UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field 

Operations (MS 5231)

Public Information copy of DOCD

Control # - S-07624

Type - Supplemental Development Operations Coordinations Document

Lease(s) - OCS-G24102 Block - 727 Mississippi Canyon Area

OCS-G24107 Block - 771 Mississippi Canyon Area

Operator - Deep Gulf Energy II, LLC

Subsea Well 002 (MC 771) and Wells 001 (MC 727)

Not Found

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

should be addressed in an Environmental Assessment.

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

Karen Dunlap

Plan Coordinator

G24107/MC/771

G24107/MC/771

G24102/MC/727

G24102/MC/727

G24102/MC/727

4613 FSL, 6743 FWL

4926 FSL, 6710 FWL

4926 FSL, 6870 FWL

4926 FSL, 6870 FWL

4373 FSL, 6743 FWL

G24102/MC/727

G24102/MC/727

G24102/MC/727

G24102/MC/727

G24102/MC/727

WELL/002

WELL/002

WELL/003

WELL/003

WELL/003

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

Description -

Rig Type -

Subject:

From:

February 12, 2014
Records of Changes – PUBLIC COPY 

Plan Control Number S-7624 

Supplemental Development Operations Coordination Document, Deep Gulf Energy II, LLC, 

OCS-G 24102/24107; Mississippi Canyon 727 / 771 

Date Section Page Remarks 

07/31/2013 All All Plan received by BOEM. 09/09/2013 Cover Letter Revise the first number in the Unit Agreement. 09/09/2013 1 5 Include previous activities. 09/09/2013 1 7 Update storage tank total capacity (1, 3 and 4th tan09/09/2013 Attachment 1-A Include the end date for production. Update descr

pipelines. 

09/09/2013 2 Page 8 Update bonding statement. 09/09/2013 4 Page 11 Added Request for H2s Determination. 09/09/2013 7 Attachment 7-A Updated Waste Table including discharge rate and 09/09/2013 8 Attachment 8-A Added AQR Reduction Measure chart. 09/09/2013 9 Page 19 Referenced the plan the GB506 #004 WCD was v09/09/2013 14 Page 25 

Included crew boats to the support vessel chart ansupply vessels capacity as “gallons”. 

09/09/2013 16 Pages 27-29 and Attachment 16-A 

Included Texas CZM Enforceable Policies and a TCertification. 

09/10/2013 2 Page 10 Updated bonding statement. 09/11/2013 Cover Letter Revise from Initial DOCD to Supplemental DOCD 09/24/2013 7 Attachment 7-A Updated waste table. 09/24/2013 14 Attachment 14-A Updated waste table. 09/27/2013 7 Attachment 7-A Removed discharge of synthetic based mud from 01/09/2014 1 Attachments 1-A and 1-B Updated for new surface locations. 01/09/2014 6 Attachment 6-A Updated for new surface locations 01/09/2014 9 Pages 19 and 20 

Updated 9.1 to reflect OSRP approval and 9.4 comreflect MC771 #002 as WCD in both DOCD and a

01/10/2014 1 Attachment 1-A Update Surface Location E/W Departure 01/10/2014 9 Pages 19 and 20 Include certification statement. 01/30/2014 18 Page 31 Update bibliography to include OSRP Control Num01/30/2014 All All Complete copy of Supplemental DOCD. 
PUBLIC COPY 

July, 2013 

UNIT DEVELOPMENT 

OPERATIONS COORDINATION DOCUMENT

KODIAK DEVELOPMENT UNIT 

UNIT CONTRACT NO. 754313008

Lease Numbers: OCS-G 24102 / 24107 

Area/Block: Mississippi Canyon Blocks 727 / 771 

Prospect Name: Kodiak

Offshore: Louisiana / Mississippi

Submitted by: Deep Gulf Energy II, LLC 

 738 Highway 6 South 

 Suite 800 

 Houston, Texas 77079 

 Company Contact: 

 Thomas E. Young 

 (281) 596-0933 

tyoung@deepgulfenergy.com 

Estimated start-up date: September 2014 

Authorized Representative: No. Copies Being Submitted: 

Kelley Pisciola Proprietary: 1 Copy & CD 

J. Connor Consulting, Inc. Public Info: 1 Copy & CD 

16225 Park Ten Place, Suite 700 

Houston, Texas 77084 For BOEM: 

(281) 578-3388 Plan No. 

kelley.pisciola@jccteam.com Assigned to: 
SECTION ATTACHMENTS

Section 1 Plan Contents 

 1-A OCS Plan Information Form 

 1-B Well Location Plat 

 1-C Pay.gov Receipt 

Section 2 General Information

 2-A Blowout Assumptions and Worst Case Discharge Calculations 

Section 3 Geological, Geophysical Information 

 3-A Structure Contour Maps (Proprietary Plan Only)

 3-B Interpreted Seismic Lines (Proprietary Plan Only)

 3-C Geological Structure Cross Sections (Proprietary Plan Only)

 3-D Shallow Hazard Assessments 

 3-E Stratigraphic Column (Proprietary Plan Only)

Section 6 Biological, Physical and Socioeconomic Information 

 6-A Topographic Features Map 

Section 7 Wastes and Discharges Information 

 7-A Wastes You Will Generate, Treat and Downhole Dispose or 

Discharge to the GOM 

Section 8 Air Emissions Information 

 8-A Emissions Worksheets

Section 9 Oil Spill Information 

 9-A Oil Spill Response Discussion 

 9-B 

Worst Case Discharge Calculations and Assumptions (Proprietary 

Plan Only)

Section 14 Support Vessels and Aircraft Information 

 14-A Waste You Will Transport and/or Dispose Onshore 

 14-B Vicinity Map 

Section 16 Coastal Zone Management Act Information 

 16-A Coastal Zone Consistency Certification, Texas 

Section 17 Environmental Impact Analysis (EIA) 

 17-A Environmental Impact Analysis (EIA) 
TOC Pg 1 of 31 

TABLE OF CONTENTS 

SECTION 1 PLAN CONTENTS ..................................................................................... 5

1.1 PLAN INFORMATION ............................................................................................ 5

1.2 LOCATION ............................................................................................................. 5

1.3 SAFETY AND POLLUTION PREVENTION FEATURES ....................................... 5

1.4 STORAGE TANKS AND PRODUCTION VESSELS .............................................. 7

1.5 POLLUTION PREVENTION MEASURES ............................................................. 7

1.6 ADDITIONAL MEASURES .................................................................................... 7

1.7 COST RECOVERY FEE ........................................................................................ 7

SECTION 2 GENERAL INFORMATION ........................................................................ 8

2.1 APPLICATIONS AND PERMITS ........................................................................... 8

2.2 DRILLING FLUIDS ................................................................................................. 8

2.3 PRODUCTION ....................................................................................................... 8

2.4 OIL CHARACTERISTICS ...................................................................................... 8

2.5 NEW OR UNUSUAL TECHNOLOGY .................................................................... 8

2.6 BONDING STATEMENT ........................................................................................ 8

2.7 OIL SPILL FINANCIAL RESPONSIBILITY (OSFR) ............................................... 9

2.8 DEEPWATER WELL CONTROL STATEMENT .................................................... 9

2.9 SUSPENSION OF PRODUCTION ........................................................................ 9

2.10 BLOWOUT SCENARIO ....................................................................................... 9

SECTION 3 GEOLOGICAL AND GEOPHYSICAL INFORMATION ........................... 10

3.1 GEOLOGICAL DESCRIPTION ............................................................................ 10

3.2 STRUCTURE CONTOUR MAPS ......................................................................... 10

3.3 INTERPRETED 3-D SEISMIC LINES .................................................................. 10

3.4 GEOLOGICAL STRUCTURE CROSS-SECTIONS ............................................. 10

3.5 SHALLOW HAZARDS REPORT ......................................................................... 10

3.6 SHALLOW HAZARDS ASSESSMENT ................................................................ 10

3.7 HIGH-RESOLUTION SEISMIC LINES ................................................................. 10

3.8 STRATIGRAPHIC COLUMN ............................................................................... 10
TOC Pg 2 of 31 

3.9 TIME VS DEPTH TABLES ................................................................................... 10

SECTION 4 HYDROGEN SULFIDE INFORMATION .................................................. 10

4.1 CONCENTRATION .............................................................................................. 11

4.2 CLASSIFICATION ............................................................................................... 11

4.3 H2S CONTINGENCY PLAN ................................................................................ 11

4.4 MODELING REPORT .......................................................................................... 11

SECTION 5 MINERAL RESOURCE CONSERVATION INFORMATION .................... 12

5.1 TECHNOLOGY & RESERVOIR ENGINEERING PRACTICES AND 

PROCEDURES .......................................................................................................... 12

5.2 TECHNOLOGY AND RECOVERY PRACTICES AND PROCEDURES .............. 12

5.3 RESERVOIR DEVELOPMENT ............................................................................ 12

SECTION 6 BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION .... 13

6.1 DEEPWATER BENTHIC COMMUNITIES ........................................................... 13

6.2 TOPOGRAPHIC FEATURES (BANKS) ............................................................... 13

6.3 TOPOGRAPHIC FEATURES STATEMENT (SHUNTING) .................................. 13

6.4 LIVE-BOTTOMS (PINNACLE TREND FEATURES) ............................................ 13

6.5 LIVE BOTTOMS (LOW RELIEF) ......................................................................... 13

6.6 POTENTIALLY SENSITIVE BIOLOGICAL FEATURES ...................................... 13

6.7 REMOTELY OPERATED VEHICLE (ROV) SURVEYS ....................................... 14

6.8 THREATENED AND ENDANGERED SPECIES, CRITICAL HABITAT, AND 

MARINE MAMMAL INFORMATION .......................................................................... 14

6.9 ARCHAEOLOGICAL REPORT ............................................................................ 16

6.10 AIR AND WATER QUALITY INFORMATION .................................................... 16

6.11 SOCIOECONOMIC INFORMATION .................................................................. 16

SECTION 7 WASTES AND DISCHARGES INFORMATION ...................................... 17

7.1 PROJECTED GENERATED WASTES ................................................................ 17

7.2 MODELING REPORT .......................................................................................... 17

SECTION 8 AIR EMISSIONS INFORMATION ............................................................ 18

8.1 EMISSIONS WORKSHEETS AND SCREENING QUESTIONS .......................... 18

8.2 SUMMARY INFORMATION ................................................................................. 18

SECTION 9 OIL SPILL INFORMATION ...................................................................... 19
TOC Pg 3 of 31 

9.1 OIL SPILL RESPONSE PLANNING .................................................................... 19

9.2 SPILL RESPONSE SITES ................................................................................... 19

9.3 OSRO INFORMATION ........................................................................................ 19

9.4 WORST-CASE DISCHARGE SCENARIO DETERMINATION ............................ 19

SECTION 10 ENVIRONMENTAL MONITORING INFORMATION .............................. 21

10.1 MONITORING SYSTEMS .................................................................................. 21

10.2 INCIDENTAL TAKES ......................................................................................... 21

10.3 FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY ..................... 21

SECTION 11 LEASE STIPULATIONS INFORMATION .............................................. 22

11.5 MARINE PROTECTED SPECIES ..................................................................... 22

SECTION 12 ENVIRONMENTAL MITIGATION MEASURES INFORMATION ........... 23

12.1 MEASURES TAKEN TO AVOID, MINIMIZE, AND MITIGATE IMPACTS .......... 23

12.2 INCIDENTAL TAKES ......................................................................................... 23

SECTION 13 RELATED FACILITIES AND OPERATIONS INFORMATION .............. 24

13.1 RELATED OCS FACILITIES AND OPERATIONS ............................................. 24

13.2 TRANSPORTATION SYSTEM .......................................................................... 24

13.3 PRODUCED LIQUID HYDROCARBONS TRANSPORTATION VESSELS ....... 24

SECTION 14 SUPPORT VESSELS AND AIRCRAFT INFORMATION ...................... 25

14.1 GENERAL .......................................................................................................... 25

14.2 DIESEL OIL SUPPLY VESSELS ....................................................................... 25

14.3 DRILLING FLUID TRANSPORTATION ............................................................. 25

14.4 SOLID AND LIQUID WASTE TRANSPORTATION ........................................... 25

14.5 VICINITY MAP ................................................................................................... 25

SECTION 15 ONSHORE SUPPORT FACILITIES INFORMATION ............................ 26

15.1 GENERAL .......................................................................................................... 26

15.2 SUPPORT BASE CONSTRUCTION OR EXPANSION ..................................... 26

15.3 SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE ................ 26

15.4 WASTE DISPOSAL ........................................................................................... 26

SECTION 16 COASTAL ZONE MANAGEMENT (CZM) INFORMATION ................... 27

SECTION 17 ENVIRONMENTAL IMPACT ANALYSIS (EIA) ..................................... 30

SECTION 18 ADMINISTRATIVE INFORMATION ........................................................ 31
TOC Pg 4 of 31 

18.1 EXEMPTED INFORMATION DESCRIPTION .................................................... 31

18.2 BIBLIOGRAPHY ................................................................................................ 31
Deep Gulf Energy II, LLC Section 1 – Pg. 5 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 1 

PLAN CONTENTS 

1.1 PLAN INFORMATION 

Effective February 1, 2013, Mississippi Canyon Blocks 727 (S/2) and 771 (N/2), (Leases 

OCS-G 24102 and 24107 respectively) were unitized under Unit Contract No. 

754313008 (Mississippi Canyon (MC) Block 727 Unit (Kodiak Unit)). Deep Gulf Energy 

II, LLC (DGE II) as designated operator of the subject unit hereby submits this Unit 

Development Operations Coordination Document. 

DGE II proposes to drill, complete and produce two well locations and two lease-term 

pipelines. The subsea system will include the installation of (2) subsea trees, (2) leaseterm jumper pipelines, a bulk right-of-way pipeline, flowline end termination (FLET), an 

umbilical termination assembly (UTA) and associated electrical/optical/hydraulic flying 

leads. These development operations are in approximately 4833 feet of water. The 

wells will be drilled with a dynamically positioned semi-submersible MODU. The right-ofway pipeline, lease term pipelines and umbilical system will be installed using a 

dynamically positioned lay barge. 

