UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field 

Operations (MS 5231)

Public Information copy of DOCD

Control # - S-07652

Type - Supplemental Development Operations Coordinations Document

Lease(s) - OCS-G08035 Block - 574 Atwater Valley Area

OCS-G08038 Block - 618 Atwater Valley Area

Operator - BHP Billiton Petroleum (GOM) Inc.

Wells SB03 and SB03R

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

should be addressed in an Environmental Assessment.

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

Chiquita Hill

Plan Coordinator

G08035/AT/574

G08035/AT/574

1555 FNL, 5440 FEL

1589 FNL, 5390 FEL

G08038/AT/618

G08038/AT/618

WELL/SB03

WELL/SB03R

Site Type/Name Botm Lse/Area/Blk Surface Location Surf Lse/Area/Blk

Description -

Rig Type -

Subject:

From:

April 8, 2014
bhpbiUiton 

BHP Billiton Petroleum (GOM) Inc. 

1360 Post Oak Boulevard Suite 150 

Houston Texas 77056-3020 USA 

Tel 713 961 8500 Fax 713 499 5994 

www.bhpbllliton.com 

January 30, 2014 

Mr. Bob Sebastian 

Regional Supervisor for Leasing and Plans 

U.S. Department of the Interior 

Bureau of Ocean Energy IVIanagement 

1201 Elmwood Park Boulevard 

New Orleans, LA 70123-2394 

ATTN: Plans Unit 

RE: Supplemental Unit Development Operations Coordination Document (DOCD) 

Atwater Valley 574 Unit (Agreement No. 754395004) 

Lease OCS-G 08035, Atwater Valley Area, Block 574, Well SB003 

OCS Federal Waters, Gulf of Mexico, Offshore, Louisiana 

Gentlemen: 

In accordance with the provisions of Title 30 CFR 250 Subpart B, 550 Subpart B and further defined in 

Notice to Lessees (NTL) 2010-N06, 2009-G27 and 2008-G04 (extended by NTL 2014-G03, BHP Billiton 

Petroleum (GOM) Inc. (herein referred to as 'BHPB') hereby submits for your review and approval a 

Supplemental DOCD for the above referenced Unit. 

Enclosed are two (2) hard copies (One for Public Information and One for Proprietary Data) with one (1) 

CD for each. The State of Louisiana CZM does not require a review at this time. 

Under this Supplemental DOCD BHPB proposes to supplement the Initial DOCD Plan No. N-8542 by 

permitting two (2) additional wells, installing one (1) associated jumper and commencing production in the 

Atwater Valley Area, Block 574, Lease OCS-G 08035, Offshore, Louisiana. 

BHPB anticipates commencing drilling operations on May 1, 2014. 

Should additional information be required, please contact the undersigned at 713.599.6349. Please 

forward all approval documents to susan.wilson@bhpbilliton.com. 

Sincerely, 

Susan Wilson 

Senior Regulatory Specialist 

SW:JC 

Enclosures 

PUBLIC INFORMATION COPY
TABLE OF CONTENTS

SECTION 1:

CONTENTS OF PLAN.............................................................................................................................. 1 

Plan Information Form ................................................................................................................................ 2 

Bathymetry Map and Location Plat............................................................................................................. 2 

Safety and Pollution Prevention Features................................................................................................... 2 

Storage Tanks and Production Vessels........................................................................................................ 3 

Service Fees ................................................................................................................................................ 4 

Pollution Prevention Measures to Prevent Discharge of Oils and Greases during Rainfall and Routine 

Operations................................................................................................................................................... 4 

Safety, Pollution Prevention and Early Spill Detection Measures............................................................... 4 

SECTION 2:

GENERAL INFORMATION ...................................................................................................................... 5 

Applications and Permits............................................................................................................................. 5 

Drilling Fluids............................................................................................................................................... 5 

Peak Production Rates / Life of Reserves.................................................................................................... 5 

Oil Characteristics........................................................................................................................................ 5 

New or Unusual Technology ....................................................................................................................... 5 

Bonding Information ................................................................................................................................... 5 

Oil Spill Financial Responsibility (OSFR)....................................................................................................... 6 

Deepwater Well Control Statement ........................................................................................................... 6 

Suspensions of Production.......................................................................................................................... 6 

Blowout Scenario ........................................................................................................................................ 6 

Chemical Products ...................................................................................................................................... 9 

SECTION 3:

GEOLOGICAL AND GEOPHYSICAL INFORMATION................................................................................. 10

Geological Description .............................................................................................................................. 10

Structure Contour Maps ........................................................................................................................... 11

Interpreted 2-D or 3-D Seismic Lines ........................................................................................................ 11

Geological Structure Cross-Sections ......................................................................................................... 11

Shallow Hazards Report ............................................................................................................................ 11

Site Specific Shallow Hazards Assessment ............................................................................................... 11

High Resolution Seismic Lines .................................................................................................................. 12

PUBLIC INFORMATION COPY
Stratigraphic Column ................................................................................................................................ 12

Time Versus Depth Table .......................................................................................................................... 12

Geochemical Information ......................................................................................................................... 12

Future G&G Activities ............................................................................................................................... 12

SECTION 4:

HYDROGEN SULFIDE INFORMATION ................................................................................................... 13

Concentration ........................................................................................................................................... 13

Classification Request ............................................................................................................................... 13

Contingency Plan ...................................................................................................................................... 13

Modeling Report ....................................................................................................................................... 13

SECTION 5:

MINERAL AND RESOURCE CONVERSATION INFORMATION ................................................................. 14

Technology and Reservoir Engineering Practices and Procedures .......................................................... 14

Technology and Recovery Practices and Procedures ............................................................................... 14

Reservoir Development ............................................................................................................................ 14

SECTION 6:

BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION ........................................................... 15

Chemosynthetic Communities Report ..................................................................................................... 15

Topographic Features Map ....................................................................................................................... 15

Topographic Features Statement ............................................................................................................ 15

Live Bottom (Pinnacle Trend) Map ........................................................................................................... 15

Live Bottom (Low Relief) Map .................................................................................................................. 15

Potentially Sensitive Biological Features .................................................................................................. 15

ROV Monitoring Survey Plan .................................................................................................................... 16

Threatened and Endangered Species Information ................................................................................... 16

Archaeological Report .............................................................................................................................. 17

Air and Water Quality Information .......................................................................................................... 17

Socioeconomic Information ..................................................................................................................... 17

SECTION 7: 

WASTE AND DISCHARGE INFORMATION ............................................................................................ 18

Projected Generated Wastes ................................................................................................................... 18

Projected Ocean Discharges ..................................................................................................................... 18 

Modeling Report ....................................................................................................................................... 18 

NPDES Permits ......................................................................................................................................... 18 

PUBLIC INFORMATION COPY
Cooling Water Intakes .............................................................................................................................. 18 

SECTION 8:

AIR EMISSIONS INFORMATION .......................................................................................................... 19 

Screening Checklist ................................................................................................................................... 19 

Summary Table(s) of Plan Emissions ......................................................................................................... 19 

SECTION 9:

OIL SPILL INFORMATION .................................................................................................................... 20

Site Specific OSRP...................................................................................................................................... 20

Regional or Sub-Regional OSRP Information............................................................................................. 20

Spill Response Sites................................................................................................................................... 20

OSRO Information ..................................................................................................................................... 20

Worst Case Scenario Determination......................................................................................................... 21

NTL 2010-NO6- WCD Calculations Overview ............................................................................................ 21

Oil Spill Response Discussion / NEPA Analysis .......................................................................................... 22 

Modeling Report........................................................................................................................................ 22 

SECTION 10: 

ENVIRONMENTAL MONITORING INFORMATION ................................................................................ 23 

Monitoring Systems .................................................................................................................................. 23 

Incidental Takes......................................................................................................................................... 23 

Flower Garden Banks National Marine Sanctuary ................................................................................... 23 

SECTION 11:

LEASE STIPULATIONS INFORMATION .................................................................................................. 24 

SECTION 12: 

ENVIRONMENTAL MITIGATION MEASURES INFORMATION ................................................................ 25 

Impacts to Marine & Coastal Environments & Habitats, Biota, and Threatened & Endangered Species 25 

Incidental Takes......................................................................................................................................... 25 

SECTION 13: 

DECOMMISSIONING INFORMATION ................................................................................................... 26 

SECTION 14: 

RELATED FACILITIES AND OPERATIONS INFORMATION ....................................................................... 27 

Related OCS Facilities and Operations ..................................................................................................... 27 

Transportation System ............................................................................................................................. 27 

Produced Liquid Hydrocarbons Transportation Vessels .......................................................................... 27 

SECTION 15: 

SUPPORT VESSELS AND AIRCRAFT INFORMATION .............................................................................. 28 

PUBLIC INFORMATION COPY
General ...................................................................................................................................................... 28 

Diesel Oil Supply Vessels .......................................................................................................................... 28 

Drilling Fluids Transportation ................................................................................................................... 28 

Solid and Liquid Wastes Transportation ................................................................................................... 28 

Vicinity Map .............................................................................................................................................. 28 

SECTION 16: 

ONSHORE SUPPORT FACILITIES INFORMATION ................................................................................... 29

General ..................................................................................................................................................... 29 

Support Base Construction or Expansion.................................................................................................. 29 

Support Base Construction or Expansion Timetable ................................................................................ 29 

Air Emissions ............................................................................................................................................. 29 

Unusual Solid and Liquid Wastes ............................................................................................................. 29 

Waste Disposal ......................................................................................................................................... 29 

SECTION 17: 

SULPHUR OPERATIONS INFORMATION .............................................................................................. 30

SECTION 18: 

COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION ............................................................... 31

Consistency Certification .......................................................................................................................... 31

Other Information ..................................................................................................................................... 31

SECTION 19: 

ENVIRONMENTAL IMPACT ANALYSIS (EIA) ......................................................................................... 32 

Impact Producing Factors (IPFs) from the Proposed Activities ................................................................ 32 

Analysis ..................................................................................................................................................... 33 

Environmental Hazards ............................................................................................................................ 40

Alternatives ............................................................................................................................................... 41

Mitigation Measures ................................................................................................................................ 41

Consultation ............................................................................................................................................. 41

Preparer(s) ................................................................................................................................................ 41

References ................................................................................................................................................ 41

SECTION 20: 

ADMINISTRATIVE INFORMATION ....................................................................................................... 43 

Exempted Information Description (Public Information Copies Only) ..................................................... 43 

Bibliography .............................................................................................................................................. 43 

PUBLIC INFORMATION COPY
Plan Attachments

Attachment A Plan Information Forms 

Attachment B Well Location Maps 

Attachment C Bathymetry Map

Attachment D Pay.gov Service Fee

Attachment E Structure Map

Attachment F Cross Section

Attachment G Seismic 

Attachment H Solid and Liquid Wastes Transportation

Attachment I Air Emissions

Attachment J NEPA Spill Response Discussion

Attachment K Subsea Tree Drawing

Attachment L Vicinity Map 

Attachment M Worst Case Discharge

 

 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 1 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

Supplemental Unit Development Operations Coordination Document (DOCD) 

For

Atwater Valley 574 Unit Agreement No. 754395004 

Blocks 574, 575 and 618

Leases OCS- G 08035, 08036 and 08038

Offshore Louisiana

SECTION 1 - CONTENTS OF PLAN

Under this Supplemental DOCD BHP Billiton Petroleum (GOM) Inc. (herein referred to as BHPB) is 

submitting the following information as a Supplement to the Initial DOCD (Control No. N-08542) granted 

to BHPB on May 3, 2006 to install a TLP (Platform A) and the infrastructure to produce several subsea 

wells. 

BHPB proposes to supplement the DOCD as follows: 

• Drill and complete Subsea Well SB003 to a proposed bottom hole located in Block 574 – 

the surface will be located adjacent to the existing sled and existing Wells SB001 and SB002 in 

Block 618

 

• Install one (1) jumper from the proposed SB003 well to the existing inline sled

• Commence production by May 1, 2014

• BHPB is requesting approval for an additional well (to be designated SB003 (Respud)) in the 

event an issue arises during drilling of the riserless portion of SB003.

The following is a history of the wells approved under Initial and Supplemental Plans:

Initial DOCD – Plan N-8542 – approved May 3, 2006

Well Name Complete Date Production Start

Date Status 

TLP “A”

SA001 See Remarks Permanently Abandoned

SB001ST01 02/19/2008 07/21/2008 Producing

SC001ST03 11/30/2007 07/10/2008 Producing

SC002 07/04/2007 07/07/2008 Producing

SC003 08/15/2007 07/08/2008 Producing

SD001 10/10/2007 08/10/2008 Presently being TA’d

SD001ST01 See Remarks Not drilled yet

SD002 See Remarks Not drilled yet

Revised DOCD – Plan R-4376 – approved November 30, 2006 to revise air emissions for lease term 

pipelines.

Supplemental DOCD – Plan S-7198 – approved June 3, 2008

Well Name Complete Date Production Start 

Date Status 

SC004 05/10/2008 07/17/2008 Producing

Supplemental DOCD – Plan S-7343 – approved August 29, 2009

Well Name Complete Date Production Start 

Date Status 

SB002 09/16/2009 12/21/2009 Producing

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 2 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

Supplemental DOCD – Plan S-7463 – approved September 11, 2011

Well Name Complete Date Production Start 

Date Status 

E001 Not Drilled Yet

E002 Not Drilled Yet

F001 Not Drilled Yet

F002 Not Drilled Yet

SA01ST01 P&A’d

Supplemental DOCD – Plan S-7614 – in review

Well Name Complete Date Production Start 

Date Status 

SS003 Not Drilled Yet

(a) Plan Information Form 

 

An OCS Plan Information Form (BOEM-137) with details of the proposed drilling and completion 

operations and jumper installation along with BHPB’s tentative schedule leading up to commencement of 

production is included as Attachment A. 

The proposed well(s) will be drilled with either a DP drill ship (CRL) or a DP semi-submersible (Invictus) 

using subsurface BOPs. There will be no anchors associated with the operations proposed in this Plan.

(b) Bathymetry Map and Location Plat 

The Well Location Plats along with a Bathymetry Map are included as Attachments B and C, 

respectively. The location plats illustrate the existing and proposed surface and bottomhole locations of 

the wells addressed in this Plan.

BHP Billiton proposes to utilize dynamically-positioned drilling vessels; therefore, there will be no anchors 

associated with this activity.

(c) Safety and Pollution Prevention Features

The proposed wells addressed in this Plan will be drilled with the either a DP drillship or a DP semisubmersible using subsurface BOPs. 

Safety features on the MODU will include well control, pollution prevention, welding procedure, and 

blowout prevention equipment as described in the following Federal Register Notices, Notice to Lessees 

(NTL) and Subparts located in Title 30 CFR Part 250:

• Federal Register, Vol. 77, No. 163, August 22, 2012, Final Rule for Increased Safety Measures 

for Energy Development on the Outer Continental Shelf

• Federal Register, Vol. 75, No. 198, October 14, 2010, Final Rule for Increased Safety Measures 

for Energy Development on the Outer Continental Shelf

• NTL 2010-N06 for Information Requirements for Exploration Plans, Development and Production 

Plans, and Development Operations Coordination Documents on the OCS

• NTL 2010-N10 for Statement of Compliance with Applicable Regulations and Evaluation of 

Information Demonstrating Adequate Spill Response and Well Containment Resources

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 3 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

These regulations may be further clarified by Safety Alerts, and current policy making invoked by the 

Bureau of Ocean Energy Management, Regulation and Enforcement (BOEM), Environmental Protection 

Agency (EPA) and the U.S. Coast Guard (USCG). 

The appropriate life rafts, life jackets, ring buoys, etc., as prescribed by the U.S. Coast Guard will be 

maintained on the MODU at all times.

BSEE is required to conduct 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. 

BSEE also inspects the stockpiles of equipment listed in the Operator's approved Oil Spill Response Plan 

that would be used for the containment and cleanup of hydrocarbon spills and is further addressed in the 

“Oil Spill Information” section of this Plan.

In accordance with Title 30 CFR 250.1501, the goal of our training program is safe and clean OCS 

operations. To accomplish this, BHPB ensures that our employees and contractor personnel engaged in 

well control understand and can properly perform their duties.

Supervisory and certain designated personnel on-board the facility are to be familiar with the effluent 

limitations and guidelines for overboard discharges into the receiving waters, as outlined in the EPA’s 

NPDES General Permit GMG290000. Some of these pollution prevention measures include installation of 

curbs, gutters, drip pans, and drains on drilling deck areas to collect all contaminants and debris. 

All discharges related to the operations proposed in this Plan are covered under EPA’s NPDES General 

Permit referenced above. BHPB’s permit number is GMG290184.

(d) Storage Tanks and Production Vessels

Tanks with a capacity of 25 bbls or more of oil as defined at 30 CFR 254.6 is listed below:

Type of Storage 

Tank Type of Facility Tank Capacity (bbls)

Number of 

Tanks

Total Capacity 

(bbls)

Fluid Gravity 

(API)

Lube Oil Tank P / S Drillship – CRL 661 2 1322 29-39o

Dirty Oil Tank AFT Drillship – CRL 296 1 296 29-39o 

Dirty Oil Tank FWD Drillship – CRL 69 1 69 29-39o 

Diesel Oil Drillship – CRL

8549(2); 7906(2); 

3736(2); 2665(2); 

290(2); 775(4)

12 49,392 29-39o

Base Oil Drillship – CRL 3541 1 3541 29-39o 

Type of Storage 

Tank Type of Facility Tank Capacity (bbls) Number of Tanks

Total Capacity 

(bbls)

Fluid Gravity 

(API)

Lube Oil Tank P / S Drillship – Invictus 371; 123; 183; 164 4 842 24-26o 

Dirty Oil Tank Drillship – Invictus 48; 658; 243 3 949 29-39o 

Diesel Oil Drillship – Invictus

14,960; 14,268(2); 

1,336; 1,413(2); 1,336; 

1,145(2)

9 51,285 35o

Base Oil Drillship – Invictus 5,058; 398 2 5,455 33o 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 4 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(e) Service Fees

In accordance with 30 CFR 550.125 (a) BHPB has used the following table showing the fees that must be 

paid to BOEM for the activity proposed in this Plan. The fees will be adjusted periodically according to 

the Implicit Price Deflator for Gross Domestic Product by publication of a document in the Federal 

Register. If a significant adjustment is needed to arrive at the new actual cost for any reason other than 

inflation, then a proposed rule containing the new fees will be published in the Federal Register for 

comment.

