Deepwater Benthic Communities Information 

Seafloor and Surficial Sediments 

A seafloor ridge is present at the western half of the diapiriclally uplifted salt. This ridge trends north to south across the 

center of Blocks KC 919 and 963. On its flanks, the seafloor slopes to the southeast and southwest with dips locally 

approaching 14°. 

Four Piston cores were collected (February 2004) and analyzed by TDI-Brooks. Two samples contained significant volumes 

of higher hydrocarbons. Samples KC919_CO1 and KC919_CO2 (located <2.3 miles away from the proposed locations) 

contained live oil, gas and hydrogen sulfide were taken from a fault that cuts the seafloor in a southwest to northeast trend 

through blocks KC 919 and KC 963. This shallow fault extends down to the salt nappe and provides a migration pathway for 

hydrocarbons to the seafloor. These hydrocarbons may have migrated along a salt weld, along a salt suture or from deepseated faults that encounter the base of salt and are then able to migrate along welds or sutures through the salt section. 

Six other piston cores evaluated indicated no evidence of macro-seepage, such as oil staining above molecular levels, gas 

expansion pockets, gas hydrates, authigenic carbonates, odor or anomalous headspace gas values. Based on published 

organic geochemical characteristics of sediments from complex high-density deepwater benthic communities on the Gulf 

slope (Sassen et al., 1994) and results of the geochemical testing of the cores; hydrocarbon concentrations capable of 

supporting high-density deepwater benthic communities are unlikely to be present in the KC Block 964 near the proposed 

locations, including all areas of the seafloor that may be impacted by drilling operations. 

 Anchoring Considerations 

The surface locations proposed in this Exploration Plan will be drilled by a dynamically positioned semi-submersible. This 

mobile drilling unit will not use a mooring system for station keeping. Therefore, anchoring considerations are not 

applicable. Seafloor impact will be limited to the point of emplacement of the structural casing, wellhead, and BOP stack. 

No high-density deepwater benthic communities occur within a 2,000-foot radius of each proposed surface location. 

Therefore, incidental discharges during drilling operations will have no adverse affect on deepwater benthic fauna. 

Analysis and Summary Statement 

Location KC 919B

 NO ASSOCIATED ANCHORS -- NO DISTURBANCE WITHIN 2,000 FEET OF DEEPWATER BENTHIC COMMUNITIES. 

 Features or areas that could support high-density deepwater benthic communities are not located within 2,000 feet of 

the proposed mud and cuttings discharge location. 

Location KC 919D 

 NO ASSOCIATED ANCHORS -- NO DISTURBANCE WITHIN 2,000 FEET OF DEEPWATER BENTHIC COMMUNITIES. 

 Features or areas that could support high-density deepwater benthic communities are not located within 2,000 feet of 

the proposed mud and cuttings discharge location. 

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Location KC 919E 

 NO ASSOCIATED ANCHORS -- NO DISTURBANCE WITHIN 2,000 FEET OF DEEPWATER BENTHIC COMMUNITIES. 

 Features or areas that could support high-density deepwater benthic communities are not located within 2,000 feet of 

the proposed mud and cuttings discharge location. 

Included herein is bathymetry map showing the proposed surface location of Well E. 

In accordance with the guidelines set forth in Notice to Lessees and Operators 2008 G-05 (effective May 1, 2008 ) and 

Notice to Lessees and Operators 2009-G40 (effective January 27, 2010); all relevant Geophysical Site-Survey data, 3D Short 

Offset seismic, seabed piston core data and offset well data have been evaluated. No prohibitive top-hole conditions exist at 

any of these proposed locations. All Company drilling and operations personnel will be apprised of these conditions. 

Prepared by: Heather McCarren, Site Investigation Specialist 

ExxonMobil Exploration Company 

Topographic features, Live bottoms, (Pinnacle Trend) map, Live bottoms (low relief)

Pursuant to NTL No. 2008-G04 the proposed operations covered by this REP do not involve operations impacting the 

following: Topographic features map, Topographic features statement (shunting), Live bottoms, (Pinnacle Trend) map, Live 

bottoms (low relief) map, potentially sensitive biological features map. 

Remotely Operated Vehicle (ROV) Monitoring Plan 

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

Block 919 is located in Grid 8. The activities proposed in this Plan are located within an area where ROV Surveys are 

required. 

ExxonMobil will, if required, conduct surveys immediately prior to commencing drilling operations on location for KC 919 

wells proposed in this Plan and following the completion of drilling operations on said wells approximately 110 days later. 

ExxonMobil will use the rig based ROV equipped with video imaging capabilities. The survey pattern will consist of six 

transects centered on the well location with tracks extending approximately 100 meters away from the well on bearings of 

30 degrees, 90 degrees, 150 degrees, 210 degrees, 270 degrees and 330 degrees. The seafloor will be videotaped 

continuously along each track. 

 Threatened and Endangered Species Information 

There are 5 species of sea turtles that may be found in the Gulf of Mexico (see table). No critical habitat for these 

species has been designated in the Gulf of Mexico. 

Common Name Scientific Name

T/E 

Status

Hawksbill Turtle Eretmochelys imbricata E

Green Turtle Chelonia mydas T

Kemp's Ridley Turtle Lepidochelys kempii E

Leatherback Turtle Dermochelys coriacea E

Loggerhead Turtle Caretta caretta T

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There are 29 species of marine mammals that may be found in the Gulf of Mexico (see table). 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

Northern 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

Sperm Whale Physeter macrocephalus E

Spinner Dolphin (Long-snouted) Stenella longirostris

Striped Dolphin Stenella coeruleoalba

West Indian manatee Trichechus manatus E

The EIA found in Attachment 18 discusses potential impacts and mitigation measures related to threatened and 

endangered species. 

 

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Archaeological Report 

No archaeological resources were detected during the shallow hazards investigation for the proposed Hadrian-6 

exploration well. Per 30 CFR 250.194 (c), 250.1010(c), NTL 2008-G20 and NTL 2005-G07, if man-made debris 

suggestive of the presence of a shipwreck is observed, drilling operations with be stopped and reported 

immediately to BOEM. 

Prepared by: Scott Leonard, Operations Geology Supervisor – Site Investigation 

ExxonMobil Exploration Company 

ExxonMobil will comply with all conditions of NTL 2005-G07. 

Air and Water Quality Information 

Pursuant to NTL 2008-G04 the proposed operations covered by this REP do not require ExxonMobil to provide 

additional information relating to air and water quality information. For specific information relating to air and 

water quality information please refer to Section 18. 

Socioeconomic Information 

Pursuant to NTL 2008-G04 the proposed operations covered by this REP do not require ExxonMobil to provide 

additional information relating to air and water quality information. For specific information relating to 

socioeconomic information please refer Section 18. 

Public Information Copy
Proposed Hadrian-6 Well Location

92°3'30"W92°3'0"W92°2'30"W

26°5'30"N

26°5'0"N

1,950,0001,952,0001,954,0001,956,000

9,464,000

9,466,000

9,468,000

9,470,000

0 500 1,000 2,000 Feet

0 125 250 500 Meters

Chart Scale 1" = 1,000'

Seabed Amplitude Extract

Figure 3

(Hadrian-6)

±

Proposed Hadrian-6 Well Location

(1,952,286ft E, 9,467,323ft N)

3® 3

3

3

Relative Seabed Amplitude

2,000ft Radius

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