A Development Operations Coordination Document (N-8279) was submitted by 

Dominion Exploration & Production, Inc. on November 19, 2004 and approved on 

January 20, 2005. The plan provided for the production of Mississippi Canyon Block 

771, Lease OCS-G 24107 (Goldfinger SS005), and the installation of a jumper pipeline 

to tie the well into the flowline. To date, the jumper has been installed, and the well has 

been placed on continuous production. 

The OCS Plan Information Form BOEM-137 is included as Attachment 1-A.

1.2 LOCATION 

Well Location Plats depicting the proposed surface and bottomhole locations of the 

proposed wells, measured depth/total vertical depth and water depth for each location 

are included as Attachment 1-B. Operations proposed in this plan will be conducted 

using dynamically positioned vessels; therefore, there will be no associated anchors. 

1.3 SAFETY AND POLLUTION PREVENTION FEATURES 

Safety of personnel and protection of the environment during the proposed operations is 

one of the primary concerns of DGE II. DGE II mandates regulatory compliance with the 

contractors and vendors associated with the proposed operations as follows: 
Deep Gulf Energy II, LLC Section 1 – Pg. 6 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

The Bureau of Ocean Energy Management (BOEM) mandates that the operations 

described in this Initial DOCD comply with well control, pollution prevention, 

construction, welding procedures, and training described in BSEE regulations 30 CFR 

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

The Bureau of Safety and Environmental Enforcement (BSEE) conducts periodic 

announced and unannounced onsite inspections of offshore facilities to confirm 

operators are complying with lease stipulations, operating regulatory regulations, 

approved plans, and other conditions; as well as to assure safety and pollution 

prevention requirements are being met. The National Potential Incident of 

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

U.S. Coast Guard regulations contained in Title 33 CFR Part 144 mandate that 

appropriate life rafts, life jackets, ring buoys, etc. be maintained on the facilities at all 

times. 

U.S. Environmental Protection Agency regulations contained in the NPDES General 

Permit GMG290000 mandate that supervisory and certain designated personnel onboard the facility be familiar with the effluent limitations and guidelines for overboard 

discharges into the receiving waters. 

A description of the drilling unit is included on the OCS Plan Information Form which 

complies with all relevant regulations. Rig specifications will be made part of each 

Application for Permit to Drill. DGE II will drill these wells with a dynamically positioned 

semi-submersible MODU which will be equipped with a Subsea BOP. Once a rig is 

contracted, BOP information and schematics will be included as a part of the Application 

for Permit to Drill.

Safety features on the drilling unit will include well control, pollution prevention, and 

blowout prevention equipment as described in BSEE regulations 30 CFR 250 C, D, E, O 

and S; and as further clarified by BSEE Notices to Lessees, and current policy making 

invoked by the BSEE, Environmental Protection Agency and the U.S. Coast Guard. 

Appropriate life rafts, life jackets, ring buoys, etc., will be maintained on the facility at all 

times. 

Pollution prevention measures include installation of curbs, gutters, drip pans, and 

drains on drilling deck areas to collect all contaminants and debris. 
Deep Gulf Energy II, LLC Section 1 – Pg. 7 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

1.4 STORAGE TANKS AND PRODUCTION VESSELS 

All facility tanks with a capacity of 25 bbls or more. 

Type of 

Storage 

Tank 

Type of 

Facility 

Tank 

Capacity 

(bbls) 

Number 

of Tanks 

Total 

Capacity 

(bbls) 

Fluid 

Gravity 

(API) 

Fuel Oil 

(day/settling 

tanks) 

DP 

Semisubmersible 360/256/161 3 777 No.2 Diesel 

Emergency 

Generator 

Fuel Oil 

DP 

Semisubmersible 31 1 31 No. 2 Diesel 

Fuel Oil 

(port) 

DP 

Semisubmersible 4541/3396 2 7937 No. 2 Diesel 

Fuel Oil 

(stb) 

DP 

Semisubmersible 4541/3396 2 7937 No. 2 Diesel 

Lube Oil DP 

Semisubmersible 116 1 116 26° 

Waste Oil DP 

Semisubmersible 38/28 2 66 26° 

Oily Water 

(port) 

DP 

Semisubmersible 186/178 2 364 N/A 

Oily Water 

(stb) 

DP 

Semisubmersible 186/178 2 364 N/A 

1.5 POLLUTION PREVENTION MEASURES 

These operations do not propose activities for which the State of Florida is an affected 

state; therefore, relevant information is not required. 

1.6 ADDITIONAL MEASURES 

DGE II does not propose any additional safety, pollution prevention, or early spill 

detection measures beyond those required by 30 CFR Part 250. 

1.7 COST RECOVERY FEE 

A pay.gov receipt in the amount of $8,476.00 to cover the cost recovery fee associated 

with this plan is included as Attachment 1-C. 
U.S. Department of the Interior ATTACHMENT 1-A

Bureau of Ocean Energy Management 

Have you previously provided information to verify the calculations and assumptions for your WCD? Yes X No 

If so, provide the Control Number of the EP or DOCD with which this information was provided 

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

Do you propose to use a vessel with anchors to install or modify a structure? Yes X No 

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

Description of Proposed Activities and Tentative Schedule (Mark all that apply) 

Proposed Activity Start Date End Date No. of Days 

Drill and Complete Well Location A – MC771 #002 09/01/2014 04/18/2015 229 

Install Lease Term Jumper Pipeline 04/24/2015 04/30/2015 7 

Commence Production from Location A – MC772 #002 05/15/2015 05/15/2025 10 years 

Drill and Complete Well Location B – MC727 #003 01/01/2016 08/17/2016 229 

Install Lease Term Jumper Pipeline 08/25/2016 08/31/2016 7 

Commence Production from Location B – MC727 #003 09/18/2016 09/18/2026 10 years 

 

Description of Drilling Rig Description of Structure 

 Jackup Drillship Caisson Tension leg platform 

 Gorilla Jackup Platform rig Fixed platform Compliant tower 

 Semisubmersible Submersible Spar Guyed tower 

X DP Semisubmersible Other (Attach description) Floating production 

system Other (Attach description) 

Drilling Rig Name (If known): Ensco Series 8500 equivalent or similar MODU 

Description of Lease Term Pipelines 

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

Well Location A – MC771 #002 MC727 FLET 8-inch 85 

Well Location B – MC727 #003 MC727 FLET 8-inch 85 

Form BOEM- 0137 (December 2011 – Supersedes all previous editions of this form which may not be used.) Page 1 of 4 

General Information 

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

Company Name: Deep Gulf Energy II, LLC BOEM Operator Number: 02985 

Address: 738 Highway 6 South, Suite 800 Contact Person: Kelley Pisciola 

 Houston, TX 77079 Phone Number: 281-698-8519 

E-Mail Address: kelley.pisciola@jccteam.com 

If a service fee is required under 30 CFR 550.125(a), provide the Amount paid $8476.00 Receipt No. NA 

Project and Worst Case Discharge (WCD) Information 

Lease(s): G24102 / 24107 Area: Mississippi Canyon Block(s) 727 / 771 Project Name (If Applicable): Kodiak 

Objective(s) X Oil Gas Sulphur Salt Onshore Support Base(s): Fourchon, LA 

Platform / Well Name: MC771 Well No. 002 Total Volume of WCD: 14,974,192 bbls API Gravity: 35° 

Distance to Closest Land (Miles): 54 Volume from uncontrolled blowout: 107,728 bbls/day 

OCS PLAN INFORMATION FORM 

OMB Control Number: 1010-0151

OMB Approval Expires: 12/31/14 
OCS PLAN INFORMATION FORM (CONTINUED) 

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

Proposed Well/Structure Location 

Well or Structure Name/Number (If renaming well or 

structure, reference previous name): A - MC771 #002 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. 

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): 107,728 

For structures, volume of all storage and pipelines 

(Bbls): N/A API Gravity of fluid 35° 

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple completions, enter 

separate lines) 

Lease No. OCS-G 24102 OCS 

OCS 

Area Name Mississippi Canyon 

Block No. 727 

Blockline 

Departures 

(in feet) 

N/S Departure 4,926.00’ FSL N/S Departure 

N/S Departure F __ L 

N/S Departure F __ L 

N/S Departure F __ L 

E/W Departure 6,710.00’ FWL E/W Departure 

E/W Departure F __ L 

E/W Departure F __ L 

E/W Departure F __ L 

Lambert X-Y 

coordinates 

 

X: 1,052,150.00’ X: 

X: 

X: 

X: 

Y: 10,253,406.00’ Y: 

Y: 

Y: 

Y: 

Latitude/ 

Longitude 

Latitude 28° 14’ 32.9302” Latitude 

Latitude 

Latitude 

Latitude 

Longitude 88° 49’ 39.1139” Longitude 

Longitude 

Longitude 

Longitude 

Water Depth (Feet): 4,818’ MD (Feet): TVD (Feet): MD (Feet): 

MD (Feet): 

MD (Feet): 

TVD (Feet): 

TVD (Feet): 

Anchor Radius (if applicable) in feet: N/A TVD (Feet): 

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 4 
OCS PLAN INFORMATION FORM (CONTINUED) 

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

Proposed Well/Structure Location 

Well or Structure Name/Number (If renaming well or 

structure, reference previous name): B - MC727 #003 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. 

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): 107,728 

For structures, volume of all storage and pipelines 

(Bbls): N/A API Gravity of fluid 35° 

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple completions, enter 

separate lines) 

Lease No. OCS-G 24102 OCS 

OCS 

Area Name Mississippi Canyon 

Block No. 727 

Blockline 

Departures 

(in feet) 

N/S Departure 4,926.00’ FSL N/S Departure 

N/S Departure F __ L 

N/S Departure F __ L 

N/S Departure F __ L 

E/W Departure 6,870.00’ FWL E/W Departure 

E/W Departure F __ L 

E/W Departure F __ L 

E/W Departure F __ L 

Lambert X-Y 

coordinates 

 

X: 1,052,310.00’ X: 

X: 

X: 

X: 

Y: 10,253,406.00’ Y: 

Y: 

Y: 

Y: 

Latitude/ 

Longitude 

Latitude 28° 14’ 32.9548” Latitude 

Latitude 

Latitude 

Latitude 

Longitude 88° 49’ 37.3251” Longitude 

Longitude 

Longitude 

Longitude 

Water Depth (Feet): 4,823’ MD (Feet): TVD (Feet): MD (Feet): 

MD (Feet): 

MD (Feet): 

TVD (Feet): 

TVD (Feet): 

Anchor Radius (if applicable) in feet: N/A TVD (Feet): 

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 4 
MC_727

MC_771

11

34

5

6

1

1

2

23

Deep Gulf Energy II, LLC

Kodiak MC 727-771

Well Surface Locations

Base Map 

0 12000 ft 4000 8000

Scale = 1:48000

X/Y:

Feet

X = 1,061,280’

X = 1,045,440’

Y = 10,264,320’’

Y = 10,248,480’

Y = 10,232,640’

Surface Location

OCS‐G 24107 Well No. 2

X = 1,,052,150.00’

Y = 10,253,406.00’

Lat: 28 ° 14’ 32.9302” N

Long: 88 ° 49’ 39.1139” W

6,710’ FWL of MC 727

4,926’ FSL of MC 727

PTD: 29,769’md  28,350’tvd

Water Depth 4,818’

Surface Location

OCS‐G 24102 Well No. 3

X = 1,052,310.00’

Y = 10,253,406.00’

Lat: 28 ° 14’ 32.9548” N

Long: 88 ° 49’ 37.3251” W

6,870’ FWL of MC 727

4,926’ FSL of MC 727

PTD: 27,589’md   26,075’tvd

Water Depth 4,823’
1

Kelley Pisciola

From: paygovadmin@mail.doc.twai.gov

Sent: Friday, July 26, 2013 8:46 AM

To: Ruth Strange

Subject: Pay.gov Payment Confirmation: BOEM Development/DOCD Plan - BD

Your payment has been submitted to Pay.gov and the details are below. If you have any questions or wish to cancel this

payment, you will need to contact Wendy Yanez at (504) 736‐2818.

Application Name: BOEM Development/DOCD Plan ‐ BD Pay.gov Tracking ID: 25BNBB96 Agency Tracking ID:

74481773863

Account Holder Name: Deep Gulf Energy II, LLC Transaction Type: ACH Debit Transaction Amount: $8,476.00 Payment

Date: Jul 29, 2013 Account Type: Business Checking Routing Number: 121000248 Account Number: ************3536

Transaction Date: Jul 26, 2013 9:45:53 AM Total Payments Scheduled: 1

Frequency: OneTime

Region: Gulf of Mexico

Contact: Kelley Pisciola 281‐698‐8519

Company Name/No: Deep Gulf Energy II, LLC, 02985 Lease Number(s): 24102, 24107, , ,

Area‐Block: Mississippi Canyon MC, 727: Mississippi Canyon MC, 771: , : , : ,

Type‐Wells: Initial Plan, 2  

THIS IS AN AUTOMATED MESSAGE.  PLEASE DO NOT REPLY.
Deep Gulf Energy II, LLC Section 2 – Pg. 8 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 2 

GENERAL INFORMATION 

2.1 APPLICATIONS AND PERMITS 

Listed in the table below are the additional applications/permits to be filed before 

operations can commence under this DOCD. 

Application/Permit Issuing Agency Status 

APD BSEE To be Submitted 

Surface Commingling Application BSEE To be Submitted 

Deepwater Operations Plan BSEE To be Submitted 

Conservation Information Document BOEM Submitted 07/30/2013 

Lease Term Pipeline Application BSEE To be Submitted 

ROW Pipeline Application BSEE To be Submitted 

Suspension of Production BSEE To be Submitted 

2.2 DRILLING FLUIDS 

The following table provides information on the types and amounts of the drilling fluids

DGE II plans to use to drill the proposed wells.

Type of Drilling Fluid Estimated Volume of Drilling Fluid to be 

Used per Well 

Water-based 40000 bbls/well 

Oil-based (diesel, minerals) N/A 

Synthetic-based 20000 bbls/well 

2.3 PRODUCTION 

Proprietary Information 

2.4 OIL CHARACTERISTICS 

Proprietary Information 

2.5 NEW OR UNUSUAL TECHNOLOGY 

No new or unusual technology is proposed in this DOCD. 