Service Fee Table

Service — processing of the following: Fee amount 30 CFR citation

Supplemental Development Operations 

Coordination Document (DOCD)

$4,238 per well §550.211(d)

[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006; 72 FR 25199, May 4, 2007; 73 FR 49946, Aug. 25, 2008; 75 FR 20288, Apr. 

19, 2010]

A copy of the receipt for payment of the above referenced fee(s) accompanies the submission of this 

document as Attachment D. It is our understanding that once a fee is paid, it is nonrefundable, even if 

an application or other request is withdrawn. If our application is returned as incomplete, we are not 

required to submit a new fee if and when we submit an amended application.

(f) Pollution Prevention Measures to Prevent the Discharge of Oils and Greases 

during Rainfall and Routine Operations 

Supervisory and certain designated personnel on-board the MODU and / or the facility are to be familiar 

with the effluent limitations and guidelines for overboard discharges into the receiving waters, as outlined 

in EPA’s NPDES General Permit GMG290000. 

Some of these pollution prevention measures include installation of curbs, gutters, drip pans, and drains 

to collect all contaminants and debris to prevent the discharge of oils and greases from drilling rigs or 

platforms during rainfall and routine operations.

BHPB will utilize the best management practices available for ensuring all operations are performed in a 

safe and workmanlike conduct in accordance with 30 CFR 250.107 and will ensure that our employees 

and contractor personnel engaged in our offshore drilling operations understand the state and federal 

regulations.

All discharges related to the operations proposed in this Plan are covered under EPA’s NPDES General 

Permit referenced above. BHPB’s permit number is GMG290184.

(g) Safety, Pollution Prevention, and Early Spill Detection Measures

In accordance with the provisions of Title 30 CFR Parts 254.2(b), 254.23, 254.24, 254.25 and 254.26(d) 

and as further defined by Notice to Lessees (NTL) 2010-N10, BHPB submitted for review and BOEM has 

accepted a proposed Containment Plan which outlines the response to a complete loss of well control. 

BHPB is a member of the Marine Well Containment Company (MWCC). At this time, MWCC is the 

containment response system of choice for BHPB’s exploration project.

These are also addressed above in Sections (c) and (f). 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 5 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 2 - GENERAL INFORMATION

(a) Applications and Permits

Application / Permit Issuing Agency Status 

APD BSEE District To be submitted via eWell

Supplemental DWOP BSEE Region In preparation

Lease Term Pipeline BSEE Region In preparation

Surface Safety Systems BSEE District In preparation

Notice of Intent to Discharge EPA Region 6 In preparation

Surface Commingle BSEE Region In preparation

(b) Drilling Fluids 

(1) The following table provides information on the types and amounts of the drilling fluids BHPB plan

to use during drilling operations.

Type of Drilling Fluid Estimated Volume of Drilling Fluid to be Used 

Water-based (SW, FW, Barite) 28,216 bbls

Oil-based (diesel, mineral oil) NA

Synthetic-based (internal olefin, ester, etc) 2,070 bbls

(i) Since BHPB does NOT intend to use oil-based drilling fluid (as shown above) then the 

table of major components is not required at this time.

(ii) Material Safety Data Sheets (MSDS) are not required at this time. 

(c) Peak Production Rates / Life of Reserves

PROPRIETARY DATA

(d) Oil Characteristics 

There is no change to the information previously submitted with the Initial DOCD (Control No. N-08542).

(e) New or Unusual Technology

BHPB does not propose the use of any new or unusual technology in the development activities proposed 

under this plan.

(f) Bonding Information 

The bond requirements for the activities and facilities proposed in this Supplemental Plan are satisfied by 

an area-wide bond furnished and maintained according to 30 CFR Part 256, Subpart I; NTL No. 2000-

G16, “Guidelines for General Lease Surety Bonds”; and National NTL No. 2008-N07, “Supplemental 

Bond Procedures”.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 6 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(g) Oil Spill Financial Responsibility (OSFR)

BHPB (BOEM Operator No. 02010) has demonstrated oil spill financial responsibility for the facilities 

proposed in this Supplemental Plan 30 CFR Part 253, and NTL No. 2008-N05, “Guidelines for Oil Spill 

Financial Responsibility for Covered Facilities”.

(h) Deepwater Well Control Statement

BHPB (BOEM Operator No. 02010) has the financial capability to drill a relief well and conduct other 

emergency well control operations. 

(i) Suspensions of Production

At this time there are no approved or anticipated suspensions of production needed to hold the leases or 

unit involved with our DOCD.

(j) Blowout Scenario

The proposed wells will penetrate the objective, hydrocarbon bearing sands with a 12-1/4-inch drilling 

assembly below the 13-5/8-inch intermediate casing string. It is assumed that a hydrocarbon influx is 

taken while tripping out of the hole, and subsequently an uncontrolled well control event occurs in which 

the BOPs fail to function as designed and subsequently the marine riser fails. The end result is an 

uncontrolled blowout at the sea floor.

The expected spill rate for this scenario would be 101,730 STB/Day of 22.9o API gravity oil (initial oil rate). 

It is assumed that the well will not bridge over and will continue to flow until the well is either capped by 

subsea containment devices or is killed via a relief well. Due to the complex nature of the flux calculation 

and mechanical earth modeling, BHPB considers that it is not possible to predict with certainty if the open 

hole section will collapse and bridge off. BHPB has two (2) rigs contracted and working in the Gulf of 

Mexico that are capable of drilling in 7,500ft of water if a relief well is required. It is estimated that it would 

take 10 days to acquire a rig and move onto location with approximately 90 days to drill the relief well 

and perform kill operations, for a total of 100 days.

Based on 100 days, the estimated cumulative discharge volume is 10.173 MMSTB oil.

Relief Rig Availability

BHPB has a Master Service Agreement (MSA) with Transocean Ltd. that will allow access to the multiple 

rigs of opportunity operating in the Gulf of Mexico. 

The rigs listed below are currently contracted in GOM:

Rig Name Contractor Contractor Rated Water 

Depth (ft) MODU Type Rig Status

Discoverer Americas Transocean 12,000 DP Drill Ship Contracted GOM

C.R. Luigs Transocean 10,000 DP Drill Ship Contracted GOM

Discoverer Deep Seas Transocean 10,000 DP Drill Ship Contracted GOM

Ensco 8500 ENSCO 8,500 DP Semisubmersible Contracted GOM

Ensco 8501 ENSCO 8,500 DP Semisubmersible Contracted GOM

Ensco 8502 ENSCO 8,500 DP Semisubmersible Contracted GOM

West Sirius Seadrill 10,000 DP Semisubmersible Contracted GOM

Maersk Developer Maersk 10,000 DP Semisubmersible Contracted GOM

Danny Adkins Noble 12,000 DP Semisubmersible Contracted GOM

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 7 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

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PROPRIETARY DATA REV 3-1-2014
BHP Billiton Petroleum (GOM) Inc. 8 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

The BOP stacks on the C.R. Luigs and Invictus rigs are both six (6) ram stacks configured to provide 

enhanced well control and emergency response capability, including dual blind shear rams, casing shear 

rams, and three variable bore pipe rams. Procedures pertinent to these BOP configurations are well 

established and familiar to the drillers, tool pushers, and BHPB Drilling Supervisors.

Likelihood for Surface Intervention to Stop the Blowout

The likelihood for surface intervention to stop the blowout is high.

The 13-5/8” intermediate long string will design for a full column of oil to the mudline. As a result, it would 

be possible to install a containment device (such as a capping stack) which would subsequently allow for 

the blowout to be stopped.

BHPB has standardized the BOP wellhead connector for both of its contracted MODU’s, the Invictus and 

the C.R. Luigs, to ensure that either rig is capable of latching onto an existing BHPB wellhead.

Plans for Effective and Early Intervention

Both rigs contracted by BHPB have a Deadman / Autoshear which will function in the event of a LMRP 

disconnect or a loss of both hydraulic pressure and electrical communication with the BOP control system 

on surface.

“Surface” deployment of ROVs to close any open BOPs which could affect well closure:

• The ROV panel will be tested subsea with the BOP on a wellhead.

• BHPB has upgraded the pump skid on the rigs’ ROV’s with a more powerful pump capable of 

producing higher flow rates. Additionally, the receptacles have been changed to allow for more 

flow rate to reduce closing times.

• BHPB has designed, built, tested and deployed dedicated subsea accumulator banks to the 

seafloor to further improve the ROV closure response times.

BHPB is a member of the Marine Well Containment Company (MWCC) group, which maintains capping 

and well control equipment for its member companies.

Relief Well Arrangements

Suitable surface locations for a relief well would fall within the stand-off zone defined by a 5000’ radius 

with its center at the AT 574 SB003 surface location. Shallow hazards analysis indicates favorable relief 

well locations within this area provided that existing infrastructure, localized areas of steep seafloor slope, 

and scattered gas anomalies are avoided. 

The well design should reflect the original well, depending on the root cause of the blowout.

KEY RIG SPECIFICATIONS FOR RELIEF WELL

RIG NAME INVICTUS C.R. LUIGS

RIG TYPE

DSME 12000 TBN #1 MODU 

rated for 12,000 ft water depth, 

Dynamically Positioned

5th Gen MODU rated for 10,000 

ft water depth, dynamically 

positioned

BOP Size & Pressure 

Rating: 18.75 – 15,000 psi 18.75 - 15,000 psi

Max Hookload (kips): 2,800 kips 1,800 kips

Drawworks Power (hp): 9,000 hp 5,000 hp

 Mud Pumps Power & Pressure 

(hp/psi): 

4x AKMH Wirth model TPK-7-1/2 

pumps with 2,200 hp, 7,500 psi 

working

4 x 14-P-220 NOV pumps with 

2,200 7,475 psi working

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 9 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

Mud Pit Volume (bbls): 20,000 bbls 13,267 bbls

Variable Loading (kips): 50,706 kips NA- Drill Ship

Top Drive Power & Torque 

(hp/ftlbs): Aker MH MDDM-1250-AC-2M NOV TDS-4 

Dry Bulk Storage Capacity (cu. 

ft): Total Bulk 28,250 cuft Total Bulk 27,000 cuft

Other Measures Taken

Prior to drilling BHBP will have readily available all of the materials and equipment needed to spud, drill, 

case and cement a relief well. 

BHPB has established commercial relationships with those suppliers of contingency equipment and 

services that we have identified as necessary to kill a blown out well.

(k) Chemical Products

This information is not required for the activities proposed in this plan in the BOEM GOMR.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 10 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 3 - GEOLOGICAL AND GEOPHYSICAL INFORMATION

In accordance with 43 CFR Part 2, Appendix B, those items considered proprietary have been omitted 

from the Public Information copy and have been referenced accordingly.

(a) Geological Description

PROPRIETARY DATA

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 11 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(b) Structure Contour Maps 

Enclosed as Attachment E are current structure maps drawn to the top of the proposed water injection 

zone(s). The surface and bottom hole location(s) along with the locations of the geologic cross-sections 

of the well(s) to be injected into under this Supplemental DOCD are included.

(c) Interpreted 2-D or 3-D Seismic Lines 

Enclosed as Attachment G is a copy of the migrated and annotated deep seismic line within 500 feet of 

Well SB003. 

(d) Geological Structure Cross-Sections 

An interpreted geological cross-section showing the location and depth of each existing and proposed 

well(s) with at least one key horizon and the objective sand labeled is enclosed as Attachment F. 

(e) Shallow Hazards Report 

Numerous shallow hazards reports have been issued to address seafloor and shallow geologic conditions 

pertinent to drilling wells and installing facilities in the Neptune Field. Following are brief descriptions of 

the reports pertinent to this Supplemental Plan:

A report titled “Neptune Prospect, Atwater Valley Blocks 574, 575, 618, OCS-G-8035, OCS-G-8036, 

OCS-G-8038, Shallow Drilling Hazards Assessment, Supplemental Locations K, L, M, N, and O” was 

prepared by Robert J. Bruce (Consulting Geophysicist) in November 2003. This report was submitted in 

support of a Supplemental EP (Control No. S-6324).

A report titled “Pre-Feasibility Geohazards Assessment, Neptune Development, Atwater Valley and Green 

Canyon Areas, Gulf of Mexico” was issued by Fugro GeoServices in August 2004. This report delineated 

seafloor and shallow soil conditions pertinent to field development based primarily on a high-resolution 

Autonomous Underwater Vehicle (AUV) geophysical survey acquired by C&C Technologies in February 

2004. This report has been submitted with previously reviewed plans and/or permit applications.

A report titled “Multidisciplinary Geologic / Geotechnical Engineering Report, Neptune Field Development, 

Green Canyon & Atwater Valley Areas, Gulf of Mexico” was issued by Geoscience Earth & Marine 

Services in January 2006. This report integrated results from piston coring and soil boring geotechnical 

investigations with the AUV, HR2D, and 3D geophysical surveys to identify potential geohazards and 

engineering constraints pertinent to the Neptune Field development. This report has been submitted with 

previously reviewed plans and/or permit applications.

Since the proposed activity will be within 500 feet of a previously approved surface location, these reports 

are not attached with this plan. Copies of these reports are available upon request.

(f) Site Specific Shallow Hazards Assessment 

Since the proposed well is within 500 feet of a previously approved surface location (Location K), a 

shallow hazard assessment is not required at this time. An assessment was previously submitted and 

reviewed under the Supplemental EP (Control No. S-6324) for Locations K, L, M, N and O (see report 

description above).

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 12 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(g) High Resolution Seismic Lines 

3-D Seismic Data. The 3D seismic data used are from the Western Geophysical Ultra Survey Atwater 

Phase 5. The full-fold migrated 3-D volume contains 4-msec sample rate data at a bin spacing of 41.0 x 

65.6 ft (12.5 m x 20 m). The data were enhanced with spectral whitening and coherency filtering and have 

an overall bandwidth of 7–75 Hz. The data are relative amplitude processed for hydrocarbon detection. 

Locally, 3D seismic amplitude response is attenuated at depth in proximity to the seaward limit of the 

Sigsbee Salt. Pre-stack depth migrated data based on this survey have also been used to help 

understand the structural setting for the Neptune Field. More information on this survey can be accessed 

at: http://www.multiclient.westerngeco.com/NavPDFs/ultra_surveys11.pdf.

(h) Stratigraphic Column 

This information is not required for DOCD’s.

(i) Time Versus Depth Tables 

This information is not required for DOCD’s.

 

(j) Geochemical Information

This information is not required for the activities proposed in this plan in the BOEM GOMR.

(k) Future G&G Activities

This information is not required for the activities proposed in this plan in the BOEM GOMR.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 13 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 4 - HYDROGEN SULFIDE INFORMATION

(a) Concentration

BHPB does not anticipate encountering H2S while conducting our proposed development activities.

(b) Classification Request

In accordance with Title 30 CFR 250.490(c), BHPB requests the area of operations in Atwater Blocks 

574/618, Lease OCS-G 08035 and 08038, be classified by the BOEM as an area where the “absence” of 

Hydrogen sulfide has been confirmed based upon the following:

Correlative Wells for H2S Information:

• Neptune-5 (AT574#2; OCS-G = 8035; API = 608184004400)

• Neptune-7 (AT618#2; OCS-G = 8038; API = 608184004600)

• SC02 (AT574#3; OCS-G = 8035; API = 608184006300)

(c) Contingency Plan 

BHPB does not anticipate encountering H2S while conducting our proposed development activities 

therefore a contingency plan is not required at this time.

(d) Modeling Report 

BHPB does not anticipate encountering H2S while conducting our proposed development activities 

therefore a modeling report is not required at this time.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 14 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 5 - MINERAL AND RESOURCE CONVERSATION INFORMATION

(a) Technology and Reservoir Engineering Practices and Procedures

Performance of the targeted XXX reservoir is anticipated to be similar to the southern portion of the field, 

which has been producing since July 2008. The recovery method will be depletion drive, aided by 

relatively high rock compressibility (20 – 22 msips) and potential aquifer support. Various scenarios of gas 

and water injection have been modeled with numerical simulation, resulting in small incremental 

recoveries that were uneconomic. Continued monitoring of field performance and history matching will be 

used to determine if a secondary recovery method should be implemented as part of the overall reservoir

management plan, forming part of a future update to the Neptune DOCD.

(b) Technology and Recovery Practices and Procedures 

Optimum well positioning, trajectory planning and completion design will all be utilized to maximize

recovery from primary depletion. Producing wells are connected to a piggable flowline loop that is capable 

of directing flow in either direction, back to the Neptune TLP in GC-613 Block. This provides flexibility for 

re-starts, flow assurance, well start-up, and system pressure optimization for maximum recovery of 

reserves.

(c) Reservoir Development

PROPRIETARY DATA

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 15 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 6 - BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION

(a) Chemosynthetic Communities Report

NTL 2009-G40, effective January 27, 2009, broadened the scope of a chemosynthetic communities 

report to cover all high-density deepwater benthic communities (not just high-density chemosynthetic 

communities), changed the definition of deepwater from 400 meters (1,312 feet) to 300 meters (984 feet), 

increased the separation distance from muds and cuttings discharge locations from 1,500 feet to 2,000 

feet and provided for an additional 1,000-foot buffer area beyond maximum anchor areas. 

The seafloor disturbing activities proposed in the Supplemental Plan are in water depths greater than 300 

meters (984 feet); therefore, the information described in Attachment A of NTL No. 2009-G40 is required. 

As described above, the February 2004 Fugro GeoServices’ report titled “Pre-Feasibility Geohazards 

Assessment, Neptune Development, Atwater Valley and Green Canyon Areas, Gulf of Mexico” delineated 

seafloor features pertinent to field development. According to this Fugro GeoServices’ report and the 

Shallow Drilling Hazards Assessment conducted by Robert J. Bruce (Consulting Geophysicist) in 

November 2003 for Location K, there is no evidence for hydrocarbon seepage sites capable of supporting 

high-density benthic community development within 2000 feet of the proposed activity. These reports 

have been submitted with previously reviewed plans and/or permit applications.

There are no features or areas that could support high-density benthic communities within 2000 feet of 

the proposed surface location.

(b) Topographic Features Map 

There are no topographic features located on Atwater Valley 574. 

(c) Topographic Features Statement 

Since there are no topographic features located on Atwater Valley 574 the statement for shunting 

described in NTL No. 2009-G39 “Biologically Sensitive Underwater Features and Areas” is not required.

(d) Live Bottom (Pinnacle Trend) Map 

The activities proposed in this plan are not affected by a live bottom (Pinnacle Trend) stipulation attached 

to the lease.