2.6 BONDING STATEMENT 

The bond requirements for the activities and facilities proposed in this DOCD are 

satisfied by both a lease-specific bond for OCS-G 24102 and a $3,000,000.00 areawide bond for OCS-G 24107, furnished and maintained according to 30 CFR 256, 

subpart I; NTL No. 2000-G16, "Guidelines for General Lease Surety Bonds;" and 
Deep Gulf Energy II, LLC Section 2 – Pg. 9 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

additional security under 30 CFR 256.53(D) and National NTL 2008-N07, 

“Supplemental Bond Procedures.” 

2.7 OIL SPILL FINANCIAL RESPONSIBILITY (OSFR) 

Deep Gulf Energy II, LLC, BOEM company number 02985 has demonstrated or will 

demonstrate oil spill financial responsibility for the facilities proposed in this DOCD 

according to 30 CFR Part 553; and NTL 2008-N05, "Guidelines for Oil Spill Financial 

Responsibility for Covered Facilities." 

2.8 DEEPWATER WELL CONTROL STATEMENT 

Deep Gulf Energy II, LLC, BOEM company number 02985, has the financial capability 

to drill a relief well and conduct other emergency well control operations. 

2.9 SUSPENSION OF PRODUCTION 

The subject leases are currently held by a unit suspension of production approved from 

June 1, 2013 through April 30, 2014. An additional unit suspension of production will be 

requested in 2014. 

2.10 BLOWOUT SCENARIO 

In accordance with NTL 2010-N06, “Information Requirements for Exploration Plans, 

Development and Production Plans, and Development Operations Coordination 

Documents on the OCS,” the blowout scenario is included as Attachment 2-A.
ATTACHMENT 2-A 

Blowout Scenario 

Estimated maximum flow rate 

The estimated maximum flow rate would occur in the objective section, if a kick were 

taken and the well blew out. The maximum Worst Case Discharge (WCD) modeled for 

this scenario is 107,728 BOPD. 

Maximum duration of blowout (days) 

The duration of the blowout will be a function of the well bridging over, the ability of 

surface intervention to shut-in or contain the well or, as a last resort, drilling a relief well 

to kill the blowout. The expected maximum time frames for uncontrolled flow in each of 

the different operational outcomes would be as follows: 

 Bridging Over in 2 Days, 

 Surface Intervention in 15 Days, 

 A Relief Well in 139 Days. 

Maximum discharge volume 

The following table is a linear estimate of the maximum discharge volume for each of 

the aforementioned operational outcomes assuming no reservoir depletion. 

Operational 

Outcome 

Maximum 

Discharge 

Rate 

(bbl/day) 

Discharge 

Duration 

(days) 

Maximum 

Discharge 

Volume (bbl) 

Bridging Over 107,728 2 215,456 

Surface 

Intervention 

107,728 15 1,615,920

Relief Well 107,728 139 14,974,192 

Potential of wellbore to bridge over during a blowout 

There is significant potential for the wellbore to bridge over during the WCD blowout. 

Bridging is likely to occur due to the extreme drawdown calculated between the 

formation and the open hole section. A Merlin reservoir simulation model was used to 

investigate the well conditions during the WCD blowout scenario. The estimated 

reservoir pressure is 21,167 psi. The reservoir model estimates bottom hole flowing 

pressures, based upon reservoir properties and flow rates. The calculated delta 

reservoir pressure (initial reservoir pressure minus flowing BHP at Day 1 WCD rate) is 

modeled to be 11,875 psi. 
In our experience in the deepwater GOM, we strive to limit the estimated total 

drawdown on a producing interval to reduce the risk of wellbore collapse and sand/fines 

migration into a well. We limit the drawdown to typically less than 4,000 psi by reducing 

the rates the wells produce and by completing each well with a cased hole, frac-pack 

completion. 

There is a strong likelihood of wellbore bridging over as: 

 Drawdown is estimated to be nearly 3 times greater than our operating 

practices, 

 The blowout occurs in a long open hole section of the well, with no benefit 

of casing or a frac-pack completion, 

 If any water zones are exposed this will accelerate wellbore collapse and 

bridging, 

Surface intervention to stop the blowout 

In the event of a blowout and assuming the blowout prevention equipment is still intact; 

the subsea BOP will be used for successful shut-in of the well. The well would then be 

killed and re-entered to either abandon or return to normal operations. Surface 

intervention would be the first line of defense after a blowout occurs. The specific 

intervention technique chosen will depend on actual conditions and ability to access the 

existing well. 

In the event that the subsea BOP is inoperable, the surface intervention would employ 

the Helix Well Containment Group (HWCG) containment system to achieve successful 

containment of the well. The system will be employed, while simultaneously initiating 

relief well planning and operations. Specifics will be submitted within the Well 

Containment Plan with the APD. 

Typically blowouts can be controlled with surface intervention, with a good likelihood of 

success and in a relatively short time frame, as long as, the subsea casing, wellhead 

and BOP’s are not damaged beyond use. The intervention technique chosen will 

depend on actual conditions and ability to access the existing well. There can be simple 

solutions such as rig up and bullhead kill mud or more complex solutions, but the 

solution will depend on wellbore conditions. 

Surface intervention time estimate 

The assumption is that the well has an uncontrolled blowout and the MODU has sunk 

with displacement from the wellhead. Additionally, it assumes that debris removal will be 

required to gain access to the subsea BOP system. The ROV has been deployed and 

was unsuccessful in shutting in the well, using the existing subsea BOP control panel. 

The scenario employs one of the aforementioned containment system’s capping BOPs. 

The table on the next page describes the estimated time required to shut in and secure 

the well using the containment system or capping stack. Note that these operations all 

basically start at the same point in time and are performed in parallel. The entire 

operation is estimated to take 15 days from start of site assessment until the capping 

stack has been deployed and the well shut in. 
Duration of a well capping operation 

Operation Incremental 

Duration 

(days) 

Cumulative Time Since 

Event Start 

(days) 

Assess wellbore conditions for 

surface intervention requirements. 

Conduct notifications to the 

regulatory agencies and primary 

contractors. Well capping and/or 

cap and flow operations which 

include mobilization, deployment, 

and installation of the well 

containment system 

2 2 

Site Preparation which includes 

mobilizing and deployment of the 

IWOCS System and Dispersant 

System. 

5 7 

Debris removal including 

mobilization of ROV boat and 

construction support vessel and 

execution of debris removal plan. 

7 14 

Run cap and seal well. 1 15 

Relief Well 

It is preferred to drill relief wells from an open water location, rather than a platform 

location. Open water locations provide the best option on designing a simpler intercept 

well and allow a greater choice on rig availability. There are not any platforms in the 

immediate vicinity; therefore, it is not feasible to consider as a relief well location. 

Relief well location and drilling strategy 

The surface location for a relief well(s) is a function of seabed bottom and shallow 

hazard conditions, current, wind direction and wellbore access. The relief well surface 

location for the MC 771 Well No. 002 (drilled from Well Site A surface location) could be 

drilled from an appropriately cleared-of-hazards surface location to the south-southwest 

or north-northwest of the Well Site A location. DGE II has investigated ten (10) surface 

location sites in MC 727. Two (2) of the surface location sites investigated resulted in 

Well Site A (planned MC 771 Well No. 002 location) and Well Site B (planned MC 727 

Well No. 003 location). Two (2) other surface location sites investigated (one 

approximately 2900’ south-southwest of Well Site A, one approximately 2800’ northnorthwest of Well Site A) would be appropriate for relief well locations. 
A relief well for MC 771 Well No. 002 would be designed to intersect the blowout well 

below the 14” or 11-7/8” casing point. Once the well is intersected, kill pumping 

operations would be initiated to kill the blowout well. 

Relief well design approach for other locations would be very similar, with other 

approved surface locations used to initiate relief wells. 

Relief well rig availability 

The rigs listed below could be available for relief well operations: 

Rig Name Contractor

Rated 

Water 

Depth 

MODU Type Rig Status 

Ensco 8500 Ensco 8,500’ DP Semisubmersible Contracted 

GOM

Ensco 8501 Ensco 8,500’ DP Semisubmersible Contracted 

GOM

Ensco 8505 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

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

GOM 

Discoverer Deep 

Seas 

Transocean 10,000’ DP Drill Ship Contracted 

GOM 

Relief well package constraints 

The proposed rigs for relief well operations have suitable drilling packages with 

sufficient capabilities to work in the subject water depths and drill to the required relief 

well depth. The BOP systems have met the BSEE certification requirements and will be 

re-inspected in transit, prior to drilling a relief well to the required true vertical depth. 

Relief well rig contract and mobilization timing 

A suitable rig could be selected and a contract finalized in 48 hours after undertaking 

the decision to begin relief well operations. Backup tubulars and wellhead systems are 

maintained in stock for each well. Mobilization of equipment and services to the rig for 

the relief well could be completed while operations required to suspend the rig’s current 

activity were taking place. The time required to contract, mobilize, drill a relief well and 

kill the blowout well is estimated at 139 days and is summarized below: 

 
Duration of relief well 

Description Days Cumulative Days 

Well Control Assessment. Identify suitable 

MODU for relief well operations 2 2 

MODU suspends operations from current 

well. Contract to be executed and Well 

Spud Equipment is mobilized 

14 16 

Mobilize Rig and install 36” Structural 

Casing 8 24 

Spud and drill to the top of the zone of 

interest and set casing. 105 129

Mag-Range relief well into intersecting 

position. 5 134 

R/U pumping equipment and kill well. 5 139 

R/D Pumping Equipment, PA Wellbore, Pull 

Riser, and Demobilize 15 154 

Blowout Prevention and Intervention 

Summary of prevention measures 

DGE II has maintained a safe track record of prudent operations in the GOM deepwater 

environment. We will continue to implement its safe operating practices to enhance its 

operating risk reduction program. In addition to the safe operating practices, the 

following measures will be implemented into well design, drilling and completion 

operations. 

 BOP Certification, BOP Drills, Pit Drill’s and all other required BSEE testing 

requirements, 

 Current Well Control Certification for all Drilling and Completion Rig Site 

Supervisors, 

 Taking Slow Pump Rate measurements during all open hole operations and 

critical cased hole operations, 

 Updating Kill Sheets during each tour and posting the same on the rig floor, 

 Maintain a current BOP to RKB spaceout Chart, 

 Monitoring wellbore fill-ups and displacements during trips, by the Well Site 

Supervisor, 

 Maintain the necessary circulating swages, TIW Valves and IBOP on the rig 

floor at all times during operations and function test these valves during each 

tour. 

The utilization of Pre-Job Safety meetings will continue to be implemented prior to each 

operation with all of the rig crews. These are intended to create a behavior based safety 

program and promote an atmosphere within the DGE II and rig crew interface, such that 
a “Stop the Job” mentality is promoted across the rig contractor’s crew, empowering 

every crew member to question the safety of each operation. 

Early well control intervention 

In the event of a blowout situation, due to failed BOP equipment and uncontrolled flow 

at the seafloor or at surface, assuming all other surface controlled actuation measures 

have failed or are inaccessible, a ROV will fly into position at the BOP subsea actuation 

panel and actuate the shear ram or pipe rams to establish containment. 

If the riser system and rig have been compromised, then debris removal will be initiated 

to obtain clear access to the BOP. A Capping Stack will be employed to achieve 

successful containment of the well. Once containment is established and wellbore 

pressure testing and assessment is completed by DGE II and Well Control Specialists, 

well kill operations can be initiated through the existing wellbore. 

Well control engineering services 

DGE II has a service agreement in place with Boots and Coots International Well 

Control. In the event of a blowout situation, these companies will be contacted to assist 

in the detailed design and implementation of well control and/or relief well operations. 

Additional prevention & mitigation techniques 

Pursuant to wellbore cementing and zonal isolation techniques, all cementing 

operations will be modeled and designed under the guidelines set forth in API 

Recommended Practice 65 Part 1 & 2. Operations will be dictated by the rules and 

requirements set forth in Federal Regulations, under the wellbore cementing 

requirements. 

API Standard 53 Blowout Prevention Equipment Systems for Drilling Wells and 

Recommended Practice 16Q for Marine Drilling Risers will be used as the guidelines for 

installation, testing and maintenance of the surface and subsea Marine Risers and BOP 

systems. The purpose of these recommended practices is to provide information that 

can serve as a guide for installation and testing of blowout prevention systems has 

contracted for floating marine drilling rigs. 

The goal of using these recommended practices is to assist DGE II operations in 

promoting personnel safety, public safety, and integrity of the drilling equipment and 

preservation of the environment for floating marine drilling operations. These 

recommended practices help to facilitate the broad availability of proven, sound 

engineering and operating practices. 

These practices are considered acceptable for accomplishing BOP and Marine Riser 

associated operations. However, equivalent alternative installations and practices may 

be utilized to accomplish the same objectives. When using these recommended 

practices or other alternatives, DGE II will insure that operations comply with 

requirements of Federal Regulations. 
Deep Gulf Energy II, LLC Section 2 – Pg. 10 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 3 

GEOLOGICAL AND GEOPHYSICAL INFORMATION 

3.1 GEOLOGICAL DESCRIPTION 

Proprietary Information 

3.2 STRUCTURE CONTOUR MAPS 

Proprietary Information 

3.3 INTERPRETED 3-D SEISMIC LINES 

Proprietary Information 

3.4 GEOLOGICAL STRUCTURE CROSS-SECTIONS 

Proprietary Information 

3.5 SHALLOW HAZARDS REPORT 

Proprietary Information 

3.6 SHALLOW HAZARDS ASSESSMENT 

In accordance with NTL 2008-G05, Shallow Hazards Program” (Extended by NTL 

BOEM 2013-G02, “Extension of Prior Notices to Lessees”), a 3-D seismic shallow 

hazards assessment has been prepared for each proposed surface locations, 

evaluating seafloor and subsurface geological and manmade features and conditions 

that may adversely affect drilling operations. The shallow hazards assessment is 

included as Attachment 3-D. 