(e) Live Bottom (Low Relief) Map 

The activities proposed in this plan are not affected by a live bottom (low relief) stipulation attached to the 

lease.

(f) Potentially Sensitive Biological Features

BHPB does not propose bottom-disturbing activities within 61 meters (200 feet) of potentially sensitive 

biological features; therefore the map described in NTL No. 2009-G39 “Biologically Sensitive Underwater 

Features and Areas” is not required.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 16 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(g) ROV Monitoring Survey Plan

BHPB is familiar with the ROV survey and reporting provisions of NTL 2008-G06 for “Remotely Operated 

Vehicles in Deepwater”. The wells proposed in this Supplemental Plan are located in Grid 13. Grid 13 has 

been identified by BOEM as an area with adequate ROV survey coverage.

(h) Threatened and Endangered Species Information

Congress passed the Endangered Species Act (ESA) on December 28, 1973, recognizing that the natural 

heritage of the United States was of “esthetic, ecological, educational, recreational, and scientific value to 

our Nation and its people.” It was understood that, without protection, many of our nation’s living 

resources would become extinct. The purpose of the ESA is to conserve threatened and endangered 

species and their ecosystems. There are more than 1,900 species listed under the ESA. A species is 

considered endangered if it is in danger of extinction throughout all or a significant portion of its range. A 

species is considered threatened if it is likely to become endangered in the future. The U.S. Fish and 

Wildlife Service (USFWS) and the National Marine Fisheries Service (NMFS) share responsibility for 

implementing the ESA. NMFS is responsible for 69 marine species, from whales to sea turtles and 

salmon to Johnson’s sea grass. 

The Marine Mammal Protection Act (MMPA) of 1972 was written to establish American federal 

responsibility to conserve marine mammals. Some species were in immediate danger of extinction while 

other populations were becoming severely depleted. 

Below is a list of endangered and threated species and critical habitats under the jurisdiction of NOAA 

Fisheries Service in the Gulf of Mexico:

Listed Species Scientific Name Status Date Listed

Marine Mammals

Blue Whale Balaenoptera Musculus Endangered 12/02/1970

Finback Whale Balaenoptera Physalus Endangered 12/02/1970

Humpback Whale Megaptera Novaeangliae Endangered 12/02/1970

Sei Whale Balaenoptera Borealis Endangered 12/02/1970

Sperm Whale Physeter Macrocephalus Endangered 12/02/1970

Turtles

Green Sea Turtle Chelonia Mydas Threatened1 07/28/1978

Hawksbill Sea Turtle Eretmochelys Imbricata Endangered 06/02/1970

Kemp’s Ridley Sea 

Turtle

Lepidochelys Kempii Endangered 12/02/1970

Leatherback Sea Turtle Dermochelys Coriacea Endangered 06/02/1970

Loggerhead Sea Turtle Caretta Caretta Threatened2 09/22/2011

Fish

Gulf Sturgeon Acipenser Oxyrinchus Desotoi Threatened 09/30/1991

Smalltooth Sawfish Pristis Pectinata Endangered 04/01/2003

Invertebrates

Elkhorn Coral Acropora Palmata Threatened 05/09/2006

Staghorn Coral Acropora Cervicornis Threatened 05/09/2006

1 Green turtles are listed as threatened, except for breeding populations of green turtles in Florida and on the Pacific Coast of Mexico, which are listed as endangered. 

2 Northwest Atlantic Ocean (NWA) Distinct Population Segment (DPS) was listed as threatened. NMFS and USFWS issued a final rule changing the listing of 

loggerhead sea turtles from a single, threatened species to nine DPSs listed as either threatened or endangered in 2012 (76 FR 58868). 

BHPB is aware of the above referenced federal acts and will ensure that all offshore personnel, including 

contractors and other support services-related personnel have an understanding of the need to conserve 

marine mammals and the conservation of their ecosystems. Several NTL’s were issued to address 

conservation measures to be taken by offshore operators and contractors. 

Further discussions on threatened and endangered species are included in Section 19 (EIA).

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 17 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(i) Archaeological Report

The Neptune Field is not located within an area designated to have a high probability for archaeological 

resources as defined by NTL No. 2005-G07 and 2011-JOINT-G01. However, BHP Billiton is aware of the 

Bureau of Ocean Energy Management’s (BOEM) March 2011 Pre-Seabed Disturbance Survey Mitigation 

and has submitted an archaeological assessment report issued by Geoscience Earth & Marine Services 

(GEMS) in February 2013 under separate cover (BOEM Survey No. 23658 received Feb. 27, 2013). 

None of the sonar contacts identified in the Neptune AUV survey area were recommended for 

archaeological avoidance or investigation.

(j) Air and Water Quality Information

The State of Florida is not an affected State for the activities proposed in this plan; therefore this 

information is not required.

(k) Socioeconomic Information

The State of Florida is not an affected State for the activities proposed in this plan; therefore this 

information is not required.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 18 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 7 - WASTE AND DISCHARGE INFORMATION

(a) Projected Generated Wastes

All projected solid and liquid wastes likely to be generated by our proposed activities are included in 

Attachment H (Table 1). This table includes both operational wastes permitted by the appropriate 

NPDES permit and any other identified wastes.

BHPB does not plan to treat, store or dispose of any of the above wastes down hole at our proposed 

drilling location.

(b) Projected Ocean Discharges

All projected solid and liquid wastes likely to be discharged overboard during our proposed activities are 

included in Attachment H (Table 1). This table includes both operational wastes permitted by the 

appropriate NPDES permit and any other identified wastes.

(c) Modeling Report

Not required by EPA under the OCS General Permit.

(d) NPDES Permits

This information is not required for the activities proposed in this plan in the BOEM GOMR.

(e) Cooling Water Intakes

This information is not required for the activities proposed in this plan in the BOEM GOMR.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 19 Atwater Valley Block 574/618 

Supplemental DOCD Lease OCS-G 08035/08038 

SECTION 8 - AIR EMISSIONS INFORMATION 

(a) Screening Checklist 

Included in this section, (if applicable) are the Projected Air Emissions Worksheets prepared in 

accordance with NTLs 2009-G27 and 2008-G04 (extended by NTL 2014-G03), associated with the 

Neptune Field. 

Screening Questions for DOCD’s Yes No 

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

activities more than 90% of the amounts calculated using the following formulas: CT = 3400D2/3 for CO, and 

CT = 33.3D for 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 

Does or will the facility complex associated with your proposed development and production activities process 

production from eight or more wells? 

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 in excess of the criteria set forth under 250.1105(a)(2) and (3) X 

Do you propose to burn produced hydrocarbon liquids? X 

Are your proposed development and production activities located within 25 miles from shore? X 

Are your proposed development and production activities located within 200 kilometers of the Breton 

Wilderness Area? X 

The following information was prepared by Trinity Consultants (614.433.0733), based upon drilling and 

completion information provided by BHP Billiton Petroleum Drilling group. 

(b) Summary Table of Plan Emissions 

Below are the Total Plan Emissions for well SB003. The Neptune TLP and proposed Well is not 

collocated activities. 

The planned emissions are associated with drilling and completing of the well(s) with either the drillship 

C.R. Luigs or the DP semi-submersible INVICTUS and installing flowline infrastructure. 

COMPANY AREA BLOCK LEASE PLATFORM WELL 

BHP Billiton Pet. 

(GOM) Inc. Atwater Valley 574 OCS-G 08035 NA SB003 (CRL) 

Year Emitted Substance 

 PM SOx NOx VOC CO 

2014 38.54 0.71 1187.68 47.27 294.22 

Allowable 3729.60 3729.60 3729.60 3729.60 78999.49 

COMPANY AREA BLOCK LEASE PLATFORM WELL 

BHP Billiton Pet. 

(GOM) Inc. Atwater Valley 574 OCS-G 08035 NA SB003 

(INVICTUS) 

Year Emitted Substance 

 PM SOx NOx VOC CO 

2014 77.34 1.23 1858.06 95.02 657.55 

Allowable 3729.60 3729.60 3729.60 3729.60 78999.49 

Detailed spreadsheets are included as Attachment I.

NOTE: There are six (6) diesel-fired main engines on Invictus manufactured by Hyundai Heavy 

Industries Co., Ltd. Each of these six engines is IMO Tier II certified per regulation 13.4 and rated at 

7000 kW power with 720 rpm speed. The International Air Pollution Prevention Certificates (IAPPCs) for 

these engines were obtained in Korea. Please find attached the supporting engine specification sheets 

and IAPPCs for the aforementioned six main engines on the Invictus as requested by BOEM included as 

Attachment I-1.
BHP Billiton Petroleum (GOM) Inc. 20 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 9 - OIL SPILL INFORMATION

(a) Oil Spill Response Planning

(1) Site-Specific OSRP

Lease OCS-G 08035 is not located in the Eastern Gulf of Mexico therefore a site-specific 

OSRP is not required.

(2)(i) Regional or Sub-Regional OSRP Information

BHP Billiton Petroleum (GOM) Inc. (Company No. 02010) has an approved Regional 

OSRP (No. O-43). 

The calculated WCD for Lease OCS-G 08035 does not supersede the Regional OSRP’s 

WCD.

All the proposed activities and facilities in this Supplemental DOCD will be covered by the 

Oil Spill Response Plan filed by BHP Billiton Petroleum (GOM) Inc. (Company No. 

02010) that was approved on November 21, 2013.

 

 (ii) Spill Response Sites 

 

The location of BHPB’s primary spill response equipment and the planned staging 

area(s) that would be used should we have an oil spill resulting from the activities 

proposed in our Supplemental Plan is provided in the table below:

Primary Response Equipment Location Preplanned Staging Location(s)

Port Fourchon or Houma, LA Port Fourchon, LA

 (iii) OSRO Information

BHPB’s primary equipment provider is Clean Gulf Associates (CGA). Clean Gulf 

Associates Services, LLC (CGAS) will provide closest available personnel, as well as a 

CGAS supervisor to operate the equipment.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 21 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(iv) Worst Case Scenario Determination

The calculated WCD for this Supplemental DOCD on Lease OCS-G 08035 does not

supersede the Regional OSRP’s WCD.

Category Regional 

OSRP

Supplemental 

DOCD 

Regional 

OSRP

Supplemental 

DOCD 

Type of Activity >10 Miles Drilling >10 Miles 

Drilling

>10 Miles 

Production

>10 Miles 

Production

Facility Location (area/block) GC 610 AT 574 GC 653 AT 574

Facility Designation2

Well SH103 ST01 Subsea Well 

E001 TLP “A” SB003

Distance to Nearest Shoreline (miles) 120 114 120 114

Volume3

 Storage tanks (total)

 Flowlines (on facility)

 Lease term pipelines

 Uncontrolled blowout (volume per day)

Total Volume

n/a

n/a

n/a

255,200 bbls

255,200 bbls*

n/a

n/a

n/a

101,730 bbls

101,730 bbls**

4,098 bbls

n/a

8,474 bbls

111,084 bbls

123,656 bbls

 

n/a

n/a

40 bbls

,ϭϮ͕ρ4 bbls

ϭϮ͕ρΘϬbbls

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

API Gravity(s)4 32.1° 22.9o 30o 20-23o 

*The Regional OSRP calculations and assumptions for blowout during drilling were previously submitted 

and accepted under Plan S-7487.

** The WCD for the Neptune Field was verified by BOEM and accepted via email to BHP on March 7, 

2011 under Plan S-7463.

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. Take your regional OSRP worst-case scenario volume from the appropriate section of your regional OSRP. For EP’s, the worst-case scenario 

volume is the daily volume possible from an uncontrolled blowout. Determine this volume using the provisions of 30 CFR 30 CFR 254.47(b). 

For DOCD’s, determine the volume of your worst-case scenario using the provisions of 30 CFR 30 CFR 254.47(a) or (b), as appropriate.

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

Since BHPB has the capability to respond to the appropriate worst-case spill scenario included in 

its regional OSRP approved on November 21, 2013, and since the worst-case scenario determined 

for our Supplemental DOCD does not replace the appropriate worst-case scenario in our regional 

OSRP, I hereby certify that BHPB has the capability to respond, to the maximum extent 

practicable, to a WCD, or a substantial threat of such a discharge, resulting from the activities 

proposed in our Supplemental DOCD.

NTL 2010-N06 – WCD Calculations Overview

BOEM reviewed and calculated a WCD of 101,730 BOPD under Supplemental DOCD Plan No. S-7463 in 

March 2011. The WCD volume for SB003 is 4 STB oil/day of 20-23o API gravity oil and does not 

supersede the WCD in BHPB’s approved OSRP. The estimated cumulative discharge volume after 100 

days is . MMSTB oil. Table 1 shows the expected WCD rates at day 1 and over the time taken to drill 

a relief well (up to 100 days).

Since the WCD for the Neptune Field was verified by BOEM and accepted via email to BHP on March 7, 

2011 under Plan S-7463, BHPB has only included the SB003 WCD for information purposes in 

Attachment M. 
BHP Billiton Petroleum (GOM) Inc. 22 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

(b) Oil Spill Response Discussion / NEPA Analysis

For the purpose of NEPA and Coastal Zone Management Act analysis, the largest spill volume originating 

from the proposed activity would be a well blowout during drilling operations, estimated to be 101,730

barrels of crude oil with an API gravity of 22.9°.

BHPB’s detailed spill response discussion is included as Attachment J. 

(c) Modeling Report

A modeling report for a potential oil or hazardous substance spill is not required for the activities proposed 

in this plan. In the event BHPB proposes to prepare such a report, we would contact the Regional 

Supervisor of the BOEM GOMR for guidance in preparing the report and the BOEM GOMR would be 

provided with two copies.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 23 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 10 - ENVIRONMENTAL MONITORING INFORMATION

(a) Monitoring Systems

BHPB is aware of the requirements of NTL No. 2009-G02 whereby BOEM established and implemented 

a program to monitor ocean currents and require operators to share the data for all floating MODU’s and 

production facilities operating or installed in water depths greater than 400 meters (1,312 feet). 

In the event BHPB were to monitor ocean currents during this operation, BHPB will report ocean current 

data to the National Oceanic and Atmospheric Administration (NOAA) National Data Buoy Center (NDBC) 

Internet website as required.

(b) Incidental Takes

BHPB does not believe that protected species may be incidentally taken during the development activities 

proposed in this plan.

(c) Flower Garden Banks National Marine Sanctuary

BHPB’s activity under this Plan is not located within the Protective Zones of the Flower Garden Banks or 

Stetson Bank and therefore is not required to monitor the impacts of an oil spill.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 24 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 11 - LEASE STIPULATIONS INFORMATION

Oil and gas exploration and development activities on the OCS are subject to stipulations developed 

before the lease sale and would be attached to the lease instrument, as necessary, in the form of 

mitigating measures. The MMS is responsible for ensuring full compliance with stipulations. 

The MMS did not invoke lease stipulations for Lease OCS-G 08035/08038, Atwater Valley Blocks 

574/618. 

Atwater Valley Blocks 574/618 is located within the boundaries of the Gulfmex No. 2 lightering zone. 

BHP Billiton will exercise caution while conducting the proposed activities within this area.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 25 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 12 - ENVIRONMENTAL MITIGATION MEASURES INFORMATION

(a) Impacts to Marine and Coastal Environments and Habitats, Biota, and Threatened 

and Endangered Species

The State of Florida is not an affected State for the activities proposed in this plan; therefore this 

information is not required.

(b) Incidental Takes

BHPB does not believe that any of the endangered species or marine mammals as listed in the 

ESA will be taken during the development activities proposed in this plan. 

BHPB understands that the use of explosives or seismic devices may affect marine life in the 

vicinity. There are no operations proposed in this plan that will be using explosives or seismic 

instruments.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 26 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 13 - DECOMMISSIONING INFORMATION

This information is not required for plans submitted in the BOEM GOMR.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 27 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 14 - RELATED FACILITIES AND OPERATIONS INFORMATION

(a) Related OCS Facilities and Operations

A subsea tree will be installed with the rig prior to leaving the location (Attachment K). A well 

jumper will be installed with an intervention vessel. 

Related OCS facilities and operations were discussed in depth in the Initial Unit DOCD (Plan No. 

N-8542). Under this Supplemental Unit DOCD BHPB proposes to install a sled with one (1) 

jumper, one (1) 6.625 inch flowline and associated 4 inch umbilical from the proposed SB003 well 

to one of two existing inline sleds (currently designated E and F)

Description of Lease Term Pipelines

Diameter 

(Inches) From To Length Product Max Flow SI Time

6 AT574 SB003 AT618 Jumper Hub 100’ Oil 2500 BOPD 45s

(b) Transportation System

Oil and gas production is exported via existing right-of-way pipelines to existing pipeline delivery 

systems. There will be no changes to the existing field infrastructure under this Supplemental 

Plan. 

(c) Produced Liquid Hydrocarbons Transportation Vessels

There will be no produced liquid Hydrocarbons, including well test fluids, transported by means 

other than a pipeline for the activities proposed in this plan. 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 28 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 15 - SUPPORT VESSELS AND AIRCRAFT INFORMATION

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PROPRIETARY DATA REV 3-1-2014
BHP Billiton Petroleum (GOM) Inc. 29 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 16 - ONSHORE SUPPORT FACILITIES INFORMATION

(a) General

BHPB proposes to utilize the following existing onshore base for support:

Name Location Existing, New or Modified

Chouest Base Port Fourchon, LA Existing

(1) Support Base Construction or Expansion

The proposed operations do not mandate any immediate measures for land acquisition or 

expansion of the existing onshore base facilities.

(2) Support Base Construction or Expansion Timetable

The proposed operations do not mandate any immediate measures for land acquisition or 

expansion of the existing onshore base facilities therefore a timetable is not required.

(b) Air Emissions

Information regarding air emissions generated by onshore support facilities is not required to accompany 

plans submitted in the BOEM GOMR.

(c) Unusual Solid and Liquid Wastes

Information regarding unusual solid and liquid wastes generated by onshore support facilities is not 

required to accompany plans submitted in the BOEM GOMR.

(d) Waste Disposal

All projected solid and liquid wastes likely to be disposed of during and after our proposed activities are 

included in Attachment H (Table 2). 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 30 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 17 - SULPHUR OPERATIONS INFORMATION

BHPB is not proposing to conduct sulphur operations in this plan.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 31 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 18 - COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION

The States of Texas, Louisiana, Mississippi, Alabama and Florida have federally approved coastal zone 

management programs (CZMP). Applicants for an OCS plan submitted to the BOEM must provide a 

certification with necessary data and information for the affected State to determine that the proposed 

activity(s) complies with the enforceable policies of each States’ approved program, and that such activity 

will be conducted in a manner consistent with the program.

(a) Consistency Certification

The Coastal Zone Management Consistency Certification from the State of Louisiana is not required for 

the development activities proposed in this Supplemental Plan. 

(b) Other Information

State of Louisiana: 

The enforceable policies of the State of Louisiana have been considered and will be complied with.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 32 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 19 - ENVIRONMENTAL IMPACT ANALYSIS (EIA)

(a) And (b) BHPB has placed an “X” in each IPF category that we believe (by using good 

engineering judgment) would be impacted by the activity proposed in this plan.

Environmental

Resources

Impact Producing Factors (IPFs) Categories and Examples

Emissions

(air, noise, 

light, etc.)

Effluents

(muds, cuttings, 

other 

discharges to 

the water 

column or 

seafloor)

Physical 

disturbances

to the seafloor

(rig or anchor 

emplacements, 

etc.)

Wastes 

sent to 

shore for 

treatment 

or 

disposal

Accidents

(e.g., oil 

spills, 

chemical 

spills, H2S 

releases)

Other 

IPFs you 

identify

Site-specific at Offshore 

Location

Designated topographic features (1) (1) (1)

Pinnacle Trend area live bottoms (2) (2) (2)

Eastern Gulf live bottoms (3) (3) (3)

Chemosynthetic communities (4) (4) (4)

Water quality X X X

Fisheries X X X

Marine mammals (8) X X (8) X

Sea turtles (8) X X (8) X

Air quality (9)

Shipwreck sites (known or 

potential) (7)

Prehistoric archaeological sites (7) 

Vicinity of Offshore Location

Essential fish habitat X (6) X

Marine and pelagic birds X X X

Public health and safety (5)

Coastal and Onshore

Beaches X (6) X

Wetlands (6) X

Shore birds and coastal nesting 

birds (6) X

Coastal wildlife refuges X

Wilderness areas X

Other Resources You Identify

 None

Footnotes for Environmental Impact Analysis Matrix

1. Activities that may affect a marine sanctuary or topographic feature. Specifically, if the well or platform site or any anchors will be on the seafloor 

within the:

(a) 4-mile zone of the Flower Garden Banks, or the 3-mile zone of Stetson Bank,

(b) 1000-m, 1-mile or 3-mile zone of any topographic feature (submarine bank) protected by the Topographic Features Stipulation attached to 

an OCS lease;

(c) Essential Fish Habitat (EFH) criteria of 500 ft from any no-activity zone; or

(d) Proximity of any submarine bank (500 ft buffer zone) with relief greater than 2 meters that is not protected by the Topographic Features 

Stipulation attached to an OCS lease.

2. Activities with any bottom disturbance within an OCS lease block protected through the Live Bottom (Pinnacle Trend) Stipulation attached to an 

OCS lease.

3. Activities within any Eastern Gulf OCS block where seafloor habitats are protected by the Live Bottom (Low-Relief) Stipulation attached to an 

OCS lease.

4. Activities on blocks designated by the BOEM as being in water depths 400 meters or greater.

5. Exploration or production activities where H2S concentrations greater than 500 ppm might be encountered.

6. All activities that could result in an accidental spill of produced liquid hydrocarbons or diesel fuel that you judge would impact these environmental 

resources. If the proposed action is located a sufficient distance from a resource that no impact would occur, the EIA can note that in a sentence 

or two. 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 33 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

7. All activities that involve seafloor disturbances, including anchor emplacements, in any OCS block designated by the BOEM as having highprobability for the occurrence of shipwrecks or prehistoric sites, including such blocks that will be affected that are adjacent to the lease block in 

which your planned activity will occur. If the proposed activities are located a sufficient distance from a shipwreck or prehistoric site that no 

impact would occur, the EIA can note that in a sentence or two.

8. All activities that you determine might have an adverse effect on endangered or threatened marine mammals or sea turtles or their critical 

habitats.

9. Production activities that involve transportation of produced fluids to shore using shuttle tankers or barges.

(c) ANALYSIS

Site-specific at Atwater Valley Block 574 (bottom hole located in AT 618)

1. Designated Topographic Features

The topographic features of the Central Gulf provide habitat for coral reef community organisms. Since 

1973 stipulations have been made a part of leases on or near these biotic communities so that impacts 

from nearby oil and gas activities were mitigated to the greatest extent possible. This stipulation does not 

prevent the recovery of oil and gas resources, but serves to protect valuable and sensitive biological 

resources.

There are no IPF’s (including effluents, physical disturbances to the seafloor and accidents) that could 

cause impacts from the proposed development activities in Atwater Valley Blocks 574/618 to topographic 

features. The site-specific offshore location of the proposed development activities is not located near a 

designated topographic feature. 

The activities proposed in this plan will be covered by our Regional OSRP.

2. Pinnacle Trend Area Live Bottoms

A small portion of the Central Planning Area and the Eastern Gulf of Mexico OCS planning areas include 

portions of approximately 70 lease blocks that have been classified as being within the “pinnacle trend” 

area. The Department of the Interior, Bureau of Ocean Energy Management, Regulation and 

Enforcement is the agency with jurisdiction over these leases. 

The term “live bottom” is used to refer to the biological assemblages attached to hard substrates found 

interspersed between sand and mud bottoms of the continental shelf. These assemblages often consist 

of colorful sponges, corals, sea whips and sea fans rising from the benthic environment. Some of these 

features have extensive vertical relief rising far into the water column and serving as a reefal habitat for 

numerous commercially and recreationally important fish species. 

A special “Live Bottom (Pinnacle Trend) Stipulation” is assigned to leases in those blocks intended to 

protect the pinnacle trend and associated hard-bottom communities from damage and, at the same time, 

provide for recovery of potential oil and gas resources. This stipulation was not invoked with the issuance 

of these leases.

There are no IPF’s (including effluents, physical disturbances to the seafloor, and accidents) from the 

proposed development activities in Atwater Valley Blocks 574/618 that could cause impacts to pinnacle 

trend area live bottoms. 

The activities proposed in this plan will be covered by our Regional OSRP

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 34 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

3. Eastern Gulf Live Bottoms

A small portion of the Central Planning Area and the Eastern Gulf of Mexico OCS planning areas include 

portions of approximately 70 lease blocks that have been classified as being within the “pinnacle trend” 

area. The Department of the Interior, Bureau of Ocean Energy Management, Regulation and 

Enforcement is the agency with jurisdiction over these leases. 

The term “live bottom” is used to refer to the biological assemblages attached to hard substrates found 

interspersed between sand and mud bottoms of the continental shelf. These assemblages often consist 

of colorful sponges, corals, sea whips and sea fans rising from the benthic environment. Some of these 

features have extensive vertical relief rising far into the water column and serving as a reefal habitat for 

numerous commercially and recreationally important fish species.

A special “Live Bottom (Pinnacle Trend) Stipulation” is assigned to leases in those blocks intended to 

protect the pinnacle trend and associated hard-bottom communities from damage and, at the same time, 

provide for recovery of potential oil and gas resources. This stipulation was not invoked with the issuance 

of these leases. 

There are no IPF’s (including effluents, physical disturbances to the seafloor, and accidents) from the 

proposed development activities in Atwater Valley Blocks 574/618 that could cause impacts to Eastern 

Gulf live bottoms. 

The activities proposed in this plan will be covered by our Regional OSRP.

4. Chemosynthetic Communities

Chemosynthetic communities are defined as persistent, largely sessile assemblages of marine organisms 

dependent upon chemosynthetic bacteria as their primary found source (MacDonald, 1992). 

Chemosynthetic clams, mussels, and tubeworms have been discovered in association with hydrocarbon 

seeps in the northern Gulf of Mexico. Initial discoveries of cold-water seep communities indicated that 

they are primarily associated with hydrocarbon and H2S seep areas (Kennicutt and Gallaway, 1985; 

Brooks et al., 1986a). Since the initial discovery in 1986 of chemosynthetic communities dependent on 

hydrocarbon seepage in the Gulf of Mexico, their geographic range has been found to include the Texas, 

Louisiana and Alabama continental slope with a depth range varying from less than 500 m to 2200 m 

(MacDonald, 1992). To date, there are 43 sites (in 40 blocks) across the northern Gulf of Mexico 

continental slope where the presence of chemosynthetic metazoans (dependent on hydrocarbon 

seepage) has been definitively documented (MacDonald, 1992).

There are no documented high-density chemosynthetic communities in Atwater Valley Blocks 574/618

according to Notice to Lessees and Operators (NTL) No. 2009-G40. Development activities have been 

carefully planned to avoid seafloor disturbance in the vicinity of features that could support high-density 

chemosynthetic communities.

There are no IPF’s (including effluents, physical disturbances to the seafloor, and accidents) from the 

proposed supplemental development activities in Atwater Valley Blocks 574/618 that could cause impacts 

to Chemosynthetic Communities (refer to information referenced in Section 6(a), Chemosynthetic 

Communities). 

5. Water Quality

There are no IPF’s (including effluents, physical disturbances to the seafloor, and accidents) from the 

proposed supplemental development activities in Atwater Valley Blocks 574/618 that could potentially 

cause impacts to water quality. The major discharges from offshore oil and gas production activities 

include produced water, ballast water, and uncontaminated seawater. Minor discharges from the offshore 

oil and gas industry include well completion and workover fluids; deck drainage; and other sanitary and 

domestic wastes, and miscellaneous discharges. Since all discharges will be made in accordance with a 

general National Pollutant Discharge Elimination System (NPDES) permit issued by U.S. Environmental 

Protection Agency (USEPA), operational discharges are not expected to cause significant adverse 

impacts to water quality.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 35 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

With regards to marine trash and debris, effective January 01, 2012, the Bureau of Safety and 

Environmental Enforcement issued BSEE NTL No. 2012-G01 pursuant to 30 CFR 250.103 and 30 CFR 

550.103 to provide guidance and assist the operators in preventing intentional and / or accidental 

introduction of trash and debris into the marine environment. With this assistance and with laws such as 

MARPOL-Annex V, the Marine Plastic Pollution Research and Control Act, and regulations imposed by 

various agencies including the U.S. Coast Guard and the U.S. Environmental Protection Agency, our 

employees will ensure that all offshore personnel, including contractors and other support servicesrelated personnel have complete understanding of the requirement that Operators be proactive in 

avoiding accidental loss of solid waste items on the OCS.

Offshore accidents, such as blowouts and spills could also occur and have the potential to alter offshore 

water quality. Given the low frequency of blowouts documented by the BOEM, minimum impacts on 

water quality due to resuspension of sediments are expected. 

Oil spills related to the proposed action are assumed to be mostly very small events (and for spills greater 

than 50 bbl) to occur very infrequently. It is unlikely that an accidental oil spill would occur from the 

proposed development activities. If a spill were to occur, the dissolved components and small oil droplets 

would temporarily affect the water quality of marine waters. Dispersion by currents and microbial 

degradation would remove the oil from the water column or dilute the constituents to background levels. 

The activities proposed in this plan will be covered by our Regional OSRP.

6. Fisheries

Effects on commercial fisheries from development activities associated with this plan in Atwater Valley 

Blocks 574/618 could come from oil spills and subsurface blowouts. 

An accidental oil spill that may occur as a result of the proposed development has the potential to cause 

some detrimental effects to fisheries. However, it is unlikely that an accidental surface or subsurface oil 

spill would occur from the proposed development activities. 

 

Subsurface blowouts have the potential to adversely affect commercial fishery resources. Sandy 

sediments will be quickly redeposited within 400 m of the blowout site and finer sediments will be widely 

dispersed and redeposited over a period of 30 days or longer within a few thousand meters. 

If a spill were to occur in open waters of the OCS proximate to mobile adult finfish or shellfish, the effects 

would likely be sublethal and the extent of damage would be reduced to the capability of adult fish and 

shellfish to avoid a spill, to metabolize hydrocarbons, and to excrete both metabolites and parent 

compounds. The effect of oil spills on fisheries is expected to cause less than 1 percent decrease in 

commercial populations or in commercial fishing. 

Drilling mud discharges contain chemicals toxic to marine fishes; however, this is only at concentrations 4 

or 5 orders of magnitude higher than those found more than a few meters from the discharge point. 

Offshore discharges of drilling muds will dilute to background levels within 1000 meters of the discharge 

point and have a negligible effect on Central Gulf fisheries.

The activities proposed in this plan will be covered by our Regional OSRP.

7. Marine Mammals

Marine mammals may be adversely impacted by several IPF’s (including vessel traffic, noise, accidental 

oil spills, and loss of trash and debris), all of which could occur due to the proposed development activity 

in Atwater Valley Blocks 574 or 618. 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 36 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

Chronic and sporadic sublethal effects could occur that may stress and / or weaken individuals of a local 

group or population and make them more susceptible to infection from natural or anthropogenic sources. 

Few lethal effects are expected from oil spills, chance collisions with service vessels and ingestion of 

plastic material. Oil spills of any size are estimated to be aperiodic events that may contact cetaceans. 

Disturbance (e.g., noise) may stress animals, weaken their immune systems, and make them more 

vulnerable to parasites and diseases that normally would not be fatal.

The net result of any disturbance would depend on the size and percentage of the population affected, 

ecological importance of the disturbed area, environmental and biological parameters that influence an 

animal’s sensitivity to disturbance and stress, and the accommodation time in response to prolonged 

disturbance (Geraci and St. Aubin, 1980). Collisions between cetaceans and ships could cause serious 

injury or death (Laist et al., 2001). Sperm whales are one of 11 whale species that are hit commonly by 

ships (Laist et al., 2001). Collisions between OCS vessels and cetaceans within the project area are 

expected to be unusual events.

BSEE and BOEM issued JOINT NTL No. 2012-G01 pursuant to 30 CFR 250.103, 550.103 and also 

250.282 and 550.282 to explain how Operators must implement measures to minimize the risk of vessel 

strikes to protected species and report observations of injured or dead protected species effective 

February 7, 2007. We will ensure that our contract vessel operators are aware of their requirement to 

report sightings of any injured or dead protected species immediately to the BOEM Protected Species 

Biologist by telephone.

With regards to marine trash and debris, effective January 1, 2012, BSEE issued BSEE NTL No. 2012-

G01 pursuant to 30 CFR 250.103 and 30 CFR 550.103 to provide guidance and assist the operators in 

preventing intentional and / or accidental introduction of trash and debris into the marine environment. 

With this assistance and with laws such as MARPOL-Annex V, the Marine Plastic Pollution Research and 

Control Act, and regulations imposed by various agencies including the U.S. Coast Guard and the U.S. 

Environmental Protection Agency, our employees will ensure that all offshore personnel, including 

contractors and other support services-related personnel have complete understanding of the 

requirement that Operators be proactive in avoiding accidental loss of solid waste items on the OCS. 

8. Sea Turtles

IPF’s that could impact sea turtles include vessel traffic, noise, trash and debris, and accidental oil spills. 

Small numbers of turtles could be killed or injured by chance collision with service vessels or by eating 

indigestible trash, particularly plastic items, accidentally lost from drill rigs, production facilities, and 

service vessels. Drilling rigs and project vessels produce noise that could disrupt normal behavior 

patterns and create some stress potentially making sea turtles more susceptible to disease. Oil spills and 

oil-spill-response activities are potential threats that could have lethal effects on turtles. Contact with oil, 

consumption of oil particles, and oil-contaminated prey could seriously affect individual sea turtles. Oilspill-response planning and the habitat protection requirements of the Oil Pollution Act of 1990 should 

mitigate these threats. Most OCS-related impacts on sea turtles are expected to be sublethal. Chronic 

sublethal effects (e.g., stress) resulting in persistent physiological or behavioral changes and / or 

avoidance of affected areas could cause declines in survival or productivity, resulting in gradual 

population declines.

BSEE and BOEM issued JOINT NTL No. 2012-G01 pursuant to 30 CFR 250.103, 550.103 and also 

250.282 and 550.282 to explain how Operators must implement measures to minimize the risk of vessel 

strikes to protected species and report observations of injured or dead protected species effective 

January 1, 2012. We will ensure that our contract vessel operators are aware of their requirement to 

report sightings of any injured or dead protected species immediately to the BOEM Protected Species 

Biologist by telephone.

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 37 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

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PROPRIETARY DATA

REV 3-1-2014
BHP Billiton Petroleum (GOM) Inc. 38 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

Vicinity of Offshore Location:

1. Essential Fish Habitat

IPF’s that could impact essential fish habitats as a result of the proposed development operations in the 

Neptune Field include effluents and accidents. The major effluent discharges from offshore oil and gas 

production activities include produced water, ballast water, and uncontaminated seawater. Minor 

discharges from the offshore oil and gas industry include well completion and workover fluids; deck 

drainage; and other sanitary and domestic wastes, and miscellaneous discharges. Since all discharges 

will be made in accordance with a general National Pollutant Discharge Elimination System (NPDES) 

permit issued by U.S. Environmental Protection Agency (USEPA), operational discharges are not 

expected to cause significant adverse impacts to water quality.

Offshore oil spillage from OCS operations is small compared with the volume of oil produced. Since 

1980, OCS operators have produced about 5.5 BBO of oil, while the amount of oil spilled offshore totaled 

about 61,500 bbl (0.001%) or 1 bbl spilled for every 89,500 produced. In 1994, BOEM revised its oil-spill 

occurrence rates for large spills (Anderson and LaBelle, 1994). An examination of the two major sources 

of OCS-related offshore spills (platforms and pipelines) shows that the greater risk of a large spill is from 

a pipeline. There have been no spills ≥1000 bbls from OCS platforms since 1980. 

An accidental oil spill that may occur as a result of the proposed development activity has the potential to 

cause some detrimental effects on essential fish habitat. However, it is unlikely that an accidental surface 

or subsurface oil spill would occur from the proposed activities. 

If a spill were to occur in open waters of the OCS proximate to mobile adult finfish or shellfish, the effects 

would likely be sublethal and the extent of damage would be limited and lessened due to the capability of 

adult fish and shellfish to avoid a spill, to metabolize hydrocarbons, and to excrete both metabolites and 

parent compounds. 

The activities proposed in this plan will be covered by our Regional OSRP.

2. Marine and Pelagic Birds

IPF’s that could impact marine and pelagic birds as a result of the proposed operations in Atwater Valley 

Blocks 574/618 include air emissions, accidents and discarded trash and debris. 