3.7 HIGH-RESOLUTION SEISMIC LINES 

Proprietary Information 

3.8 STRATIGRAPHIC COLUMN 

Proprietary Information 

3.9 TIME VS DEPTH TABLES 

Proprietary Information 
10344 Sam Houston Park Dr. 

 Suite 300 

Houston, Texas 77064

 713.351.7900 [o] 713.351.7996 [f] 

www.gemsinc.com 

December 26, 2013 Project No. 1213-2338 

Deep Gulf Energy Companies 

738 Highway 6 South, 

Suite 800, 

Houston, Texas 77079 

Attention: Mr. Barry G. Hexton 

Site Clearance Letter 

Proposed Kodiak Site A 

Block 727 (OCS-G-24102) 

Mississippi Canyon Area 

Gulf of Mexico 

Deep Gulf Energy Companies (DGE) contracted Geoscience Earth & Marine Services (GEMS) to prepare 

a Site Clearance Letter for the Proposed Kodiak Site A in Block 727 (OCS-G-24102), Mississippi Canyon 

(MC) Area. This letter addresses specific seafloor and subsurface geologic conditions to the Top of Salt, 

at approximately 3,269 ft below the mudline (bml). 

An area of authigenic carbonate outcrops and associated seep communities lies approximately 1,504 ft 

southwest of the proposed wellsite. Internal variability of sediment properties that could impact conductor 

jetting may be encountered within shallow mass-transport deposits and the well is expected to intersect 

two faults at depth (approximately 2,076 ft and 2,696 ft bml). Offset wells also intercepted buried faults 

but encountered no problems along the faulted intervals. There is a low to high potential for encountering 

overpressured sands and a low potential for shallow gas accumulations within slope fan deposits (Blue,

Green, and Purple Units). 

This letter provides details specific to the well location, including: available data, Notice to Lessees (NTL) 

requirements, man-made features, and wellsite conditions. 

Proposed Well Location 

The Proposed Kodiak Site A surface location lies in the south-central portion of MC 727 

(Figure MC 727-A-1). DGE plans to drill the well using a dynamically positioned (DP) drillship or 

semi-submersible. Our assessment addresses the seafloor conditions within a 2,000 ft radius around the 

proposed wellsite. The wellsite coordinates provided by DGE are as follows: 

Proposed Kodiak Site A 

Spheroid & Datum: Clarke 1866, NAD27 

Projection: UTM Zone 16 North Line Reference Block Calls 

MC 727 

X: 1,052,150 ft Latitude: 28o 14’ 32.9302” N Inline 13738 6,710 ft FWL 

Y: 10,253,406 ft Longitude: 88o 49’ 39.1139” W Crossline 13674 4,926 ft FSL 

Available Data 

The following discussions are based on the studies performed by GEMS for BP America Production 

Company (BP) in April, 2009 and DGE in November, 2013. The 2009 study assessed the geologic and 

geohazard conditions relevant to future development of the Tubular Bells/Kodiak Development Area 

(Blocks 680 to 684, 724 to 728, and 768 to 772), GEMS, 2009. The 2013 assessment was a follow up 
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 2 

FORUM ENERGY TECHNOLOGIES, INC. 

ROV investigation over a known chemosynthetic community site (Site 03) in MC 727 (GEMS, 2013). BP 

was the primary operator of the Tubular Bells/Kodiak Development Area before DGE acquired the Kodiak 

Area (Blocks 727, 771, and vicinity). 

The 2009 assessment was carried out using a suite of datasets provided by BP. The pertinent 

geophysical data include a reprocessed 3-D seismic data and high-resolution (HR) geophysical data 

(Figure MC 727-A-1). The HR data was collected using an autonomous underwater vehicle (AUV) and 

comprises the following data; side-scan sonar, multibeam bathymetry, backscatter, and subbottom profiler 

(SBP). The detailed data specifications of the seismic and HR data (AUV data) are provided in GEMS 

report no 0508-1497 (GEMS, 2009). 

DGE was provided the aforementioned AUV data and interpretations from the reprocessed seismic 

volume for this site clearance effort. GEMS imported the seismic interpretations (horizons, faults, etc.) 

into a HR pre-stack time migration (PSTM) seismic volume provided by DGE (Figure MC 727-A-1). The 

representative seismic lines and other seismic data examples presented in this letter were extracted from 

DGE’s seismic volume. The following data were also incorporated in the assessment: 

• A suite of presentations and site clearance narratives developed by BP, 

• Well information (well logs and shallow hazards observation logs) from offset wells (DGE II’s Well 

No. 1, and DGE II’s Well No. 2), 

• Geotechnical investigation reports (AOA, 2009, FMMG 2009a/b, and FMMG, 2010), 

• ROV seafloor biological survey report by Dr. Carney (Carney, 2008), 

• Checkshot survey from DGE II’s Well No. 1 – the velocity information was used to generate a 

sediment column velocity function. The velocity function was used to convert the subsurface 

horizon time to depth. The velocity function derived is as follows: 

Depth (ft) = 3410.2x6

 - 10211x5 + 10379x4 - 4370.4x3 + 1415.7x2 + 2460.1x - 0.0922 

where x is two-way travel time below the mudline (bml) in seconds 

Figure MC 727-A-1. Seafloor Rendering of the Survey Area and Vicinity, Mississippi Canyon Area, 

Gulf of Mexico. The infrastructure shown on map was obtained from BOEM database (BOEM, 2013a). 

 

DEVIL’S

TOWER

MENSA

MISSISSIPPI CANYON

AREA

N

Mass-wasting Pathway

Erosional Remnants

Chevron #1

DGE II #1

DGE II #2

3 miles

Proposed Kodiak Site A

Geotechnical Borings

3-D Reprocessed Seismic

Data (source – BP)

AUV Survey Area

(source – BP)

3-D HR PSTM Data

(source – DGE)

Existing Wells

Existing Platform

Pipelines

High-potential 

Archaelogical Area

Chemosynthetic Area

Shallow Water Flow Area

Ordnance Disposal Area
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 3 

FORUM ENERGY TECHNOLOGIES, INC. 

Attachments 

The page-size maps, accompanying illustrations, and embedded figures were extracted from the available

geophysical data. Wellsite maps are centered on the Proposed Kodiak Site A and are displayed at a 

1 inch = 1,000 ft scale (1:12,000). The maps, illustrations, and figures are as follows: 

Map No. MC 727-A-1: Bathymetry Map 

 Map No. MC 727-A-2: Seafloor Features Map 

Map No. MC 727-A-3a: Side-Scan Sonar Mosaic 

Map No. MC 727-A-3b: Side-Scan Sonar Mosaic and Seafloor Features 

Map No. MC 727-A-4: Geologic Features Map 

Illustration MC 727-A-1: Portions of Inline 13738 and Crossline 13674 Showing Conditions Beneath 

 Proposed Kodiak Site A 

Illustration MC 727-A-2: Tophole Prognosis Chart, Proposed Kodiak Site A, Mississippi Canyon, 

Block 727 

Illustration MC 727-A-3: Correlation between Proposed Kodiak Site A and Existing Wells 

Figure MC 727-A-1: Seafloor Rendering of the Survey Area and Vicinity, Mississippi Canyon 

Area, Gulf of Mexico 

Figure MC 727-A-2: Power Spectrum Analysis Curve, Proposed Kodiak Site A 

Figure MC 727-A-3: Side-scan Sonar Mosaic Showing Seep-related Features at Site 03

Figure MC 727-A-4: AUV Subbottom Profile Data Showing the Shallow Stratigraphic Unit 

Figure MC 727-A-5: Arbitrary HR Seismic Line Showing the Deep Stratigraphic Unit 

NTL Requirements

The following letter complies with the Bureau of Ocean Energy Management (BOEM) Notice to Lessees 

(NTL’s) 2008-G04, 2008-G05, and 2009-G40, (MMS, 2008a, b and 2010). The requirements set forth in 

NTL 2005-G07 are applicable because the Federal lease block MC 727 is considered to be a high 

probability archaeological block (MMS, 2005 and BOEM, 2011). In compliance with NTL 2005-G07, the 

required archaeological assessment was performed for BP by C & C Technology Survey Services in 2007 

(C & C, 2007). 

According to NTL 2008-G05 (MMS, 2008b), 3-D seismic reflection data may be used for shallow hazard 

assessments with approval from the BOEM, Gulf of Mexico Region. BP’s 3-D seismic data was 

reprocessed using near offset traces to increase the frequency content in the shallow section. The 

reprocessed data in the vicinity of the proposed well location possesses a frequency content of 50 Hz or 

more across the first second below the seabed (BOEM, 2013b). Figure MC 727-A-2 shows the power 

spectrum analysis of DGE’s HR 3-D seismic volume. The power spectrum curve was generated within a 

500 ft radius of the intersection of the inline and crossline at the proposed wellsite. The amplitude vs. 

frequency spectrum generated by the SMT software was converted to power vs. frequency by squaring 

the amplitude values as described by J. A. Coffeen, 1978. 

Figure MC 727-A-2. Power Spectrum 

Analysis Curve, Proposed Kodiak Site A. 

0

0.2

0.4

0.6

0.8

1

1.2

0 10 20 30 40 50 60 70 80

Power (Amp

2

)

Frequency (Hz)

POWER SPECTRUM
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 4 

FORUM ENERGY TECHNOLOGIES, INC. 

Man-Made Features and Archaeological Assessment

The surface location is clear of any wells, pipelines, or platforms within a 2,000 ft radius from the 

proposed wellsite. Numerous permitted pipelines are located in adjacent blocks MC 684, MC 728, and 

MC 770-772 to the northeast, east, and south of the proposed wellsite, respectively 

(Figure MC 727-A-1). There are existing wells and geotechnical borings within block MC 727; the closest 

well (DGE II’s Well No. 2) lies approximately 2,597 ft north-northeast, while the closest boring (KCPT-04) 

lies 1,901 ft east (Figure MC 727-A-1, Map MC 727-A-1). The details of the existing wells and borings are 

shown in the tables below (AOA, 2009, FMMG 2009a/b, and FMMG, 2010). 

Table 1. Existing Wells Within MC 727 

Name Other Names X 

NAD27 (ft) 

Y 

NAD27 (ft) 

Type/Status 

Code 

*Dist./Direction 

from Proposed 

Wellsite 

Chevron #1 

OCS-G 13145, 

MC727 Well No. 001 

(API 60-817-40894-00) 

1058460.06 10257338.04 Exploratory; 

*PA 1.41 miles/NE 

DGE II’s 

Well #1 

OCS-G 24107, 

MC771 Well No. 001 ST00BP00 

(API 60-817-41134-00) 

1058326.96 10254723.09 Exploratory; 

*PA 1.20 miles/ENE 

DGE II’s 

Well #1 S/T 

OCS-G 24102, 

MC727 Well No. 001 ST01BP00 

(API 60-817-41134-01) 

1058326.96 10254723.09 Exploratory; 

*PA 1.20 miles/ENE 

DGE II’s 

Well #2 

OCS-G 24102, 

MC727 Well No. 002 ST00BP00 

(API 60-817-41171-00) 

1051997.74 10255998.12 Exploratory; 

*TA 2,597 ft/NNE 

*PA - Permanently Abandoned *TA – Temporary Abandoned *Dist - Distance 

Table 2. Borings Within MC 727 

Name X 

NAD27 (ft) 

Y 

NAD27 (ft) 

Total 

Depth, 

bml (ft) 

*Dist./Direction 

from Proposed 

Wellsite 

Soil Description 

KSB-101 1048502 10257099 172 0.98 miles/NW Very soft to stiff olive 

gray clay. 

KSB-105 1056664 10254139 192 4,573 ft/ENE Very soft to very stiff 

olive gray clay. KSB-106 1058589 10249392 187 1.44 miles/SE 

BH-2A 1048956 10251181 1,023 3,893 ft/SW 

Primarily clay. Blue 

Unit comprise of 

clay, silts and sands. 

BH-2B 1049064 10251181 280 3,805 ft/SW Very soft to hard 

olive gray clay with 

intermittent silt and 

sand pockets. BH-2C 1049147 10251189 910 3,733 ft/SW 

 
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 5 

FORUM ENERGY TECHNOLOGIES, INC. 

Table 3. Seabed PCPT Within MC 727 

Name X 

NAD27 (ft) 

Y 

NAD27 (ft) 

Total Depth 

bml, (ft) 

*Dist./Direction 

from Proposed 

Wellsite 

KCPT-01 1048499 10257057 ~134 0.98 miles/NW 

KCPT-04 1054050 10253447 ~113 1,901 ft/E 

KCPT-06 1061283 10254124 ~127 1.73 miles/E 

KCPT-07 1057226 10251176 ~113 1.05 miles/SE 

Archaeological Assessment

C & C delineated seven unidentified side-scan sonar contacts in MC 727; however, none of the contacts 

appear to represent cultural resources (C & C, 2007), Table 4. The unidentified contacts were interpreted 

as debris from lease development activities or as geologic in origin. A 100 ft shallow hazard avoidance is 

recommended for the contacts but none are recommended for archaeological avoidance or investigation. 

The closest sonar contact (Number 19) lies approximately 4,830 ft east of Proposed Kodiak Site A. 

Table 4. Sonar Contacts Located Within MC 727 

No. Length 

(ft) 

Width 

(ft) 

Height 

(ft) Shape X NAD27 (ft) 

Y 

NAD27 (ft) 

Avoidance 

Radius (ft) 

12 19.7 16.4 *NMH Irregular 1053003.54 10259122.00 100 

14 16.4 13.1 NMH Irregular 1059402.91 10257553.24 100 

15 16 20 NMH Irregular 1058663.87 10255660.00 100 

16 20 16 NMH Irregular 1058590.72 10255673.88 100 

17 16 10 NMH Irregular 1060126.04 10253228.31 100 

18 16 10 NMH Irregular 1058462.32 10253253.69 100 

19 16 10 NMH Irregular 1056958.71 10253861.67 100 

*NMH – No measurable height 

Wellsite Conditions

Proposed Kodiak Site A is expected to intersect two buried faults and many small undifferentiated faults at 

depth. Within the suprasalt strata, there is a low to high potential for encountering overpressured sands 

and a low potential for shallow gas accumulations within slope fan deposits. 