Emissions of pollutant into the atmosphere from the activities associated with the proposed development 

operations in this plan are not projected to have significant impacts on air quality that could harm marine 

and pelagic birds because of the prevailing atmospheric conditions, emission heights, emission rates and 

pollutant concentrations.

An accidental oil spill that may occur as a result of the proposed action has the potential to cause some 

detrimental effects on marine and pelagic birds. Some physical oiling could occur during dives, as well as 

secondary toxic effects through the uptake of prey. 

The activities proposed in this plan will be covered by our Regional OSRP.

With regards to marine trash and debris, coastal and marine birds can commonly become entangled and 

snared in discarded trash and debris. Effective January 1, 2012 BSEE issued BSEE NTL No. 2012-G01 

pursuant to 30 CFR 250.103 and 30 CFR 550.103 to provide guidance and assist the operators in 

preventing intentional and / or accidental introduction of trash and debris into the marine environment. 

With this assistance and with laws such as MARPOL-Annex V, the Marine Plastic Pollution Research and 

Control Act, and regulations imposed by various agencies including the U.S. Coast Guard and the U.S. 

Environmental Protection Agency, our employees will ensure that all offshore personnel, including 

contractors and other support services-related personnel have complete understanding of the 

requirement that Operators be proactive in avoiding accidental loss of solid waste items on the OCS. 

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 39 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

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PROPRIETARY DATA REV 3-1-2014
BHP Billiton Petroleum (GOM) Inc. 40 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

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PROPRIETARY DATA REV 3-1-2014
BHP Billiton Petroleum (GOM) Inc. 41 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

In accordance with requirements set forth in Title 33 CFR 146.140, an Emergency Evacuation Plan (EEP) 

is prepared and submitted to the appropriate USCG Marine Safety Office or Unit for review and ultimate 

approval. This plan provides descriptions to help define the type of storm based on the winds associated 

with it (i.e. major gulf storm, squall, tropical depression, tropical storm, gale warning, storm warning, 

hurricane, etc). Major hurricanes (storm having wind speeds in excess of 74 mph) in the Gulf normally 

form in the southern Gulf or Caribbean Sea. Tropical disturbances (storms having wind speeds greater 

than 40 mph but less than 73 mph) that originate near the facility do not provide much warning, but 

usually pass the rig or facility prior to attaining hurricane status.

Each tropical disturbance will be evaluated on its own merit and the operations modified accordingly. No 

impacts are expected on the proposed activities from site-specific environmental conditions. 

(e) Alternatives

There are no alternatives other than those required by regulation to be considered to reduce the 

environmental impacts of the activities proposed in this plan.

(f) Mitigation Measures

No mitigation measures other than those required by regulation will be considered to avoid, lessen or 

eliminate potential impacts on environmental resources.

(g) Consultation

There were no outside agencies or persons consulted regarding the potential environmental impacts 

associated with the activities proposed under this Supplemental DOCD.

(h) Preparer(s)

Kathy Camp

K. Camp & Associates

Phone: 713.201.9627

Email: Kathy.camp@kcampassociates.com

(i) References

BHPB Petroleum (GOM) Inc.’s Initial Exploration Plan (Control No. N-07528) approved August 2002.

BHPB Petroleum (GOM) Inc.’s Initial Unit Development Operations Coordination Document (Control No. 

N-08542) approved May 3, 2006

Federal Register, Tuesday, August 30, 2005, 30 CFR Parts 250 and 282, Oil and Gas Sulphur 

Operations in the Outer Continental Shelf – Plans and Information; Final Rule effective September 29, 

2005

Federal Register, Vol. 77, No. 163, August 22, 2012, Final Rule for Increased Safety Measures for 

Energy Development on the Outer Continental Shelf

Federal Register, Vol. 75, No. 198, October 14, 2010, Final Rule for Increased Safety Measures for 

Energy Development on the Outer Continental Shelf

NTL 2010-N06 effective June 18, 2010 for Information Requirements for Exploration Plans, Development 

and Production Plans, and Development Operations Coordination Documents on the OCS

NTL 2009-G40 effective January 27, 2010 for Deepwater Benthic Communities

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 42 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

NTL 2009-G39 effective January 27, 2010 for Biologically-Sensitive Underwater Features and Areas

NTL 2009-G27 effective September 9, 2009 for Submitting Exploration Plans and Development 

Operations Coordination Documents

NTL 2008-G04 effective May 1, 2008 for Information Requirements for Exploration Plans and 

Development Operations Coordination Documents (extended by NTL 2014-G03),

BSEE NTL No. 2012-G01 effective January 1, 2012 for Marine Trash and Debris Awareness and 

Elimination

JOINT NTL No. 2012-G01 effective January 1, 2012 for Vessel Strike Avoidance and Injured / Dead 

Protected Species Reporting

Final EIS, Western Planning Area Sales (204, 207, 210, 215 & 218), and Central Planning Area Sales 

(025, 206, 208, 213, 216 & 222)

Marine Mammal Protection Act of 1972 (MMPA)

Endangered Species Act of 1973 (ESA)

PUBLIC INFORMATION COPY
BHP Billiton Petroleum (GOM) Inc. 43 Atwater Valley Block 574/618

Supplemental DOCD Lease OCS-G 08035/08038

SECTION 20 - ADMINISTRATIVE INFORMATION

(a) Exempted Information Description (Public Information Copies Only)

In accordance with 43 CFR Part 2, Appendix B, the following information is exempt from disclosure and 

has been omitted from the Public Information copy of this plan:

• The geologic objectives, BHL, TVD, and MD information on form BOEM-137 (OCS Plan 

Information Form) in Attachment A

• All items under Geological and Geophysical Information, except for the non-proprietary version of 

shallow hazards assessment

• Correlative well information used to justify H2S classification request under Hydrogen Sulfide 

Information 

(b) Bibliography

BHPB Petroleum (GOM) Inc.’s Initial Exploration Plan (Control No. N-07528) approved August 2002.

BHPB Petroleum (GOM) Inc.’s Initial Unit Development Operations Coordination Document (Control No. 

N-08542) approved May 3, 2006

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

Bureau of Ocean Energy Management OMB Approval Expires: 12/31/14

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FORM BOEM-0137 (December 2011 - Supersedes all previous editions of this form which may not be used. Page 1 of 5

 

PUBLIC INFORMATION COPY

ATTACHMENT A
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) SB03

Previously reviewed under an approved EP or 

DOCD? 

Yes

X 

No

Is this an existing well or 

structure?

Yes X No If this is an existing well or structure, list the 

Complex ID or API No.

Complex ID. 

Do you plan to use a subsea BOP or a surface BOP on a floating facility to conduct your proposed activities? X Yes No

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 12540

For structures, volume of all storage 

and pipelines (Bbls) 40

API Gravity of 

fluid 20-23°

Surface Location Bottom-Hole Location (For 

Wells)

Completion (For multiple 

completions, enter separate lines)

Lease No. G-08038 

Area Name AT

Block No. 618

Block Line 

Departures 

(in feet)

N/S Departure: 1555.00 FNL N/S Departure: F____L

N/S Departure: F____L

N/S Departure: F____L

E/W Departure: 5440.00 FEL E/W Departure: F____L

E/W Departure: F____L

E/W Departure: F____L

Lambert X-Y 

coordinates

X: 723,200.00 X:

X:

X:

Y: 9,930,125.00 Y:

Y:

Y:

Latitude / 

Longitude

Latitude: 27o 20’ 11.499”N Latitude:

Latitude:

Latitude:

Longitude: 89o 49’ 31.937”W Longitude:

Longitude:

Longitude:

Water Depth (Feet): 6266 MD (Feet):

 

TVD (Feet): MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet):

TVD (Feet):

Anchor Radius (if applicable) in feet: TVD (Feet):

NONE

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

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 2 of 5 

ATTACHMENT A
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) 

 SB03 (Respud)

Previously reviewed under an approved EP or 

DOCD? 

Yes

X 

No

Is this an existing well or 

structure?

Yes X No If this is an existing well or structure, list the 

Complex ID or API No.

Complex ID. 

Do you plan to use a subsea BOP or a surface BOP on a floating facility to conduct your proposed activities? X Yes No

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 

For structures, volume of all storage 

and pipelines (Bbls) 

API Gravity of 

fluid

Surface Location Bottom-Hole Location (For 

Wells)

Completion (For multiple

completions, enter separate lines)

Lease No. G-08038

Area Name AT

Block No. 618

Block Line 

Departures 

(in feet)

N/S Departure: 1589.00 FNL N/S Departure: F____L

N/S Departure: F____L

N/S Departure: F____L

E/W Departure: 5390.00 FEL E/W Departure: F____L

E/W Departure: F____L

E/W Departure: F____L

Lambert X-Y 

coordinates

X: 723,250.00 X:

X:

X:

Y: 9,930,091.00 Y:

Y:

Y:

Latitude / 

Longitude

Latitude: 27o 20’ 11.174”N Latitude:

Latitude:

Latitude:

Longitude: 89o 49’ 31.375”W Longitude:

Longitude:

Longitude:

Water Depth (Feet): 6266 MD (Feet):

 

TVD (Feet):

 

MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet):

TVD (Feet):

Anchor Radius (if applicable) in feet: TVD (Feet):

NONE

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

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 3 of 5 

ATTACHMENT A
OCS PLAN INFORMATION FORM (CONTINUED)

Provide the following information for the well with the highest Worst Case Discharge volume:

Worst Case Discharge (WCD) Well Information

WCD Well 

Name

Surface 

Lease

Surface 

Area/Block

Bottom 

Lease

Bottom 

Area/Block

Product 

Type

MD TVD

Analog Well(s)

Area/Block OCS Lease Well No. API No.

Geologic Data for WCD 

Open Hole Interval for WCD

Top (TVD in feet) Base (TVD in feet)

Sand 1 Sand 2 Sand 3 Sand 4 Sand 5 Sand 6 Sand 7 Sand 8

Formation Data

Sand Name

Estimated Top TVD

Estimated Base TVD

Estimated Net Sand Height MD 

(Net Pay if hydrocarbon)

Estimated Net Sand Height TVT 

(net Pay if hydrocarbon)

Fluid Type

Used in WCD? (Yes/No)

Seismic Survey Used

Seismic Depth Volume

Engineering Data for WCD 

WCD Engineering Items

WCD (STB/Day)

WCD Calculated at Mudline Yes No Atmosphere Yes No

Flow Correlation

Outlet Pressure (Psia)

Gas Turbulence Factor

Software Model Used

Sand 1 Sand 2 Sand 3 Sand 4 Sand 5 Sand 6 Sand 7 Sand 8

Formation Data

Sand Name

Permeability (mD)

Initial Pressure 

(PSIA)

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 4 of 5 

ATTACHMENT A
OCS PLAN INFORMATION FORM (CONTINUED)

Sand 1 Sand 2 Sand 3 Sand 4 Sand 5 Sand 6 Sand 7 Sand 8

Formation Data

Reservoir Temperature (F)

Porosity (0.00)

Water Saturation (0.00)

Rock Compressibility (microsips)

Water Salinity (ppm)

Drive Mechanism

Drainage Area (acres)

Oil Reservoir Data

Bubble Point Pressure (PSIA)

Initial Bo (RB/STB)

Bo (RB/STB) @ Bubble Point

Rsi (SCF/STB)

Initial Oil Viscosity (Cp)

Oil Viscosity (CP) @ Bubble 

Point

Oil Compressibility (1/PSIA)

Oil API Gravity (API)

Specific Gas Gravity (0.00)

Gas Reservoir Data

Condensate API Gravity (API)

Specific Gas Gravity (0.00)

Yield (STB/MMCF)

Source of Permeability Used

Permeability from MDT

Permeability from Core Analysis Percussion core: Rotary sidewall core Conventional core 

Pressure Transient Analysis

Permeability from CMR or NMR log analysis

Permeability from other source

Provide Model Input Values for Relative Permeability:

Residual Oil to Gas fraction (=1-Slc-Swc)

Residual Oil to Water fraction (=Soc)

Critical Gas fraction (Sgc, Gas/Oil-Water Systems)

Residual Gas to Water fraction (Sgc, Gas/Gas-Water Systems)

Kro Oil Curve Endpoint (fraction of absolute permeability)

Krg Gas Curve Endpoint (fraction of absolute permeability)

Krw Water Curve Endpoint (fraction of absolute permeability)

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

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

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

data according to the Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it displays a currently valid Office of Management and Budget Control Number. 

Responses are mandatory (43 U.S.C. 1334). The public reporting burden for this form is included in the burden for preparing Exploration 

Plans and Development Operations Coordination Documents. We estimate that burden to average 600 hours with an accompanying EP, or 

700 hours with an accompanying DPP or DOCD, including the time for reviewing instructions, gathering and maintaining data, and 

completing and reviewing the forms associated with subpart B. Direct comments regarding the burden estimate or any other aspect of this 

form to the Information Collection Clearance Officer, Bureau of Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 5 of 5 

ATTACHMENT A
ATTACHMENT B PUBLIC INFORMATION COPY
ATTACHMENT B PUBLIC INFORMATION COPY
99

109

124

125

126

139

SB003 (Respud)

PROPOSED AT 618 SB003 LOCATION

WATER DEPTH AND SEAFLOOR FEATURES MAP

SB003

80

SB003

(Respud)

BLOCK 618, ATWATER VALLEY, GULF OF MEXICO
Amount is per well 

Projected generated waste

Type of Waste Composition Projected Amount Discharge rate Discharge Method

Answer

Yes or No

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

Water-based drilling fluid NaCl brine; Evaporated Salt; 

Xanthan Gum; Barite

28,216 bbls 314 bbl/day overboard / seafloor No

Cuttings wetted with water-based fluid Cuttings wetted with seawater, 

gel, and fresh water pad mud residue from riserless hole sections

2,455 bbls 27 bbl/day seafloor No

Synthetic-based drilling fluid amount adhering to cuttings Baroid Accolade SBM 2,070 bbls 23 bbl/day overboard No

Cuttings wetted with synthetic-based fluid Cuttings wetted with residue of 

Baroid Accolade SBM

2,596 bbls 29 bbl/day overboard No

Will humans be there? If yes, expect conventional waste

Domestic waste Kitchen waste 24,750 bbls 275 bbl/day remove floating solids 

and discharge

No

Sanitary waste Sanitary waste 7,110 bbls 79 bbl/day chlorinate and discharge No

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

Deck Drainage Rainfall & potable water 16,200 bbls 180 bbl/day separate solids and 

0<15ppm overboard

No

Will you conduct well treatment, completion, or workover? 

Well treatment fluids NA NA NA NA NA

Well completion fluids Water Based Fluids and Sea 

Water 2,000 bbls 22 bbl/day discharge used fluids overboard No

Workover fluids NA NA NA NA NA

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

Desalinization unit discharge Max capacity 2,215,080 bbls 24,612 bbl/day overboard No

Blowout prevent fluid Stack Magic ECO-FV2 4,500 bbls 50 bbl/day overboard NoBallast water Sea Water 105,750 bbls 1,175 bbl/day overboard No

Bilge water Oil/Water Mixture 2,250 bbls 25 bbl/day 0<15ppm overboard No

Excess cement at seafloor Class H 476 bbls 5 bbl/day seafloor NoFire water Sea Water 652,500 bbls 7,250 bbl/day overboard No

Cooling water Sea Water 40,487,400 bbls 449,860 bbl/day overboard No

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

Produced water NA NA NA NA NA

Will you be covered by an individual or general NPDES permit ? General Permit

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

Projected 

Downhole 

Disposal

Projected

Ocean

Discharges 

TABLE 1. WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR DISCHARGE TO THE GOM - CR Luigs

please specify if the amount reported is a total or per well amount

ATTACHMENT H PUBLIC INFORMATION COPY
please specify whether the amount reported is a total or per wel

CRL

Projected

generated waste

Solid and Liquid Wastes 

transportation 

Type of Waste Composition Transport Method Name/Location of Facility Amount Disposal Method

Will drilling occur ? If yes, fill in the muds and cuttings.

EXAMPLE: Synthetic-based drilling fluid or mud

internal olefin, ester Below deck storage tanks on offshore 

support vessels

Newpark Environmental Services Inc., Ingleside, TX

X bbl/well Recycled

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

Oil-based drilling fluid or mud NA NA NA NA NACuttings wetted with oil-based fluids NA NA NA NA NASynthetic-based drilling fluid or mud Whole mud sent back in after 

well has been abandoned for 

reconditioning & reuse

Pipeline from dock Baroid facility at Fourchon 

shore base

7500 bbls/well recycled

Synthetic-based drilling fluid or mud Tank washings from offshore 

workboats (9.0 ppg Baroid 

Accolade SBM)

Below deck storage tanks on offshore 

support vessels

Newpark Environmental 

Services Inc., Fourchon, La

1750 bbls/well injected

Cuttings wetted with Synthetic-based fluid Cuttings wetted with residue 

of Baroid 9.0 ppg Accolade

Cuttings boxes on offshore support 

vessels

Newpark Environmental 

Services Inc., Fourchon, La

750 bbls/well injected

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

Produced sand NA NA NA NA NA

Trash and debris non-recyclable / nonhazardous refuse generated 

by personnel on board MODU

transport in bags / baskets on vessel to shorebase - picked up at shorebase and trucked to private facility

River Birch Landfill in Avondale, LA via Galliano Waste Disposal in Galliano, LA

180 cu yds / well Landfill

Trash and debris non-hazardous recyclables 

and scrap metal

transport in bags / baskets on vessel to shorebase - picked up at shorebase and trucked to private facility

ARC in New Iberia, LA 56,250 lbs / well Recycle

Waste and Used oil oil filters, rags, pads, empty 

drums

transfer for recycle or fuel blending L&L Oilfield Services in 

Fourchon, LA or SafetyKleen Systems, Inc. transfer facility in Kenner, LA

360 bbls / well Recycle or fuel 

blend

Wash water water with trace amounts of 

internal olefin & ester

Picked up at shorebase & trucked to private facility 

Newpark Environmental Services Inc., Fourchon, La

1,000 bbls / well injected

Chemical product wastes paint waste, chemicals, 

solvents, etc.

N/A N/A N/A N/A

TABLE 2. WASTES YOU WILL TRANSPORT AND /OR DISPOSE OF ONSHORE 

Waste Disposal

Will you have additional wastes that are not permitted for discharge? If yes, fill in the appropriate rows. 

NOTE: This corresponds to the cuttings wetted with synthetic base fluid that are captured in cutting boxes if the per well average limit of 6.9% ROC by weight is forecasted to be exceeded or in the event that "Tar" is encountered and "Zero" descharge is required.