Water Depth and Seafloor Conditions

The water depth at the proposed surface location is approximately -4,818 ft and the seafloor slopes 

southeast at approximately 2° (Map MC 727-A-1). Slope instability conditions are not expected at the 

proposed wellsite. 

The Proposed Kodiak Site A lies along a relatively smooth low-lying valley, less than a mile from an 

escarpment in the southeast (Map MC 727-A-2). The valleys were preferred sediment pathways for 

mass-wasting processes in the recent geologic past (Figure MC 727-A-1). Major mass-wasting 

processes have ceased since the last major sea-level lowstand. The near-surface stratigraphy consists

mostly of well-layered sediments (up to 60 ft thick). The low sonar reflectivity suggests that the seabed is 

draped by soft clays (Map MC 727-A-3a). 
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 6 

FORUM ENERGY TECHNOLOGIES, INC. 

Deepwater Benthic Communities 

The proposed wellsite lies near an identified chemosynthetic community. The seep community (Site 03) 

was identified during an ROV investigation conducted in 2008 by Oceaneering for BP. This ROV survey 

indicated that the area was partially populated by tubeworms and mussels, estimating 11.2% of the 

expulsion site coverage (Carney, 2008, GEMS, 2009), Figure MC 727-A-3. At that time, Site 03 was not 

classified as a high density population area. Also at that time, the Site 03 expulsion area boundary was 

determined to be mapped for BP Geohazards report (GEMS Report No. 0508-1497, GEMS, 2009). 

After discussions and consultations with BOEM, a subsequent follow-up ROV survey investigation over 

Site 03 was conducted in 2013 to determine if any significant changes in the chemosynthetic community 

had occurred since 2008. This survey confirmed limited seep community coverage at the expulsion zone 

(GEMS, 2013), Map MC 727-A-3b and Figure MC 727-A-3. The 2013 ROV investigation was conducted 

by Surf Subsea and GEMS. 

BOEM has reviewed the ROV videos from 2008 and 2013, and have determined that the identified Site 

03 chemosynthetic community is “at the lower end of what may be judged to be considered as high 

density communities” (Dave Moran, personal communication, December 03, 2013). It was also 

determined that the areal extent of the defined high density deepwater benthic community is represented 

by a polygon defined as “Area of closely spaced, rocky, authigenic carbonate outcrops, chemosynthetic 

organisms (predominately mussels and tubeworms) exist at and near some outcrops” (Map MC 727-A-3b, 

GEMS, 2013). 

A 1,500 ft avoidance buffer zone (as measured from the polygon defined above) has been permitted 

around this specific Site 03 seep community instead of the customary 2,000 ft avoidance zone specified

in BOEM’s NTL No. 2009-G40 (MMS, 2010). 

The Proposed Kodiak Site A lies outside the 1,500 ft avoidance zone at approximately 1,504 ft northeast 

of the Site 03 seep community polygon boundary as defined above. 

Other expulsion features are located north and southeast of the proposed wellsite; however, there are no 

apparent geophysical indicators at these sites to suggest conditions capable of supporting significant

high-density deepwater benthic communities (Maps MC 727-A-2 and MC 727-A-3a), GEMS, 2009. 

Figure MC 727-A-3. Side-scan Sonar Mosaic Showing Seep-related Features at Site 03. 

The chemosynthetic organisms (within the green polygon) are predominantly mussels and tubeworms. 

Source - *i (GEMS, 2009); *iii and *iv (GEMS, 2013). 

 

Proposed 

Kodiak Site A

N

*i

*ii

*iii

*iv

*i - 1,500 ft avoidance 

*ii - Expulsion feature 

*iii- Seafloor depression surrounding outcrops 

where bacteria cover and mussels exist

*iv - Area of closely spaced, rocky, authigenic 

carbonate outcrops. Chemosynthetic 

organisms exist at and near some outcrops

Site 03

1,000 ft

G - prior 2009 BP 

SEP Control # S-07315 Approval

I - prior 2010 BP 

SEP Control # S-07369 Approval

G

I


Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 9 

FORUM ENERGY TECHNOLOGIES, INC. 

fine-grained sediments from the Seafloor to 249 ft bml and 439 ft to 1,118 ft bml. There is a low potential 

for encountering minor accumulations of gas in the Blue Unit (249 ft to 439 ft bml), and from the Top of 

the Green Unit to the Top of Salt (1,118 ft to 3,269 ft bml). 

Hydrates. A bottom simulating reflector (BSR) was identified approximately 1,885 ft southwest of the 

proposed wellsite from 794 ft to 1,359 ft bml (GEMS, 2009). The BSR marks the Base of the Hydrate 

Stability Zone (BHSZ) and represents the acoustic impedance contrast between potentially 

hydrate-bearing sediments and free gas bearing sediments beneath the BHSZ. The proposed wellsite 

lies outside the mapped BSR extent (Map MC 727-A-4). 

There was no evidence of encountering shallow gas hydrates while drilling the riserless section at 

DGE II’s Well No. 1 and DGE II’s Well No. 2. The wireline log data at BH-2A also showed no evidence of 

gas hydrate being present in any significant quantities (AOA, 2009). Consequently, we consider that 

there is a negligible potential for encountering hydrates at Proposed Kodiak Site A. 

Shallow Water Flow. Shallow water flow (SWF) occurrences within block MC 727 were observed at 

Chevron #1 and DGE II’s No. 1 wells. Overpressured sands were encountered within the Green Unit at 

Chevron #1 and from the top of the Purple Unit to the 22-inch casing depth at DGE II’s Well No. 1 

(Illustration MC 727-A-3). Severe SWF was observed at 1,499 ft bml while drilling with seawater at 

Chevron #1. Low SWF was observed at DGE II’s Well No. 1 at 2,122 ft bml, and intermittently to the 

base of the 26-inch hole at 3,089 ft bml. The 26-inch hole was drilled with water based mud. SWF was

not observed at DGE II’s Well No. 2, likely due to better well control measures. Within the Blue Unit at 

BH-2A, locally higher pressures were measured in thin sand/silt bands and possible indication of SWF 

was noted in the temperature log (AOA, 2009). However, no SWF was observed within the Blue Unit at 

the boreholes and the existing wells. 

The potential for SWF at the proposed wellsite varies from negligible to high based on the seismic facies 

correlation between the proposed wellsite and existing wells (Illustration MC 727-A-3). There is a high 

potential for SWF within the Green Unit (1,118 ft to 2,028 ft bml); a moderate potential within the Purple 

Unit (2,547 ft to 2,751 ft bml); a low potential within the Blue Unit (249 ft to 439 ft bml), below the Green 

Unit (2,028 ft to 2,547 ft bml), and below the Purple Unit (2,751 ft to 3,269 ft bml); and a negligible 

potential in clay-rich stratigraphy between the Seafloor to 249 ft bml and 439 ft to 1,118 ft bml. 

Findings and Recommendations

An area of authigenic carbonate outcrops and associated seep communities was identified approximately 

1,504 ft southwest of the proposed wellsite. Internal variability of sediment properties that could impact 

conductor jetting may be encountered within shallow mass-transport deposits between the Seafloor and 

249 ft bml. Two sub-regional SWF units (the Blue Unit and Green Unit) occur at 249 ft bml and 1,118 ft 

bml respectively. A third SWF prone unit (Purple Unit) occurs at 2,547 ft bml. Caution is recommended 

when drilling through these sediment units, and when intersecting buried faults at approximately 2,076 ft 

and 2,696 ft bml. 

 
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 10 

FORUM ENERGY TECHNOLOGIES, INC. 

Closing

We appreciate the opportunity to be of service to Deep Gulf Energy Companies, and look forward to 

working together on future projects. 

Sincerely, 

GEOSCIENCE EARTH & MARINE 

SERVICES 

Oluwayomi Oyedele Daniel Lanier 

Geoscientist Director – Geoscience Earth & Marine Services 

Erin Williams Janes 

Project Manager/Senior Geoscientist 

Attachments (5 Maps and 3 Illustrations) 

Distribution: Mr. Barry G. Hexton, Deep Gulf Energy Companies (6 copies) 

REFERENCES 

AOA Geophysics Inc., 2009, Interpretation of wireline logging data and integration with other relevant data, Kodiak 

geotechnical investigation, Mississippi Canyon, Gulf of Mexico: Report prepared for BP America Inc., Report No. 

4041-BP-GOM-KOD-01. 

Bureau of Ocean Energy Management, 2013a, ASCII Data Files, published on the BOEM Gulf of Mexico Region 

Homepage, <http://www.gomr.boem.gov/homepg/pubinfo/freeasci/freedesc.html>, accessed December, 2013. 

Bureau of Ocean Energy Management, 2013b, Exploration Plan Control # S-07369, published on the BOEM Gulf of 

Mexico Region Homepage, < http://www.data.boem.gov/PI/PDFImages/PLANS/30/30739.pdf>, accessed June, 

2013. 

Bureau of Ocean Energy Management, 2011, Notice to lessees and operators (NTL) of federal oil and gas leases 

and pipeline right-of-way (ROW) holders on the outer continental shelf (OCS), revisions to the list of OCS lease 

blocks requiring archaeological resource surveys and reports: U.S. Departments of the Interior, Bureau of Ocean 

Energy Management, Bureau of Safety and Environmental Enforcement, Gulf of Mexico OCS Region (GOMR), NTL 

2011-JOINT-G01. Effective Date December 29, 2011. 

Carney, R.S., 2008, Summary of seafloor fauna observed during the Tubular Bells and Kodiak appraisal area ROV 

seafloor biological survey: Report prepared for BP America Inc., Report No. TBEL1-10GO-RP-000013. 

C&C Technologies Survey Services, (C&C), 2007, Archaeological Assessment Report, Block 727 & Vicinity, Mississippi 

Canyon Area: Report prepared for BP America Inc., Job no. 072456-073011. 

Coffeen, J. A., 1978, Seismic Exploration Fundamentals: Tulsa, the Petroleum Publishing Co., p. 125. 

Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009a, Deepwater geotechnical investigation, Kodiak Prospect 

SPAR development, Blocks 726, 727, 728, 770 & 771, Mississippi Canyon Area, Gulf of Mexico: Report prepared for 

BP America Inc., Report No. 0201-6584-1, volume I. 
Proposed Kodiak Site A Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 11 

FORUM ENERGY TECHNOLOGIES, INC. 

Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009b, Shallow water flow investigation, Kodiak Prospect, 

Blocks 727 & 771, Mississippi Canyon Area, Gulf of Mexico: Report prepared for BP America Inc., Report No. 0201-

6584-2, volumes I, II, & III. 

Fugro McClelland Marine Geosciences, Inc., (FMMG), 2010, Deepwater geotechnical investigation, Kodiak Prospect 

SPAR development, Blocks 726, 727, 728, 770 & 771, Mississippi Canyon Area, Gulf of Mexico: Report prepared for 

BP America Inc., Report No. 0201-6584-1, volume II.

Geoscience Earth & Marine Services, (GEMS), 2009, Tubular Bells/Kodiak development project, geologic and 

stratigraphic assessment, Blocks 680 to 684, 724 to 728, & 768 to 772, Mississippi Canyon Area, Gulf of Mexico, 

Project No. 0508-1497. 

Geoscience Earth & Marine Services, (GEMS), 2013, Seafloor verification study using ROV data, Block 727, 

Mississippi Canyon Area, Gulf of Mexico, Project No. 0713-2273. 

Minerals Management Service, 2005, Notice to lessees and operators of federal oil, gas, and sulphur leases and 

pipeline right-of-way holders in the outer continental shelf, Gulf of Mexico OCS region, Archaeological resource 

surveys and reports: U. S. Department of the Interior, Minerals Management Service, Gulf of Mexico, NTL 2005-G07. 

Minerals Management Service, 2008a, Notice to lessees and operators of federal oil, gas, and sulphur leases and 

pipeline right-of-way holders in the outer continental shelf, Gulf of Mexico OCS region, information requirements for 

exploration plans and development operations coordination documents: U. S. Department of the Interior, Minerals 

Management Service, Gulf of Mexico, NTL 2008-G04. 

Minerals Management Service, 2008b, Notice to lessees and operators of federal oil, gas, and sulphur leases and 

pipeline right-of-way holders in the outer continental shelf, Gulf of Mexico OCS region, shallow hazards requirements: 

U. S. Department of the Interior, Minerals Management Service, Gulf of Mexico, NTL 2008-G05. 

Minerals Management Service, 2010, Notice to lessees and operators of federal oil and gas leases in the outer 

continental shelf, Gulf of Mexico OCS region, deepwater benthic communities: U. S. Department of the Interior, 

Minerals Management Service, Gulf of Mexico, NTL 2009-G40. Effective Date January 27, 2010. 
10344 Sam Houston Park Dr. 

 Suite 300 

Houston, Texas 77064

 713.351.7900 [o] 713.351.7996 [f] 

www.gemsinc.com 

December 26, 2013 Project No. 1213-2338 

Deep Gulf Energy Companies 

738 Highway 6 South, 

Suite 800, 

Houston, Texas 77079 

Attention: Mr. Barry G. Hexton 

Site Clearance Letter 

Proposed Kodiak Site B 

Block 727 (OCS-G-24102) 

Mississippi Canyon Area 

Gulf of Mexico 

Deep Gulf Energy Companies (DGE) contracted Geoscience Earth & Marine Services (GEMS) to prepare 

a Site Clearance Letter for the Proposed Kodiak Site B in Block 727 (OCS-G-24102), Mississippi Canyon 

(MC) Area. This letter addresses specific seafloor and subsurface geologic conditions to the Top of Salt, 

at approximately 3,210 ft below the mudline (bml). 

An area of authigenic carbonate outcrops and associated seep communities lies approximately 1,598 ft 

southwest of the proposed wellsite. Internal variability of sediment properties that could impact conductor 

jetting may be encountered within shallow mass-transport deposits and the well is expected to intersect 

two faults at depth (approximately 1,742 ft and 2,442 ft bml). Offset wells also intercepted buried faults 

but encountered no problems along the faulted intervals. There is a low to high potential for encountering 

overpressured sands and a low potential for shallow gas accumulations within slope fan deposits (Blue,

Green, and Purple Units). 

This letter provides details specific to the well location, including: available data, Notice to Lessees (NTL) 

requirements, man-made features, and wellsite conditions. 