ATTACHMENT H PUBLIC INFORMATION COPY
Amount is per well 

Projected generated waste

Type of Waste Composition Projected Amount Discharge rate Discharge Method

Answer

Yes or No

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

Water-based drilling fluid NaCl brine; Evaporated Salt; 

Xanthan Gum; Barite

28,216 bbls 314 bbl/day overboard / seafloor No

Cuttings wetted with water-based fluid Cuttings wetted with seawater, 

gel, and fresh water pad mud residue from riserless hole sections

2,455 bbls 27 bbl/day seafloor No

Synthetic-based drilling fluid amount adhering to cuttings Baroid Accolade SBM 2,070 bbls 23 bbl/day overboard No

Cuttings wetted with synthetic-based fluid Cuttings wetted with residue of 

Baroid Accolade SBM

2,596 bbls 29 bbl/day overboard No

Will humans be there? If yes, expect conventional waste

Domestic waste Kitchen waste 35,730 bbls 397 bbl/day remove floating solids 

and discharge

No

Sanitary waste Sanitary waste 4,320 bbls 48 bbl/day chlorinate and discharge No

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

Deck Drainage Rainfall & potable water 19,890 bbls 221 bbl/day separate solids and 

0<15ppm overboard

No

Will you conduct well treatment, completion, or workover? 

Well treatment fluids NA NA NA NA NA

Well completion fluids Water Based Fluids and Sea 

Water 2,000 bbls 22 bbl/day discharge used fluids overboard No

Workover fluids NA NA NA NA NA

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

Desalinization unit discharge Max capacity 119,520 bbls 1,328 bbl/day overboard NoBlowout prevent fluid Stack Magic ECO-FV2 383 bbls 4 bbl/day overboard No

Ballast water Sea Water 45,000 bbls 500 bbl/day overboard NoBilge water Oil/Water Mixture 2,250 bbls 25 bbl/day 0<15ppm overboard No

Excess cement at seafloor Class H 476 bbls 5 bbl/day seafloor NoFire water Sea Water 97,020 bbls 1,078 bbl/day overboard NoCooling water Sea Water 59,710,410 bbls 663,449 bbl/day overboard No

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

Produced water NA NA NA NA NA

Will you be covered by an individual or general NPDES permit ? General Permit

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

Projected 

Downhole 

Disposal

Projected

Ocean

Discharges 

TABLE 1. WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR DISCHARGE TO THE GOM - Invictus

please specify if the amount reported is a total or per well amount

ATTACHMENT H PUBLIC INFORMATION COPY
please specify whether the amount reported is a total or per wel

Projected 

generated waste

Solid and Liquid Wastes 

transportation 

Type of Waste Composition Transport Method Name/Location of Facility Amount Disposal Method

Will drilling occur ? If yes, fill in the muds and cuttings.

EXAMPLE: Synthetic-based drilling fluid or mud

internal olefin, ester Below deck storage tanks on offshore 

support vessels

Newpark Environmental Services Inc., Ingleside, TX

X bbl/well Recycled

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

Oil-based drilling fluid or mud NA NA NA NA NACuttings wetted with oil-based fluids NA NA NA NA NASynthetic-based drilling fluid or mud Whole mud sent back in after 

well has been abandoned for 

reconditioning & reuse

Pipeline from dock Baroid facility at Fourchon 

shore base

7500 bbls/well recycled

Synthetic-based drilling fluid or mud Tank washings from offshore 

workboats (9.0 ppg Baroid 

Accolade SBM)

Below deck storage tanks on offshore 

support vessels

Newpark Environmental 

Services Inc., Fourchon, La

1750 bbls/well injected

Cuttings wetted with Synthetic-based fluid Cuttings wetted with residue 

of Baroid 9.0 ppg Accolade

Cuttings boxes on offshore support 

vessels

Newpark Environmental 

Services Inc., Fourchon, La

750 bbls/well injected

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

Produced sand NA NA NA NA NA

Trash and debris non-recyclable / nonhazardous refuse generated 

by personnel on board MODU

transport in bags / baskets on vessel to shorebase - picked up at shorebase and trucked to private facility

River Birch Landfill in Avondale, LA via Galliano Waste Disposal in Galliano, LA

180 cu yds / well Landfill

Trash and debris non-hazardous recyclables 

and scrap metal

transport in bags / baskets on vessel to shorebase - picked up at shorebase and trucked to private facility

ARC in New Iberia, LA 56,250 lbs / well Recycle

Waste and Used oil oil filters, rags, pads, empty 

drums

transfer for recycle or fuel blending L&L Oilfield Services in 

Fourchon, LA or SafetyKleen Systems, Inc. transfer facility in Kenner, LA

360 bbls / well Recycle or fuel 

blend

Wash water water with trace amounts of 

internal olefin & ester

Picked up at shorebase & trucked to private facility 

Newpark Environmental Services Inc., Fourchon, La

1,000 bbls / well injected

Chemical product wastes paint waste, chemicals, 

solvents, etc.

N/A N/A N/A N/A

TABLE 2. WASTES YOU WILL TRANSPORT AND /OR DISPOSE OF ONSHORE 

Waste Disposal

Will you have additional wastes that are not permitted for discharge? If yes, fill in the appropriate rows. 

NOTE: This corresponds to the cuttings wetted with synthetic base fluid that are captured in cutting boxes if the per well average limit of 6.9% ROC by weight is forecasted to be exceeded or in the event that "Tar" is encountered and "Zero" descharge is required.

ATTACHMENT H PUBLIC INFORMATION COPY
OMB Control No. 1010-0151

OMB Approval Expires: 12/31/2011

COMPANY BHP Billiton Pet. (GOM) Inc.

AREA Atwater Valley

BLOCK 574/618

LEASE OCS-G 08038 / 08035

PLATFORM NeptuneWELL SB003COMPANY CONTACT Susan WilsonTELEPHONE NO. 713 599 6349REMARKS Drill and complete Well SB003 with Drillship (Invictus)

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 1 of 8
EMISSIONS FACTORS

Fuel Usage Conversion Factors Natural Gas Turbines Natural Gas Engines Diesel Recip. Engine REF. DATE

SCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483 AP42 3.2-1 4/76 & 8/84

Btu/hp-hr 2543.5

Equipment/Emission Factors units PM SOx NOx VOC CO CO2-e [1] REF. DATE

Diesel Turbines lb/MMBtu 0.0203 0.00002 0.88 0.00803 0.0124 163.6 AP-42 3.1-2a & 

Background 3.4-2 04/00

Diesel Recip. < 600 hp. lb/MMBtu 0.31 0.29 4.41 0.36 0.95 163.6 AP-42 3.3-1 10/96

Diesel Recip. < 600 hp. lb/hp-hr 0.0022 1.08E-05 0.031 0.0025141 0.00668 1.15 AP-42 3.3-1 10/96

Diesel Recip. < 600 hp. g/hp-hr 1 4.89E-03 14.06 1.14 3.03 521.6 AP42 3.3-1 10/96

Diesel Recip. < 600 hp.-EPA Tier 1 [2] g/kW-hr 0.54 9.2 1.3 11.4 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 1 [2] lb/hp-hr 0.000888 0.0151 0.00214 0.0187 EPA Tier 1

Diesel Recip. > 600 hp.-EPA Tier 1 [10] g/kW-hr 0.54 9.2 1.3 11.4 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 2 [3] g/kW-hr 0.2 6.4 3.5 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 2 [3] lb/hp-hr 0.000329 0.0109 0.00576 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 3 [4] g/kW-hr 0.3 4 5 EPA Tier 3

Diesel Recip. < 600 hp.-EPA Tier 3 [4] lb/hp-hr 0.000329 0.00658 0.00576 EPA Tier 3

Diesel Recip. > 600 hp. lb/MMBtu 0.0573 0.000015 3.2 0.0819 0.85 163.6 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000 

rpm) [5] g/kW-hr 9.8 7.2 IMO Tier 1

Diesel Recip. > 600 hp.-Marine Tier 1 (130-

1999 rpm) [6] g/kW-hr 45*(N)^(-0.2) 40CFR94.8(a)(1) 12/07

Diesel Recip. ≥37kw -Marine Tier 2 

(displacement 1.2 L - >5.0 L/cyl.) [7] g/kW-hr 0.2 7.20 5.0 40CFR94.8(a)(2) 12/07

Diesel Recip. > 600 hp.-Invictus-Main [8] g/kW-hr 9.7

Main Engines 

Manufacturer 

Data

Diesel Recip. > 600 hp. lb/hp-hr 7.00E-04 1.08E-05 0.024 0.0007 0.0055 1.16 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp. g/hp-hr 0.32 0.00 11 0.33 2.49 526.2 AP42 3.4-1 10/96

Duel Fuel (NG & Diesel) lb/MMBtu 0.0573 0.183150 2.7 0.02 1.16 122.6 AP-42 3.4-1 10/96

Duel Fuel (NG & Diesel) lb/hp-hr 0.0007 0.001352 0.018 0.00132 0.0075 122.6 AP-42 3.4-1 10/96

Diesel Boiler lbs/bbl 0.084 0.00009075 0.84 0.008 0.21 163.6 AP-42 1.3-12,14 9/98

Sulphur Content Source Value Units

Fuel Gas 3.33 ppm

Diesel Fuel [9] 0.0015% % weight

Produced Gas( Flares) 3.33 ppm

Produced Oil (Liquid Flaring) 2.86 % weight

The following equations were used in formulating the conversion factors used in the application package

kW: hp = (kW) x (1.341 hp/kW). Factor = 1.341 hp/kW.

[10] Diesel Recip. > 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines.

[9] BHPB utilizes Ultra Low Sulfur Diesel for all diesel combustion sources. Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 15 ppm in diesel fuel assuming that 

100 percent of sulfur in the fuel is oxidized to SO2. 

[8] Diesel Recip. > 600 hp.-Invictus-Main: NOx emission factor is based on the TOI Invictus engine manufacturer's data. The main engines on Invictus are IMO Tier II certified engines.

[1] The calculated emission factors for CO2-e (CO2, CH4 and N2O) are based on 40 CFR 98, Tables C-1 & C-2.

[5] Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000 rpm): NOx emission factors for IMO Tier 1 diesel engines on certain cement unit engines with rated engine rpm is equal to or greater than 2000.

[7] Diesel Recip. ≥37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacement of 1.2 L - >5.0 L.

[6] Diesel Recip. > 600 hp.-Marine Tier 1, for NOx: 45.0 x N^(-0.20) g/kW-hr, where N is maximum/rated engine rpm from 130-1999. Vessel (Crew) maximum rpm is 1,800 per main engine. Vessel 

(Work) main engines maximum rpm are 1000 rpm, and generators and SDT are 1800 rpm.

[2] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, and CO emission factors for EPA Tier 1 diesel engines on certain wireline and cement unit engines.

[3] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline and cement unit engines.

[4] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline and cement unit engines.

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 2 of 8
COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

BHP Billiton Pet. (GOM) Inc. Atwater Valley 574/618 CS-G 08038 / 080 Neptune SB003 Susan Wilson 713 599 6349

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOU

R ESTIMATED TONS

Diesel Engines HP GAL/H

R GAL/D

Nat. Gas Engines HP SCF/HR SCF/D

Burners MMBTU/HR SCF/HR SCF/D HR/D DAYS PM SOx NOx

VOC CO CO2 PM SOx NOx

VOC CO CO2

DRILLINGDP DRILLSHIP 64865 3132.98 75191.51 24 95 46.05 0.70 1047.17 54.77 378.57 75205.34 52.50 0.80 1193.78 62.43 431.57 85734.09

PRIME MOVER>600hp diesel [1] [2] 56310 2719.77 65274.55 39.42 0.61 897.98 40.97 309.71 65319.60 0.00 0.00 0.00 0.00 0.00 0.00

Emergency Generator>600hp diesel 2279 110.08 2641.82 1.60 0.02 54.70 1.66 12.53 2643.64 0.00 0.00 0.00 0.00 0.00 0.002-300 HP WIRELINE <600hp diesel-POSU-CA PU Eng. [3] 600 28.98 695.52 0.20 0.01 3.95 1.51 3.46 690.00 0.00 0.00 0.00 0.00 0.00 0.00

WIRELINE <600hp diesel-GSU-W Generator 160 7.73 185.47 0.35 0.00 4.96 0.40 1.07 184.00 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hp diesel-Generator DHPS 160 7.73 185.47 0.35 0.00 4.96 0.40 1.07 184.00 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hp diesel-Batch Mixer [4] 250 12.08 289.80 0.08 0.00 2.73 0.63 1.44 287.50 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hp diesel (Nitrogen pump) [5] 490 23.67 568.01 0.44 0.01 7.41 1.05 9.18 563.50 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hp diesel [6] 860 41.54 996.91 0.60 0.01 13.86 0.63 4.73 997.60 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hp diesel [6] 860 41.54 996.91 0.60 0.01 13.86 0.63 4.73 997.60 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP <600hp diesel-Fast Rescue 149 7.20 172.72 0.33 0.00 4.62 0.37 1.00 171.35 0.00 0.00 0.00 0.00 0.00 0.006-29HP EMERGENCY EQUIP <600hp diesel-Lifeboat 174 8.40 201.70 0.38 0.00 5.39 0.44 1.16 200.10 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP <600hp diesel-Air Compressor 38 1.84 44.05 0.08 0.00 1.18 0.10 0.25 43.70 0.00 0.00 0.00 0.00 0.00 0.003-415 HP SEISMIC OP ENGINE <600hp diesel [8] 1245 60.13 1443.20 0.41 0.01 13.57 3.13 7.17 1431.75 0.00 0.00 0.00 0.00 0.00 0.00

SLICKLINE <600hp diesel [9] 106 5.12 122.88 0.23 0.00 1.60 0.27 0.71 121.90 0.00 0.00 0.00 0.00 0.00 0.00

FLUID FILTRATION PUMP <600hp diesel [10] 174 8.40 201.70 0.09 0.00 1.14 0.44 1.43 200.10 0.00 0.00 0.00 0.00 0.00 0.00COIL TUBING POWER PACK <600hp diesel [11] 260 12.56 301.39 0.23 0.00 3.93 0.56 4.87 299.00 0.00 0.00 0.00 0.00 0.00 0.00COIL TUBING PUMP >600hp diesel [12] 750 36.23 869.40 0.67 0.01 11.34 1.60 14.06 870.00 0.00 0.00 0.00 0.00 0.00 0.00

ECO Crew VESSELS>600hp diesel(crew) (main-4) [13] 9000 434.70 10432.80 24 95 2.96 0.10 106.53 6.55 49.50 10440.00 3.37 0.11 121.45 7.46 56.43 11901.60

VESSELS<600hp diesel(crew) (gens-3) [13] 1083 52.31 1255.41 24 95 0.36 0.01 12.82 2.72 8.90 1245.45 0.41 0.01 14.61 3.10 10.15 1419.81

Work/Supply VESSELS>600hp diesel(work) (main-2) [7] 13196 637.37 15296.80 24 95 9.24 0.14 245.22 9.60 72.58 15307.36 10.53 0.16 279.56 10.94 82.74 17450.39

2 vessels VESSELS>600hp diesel(work) (gen.-2) [7] 8000 386.40 9273.60 24 95 5.60 0.09 132.18 5.82 44.00 9280.00 6.38 0.10 150.68 6.64 50.16 10579.20

VESSELS>600hp diesel(work) (SDT) [7] 2200 106.26 2550.24 24 95 1.54 0.02 36.35 1.60 12.10 2552.00 1.76 0.03 41.44 1.82 13.79 2909.28VESSELS<600hp diesel(work) (E-Generator) 502 24.22 581.38 24 95 1.11 0.01 15.55 1.26 3.35 581.78 1.26 0.01 17.72 1.44 3.82 663.23

INSTALLATION INSTALLATION Vessel >600hp diesel 4700 227.01 5448.24 24 4 3.29 0.05 112.80 3.42 25.85 17319.46 0.16 0.00 5.41 0.16 1.24 831.33jumper / flowline SUPPORT VESSEL >600hp diesel 17000 821.1 19706.40 24 4 11.90 0.18 408.00 12.37 93.50 62644.87 0.57 0.01 19.58 0.59 4.49 3006.95umbilical VESSELS>600hp diesel(supply) 12000 579.6 13910.40 24 4 8.40 0.13 288.00 8.73 66.00 44219.91 0.40 0.01 13.82 0.42 3.17 2122.56

2014 YEAR TOTAL (ANNUAL) 90.44 1.43 2404.62 106.84 754.35 238796.17 77.34 1.23 1858.06 95.02 657.55 136618.44

EXEMPTION 

CALCULATION DISTANCE FROM LAND IN MILES 3729.60 3729.60 3729.60 3729.60 78999.49

112

Drill and complete Well SB003 with Drillship (Invictus)

[7] Diesel Recip. > 600 hp.-EPA Marine Tier 1: VESSELS: EPA Marine Engine Tier 1 for NOx: 45.0 x N^(-0.20) g/kW-hr, where N is maximum/rated engine rpm. Vessel (Crew) maximum rpm is 1,800 per main engine. Vessel (Work) main engines maximum rpm are 1000 rpm, and generators and SDT are 1800 rpm.[1] PRIME MOVER >600hp diesel-Invictus: TOI's Invictus maximum output per main engine is 9385 hp/7000 kW. These calculations c[8] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines.

onservatively assume operating 6 of 6 engines.

[2] PRIME MOVER >600 hp. diesel-Invictus: NOx emission factor is based on the TOI Invictus engine manufacturer's data. The main engines on Invictus are IMO Tier II certified engines.[3] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline and cement unit engines.[4] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline and cement unit engines.[5] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines on certain cement unit engines.[6] Diesel Recip. > 600 hp.-IMO Tier I (=> 2000 rpm): NOx emission factors for IMO Tier I diesel engines on certain cement unit engines with rated engine rpm is equal to or greater than 2000.[13] Diesel Recip. ≥37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacement of 1.2 L - >5.0 L.

[9] Diesel Recip. < 600 hp.-EPA Tier 1: NOx emission factor for EPA Tier 1 diesel engines.[10] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines.[11] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines.[12] Diesel Recip. > 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines.

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 3 of 8
SUMMARY

COMPANY AREA BLOCK LEASE PLATFORM WELLBHP Billiton Pet. (GOM) Inc. Atwater Valley 574/618 OCS-G 08038 / 08035 Neptune SB003

Emitted Substance

Year

 PM SOx NOx VOC CO

2014 77.34 1.23 1858.06 95.02 657.55

Allowable 3729.60 3729.60 3729.60 3729.60 78999.49

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 8 of 8
OMB Control No. 1010-0151

OMB Approval Expires: 12/31/2011

COMPANY BHP Billiton Pet. (GOM) Inc.

AREA Atwater Valley

BLOCK 574LEASE OCS-G 08035PLATFORMWELL SB003COMPANY CONTACT Kathy CampCRL 713.201.9627REMARKS Drill / complete Well SB003 with CRLLEASE TERM PIPELINE CONSTRUCTION INFORMATION:

YEAR NUMBER OF TOTAL NUMBER OF CONSTRUCTION DAYS

PIPELINES

2014 1 4

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 1 of 8
EMISSIONS FACTORS

Fuel Usage Conversion Factors Natural Gas Turbines Natural Gas Engines Diesel Recip. Engine REF. DATE

SCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483 AP42 3.2-1 4/76 & 8/84

Btu/hp-hr 2543.5

Equipment/Emission Factors units PM SOx NOx VOC CO CO2-e [1] REF. DATE

Diesel Turbines lb/MMBtu 0.0203 0.00152 0.88 0.00803 0.0124 163.6 AP-42 3.1-2a & 

Background 3.4-2 04/00

Diesel Recip. < 600 hp. lb/MMBtu 0.31 0.29 4.41 0.36 0.95 163.6 AP-42 3.3-1 10/96

Diesel Recip. < 600 hp. gms/hp-hr 1 0.005505 14 1.12 3.03 163.6 AP42 3.3-1 10/96

Diesel Recip. < 600 hp.-EPA Tier 1 [2] gms/kW-hr 0.54 9.2 1.3 11.4 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 1 [2] lb/hp-hr 0.000888 0.0151 0.00214 0.0187 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 2 [3] gms/kW-hr 0.2 6.4 3.5 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 2 [3] lb/hp-hr 0.000329 0.0109 0.00576 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 3 [4] gms/kW-hr 0.2 4 3.5 EPA Tier 3

Diesel Recip. < 600 hp.-EPA Tier 3 [4] lb/hp-hr 0.000329 0.00658 0.00576 EPA Tier 3

Diesel Recip. > 600 hp. lb/MMBtu 0.0573 0.001515 3.2 0.0819 0.85 163.6 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp.-CRL-Main [5] g/kW-hr 17.02 2.42 COMM Test Apr-10

Diesel Recip. > 600 hp.-IMO Tier 1 (=> 

2000 rpm) [6] g/kW-hr 9.8 7.2 IMO Tier 1

Diesel Recip. > 600 hp.-Marine Tier 1 

(130-1999 rpm) [7] g/kW-hr 45*(N)^(-0.2) 40CFR94.8(a)(

1) 12/07

Diesel Recip. ≥37kw -Marine Tier 2 

(displacement 1.2 L - >5.0 L/cyl.) [8] g/kW-hr 0.2 7.20 5.0 40CFR94.8(a)(

2) 12/07

Diesel Recip. > 600 hp.-DD1-Main [9] g/kW-hr 14.06 1.98 COMM Test May-10

Diesel Recip. > 600 hp. lb/hp-hr 0.0007 0.000012 0.024 0.00064155 0.0055 163.6 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp. gms/hp-hr 0.32 0.005505 11 0.33 2.4 163.6 AP42 3.4-1 10/96

Duel Fuel (NG & Diesel) lb/MMBtu 0.0573 0.183150 2.7 0.02 1.16 122.6 AP-42 3.4-1 10/96

Duel Fuel (NG & Diesel) lb/hp-hr 0.0007 0.001352 0.018 0.00132 0.0075 122.6 AP-42 3.4-1 10/96

Diesel Boiler lbs/bbl 0.084 0.009075 0.84 0.008 0.21 163.6 AP-42 1.3-12,14 9/98

Sulphur Content Source Value Units

Fuel Gas 3.33 ppm

Diesel Fuel [10] 0.0015 % weight

Produced Gas( Flares) 3.33 ppm

Produced Oil (Liquid Flaring) 2.86 % weight

The following equations were used in formulating the conversion factors used in the application package

kW: hp = (kW) x (1.341 hp/kW). Factor = 1.341 hp/kW.

[1] The calculated emission factors for CO2-e (CO2, CH4 and N2O) are based on 40 CFR 98, Tables C-1 & C-2.

[5] Diesel Recip. > 600 hp.-CRL-Main: COMM Engineering testing of Transocean International's C.R. Luigs' (CRL) eight (8) main engines for NOx and CO was conducted April 2010. 

The NOx emission factor was conservatively calculated 110% of the test average; the CO emission factor utilizes the maximum CO emission rate of the tests.

[6] Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000 rpm): NOx emission factors for IMO Tier 1 diesel engines on certain cement unit engines with rated engine rpm is equal to or greater 

than 2000.

[8] Diesel Recip. ≥37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacement of 1.2 L - >5.0 L.

[7] Diesel Recip. > 600 hp.-Marine Tier 1, for NOx: 45.0 x N^(-0.20) g/kW-hr, where N is maximum/rated engine rpm from 130-1999. Vessel (Crew) maximum rpm is 1,800 per main 

engine. Vessel (Work) main engines maximum rpm are 1000 rpm, and generators and SDT are 1800 rpm.

[2] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, and CO emission factors for EPA Tier 1 diesel engines on certain wireline and cement unit engines.

[3] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline and cement unit engines.

[4] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline and cement unit engines.

FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 2 of 8
COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

BHP Billiton Pet. (GOM) Atwater Valley 574 OCS-G 08035 0 SB003 Kathy Camp 713.201.9627 Drill / complete Well SB003 with CRL

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR ESTIMATED TONS

Diesel Engines HP GAL/HR GAL/D

Nat. Gas Engines HP SCF/HR SCF/D

Burners MMBTU/HR SCF/HR SCF/D HR/D DAYS PM SOx NOx VOC CO CO2 PM SOx NOx VOC CO CO2

DRILLINGDP DRILL SHIP [1] 53417 2580.04 19924.50 24 95 39.86 0.65 1451.87 43.29 229.96 61204.61 14.62 0.24 532.58 15.88 84.35 22451.15

CRL PRIME MOVER>600hp diesel [2] [3] 47000 2270.10 54482.40 33.16 0.57 1315.12 34.19 186.99 53852.18 0.00 0.00 0.00 0.00 0.00 0.00

CRANES<600hp diesel [4] [5] 1220 58.93 1414.22 2.69 0.01 37.66 3.01 8.15 1397.84 0.00 0.00 0.00 0.00 0.00 0.00

Emergency Generator>600hp diesel 2064 99.69 2392.59 1.46 0.03 50.05 1.50 10.92 2364.87 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP<600hp diesel 323 15.60 374.42 0.71 0.00 9.97 0.80 2.16 370.08 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hp diesel-POSU-CA PU Eng. [6] 300 14.49 347.76 0.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00

WIRELINE <600hp diesel-POSU-CA PU Eng. [6] 300 14.49 347.76 0.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hp diesel (Nitrogen pump) [7] 490 23.67 568.01 0.44 0.01 7.41 1.05 9.18 561.43 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hp diesel [8] 860 41.54 996.91 0.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hp diesel [8] 860 41.54 996.91 0.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00

ECO Crew VESSELS ≥37kw diesel(crew) (main-4) [9] 9000 434.70 10432.80 24 95 2.96 0.11 106.53 6.55 47.62 10311.95 3.37 0.12 121.45 7.46 54.29 11755.63

VESSELS ≥37kw diesel(crew) (gens-3) [9] 1083 52.31 1255.41 24 95 0.36 0.01 12.82 2.67 8.90 1240.87 0.41 0.01 14.61 3.05 10.15 1414.59

Work/Supply VESSELS>600hp diesel(work) (main-2) [10] 13196 637.37 15296.80 24 95 9.31 0.16 245.22 9.60 69.82 15119.62 10.61 0.18 279.56 10.94 79.60 17236.36

2 vessels VESSELS>600hp diesel(work) (gen.-2) [10] 4881 235.76 5658.33 24 95 3.44 0.06 80.65 3.55 25.83 5592.79 3.93 0.07 91.94 4.05 29.44 6375.78

VESSELS>600hp diesel(work) (SDT) [10] 2200 106.26 2550.24 24 95 1.55 0.03 36.35 1.60 11.64 2520.70 1.77 0.03 41.44 1.82 13.27 2873.60VESSELS<600hp diesel(work) (E-Generator) 502 24.22 581.38 24 95 1.11 0.01 15.48 1.24 3.35 574.64 1.26 0.01 17.65 1.41 3.82 655.09

INSTALLATION INSTALLATION Vessel >600hp diesel 47000 2270.1 54482.40 24 4 33.16 0.57 1139.80 34.19 248.68 53851.31 1.59 0.03 54.71 1.64 11.94 2584.86jumper / flowline SUPPORT VESSEL >600hp diesel 17000 821.1 19706.40 24 4 11.99 0.21 412.27 12.37 89.95 19478.13 0.58 0.01 19.79 0.59 4.32 934.95umbilical VESSELS>600hp diesel(supply) 12000 579.6 13910.40 24 4 8.47 0.15 291.01 8.73 63.49 13749.27 0.41 0.01 13.97 0.42 3.05 659.97

2014 YEAR TOTAL (ANNUAL) 152.07 2.59 5243.86 167.08 1029.21 244848.50 38.54 0.71 1187.68 47.27 294.22 66941.98

EXEMPTION 

CALCULATION DISTANCE FROM LAND IN MILES 3729.60 3729.60 3729.60 3729.60 78999.49

112

[7] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines on certain cement unit engines.[1] DRILL SHIP: TOI's CRL's average daily fuel usage for the period June 1, 2011 through May 31, 2012 was 13,283 gallons/day. Actual fuel usage is conservatively estimated at 150% of this average.[2] PRIME MOVER>600hp diesel: TOI's CRL's maximum output per main engine is 5875 hp/4184 kW with normal operation involving operating four (4) of eight (8) main engines. These calculations conservatively assume operating 8 of 8 engines.[3] PRIME MOVER>600hp diesel: Based on TOI's CRL. For all pollutants except NOx and CO, the maximum hourly emissions (lbs/hr) are calculated based on the appropriate AP-42 and EPA emission factor and the total engine rating of 5875 HP (mechanical), as the AP-42 and EPA emission factors are 

based on brake HP. COMM Engineering testing of Transocean International's (TOI) C.R. Luigs' (CRL) eight (8) main engines for NOx and CO was conducted April 2010. The NOx emission factor was conservatively calculated 110% of the test average; the CO emission factor utilizes the maximum CO 

emission rate of the tests.[4] CRANES<600hp diesel: Based on TOI's CRL. Assumes operation of 4 of 4 cranes (305 hp each) at any one time.[5] CRANES<600hp diesel: Based on TOI's CRL. From TOI, each crane engine consumes 0.066 tonnes diesel /hr @ 75% load (27.32 gal per hour @ 100% load and 7.1 lb/gal.)[6] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline unit engines.

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 3 of 8
SUMMARY

COMPANY AREA BLOCK LEASE PLATFORM WELLBHP Billiton Pet.Atwater Valley 574 OCS-G 08035 0 SB003

Emitted Substance

Year

 PM SOx NOx VOC CO

2014 38.54 0.71 1187.68 47.27 294.22

Allowable 3729.60 3729.60 3729.60 3729.60 78999.49

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 8 of 8
Page 1 of 14 

SPILL RESPONSE DISCUSSION 

For the purpose of NEPA and Coastal Zone Management Act analysis, the largest spill volume 

originating from the proposed activity would be a well blowout during drilling operations, 

estimated to be 101,730 barrels of crude oil with an API gravity of 22.9°. 

Land Segment and Resource Identification

Trajectories of a spill and the probability of it impacting a land segment have been projected 

utilizing information in the BSEE Oil Spill Risk Analysis Model (OSRAM) for the Central and 

Western Gulf of Mexico available on the BSEE website. The results are shown in Figure 1. The 

BSEE OSRAM identifies a 3% probability of impact to the shorelines of Plaquemines Parish, 

Louisiana within 30 days. Plaquemines Parish includes Barataria Bay, the Mississippi River 

Delta, Breton Sound and the affiliated islands and bays. This region is an extremely sensitive 

habitat and serves as a migratory, breeding, feeding and nursery habitat for numerous species of 

wildlife. Beaches in this area vary in grain particle size and can be classified as fine sand, shell 

or perched shell beaches. Sandy and muddy tidal flats are also abundant. 

Response

BHP Billiton Petroleum (GOM) Inc. will make every effort to respond to the Worst Case 

Discharge as effectively as practicable. A description of the response equipment under contract 

to contain and recover the Worst Case Discharge is shown in Figure 2.

Using the estimated chemical and physical characteristics of crude oil, an ADIOS weathering 

model was run on a similar product from the ADIOS oil database. The results indicate 12% or 

approximately 12,208 barrels of crude oil would be evaporated/dispersed within 24 hours, with 

approximately 89,522 barrels remaining. 

Spill Response AT 574, Well E001 Barrels of Oil 

WCD Volume 101,730 

Less 12% natural evaporation/dispersion 12,208 

Remaining volume 89,522 

Figure 2 outlines equipment, personnel, materials and support vessels as well as temporary 

storage equipment available to respond to a spill of approximately 89,522 barrels. The volume 

accounts for the amount remaining after evaporation/dispersion at 24 hours. The list estimates 

individual times needed for procurement, load out, travel time to the site and deployment. Figure 

2 also indicates how operations will be supported. 

BHP Billiton Petroleum (GOM) Inc.’s Oil Spill Response Plan includes alternative response 

technologies such as dispersants and in-situ burn. Strategies will be decided by Unified 

Command based on the size of the spill, weather and potential impacts. If aerial dispersants are 

utilized, 8 sorties (9,600 gallons) from two of the DC-3 aircrafts and 4 sorties (8,000 gallons) 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 2 of 14 

from the Basler aircraft would provide a daily dispersant capability of 7,540 barrels. If the 

conditions are favorable for in-situ burning, the proper approvals have been obtained and the 

proper planning is in place, in-situ burning of oil may be attempted. Slick containment boom 

would be immediately called out and on-scene as soon as possible. Offshore response strategies 

may include attempting to skim utilizing the HOSS Barge, nine Fast Response Units (FRUs), and 

six sets of Koseq skimming arms, with a total derated skimming capacity of 188,233 barrels. 

Temporary storage associated with skimming equipment equals 17,700 barrels. If additional 

storage is needed, a 25,000 barrel storage barge, three 20,000 barrel storage barges, and an 

86,948 barrel storage barge may be mobilized and centrally located to provide temporary storage 

allowing the skimmers to stay in the area of operations as much as possible. Safety is first 

priority. Air monitoring will be accomplished and operations deemed safe prior to any 

containment/skimming attempts. 

If the spill went unabated, shoreline impact in Plaquemines Parish, Louisiana would depend 

upon existing environmental conditions. Shoreline protection would include the use of CGA’s 

near shore and shallow water skimmers with a totaled derated skimming capacity of 86,570 

barrels. Temporary storage associated with skimming equipment equals 1,292 barrels. If 

additional storage is needed, two 23,000 barrel storage barges and one 47,000 barrel storage 

barge may be mobilized and centrally located to provide temporary storage allowing the 

skimmers to stay in the area of operations as much as possible. Onshore response may include 

the deployment of shoreline boom on beach areas, or protection and sorbent boom on vegetated 

areas. A Master Service Agreement with ES&H will ensure access to 140,000 feet of 18” 

shoreline protection boom. Figure 2 outlines individual times needed for procurement, load out, 

travel time to the site and deployment. Strategies would be based upon surveillance and real 

time trajectories that depict areas of potential impact given actual sea and weather conditions. 

The State of Louisiana Initial Oil Spill Response Plan for Plaquemines Parish and Unified 

Command would be consulted to ensure that environmental and special economic resources 

would be correctly identified and prioritized to ensure optimal protection. Shoreline protection 

strategies depict the protection response modes applicable for oil spill clean-up operations. The 

State of Louisiana Initial Oil Spill Response Plan provides detailed shoreline protection 

strategies for this area, and it describes necessary action to keep the oil spill from entering 

Louisiana’s coastal wetlands, based on the assumption that removal of the released oil will be 

much easier and less damaging to fragile coastal ecosystems if done in the open waters of the 

Gulf of Mexico. Supervisory personnel have the option to modify the deployment and operation 

of equipment allowing a more effective response to site-specific circumstances. BHP Billiton 

Petroleum (GOM) Inc.’s contract Spill Management Team holds a copy of the State of Louisiana 

Initial Oil Spill Response Plan. 

Based on the anticipated worst case discharge scenario, BHP Billiton Petroleum (GOM) Inc. can 

be onsite with contracted oil spill recovery equipment with adequate response capacity to contain 

and recover surface hydrocarbons, and prevent land impact, to the maximum extent practicable, 

within an estimated 62 hours (based on the equipment’s Effective Daily Recovery Capacity 

(EDRC)). 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 3 of 14 

Initial Response Considerations 

Actual actions taken during an oil spill response will be based on many factors which include but 

are not limited to: 

• Weather 

• Equipment and materials availability 

• Ocean currents and tides 

• Location of the spill 

• Product spilled 

• Amount spilled 

• Environmental risk assessments 

• Trajectory and product analysis 

• Well status, i.e., shut in or continual release 

BHP Billiton Petroleum (GOM) Inc. will take action to provide a safe, aggressive response to 

contain and recover as much of the spilled oil as quickly as it is safe to do so. In an effort to 

protect the environment, response actions will be designed to provide an “in-depth” protection 

strategy meant to recover as much oil as possible as far from environmentally sensitive areas as 

possible. Safety will take precedence over all other considerations during these operations. 

Coordination of response assets will be supervised by the designation of a SIMOPS group as 

necessary for close quarter vessel response activities. Most often, this group will be used during 

source control events that require a significant number of large vessels operating independently, 

but in coordination to complete a common objective, in a small area and in close coordination 

and support of each other. This group must also monitor the subsurface activities of each vessel 

(ROV, dispersant application, well control support, etc.). The SIMOPS group leader reports to 

the Source Control Section Chief. 

In addition, these activities will be monitored by the spill management team (SMT) and Unified 

Command via a structured Common Operating Picture (COP) established to track resource and 

slick movement in real time. 