Proposed Well Location 

The Proposed Kodiak Site B surface location lies in the south-central portion of MC 727 

(Figure MC 727-B-1). DGE plans to drill the well using a dynamically positioned (DP) drillship or 

semi-submersible. Our assessment addresses the seafloor conditions within a 2,000 ft radius around the 

proposed wellsite. The wellsite coordinates provided by DGE are as follows: 

Proposed Kodiak Site B 

Spheroid & Datum: Clarke 1866, NAD27 

Projection: UTM Zone 16 North Line Reference Block Calls 

MC 727 

X: 1,052,310 ft Latitude: 28o 14’ 32.9548” N Inline 13740 6,870 ft FWL 

Y: 10,253,406 ft Longitude: 88o 49’ 37.3251” W Crossline 13671 4,926 ft FSL 

Available Data 

The following discussions are based on the studies performed by GEMS for BP America Production 

Company (BP) in April, 2009 and DGE in November, 2013. The 2009 study assessed the geologic and 

geohazard conditions relevant to future development of the Tubular Bells/Kodiak Development Area 

(Blocks 680 to 684, 724 to 728, and 768 to 772), GEMS, 2009. The 2013 assessment was a follow up 
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 2 

FORUM ENERGY TECHNOLOGIES, INC. 

ROV investigation over a known chemosynthetic community site (Site 03) in MC 727 (GEMS, 2013). BP 

was the primary operator of the Tubular Bells/Kodiak Development Area before DGE acquired the Kodiak 

Area (Blocks 727, 771, and vicinity). 

The 2009 assessment was carried out using a suite of datasets provided by BP. The pertinent 

geophysical data include a reprocessed 3-D seismic data and high-resolution (HR) geophysical data 

(Figure MC 727-B-1). The HR data was collected using an autonomous underwater vehicle (AUV) and 

comprises the following data; side-scan sonar, multibeam bathymetry, backscatter, and subbottom profiler 

(SBP). The detailed data specifications of the seismic and HR data (AUV data) are provided in GEMS 

report no 0508-1497 (GEMS, 2009). 

DGE was provided the aforementioned AUV data and interpretations from the reprocessed seismic 

volume for this site clearance effort. GEMS imported the seismic interpretations (horizons, faults, etc.) 

into a HR pre-stack time migration (PSTM) seismic volume provided by DGE (Figure MC 727-B-1). The 

representative seismic lines and other seismic data examples presented in this letter were extracted from 

DGE’s seismic volume. The following data were also incorporated in the assessment: 

• A suite of presentations and site clearance narratives developed by BP, 

• Well information (well logs and shallow hazards observation logs) from offset wells (DGE II’s Well 

No. 1, and DGE II’s Well No. 2), 

• Geotechnical investigation reports (AOA, 2009, FMMG 2009a/b, and FMMG, 2010), 

• ROV seafloor biological survey report by Dr. Carney (Carney, 2008), 

• Checkshot survey from DGE II’s Well No. 1 – the velocity information was used to generate a 

sediment column velocity function. The velocity function was used to convert the subsurface 

horizon time to depth. The velocity function derived is as follows: 

Depth (ft) = 3410.2x6

 - 10211x5 + 10379x4 - 4370.4x3 + 1415.7x2 + 2460.1x - 0.0922 

where x is two-way travel time below the mudline (bml) in seconds 

Figure MC 727-B-1. Seafloor Rendering of the Survey Area and Vicinity, Mississippi Canyon Area, 

Gulf of Mexico. The infrastructure shown on map was obtained from BOEM database (BOEM, 2013a). 

 

DEVIL’S

TOWER

MENSA

MISSISSIPPI CANYON

AREA

N

Chevron #1

DGE II #1

DGE II #2

Proposed Kodiak Site B

Geotechnical Borings

3-D Reprocessed Seismic

Data (source – BP)

AUV Survey Area

(source – BP)

3-D HR PSTM Data

(source – DGE)

Existing Wells

Existing Platform

Pipelines

High-potential 

Archaelogical Area

Chemosynthetic Area

Shallow Water Flow Area

Ordnance Disposal Area 3 miles

Mass-wasting Pathway

Erosional Remnants
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 3 

FORUM ENERGY TECHNOLOGIES, INC. 

Attachments 

The page-size maps, accompanying illustrations, and embedded figures were extracted from the available

geophysical data. Wellsite maps are centered on the Proposed Kodiak Site B and are displayed at a 

1 inch = 1,000 ft scale (1:12,000). The maps, illustrations, and figures are as follows: 

Map No. MC 727-B-1: Bathymetry Map 

 Map No. MC 727-B-2: Seafloor Features Map 

Map No. MC 727-B-3a: Side-Scan Sonar Mosaic 

Map No. MC 727-A-3b: Side-Scan Sonar Mosaic and Seafloor Features 

Map No. MC 727-B-4: Geologic Features Map 

Illustration MC 727-B-1: Portions of Inline 13740 and Crossline 13671 Showing Conditions Beneath 

 Proposed Kodiak Site B 

Illustration MC 727-B-2: Tophole Prognosis Chart, Proposed Kodiak Site B, Mississippi Canyon, 

Block 727 

Illustration MC 727-B-3: Correlation between Proposed Kodiak Site B and Existing Wells 

Figure MC 727-B-1: Seafloor Rendering of the Survey Area and Vicinity, Mississippi Canyon 

Area, Gulf of Mexico 

Figure MC 727-B-2: Power Spectrum Analysis Curve, Proposed Kodiak Site B 

Figure MC 727-B-3: Side-scan Sonar Mosaic Showing Seep-related Features at Site 03

Figure MC 727-B-4: AUV Subbottom Profile Data Showing the Shallow Stratigraphic Unit 

Figure MC 727-B-5: Arbitrary HR Seismic Line Showing the Deep Stratigraphic Unit 

NTL Requirements

The following letter complies with the Bureau of Ocean Energy Management (BOEM) Notice to Lessees 

(NTL’s) 2008-G04, 2008-G05, and 2009-G40, (MMS, 2008a, b and 2010). The requirements set forth in 

NTL 2005-G07 are applicable because the Federal lease block MC 727 is considered to be a high 

probability archaeological block (MMS, 2005 and BOEM, 2011). In compliance with NTL 2005-G07, the 

required archaeological assessment was performed for BP by C & C Technology Survey Services in 2007 

(C & C, 2007). 

According to NTL 2008-G05 (MMS, 2008b), 3-D seismic reflection data may be used for shallow hazard 

assessments with approval from the BOEM, Gulf of Mexico Region. BP’s 3-D seismic data was 

reprocessed using near offset traces to increase the frequency content in the shallow section. The 

reprocessed data in the vicinity of the proposed well location possesses a frequency content of 50 Hz or 

more across the first second below the seabed (BOEM, 2013b). Figure MC 727-B-2 shows the power 

spectrum analysis of DGE’s HR 3-D seismic volume. The power spectrum curve was generated within a 

500 ft radius of the intersection of the inline and crossline at the proposed wellsite. The amplitude vs. 

frequency spectrum generated by the SMT software was converted to power vs. frequency by squaring 

the amplitude values as described by J. A. Coffeen, 1978. 

Figure MC 727-B-2. Power Spectrum 

Analysis Curve, Proposed Kodiak 

Site B. 

0

0.2

0.4

0.6

0.8

1

1.2

0 10 20 30 40 50 60 70 80

Power (Amp

2

)

Frequency (Hz)

POWER SPECTRUM
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 4 

FORUM ENERGY TECHNOLOGIES, INC. 

Man-Made Features and Archaeological Assessment

The surface location is clear of any wells, pipelines, or platforms within a 2,000 ft radius from the 

proposed wellsite. Numerous permitted pipelines are located in adjacent blocks MC 684, MC 728, and 

MC 770-772 to the northeast, east, and south of the proposed wellsite, respectively 

(Figure MC 727-B-1). There are existing wells and geotechnical borings within block MC 727; the closest 

well (DGE II’s Well No. 2) lies approximately 2,611 ft north-northeast, while the closest boring (KCPT-04) 

lies 1,741 ft east (Figure MC 727-B-1, Map MC 727-B-1). The details of the existing wells and borings are 

shown in the tables below (AOA, 2009, FMMG 2009a/b, and FMMG, 2010). 

Table 1. Existing Wells Within MC 727 

Name Other Names X 

NAD27 (ft) 

Y 

NAD27 (ft) 

Type/Status 

Code 

*Dist./Direction 

from Proposed 

Wellsite 

Chevron #1 

OCS-G 13145, 

MC727 Well No. 001 

(API 60-817-40894-00) 

1058460.06 10257338.04 Exploratory; 

*PA 1.38 miles/NE 

DGE II’s 

Well #1 

OCS-G 24107, 

MC771 Well No. 001 ST00BP00 

(API 60-817-41134-00) 

1058326.96 10254723.09 Exploratory; 

*PA 1.17 miles/ENE 

DGE II’s 

Well #1 S/T 

OCS-G 24102, 

MC727 Well No. 001 ST01BP00 

(API 60-817-41134-01) 

1058326.96 10254723.09 Exploratory; 

*PA 1.17 miles/ENE 

DGE II’s 

Well #2 

OCS-G 24102, 

MC727 Well No. 002 ST00BP00 

(API 60-817-41171-00) 

1051997.74 10255998.12 Exploratory; 

*TA 2,611 ft/NNE 

*PA - Permanently Abandoned *TA – Temporary Abandoned *Dist - Distance 

Table 2. Borings Within MC 727 

Name X 

NAD27 (ft) 

Y 

NAD27 (ft) 

Total 

Depth, 

bml (ft) 

*Dist./Direction 

from Proposed 

Wellsite 

Soil Description 

KSB-101 1048502 10257099 172 1.01 miles/NW Very soft to stiff olive 

gray clay. 

KSB-105 1056664 10254139 192 4,415 ft/ENE Very soft to very stiff 

olive gray clay. KSB-106 1058589 10249392 187 1.41 miles/SE 

BH-2A 1048956 10251181 1,023 4,025 ft/SW 

Primarily clay. Blue 

Unit comprise of 

clay, silts and sands. 

BH-2B 1049064 10251181 280 3,935 ft/SW Very soft to hard 

olive gray clay with 

intermittent silt and 

sand pockets. BH-2C 1049147 10251189 910 3,863 ft/SW 

 
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 5 

FORUM ENERGY TECHNOLOGIES, INC. 

Table 3. Seabed PCPT Within MC 727 

Name X 

NAD27 (ft) 

Y 

NAD27 (ft) 

Total Depth 

bml, (ft) 

*Dist./Direction 

from Proposed 

Wellsite 

KCPT-01 1048499 10257057 ~134 1 mile/NW 

KCPT-04 1054050 10253447 ~113 1,741 ft/E 

KCPT-06 1061283 10254124 ~127 1.71 miles/E 

KCPT-07 1057226 10251176 ~113 1.02 miles/SE 

Archaeological Assessment

C & C delineated seven unidentified side-scan sonar contacts in MC 727; however, none of the contacts 

appear to represent cultural resources (C & C, 2007), Table 4. The unidentified contacts were interpreted 

as debris from lease development activities or as geologic in origin. A 100 ft shallow hazard avoidance is 

recommended for the contacts but none are recommended for archaeological avoidance or investigation. 

The closest sonar contact (Number 19) lies approximately 4,671 ft east of Proposed Kodiak Site B. 

Table 4. Sonar Contacts Located Within MC 727 

No. Length 

(ft) 

Width 

(ft) 

Height 

(ft) Shape X NAD27 (ft) 

Y 

NAD27 (ft) 

Avoidance 

Radius (ft) 

12 19.7 16.4 *NMH Irregular 1053003.54 10259122.00 100 

14 16.4 13.1 NMH Irregular 1059402.91 10257553.24 100 

15 16 20 NMH Irregular 1058663.87 10255660.00 100 

16 20 16 NMH Irregular 1058590.72 10255673.88 100 

17 16 10 NMH Irregular 1060126.04 10253228.31 100 

18 16 10 NMH Irregular 1058462.32 10253253.69 100 

19 16 10 NMH Irregular 1056958.71 10253861.67 100 

*NMH – No measurable height 

Wellsite Conditions

Proposed Kodiak Site B is expected to intersect two buried faults and many small undifferentiated faults at 

depth. Within the suprasalt strata, there is a low to high potential for encountering overpressured sands 

and a low potential for shallow gas accumulations within slope fan deposits. 

Water Depth and Seafloor Conditions

The water depth at the proposed surface location is approximately -4,823 ft and the seafloor slopes 

southeast at approximately 4° (Map MC 727-B-1). Slope instability conditions are not expected at the 

proposed wellsite. 

The Proposed Kodiak Site B lies along a relatively smooth low-lying valley, less than a mile from an 

escarpment in the southeast (Map MC 727-B-2). The valleys were preferred sediment pathways for 

mass-wasting processes in the recent geologic past (Figure MC 727-B-1). Major mass-wasting 

processes have ceased since the last major sea-level lowstand. The near-surface stratigraphy consists

mostly of well-layered sediments (up to 60 ft thick). The low sonar reflectivity suggests that the seabed is 

draped by soft clays (Map MC 727-B-3a). 
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 6 

FORUM ENERGY TECHNOLOGIES, INC. 

Deepwater Benthic Communities 

The proposed wellsite lies near an identified chemosynthetic community. The seep community (Site 03) 

was identified during an ROV investigation conducted in 2008 by Oceaneering for BP. This ROV survey 

indicated that the area was partially populated by tubeworms and mussels, estimating 11.2% of the 

expulsion site coverage (Carney, 2008, GEMS, 2009), Figure MC 727-B-3. At that time, Site 03 was not 

classified as a high density population area. Also at that time, the Site 03 expulsion area boundary was 

determined to be mapped for BP Geohazards report (GEMS Report No. 0508-1497, GEMS, 2009). 

After discussions and consultations with BOEM, a subsequent follow-up ROV survey investigation over 

Site 03 was conducted in 2013 to determine if any significant changes in the chemosynthetic community 

had occurred since 2008. This survey confirmed limited seep community coverage at the expulsion zone 

(GEMS, 2013), Map MC 727-B-3b and Figure MC 727-B-3. The 2013 ROV investigation was conducted 

by Surf Subsea and GEMS. 

BOEM has reviewed the ROV videos from 2008 and 2013, and have determined that the identified Site 

03 chemosynthetic community is “at the lower end of what may be judged to be considered as high 

density communities” (Dave Moran, personal communication, December 03, 2013). It was also 

determined that the areal extent of the defined high density deepwater benthic community is represented 

by a polygon defined as “Area of closely spaced, rocky, authigenic carbonate outcrops, chemosynthetic 

organisms (predominately mussels and tubeworms) exist at and near some outcrops” (Map MC 727-B-3b, 

GEMS, 2013). 

A 1,500 ft avoidance buffer zone (as measured from the polygon defined above) has been permitted 

around this specific Site 03 seep community instead of the customary 2,000 ft avoidance zone specified

in BOEM’s NTL No. 2009-G40 (MMS, 2010). 

The Proposed Kodiak Site B lies outside the 1,500 ft avoidance zone at approximately 1,598 ft northeast 

of the Site 03 seep community polygon boundary as defined above. 

Other expulsion features are located north and southeast of the proposed wellsite; however, there are no 

apparent geophysical indicators at these sites to suggest conditions capable of supporting significant

high-density deepwater benthic communities (Maps MC 727-B-2 and MC 727-B-3a), GEMS, 2009. 

Figure MC 727-B-3. Side-scan Sonar Mosaic Showing Seep-related Features at Site 03. 

The chemosynthetic organisms (within the green polygon) are predominantly mussels and tubeworms. 

Source - *i (GEMS, 2009); *iii and *iv (GEMS, 2013). 

 

Proposed 

Kodiak Site B

N

*i

*ii

*iii

*iv

*i - 1,500 ft avoidance 

*ii - Expulsion feature 

*iii- Seafloor depression surrounding outcrops 

where bacteria cover and mussels exist

*iv - Area of closely spaced, rocky, authigenic 

carbonate outcrops. Chemosynthetic 

1,000 ft organisms exist at and near some outcrops

G - prior 2009 BP 

SEP Control # S-07315 Approval

I - prior 2010 BP 

SEP Control # S-07369 Approval

Site 03

G

I


Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 9 

FORUM ENERGY TECHNOLOGIES, INC. 

fine-grained sediments from the Seafloor to 246 ft bml and 437 ft to 1,118 ft bml. There is a low potential 

for encountering minor accumulations of gas in the Blue Unit (246 ft to 437 ft bml), and from the Top of 

the Green Unit to the Top of Salt (1,118 ft to 3,210 ft bml). 

Hydrates. A bottom simulating reflector (BSR) was identified approximately 1,960 ft southwest of the 

proposed wellsite from 794 ft to 1,359 ft bml (GEMS, 2009). The BSR marks the Base of the Hydrate 

Stability Zone (BHSZ) and represents the acoustic impedance contrast between potentially 

hydrate-bearing sediments and free gas bearing sediments beneath the BHSZ. The proposed wellsite 

lies outside the mapped BSR extent (Map MC 727-B-4). 

There was no evidence of encountering shallow gas hydrates while drilling the riserless section at 

DGE II’s Well No. 1 and DGE II’s Well No. 2. The wireline log data at BH-2A also showed no evidence of 

gas hydrate being present in any significant quantities (AOA, 2009). Consequently, we consider that 

there is a negligible potential for encountering hydrates at Proposed Kodiak Site B. 

Shallow Water Flow. Shallow water flow (SWF) occurrences within block MC 727 were observed at 

Chevron #1 and DGE II’s No. 1 wells. Overpressured sands were encountered within the Green Unit at 

Chevron #1 and from the top of the Purple Unit to the 22-inch casing depth at DGE II’s Well No. 1 

(Illustration MC 727-B-3). Severe SWF was observed at 1,499 ft bml while drilling with seawater at 

Chevron #1. Low SWF was observed at DGE II’s Well No. 1 at 2,122 ft bml, and intermittently to the 

base of the 26-inch hole at 3,089 ft bml. The 26-inch hole was drilled with water based mud. SWF was

not observed at DGE II’s Well No. 2, likely due to better well control measures. Within the Blue Unit at 

BH-2A, locally higher pressures were measured in thin sand/silt bands and possible indication of SWF 

was noted in the temperature log (AOA, 2009). However, no SWF was observed within the Blue Unit at 

the boreholes and the existing wells. 

The potential for SWF at the proposed wellsite varies from negligible to high based on the seismic facies 

correlation between the proposed wellsite and existing wells (Illustration MC 727-B-3). There is a high 

potential for SWF within the Green Unit (1,118 ft to 1,932 ft bml); a moderate potential within the Purple 

Unit (2,500 ft to 2,718 ft bml); a low potential within the Blue Unit (246 ft to 437 ft bml), below the Green 

Unit (1,932 ft to 2,500 ft bml), and below the Purple Unit (2,718 ft to 3,210 ft bml); and a negligible 

potential in clay-rich stratigraphy between the Seafloor to 246 ft bml and 437 ft to 1,118 ft bml. 

Findings and Recommendations

An area of authigenic carbonate outcrops and associated seep communities was identified approximately 

1,598 ft southwest of the proposed wellsite. Internal variability of sediment properties that could impact 

conductor jetting may be encountered within shallow mass-transport deposits between the Seafloor and 

246 ft bml. Two sub-regional SWF units (the Blue Unit and Green Unit) occur at 246 ft bml and 1,118 ft 

bml respectively. A third SWF prone unit (Purple Unit) occurs at 2,500 ft bml. Caution is recommended 

when drilling through these sediment units, and when intersecting buried faults at approximately 1,742 ft 

and 2,442 ft bml.

 
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 10 

FORUM ENERGY TECHNOLOGIES, INC. 

Closing

We appreciate the opportunity to be of service to Deep Gulf Energy Companies, and look forward to 

working together on future projects. 

Sincerely, 

GEOSCIENCE EARTH & MARINE 

SERVICES 

Oluwayomi Oyedele Daniel Lanier 

Geoscientist Director – Geoscience Earth & Marine Services 

Erin Williams Janes 

Project Manager/Senior Geoscientist 

Attachments (5 Maps and 3 Illustrations) 

Distribution: Mr. Barry G. Hexton, Deep Gulf Energy Companies (6 copies) 

REFERENCES 

AOA Geophysics Inc., 2009, Interpretation of wireline logging data and integration with other relevant data, Kodiak 

geotechnical investigation, Mississippi Canyon, Gulf of Mexico: Report prepared for BP America Inc., Report No. 

4041-BP-GOM-KOD-01. 

Bureau of Ocean Energy Management, 2013a, ASCII Data Files, published on the BOEM Gulf of Mexico Region 

Homepage, <http://www.gomr.boem.gov/homepg/pubinfo/freeasci/freedesc.html>, accessed December, 2013. 

Bureau of Ocean Energy Management, 2013b, Exploration Plan Control # S-07369, published on the BOEM Gulf of 

Mexico Region Homepage, < http://www.data.boem.gov/PI/PDFImages/PLANS/30/30739.pdf>, accessed June, 

2013. 

Bureau of Ocean Energy Management, 2011, Notice to lessees and operators (NTL) of federal oil and gas leases 

and pipeline right-of-way (ROW) holders on the outer continental shelf (OCS), revisions to the list of OCS lease 

blocks requiring archaeological resource surveys and reports: U.S. Departments of the Interior, Bureau of Ocean 

Energy Management, Bureau of Safety and Environmental Enforcement, Gulf of Mexico OCS Region (GOMR), NTL 

2011-JOINT-G01. Effective Date December 29, 2011. 

Carney, R.S., 2008, Summary of seafloor fauna observed during the Tubular Bells and Kodiak appraisal area ROV 

seafloor biological survey: Report prepared for BP America Inc., Report No. TBEL1-10GO-RP-000013. 

C&C Technologies Survey Services, (C&C), 2007, Archaeological Assessment Report, Block 727 & Vicinity, Mississippi 

Canyon Area: Report prepared for BP America Inc., Job no. 072456-073011. 

Coffeen, J. A., 1978, Seismic Exploration Fundamentals: Tulsa, the Petroleum Publishing Co., p. 125. 

Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009a, Deepwater geotechnical investigation, Kodiak Prospect 

SPAR development, Blocks 726, 727, 728, 770 & 771, Mississippi Canyon Area, Gulf of Mexico: Report prepared for 

BP America Inc., Report No. 0201-6584-1, volume I. 
Proposed Kodiak Site B Clearance Letter 

Deep Gulf Energy Companies // December 26, 2013

Geoscience Earth & Marine Services // 11 

FORUM ENERGY TECHNOLOGIES, INC. 

Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009b, Shallow water flow investigation, Kodiak Prospect, 

Blocks 727 & 771, Mississippi Canyon Area, Gulf of Mexico: Report prepared for BP America Inc., Report No. 0201-

6584-2, volumes I, II, & III. 

Fugro McClelland Marine Geosciences, Inc., (FMMG), 2010, Deepwater geotechnical investigation, Kodiak Prospect 

SPAR development, Blocks 726, 727, 728, 770 & 771, Mississippi Canyon Area, Gulf of Mexico: Report prepared for 

BP America Inc., Report No. 0201-6584-1, volume II.

Geoscience Earth & Marine Services, (GEMS), 2009, Tubular Bells/Kodiak development project, geologic and 

stratigraphic assessment, Blocks 680 to 684, 724 to 728, & 768 to 772, Mississippi Canyon Area, Gulf of Mexico, 

Project No. 0508-1497. 

Geoscience Earth & Marine Services, (GEMS), 2013, Seafloor verification study using ROV data, Block 727, 

Mississippi Canyon Area, Gulf of Mexico, Project No. 0713-2273. 

Minerals Management Service, 2005, Notice to lessees and operators of federal oil, gas, and sulphur leases and 

pipeline right-of-way holders in the outer continental shelf, Gulf of Mexico OCS region, Archaeological resource 

surveys and reports: U. S. Department of the Interior, Minerals Management Service, Gulf of Mexico, NTL 2005-G07. 

Minerals Management Service, 2008a, Notice to lessees and operators of federal oil, gas, and sulphur leases and 

pipeline right-of-way holders in the outer continental shelf, Gulf of Mexico OCS region, information requirements for 

exploration plans and development operations coordination documents: U. S. Department of the Interior, Minerals 

Management Service, Gulf of Mexico, NTL 2008-G04. 

Minerals Management Service, 2008b, Notice to lessees and operators of federal oil, gas, and sulphur leases and 

pipeline right-of-way holders in the outer continental shelf, Gulf of Mexico OCS region, shallow hazards requirements: 

U. S. Department of the Interior, Minerals Management Service, Gulf of Mexico, NTL 2008-G05. 

Minerals Management Service, 2010, Notice to lessees and operators of federal oil and gas leases in the outer 

continental shelf, Gulf of Mexico OCS region, deepwater benthic communities: U. S. Department of the Interior, 

Minerals Management Service, Gulf of Mexico, NTL 2009-G40. Effective Date January 27, 2010. 
Deep Gulf Energy II, LLC Section 2 – Pg. 11 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 4 

HYDROGEN SULFIDE INFORMATION 

4.1 CONCENTRATION 

DGE II does not anticipate encountering any H2S during the proposed operations. 

4.2 CLASSIFICATION 

In accordance with Title 30 CFR 250.490(c), DGE II requests that MC Block 727 Unit 

(Kodiak Unit) be classified by the BSEE as H2S absent. 

4.3 H2S CONTINGENCY PLAN 

Not applicable to the operations proposed in this plan. 

4.4 MODELING REPORT 

Not applicable to the operations proposed in this plan. 
Deep Gulf Energy II, LLC Section 5 – Pg. 12 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 5 

MINERAL RESOURCE CONSERVATION INFORMATION 

5.1 TECHNOLOGY & RESERVOIR ENGINEERING PRACTICES AND 

PROCEDURES 

Proprietary Information 

5.2 TECHNOLOGY AND RECOVERY PRACTICES AND PROCEDURES 

Proprietary Information 

5.3 RESERVOIR DEVELOPMENT 

Proprietary Information 
Deep Gulf Energy II, LLC Section 6 – Pg. 13 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 6 

BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION 

6.1 DEEPWATER BENTHIC COMMUNITIES 

The seafloor disturbing activities proposed in this plan are in water depths greater than 

300 meters (984’). Geoscience Earth & Marine Services, Inc. (GEMS) was contracted to 

provide an assessment of the shallow conditions at the proposed surface locations. 

The purpose of the assessment was to address seafloor conditions that may impact 

exploratory drilling operations within 2,000 feet of the proposed well sites. DGE II will 

avoid all high-density deepwater benthic communities by 2,000 feet from each proposed 

mud and cuttings discharge location and 250 feet from the location of all other seafloor 

disturbances. As per NTL 2009-G40, “Deepwater Benthic Communities,” a map 

showing the 2,000 foot radius around the well site is included as Attachment 6-A. 

6.2 TOPOGRAPHIC FEATURES (BANKS) 

Activities proposed in this DOCD do not fall within 305 meters (1000 feet) of a 

topographic “no activity zone”; therefore, no map is required per NTL 2009-G39, 

“Biologically Sensitive Underwater Features and Areas.”

6.3 TOPOGRAPHIC FEATURES STATEMENT (SHUNTING) 

All activities proposed under this DOCD will be conducted outside all Topographic 

Feature Protective Zones; therefore, shunting of drill cuttings and drilling fluids is not 

required per NTL 2009-G39, “Biologically Sensitive Underwater Features and Areas.”

6.4 LIVE-BOTTOMS (PINNACLE TREND FEATURES) 

MC Block 727 Unit (Kodiak Unit) is not located within 61 meters (200 feet) of any 

pinnacle trend feature; therefore, a separate bathymetric map is not required per NTL 

2009-G39, “Biologically Sensitive Underwater Features and Areas.”

6.5 LIVE BOTTOMS (LOW RELIEF) 

MC Block 727 Unit (Kodiak Unit) is not located within 30 meters (100 feet) of any 

pinnacle trend feature with vertical relief equal to or greater than 8 feet; therefore, live 

bottom (low relief) maps are not required per NTL 2009-G39, “Biologically Sensitive 

Underwater Features and Areas.”