Upon notification of a spill, the following actions will be taken: 

• Information will be confirmed 

• An assessment will be made and initial objectives set 

• OSROs and appropriate agencies will be notified 

• ICS 201, Initial Report Form will be completed 

• Initial Safety plan will be written and published 

• Unified Command will be established 

o Overall safety plan developed to reflect the operational situation and coordinated 

objectives 

o Areas of responsibility established for Source Control and each surface operational 

site 

o On-site command and control established 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 4 of 14 

Decanting Strategy 

Recovered oil and water mixtures will typically separate into distinct phases when left in a 

quiescent state. When separation occurs, the relatively clean water phase can be siphoned or 

decanted back to the recovery point with minimal, if any, impact. Decanting therefore increases 

the effective on-site oil storage capacity and equipment operating time. FOSC/SOSC approval 

will be requested prior to decanting operations. This practice is routinely used for oil spill 

recovery. 

Offshore Response Actions 

Equipment Deployment

Surveillance 

• Surveillance Aircraft will be deployed within two hours of Qualified Individual (QI) 

notification, or at first light

• Provide trained observer to provide on site status reports 

• Provide command and control platform at the site if needed 

• Continual surveillance of oil movement by remote sensing systems, aerial photography 

and visual confirmation 

• Continual monitoring of vessel assets using vessel monitoring systems 

Dispersant application assets 

• Put Airborne Support Inc. (ASI) on standby 

• With the Federal On-Scene Coordinator (FOSC), conduct analysis to determine 

appropriateness of dispersant application 

• Gain FOSC approval for use of dispersants on the surface 

• Deploy aircraft in accordance with a plan developed for the actual situation 

• Coordinate movement of dispersants, aircraft, and support equipment and personnel 

• Confirm dispersant availability for current and long range operations 

• Start ordering dispersant stocks required for expected operations 

Containment boom , 

• Call out early and expedite deployment to be on scene ASAP 

• Ensure boom handling and mooring equipment is deployed with boom 

• Provide continuing reports to vessels to expedite their arrival at sites that will provide for 

their most effective containment 

• Use Vessels of Opportunity (VOO) to deploy and maintain boom 

Dedicated off-shore skimming systems 

General 

• Deployed to the highest concentration of oil 

• Assets deployed at safe distance from aerial dispersant and in-situ burn operations 

ATTACHMENT J PUBLIC INFORMATION COPY
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CGA HOSS Barge 

• Use in areas with heaviest oil concentrations 

• Consider for use in areas of known debris (seaweed, and other floating materials) 

CGA FRUs 

• To the area of the thickest oil 

• Use as far off-shore as allowed 

• VOOs 140’ – 180’ in length 

• VOOs with minimum of 18’ x 38’ or 23’ x 50’ of optimum deck space 

• VOOs in shallow water should have a draft of <10 feet when fully loaded 

Storage Vessels 

• Establish availability of CGA contracted assets 

• Early call out (to allow for tug boat acquisition and deployment speeds) 

• Phase mobilization to allow storage vessels to arrive at the same time as skimming 

systems 

• Position as closely as possible to skimming assets to minimize offloading time 

Vessels of Opportunity (VOO) 

• Use BHP Billiton Petroleum (GOM) Inc.’s contracted resources as applicable 

• Industry vessels are usually best for deployment of Vessel of Opportunity Skimming 

Systems (VOSS) 

• Acquire additional resources as needed 

• Consider use of local assets, i.e. fishing and pleasure craft 

• Expect mission specific and safety training to be required 

• Plan with the US Coast Guard for vessel inspections 

In-situ Burn assets 

• Determine appropriateness of in-situ burn operation in coordination with the FOSC and 

affected State On-Scene Coordinator (SOSC) 

• Determine availability of fire boom and selected ignition systems 

• Start ordering fire boom stocks required for expected operations 

• Contact boom manufacturer to provide training if required 

• Determine assets to perform on water operation 

• Build operations into safety plan 

• Conduct operations in accordance with an approved plan 

Adverse Weather Operations: 

In adverse weather, when seas are > 3 feet, the use of larger recovery and storage vessels, 

oleophilic skimmers, and large offshore boom will be maximized. Safety will be the overriding 

factor in all operations and will cease at the order of the Unified Command, vessel captain, or in 

an emergency, ”stop work” may be directed by any crew member. 

ATTACHMENT J PUBLIC INFORMATION COPY
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Near Shore Response Actions 

Timing 

• Place near shore assets on standby and deploy in accordance with planning based on the 

actual situation, actual trajectories and oil budgets 

• VOO identification and training in advance of spill nearing shoreline if possible 

• Outfitting of VOOs for specific missions 

• Deployment of assets based on actual movement of oil 

Considerations 

• Water depth, vessel draft 

• Shoreline gradient 

• State of the oil 

• Use of VOOs 

• Distance of surf zone from shoreline 

Equipment Deployment 

Surveillance 

• Provide trained observer to direct skimming operations 

• Continual surveillance of oil movement by remote sensing systems, aerial photography 

and visual confirmation 

• Continual monitoring of vessel assets 

Dispersant Use 

• Generally will not be approved within 3 miles of shore or with less than 10 meters of 

water depth 

• Approval would be at Regional Response Team level (Region 6) 

Vessel Deployment 

Dedicated Near Shore skimming systems 

• Fast Response Vessels (FRV) 

• Egmopol and Marco Shallow Water Skimmer (SWS) 

• Operate with aerial spotter directing systems to observed oil slicks 

VOO 

• Use BHP Billiton Petroleum (GOM) Inc.’s contracted resources as applicable 

• Industry vessels are usually best for deployment of Vessel of Opportunity Skimming 

Systems (VOSS) 

• Acquire additional resources as needed 

• Consider use of local assets, i.e. fishing and pleasure craft 

• Expect mission specific and safety training to be required 

• Plan with the US Coast Guard for vessel inspections 

• Operate with aerial spotter directing systems to oil patches 

ATTACHMENT J PUBLIC INFORMATION COPY
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Shoreline Protection Operations 

Response Planning Considerations 

• Environmental risk assessments (ERA) to determine priorities for area protection 

• Time to acquire personnel and equipment and their availability 

• Previous contingency planning contained in the appropriate Area Contingency Plan, and 

currently for Louisiana, The State of Louisiana Initial Oil Spill Response Plan, Deep 

Water Horizon, dated 2 May 2010 

Actions 

Placement of boom 

• Position boom in accordance with the ERA based on the actual situation or the 

appropriate ACP 

• Assess timing of booming operations to ensure it is where it needs to be at time of 

impact. Consider: 

o Trajectories 

o Weather forecast 

o Oil Impact forecast 

o Verified spill movement 

o Boom, manpower and vessel (shallow draft) availability 

o Near shore boom and support material, (stakes, anchors, line) 

Beach Preparation 

Considerations and Actions 

• Use of a 10 mile go/no go line to determine timing of beach cleaning 

• Shoreline Cleanup and Assessment Team Reports and recommendations 

• Determination of Archeological sites and gaining authority to enter 

• Monitoring of tide tables and weather to determine extent of high tides 

• Pre cleaning of beaches by moving waste above high tide lines to minimize waste 

• Staging of equipment and housing of response personnel as close to the job site as 

possible to maximize on-site work time 

• Boom tending, repair, replacement and security (use of local assets may be advantageous) 

• Constant awareness of weather and oil movement for resource redeployment as necessary 

• In-situ burn may be considered when marshes have been impacted 

• Passive clean up of marshes should be considered and appropriate stocks of sorbent boom 

and/or sweep obtained 

• Earthen berms and shoreline protection boom may be considered to protect sensitive 

inland areas 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 8 of 14 

Decanting Strategy 

Recovered oil and water mixtures will typically separate into distinct phases when left in a 

quiescent state. When separation occurs, the relatively clean water phase can be siphoned or 

decanted back to the recovery point with minimal, if any, impact. Decanting therefore increases 

the effective on-site oil storage capacity and equipment operating time. FOSC/SOSC approval 

will be requested prior to decanting operations. This practice is routinely used for oil spill 

recovery. 

CGA Equipment Limitations 

The capability for any spill response equipment, whether a dedicated or portable system, to 

operate in differing weather conditions will be directly in relation to the capabilities of the vessel 

the system in placed on. Most importantly, however, the decision to operate will be based on the 

judgment of the Unified Command and/or the Captain of the vessel, who will ultimately have the 

final say in terminating operations. Skimming equipment listed below may have operational 

limits which exceed those safety thresholds. As was seen in the Deepwater Horizon (DWH) oil 

spill response, vessel skimming operations ceased when seas reached 5-6 feet and vessels were 

often recalled to port when those conditions were exceeded. Systems below are some of the 

most up-to-date systems available and were employed during the DWH spill. 

Boom 3 foot seas, 20 knot winds 

Dispersants Winds more than 25 knots 

Visibility less than 3 nautical miles 

Ceiling less than 1,000 feet. 

FRU 8 foot seas 

HOSS Barge/OSRB 8 foot seas 

Koseq Arms 8 foot seas 

OSRV 4 foot seas 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 9 of 14 

Environmental Conditions in the GOM

Louisiana is situated between the easterly and westerly wind belts, and therefore, experiences 

westerly winds during the winter and easterly winds in the summer. Average wind speed is 

generally 14-15 mph along the coast. Wave heights average 4 and 5 feet. However, during 

hurricane season, Louisiana has recorded wave heights ranging from 40 to 50 feet high and 

winds reaching speeds of 100 mph. Because much of southern Louisiana lies below sea level, 

flooding is prominent. 

Surface water temperature ranges between 70 and 80 ̊F during the summer months. During the 

winter, the average temperature will range from 50 and 60 ̊F. 

The Atlantic and Gulf of Mexico hurricane season is officially from 1 June to 30 November. 

97% of all tropical activity occurs within this window. The Atlantic basin shows a very peaked 

season from August through October, with 78% of the tropical storm days, 87% of the minor 

(Saffir-Simpson Scale categories 1 and 2) hurricane days, and 96% of the major (Saffir-Simpson 

categories 3, 4 and 5) hurricane days occurring then. Maximum activity is in early to mid 

September. Once in a few years there may be a hurricane occurring "out of season" - primarily in 

May or December. Globally, September is the most active month and May is the least active 

month. 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 10 of 14 

FIGURE 1 

TRAJECTORY BY LAND SEGMENT 

Trajectory of a spill and the probability of it impacting a land segment have been projected 

utilizing BHP Billiton Petroleum (GOM) Inc.’s WCD and information in the BSEE Oil 

Spill Risk Analysis Model (OSRAM) for the Central and Western Gulf of Mexico 

available on the BSEE website using 30 day impact. The results are tabulated below. 

Area/Block OCS-G Launch 

Area 

Land Segment and/or 

Resource 

Conditional 

Probability (%) 

within 30 days 

AT 574, Well E001 

114 miles from shore 

G08035 C62 Jefferson, TX 

Cameron, LA 

Vermilion, LA 

Terrebonne, LA 

Lafourche, LA 

Plaquemines, LA 

1 

2 

1 

1 

1 

3 

ATTACHMENT J PUBLIC INFORMATION COPY
Page 11 of 14 

WCD Scenario– BASED ON WELL BLOWOUT DURING DRILLING OPERATIONS (114 miles from shore) 

89,522 bbls of crude oil (Volume considering natural weathering) API Gravity 22.9° 

FIGURE 2 – Equipment Response Time to AT 574, Well E001 

Dispersants/Surveillance

Dispersant/Surveillance Dispersant Capacity (gal) Storage Capacity Persons Req. From Hrs to Procure Hrs to Loadout Travel to site Total Hrs 

CGA 

Basler 67T 2000 NA 2 Houma 1 1 0.8 2.8 

ASI 

DC 3 1200 NA 2 Houma 1 1 1 3 DC 3 1200 NA 2 Houma 1 1 1 3 Aero Commander NA NA 2 Houma 1 1 0.8 2.8 

Offshore Response

Offshore Equipment No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure Hrs to Loadout Hrs to GOM Travel to Spill Site Hrs to Deploy Total Hrs 

T&T Marine (available through contract with CGA) 

Koseq Skimming Arms (3) 53487 6000 3 Utility 18 Leeville 24 24 2 10 2 62 Koseq Skimming Arms (1) 17829 2000 1 Utility 6 Fourchon 24 24 1 10 2 61 Koseq Skimming Arms (2) 35658 4000 2 Utility 12 Venice 24 24 2 9.2 2 61.2 

CGA 

HOSS Barge 43000 4000 3 Tugs 5 Harvey 7 0 5 13.8 1 26.8 Boom Barge (CGA-300) 42” Auto Boom (25000’) NA NA 1 Tug 50 Crew 4 (Barge) 2 (Per Crew) Leeville 4 0 6 17.1 1.5 28.6 

Recovered Oil Storage No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure Hrs to Loadout Hrs to GOM Travel to Spill Site Hrs to Deploy Total Hrs 

K-Sea Operating (available through contract with CGA) 

DBL 81 1132231 NA 86948 1 Tug 6 Venice 4 12 2 13.75 1 32.75 

Enterprise Marine Services LLC (available through contract with CGA) 

CTCo 2603 NA 25000 1 Tug 6 Amelia 4 12 4 20 1 41 CTCo 2604 NA 20000 1 Tug 6 Amelia 4 12 4 20 1 41 CTCo 2605 NA 20000 1 Tug 6 Amelia 4 12 4 20 1 41 CTCo 2606 NA 20000 1 Tug 6 Amelia 4 12 4 20 1 41 
Page 12 of 14 

Staging Area: Venice

Offshore Equipment With 

Staging EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging Travel to Site Hrs to Deploy Total Hrs 

CGA 

FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Galveston 1 2 8 9.2 1 21.2 FRU (1) + 100 bbl Tank (1) 4251 100 1 Utility 6 Harvey 1 2 1.75 9.2 1 14.9 FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Ingleside 1 2 11 9.2 1 24.2 FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Lake Charles 1 2 5.5 9.2 1 18.7 FRU (2) + 100 bbl Tank (2) 8502 400 2 Utility 12 Leeville 1 2 3.5 9.2 1 16.7 FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Morgan City 1 2 3.25 9.2 1 16.4 FRU (2) + 100 bbl Tank (4) 8502 400 2 Utility 12 Venice 1 2 0 9.2 1 13.2 Hydro-Fire Boom NA NA 8 Utility 40 Harvey 1 4 1.75 9.2 6 21.9 
Page 13 of 14 

Nearshore Response

Nearshore Equipment No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure Hrs to Loadout Hrs to GOM Travel to Spill Site Hrs to Deploy Total Hrs 

CGA 

46’ FRV 5000 65 NA 4 Leeville 1 0 2 2 0 5 46’ FRV 5000 65 NA 4 Venice 1 0 1 2 0 4 Trinity SWS 21500 249 NA 4 Leeville 1 2 2 2 0 7 Trinity SWS 21500 249 NA 4 Morgan City 1 2 2 4.8 0 9.8 Trinity SWS 21500 249 NA 4 Venice 1 2 2 2 0 7 

Enterprise Marine Services LLC (available through contract with CGA) 

CTCo 2607 NA 23000 1 Tug 6 Amelia 4 12 4 15 1 36 CTCo 2608 NA 23000 1 Tug 6 Amelia 4 12 4 15 1 36 CTCo 5001 NA 47000 1 Tug 6 Amelia 4 12 4 15 1 36 

Staging Area: Venice

Nearshore and Inland Skimmers 

With Staging EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging Travel to Deployment Hrs to Deploy Total Hrs 

CGA 

SWS Egmopol 3000 100 NA 3 Morgan City 1 2 3.25 2 0 8.25 SWS Marco 3588 34 NA 3 Leeville 1 2 3.5 2 0 8.5 SWS Marco 3588 34 NA 3 Venice 1 2 0 2 0 5 Rope Mop 77 2 0 3 Harvey 1 2 8 2 0 13 Foilex Skim Package (TDS 150) 891 45 NA 3 Harvey 1 2 1.75 2 0 11 4 Drum Skimmer (Magnum 100) 686 100 1 Crew 3 Harvey 1 2 1.75 2 0 11 2 Drum Skimmer (TDS 118) 240 100 1 Crew 3 Lake Charles 1 2 5.5 2 0 8 
Page 14 of 14 

Shoreline Protection 

Staging Area: Venice 

Shoreline Protection 

Boom VOO Persons Req. Storage/Warehouse Location Hrs to Procure Hrs to Loadout Travel to Staging Travel to Deployment Hrs to Deploy Total Hrs 

ES&H (available through MSA) 

50,000’ 18” Boom 15 Lake Charles, LA .5 .5 5.5 2 15 23.5 20,000’ 18” Boom 10 Belle Chasse, LA .5 .5 2 2 6 11 15,000’ 18” Boom 8 Mobile, AL .5 .5 4.25 2 4 11.25 

5,000’ 18” Boom 4 Dallas Ft. Worth, TX .5 .5 10.25 2 2 15.25 

50,000’ 18” Boom 15 Houma, LA .5 .5 3 2 15 21 

Beach Boom EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging Travel to Deployment Hrs to Deploy Total Hrs 

CGA 

Beach Boom (2000’) NA NA NA 6 Galveston 1 2 8 1 2 14 Beach Boom (1000’) NA NA NA 4 Ingleside 1 2 11 1 2 17 Beach Boom (2000’) NA NA NA 6 Pascagoula 1 2 4 1 2 10 

Wildlife Response EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging Travel to Deployment Hrs to Deploy Total Hrs 

CGA 

Wildlife Support Trailer NA NA NA 2 Houma 1 2 3 1 2 9 Bird Scare Guns (24) NA NA NA 2 Belle Chasse 1 2 1.5 1 2 7.5 Bird Scare Guns (12) NA NA NA 2 Galveston 1 2 8 1 2 14 Bird Scare Guns (24) NA NA NA 2 Houma 1 2 3 1 2 9 Bird Scare Guns (12) NA NA NA 2 Ingleside 1 2 11 1 2 17 Bird Scare Guns (24) NA NA NA 2 Lake Charles 1 2 5.5 1 2 11.5 Bird Scare Guns (24) NA NA NA 2 Pascagoula 1 2 4 1 2 10 

Response Asset Total 

Offshore EDRC 188,233 

Offshore Recovered Oil Storage 189,648 

Nearshore / Shallow Water EDRC 86,570 

Nearshore / Shallow Water Recovered Oil Storage 94,292 
PUBLIC INFORMATION COPY
ATTACHMENT L PUBLIC INFORMATION COPY
Worst Case Discharge Modeling

Neptune SB03