6.6 POTENTIALLY SENSITIVE BIOLOGICAL FEATURES 

MC Block 727 Unit (Kodiak Unit) is not located within 30 meters (100 feet) of potentially 

sensitive biological features; therefore, biologically sensitive area maps are not 

required. 
Deep Gulf Energy II, LLC Section 6 – Pg. 14 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

6.7 REMOTELY OPERATED VEHICLE (ROV) SURVEYS 

BOEM has determined there is enough data gathered in Grid Area 16; therefore, ROV 

surveys either pre-spudding or post-drilling operations per NTL 2008-G06, “Remotely 

Operated Vehicle Surveys in Deepwater,” (Extended by NTL BOEM 2013-G02, 

“Extension of Prior Notices to Lessees”) is not required. However; based on prior 

discussion with BOEM, DGE II is planning on conducting underwater ROV surveys in 

the area. 

6.8 THREATENED AND ENDANGERED SPECIES, CRITICAL HABITAT, AND 

MARINE MAMMAL INFORMATION 

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

that any actions they authorize, fund, or carry out are not likely to jeopardize the 

continued existence of a listed species, or destroy or adversely modify its designated 

critical habitat. 

In accordance with 30 CFR 550, Subpart B, and further outlined in NTL 2008-G04, 

“Information Requirements for Exploration Plans and Development Operations 

Coordination Documents” (Extended by NTL BOEM 2013-G02, “Extension of Prior 

Notices to Lessees”) and NTL 2012-JOINT-G01,“Vessel Strike Avoidance and 

Injured/Dead Protected Species Reporting,” lessees/operators are required to address 

site-specific information on the presence of federally listed threatened or endangered 

species and critical habitat designated under the ESA and marine mammals protected 

under the Marine Mammal Protection Act (MMPA) in the area of proposes activities 

under this plan. 

There are five species of sea turtles that may be found in the Gulf of Mexico (see table 

below). NOAA fisheries currently lists all five of these turtles as endangered (E) or 

threatened (T). 

Species Scientific Name Status Potential Presence Critical Habitat 

Designated in 

the Gulf of 

Mexico 

Lease 

Area 

Coastal 

Sea Turtles 

Loggerhead Carettsa caretta T X X None 

Green Chelonia mydas T,E X X None 
Deep Gulf Energy II, LLC Section 6 – Pg. 15 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

Leatherback Dermochelys 

corlacea 

E X X None 

Hawksbill Eretmochelys 

imbricata 

E X X None 

Kemp’s 

Ridley 

Lepidochelys 

kempli 

E X X None 

In addition, there are 28 species of marine mammals that may be found in the Gulf of 

Mexico. The table provided below identifies the seven (7) species of marine mammals 

that are listed as endangered or threatened. Currently, there are no designated critical 

habitats for the listed species in the Gulf of Mexico Outer Continental Shelf; however, it 

is possible that one or more of these species could be seen in the area during 

operations. 

Species Scientific Name Status Potential 

Presence 

Critical 

Habitat 

Designated 

in the Gulf of 

Mexico 

Lease 

Area Coastal 

Marine Mammals 

Sperm Whale Physeter 

macrocephalus 

E X -- None 

Florida Manatee Trichechusmanatus 

latirostris 

E -- X Florida 

(Peninsular) 

Blue Whale Balaenoptera 

masculus 

E X -- None 

Fin Whale Balaenoptera 

physalus 

E X -- None 

Humpback 

Whale 

Megaptera 

novaeangliae 

E X -- None 

North Atlantic 

Right Whale 

Eubalaena glacialis E X -- None 

Sei Whale Balaenopiera 

borealis 

E X -- None 

There is one (1) species of fish that NOAA fisheries currently list as threatened (T) that 

may be found in the Gulf of Mexico. The Gulf sturgeon, also known as the Gulf of 

Mexico sturgeon, is an anadromous (breeding in freshwater after migrating up rivers 
Deep Gulf Energy II, LLC Section 6 – Pg. 16 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

from marine and estuarine environments) fish overwintering in estuaries, bays, and the 

Gulf of Mexico (see table below). 

Species Scientific Name Status Potential 

Presence 

Critical 

Habitat 

Designated 

in the Gulf of 

Mexico 

Lease 

Area Coastal 

Fish 

Gulf sturgeon Acipenser 

oxyrinchus 

(=oxyrhynchus) 

desotoi 

T X X None 

6.9 ARCHAEOLOGICAL REPORT 

MC Block 727 Unit (Kodiak Unit) has been determined to have a high potential for 

containing archaeological properties. Review of the data obtained during the shallow 

hazard study does not indicate the presence of any historic period shipwrecks. 

Should DGE II discover man-made debris that appears to indicate the presence of a 

shipwreck (e.g. a sonar image or visual confirmation of an iron, steel or wooden hull, 

piles of ballast rock) within or adjacent to our lease area during the course of 

operations, DGE II will immediately halt operations, take steps to ensure that the site is 

not disturbed in any way and contact the Regional Supervisor, Leasing and 

Environment, within 48 hours of the discovery. DGE II will cease all operations within 

1000 feet (305 meters) of the site until the Regional Director instructs our office on what 

steps to take to assess the site’s potential historical significance and what steps to 

protect it. 

6.10 AIR AND WATER QUALITY INFORMATION 

Air and water quality information is not required to be included in this plan per NTL 

2008-G04, “Information Requirements for Exploration Plans and Development 

Operations Coordination Documents.” 

6.11 SOCIOECONOMIC INFORMATION 

Socioeconomic Information is not required to be included in this plan per NTL 2008-

G04, “Information Requirements for Exploration Plans and Development Operations 

Coordination Documents.” 


Deep Gulf Energy II, LLC Section 7 – Pg. 17 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 7 

WASTES AND DISCHARGES INFORMATION 

7.1 PROJECTED GENERATED WASTES 

 “Wastes You Will Generate, Treat and Downhole Dispose or Discharge to the Gulf of 

Mexico” is included as Attachment 7-A. 

7.2 MODELING REPORT 

Modeling reports are not required to be submitted with this plan. 
ATTACHMENT 7‐A

Drill cuttings wetted with water-based fluid Cuttings coated with water based drilling mud 1,000 bbl/well 250 bbl/day/well Discharged at mudline prior to BOP 

installation

Drill cuttings wetted with synthetic-based fluid Cuttings coated with synthetic- based drilling mud 9,521 bbl/well 73 bbl/day/well

Drill cuttings from the wellbore are pro

solids control equipment (shakers, cu

which substantially reduces ROC per

processed cuttings are discharged thro

to 25' below water's surfac

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

Waste you will generate, treat and downhole dispose or discharge to the GOM

Projected Generated Waste Projected Ocean Discharges

Type of Waste Composition Projected Amount Discharge Rate Discharge Method

Discharge overboard

Discharged at mudline prior to BOP 

installation Water-based Drilling Fluids Water based drilling fluid 40,000/bbl/well 10,000 bbl/day/well

EXAMPLE: Cuttings wetted with synthetic based 

fluid

Cuttings generated while 

using synthetic based drilling 

fluid

X bbl/well X bbl/day /well

Will humans be there? If yes, expect conventional waste

Domestic waste Gray water (laundry, galley, lavatory) 27,251 bbl/well 5 bbl/hr/well Discharged overboard. Associated foo

processed using an approved g

Sanitary waste Treated human body waste from toilets 27,251 bbl/well 5 bbl/hr/well USCG approved MSD

Will you conduct well treatment, completion or workover? If yes, only fill in those associated with your activity

Well treatment fluids KCL/HCL/NaCL/NaBr 2,000 bbl/well 10 bbl/min/well Discharged overboard

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

Deck Drainage Platform washings and rainwater 550 bbl/well 0.1 bbl/hr/well Oily water is treated in Oily Water 

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

Desalinization unit discharge Rejected water from water maker unit 313,959 bbl/well 57 bbl/hr Cuttings chuteBlowout prevent fluid

Stackmagic 200/0/5% glycol 

based on 2% mixture with 

potable water

384 bbl/well 12 bbl/week with function test Discharged from BOP near m

Ballast water Uncontaminated seawater used to maintain proper draft 49,464 bbl/well 9 bbl/hr Discharged overboardBilge Water Bilge water 550 bbl/well 0.1 bbl/hr Discharged overboardExcess cement at seafloor Cement slurry 900 bbl/well 19 bbl/hr Discharged at the mudline during c

conductor casing

Wash water Wash water, sink drainage, etc 27,251 bbl/well 5 bbl/hr/well Discharged overboardFirewater Seawater with no addition of chemicals N/A N/A Discharged overboardCooling water Seawater with no addition of 9,160,000 bbl/well 1,667 bbl/hr Discharged overboard

Will you be covered by an individual or general NPDES permit:

General - NPDES ID GMG290356

NOTE: IF YOU WILL NOT HAVE A TYPE OF WASTE, ENTER “NA” IN THE ROW.

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

Produced water N/A N/A N/A N/A 
Deep Gulf Energy II, LLC Section 8 – Pg. 18 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 8 

AIR EMISSIONS INFORMATION 

8.1 EMISSIONS WORKSHEETS AND SCREENING QUESTIONS 

Screen Procedures for DOCD’s Yes No 

Is any calculated Complex Total (CT) Emission amount (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 the other air pollutants (where D = distance to shore in miles)? 

 X 

Do your emission calculations include any emission reduction measures or 

modified emission factors? X 

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 (40 kilometers) from shore? X 

Are your proposed development and production activities located within 

124 miles (200 kilometers) of the Breton Wilderness Area? X 

8.2 SUMMARY INFORMATION 

There are no co-existing facilities; therefore, the total complex emissions and the plan 

emissions are the same. Included as Attachment 8-A are Air Emission Worksheets 

which show the emissions calculations. 

This information was calculated by: Kelley Pisciola 

 (281) 578-3388

 kelley.pisciola@jccteam.com 

Air Emissions were calculated using Ensco 8500 Series Specific Horsepower and fuel 

consumption. DGE II will use a Rig equal to or similar to an Ensco 8500 Series Rig. 

Air emissions for the production life of the wells proposed in this plan will be included in 

the AQR submitted for the third party host facility. 
DOCD AIR QUALITY SCREENING CHECKLIST 

OMB 

COMPANY DGE II

AREA MCBLOCK 727LEASE G-24102 / G24107 (Kodiak Unit)PLATFORM N/A

WELL A (MC771) & B (MC727)

COMPANY CONTACT Kelley PisciolaTELEPHONE NO. 281-698-8519

REMARKS Drill, complete & produce Locations A (MC771 #2) and B (MC727 #3); 

install 2 lease jumper pipelines and commence production.AQR calculated using Ensco 8500 Series Specific Horsepower

LEASE TERM PIPELINE CONSTRUCTION INFORMATION:

YEAR NUMBER OF TOTAL NUMBER OF CONSTRUCTION DAYS

PIPELINES

20142015 1 72016 1 7

FORM BOEM-0139 (December 2011- Supersedes all previous versions of this form which may not be used). Page 1 of 8
AIR EMISSIONS CUMPUTATION FACTORS

Fuel Usage Conversion Factors Natural Gas Turbines Natural Gas Engines Diesel Recip. Engine RE

SCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483 AP42 

Equipment/Emission Factors units PM SOx NOx VOC CO RENG Turbines gms/hp-hr 0.00247 1.3 0.01 0.83 AP42 3.2-NG 2-cycle lean gms/hp-hr 0.00185 10.9 0.43 1.5 AP42 NG 4-cycle lean gms/hp-hr 0.00185 11.8 0.72 1.6 AP42 NG 4-cycle rich gms/hp-hr 0.00185 10 0.14 8.6 AP42 Diesel Recip. < 600 hp. gms/hp-hr 1 1.468 14 1.12 3.03 AP42 Diesel Recip. > 600 hp. gms/hp-hr 0.32 1.468 11 0.33 2.4 AP42 Diesel Boiler lbs/bbl 0.084 2.42 0.84 0.008 0.21 AP42 1.3NG Heaters/Boilers/Burners lbs/mmscf 7.6 0.593 100 5.5 84 P42 1.4-1, 1NG Flares lbs/mmscf 0.593 71.4 60.3 388.5 AP42 1Liquid Flaring lbs/bbl 0.42 6.83 2 0.01 0.21 AP42 1.3-Tank Vapors lbs/bbl 0.03 E&P FFugitives lbs/hr/comp. 0.0005 API SGlycol Dehydrator Vent lbs/mmscf 6.6 La. DGas Venting lbs/scf 0.0034

Sulphur Content Source Value Units

Fuel Gas 3.33 ppm

Diesel Fuel 0.4 % weight

Produced Gas( Flares) 3.33 ppm

Produced Oil (Liquid Flaring) 1 % weight

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 2 of 8
AIR EMISSIONS CALCULATIONS - FIRST YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

DGE II MC 727 G-24102 / G241 N/A B Kelley Pisciola 281-698-8519

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR 

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 PM 

DRILLING PRIME MOVER>600hp diesel 21739 1049.9937 25199.85 24 122 15.32 70.29 526.72 15.80 114.92 22.43 

PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

Vessel trips / wk BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

AUXILIARY EQUIP<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

2 VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 8 34 1.46 6.68 50.03 1.50 10.92 0.20 2 VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 34 3.10 14.23 106.61 3.20 23.26 0.53 

VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PIPELINE PIPELINE LAY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 INSTALLATION SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 FLARE- 0 0 0 0.00 0.00 0.00 0.00 PROCESS VENT- 0 0 0 0.00 FUGITIVES- 0.0 0 0.00 GLYCOL STILL VENT- 0 0 0 0.00 

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 

2014 YEAR TOTAL 19.88 91.20 683.36 20.50 149.10 23.16 

EXEMPTION 

CALCULATION

DISTANCE FROM LAND IN 

MILES 1798.20 

54.0

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 3 of 8
AIR EMISSIONS CALCULATIONS - SECOND YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

DGE II MC 727 G-24102 / G241 N/A B Kelley Pisciola 281-698-8519 #REF!

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR 

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 PM S

DRILLING PRIME MOVER>600hp diesel 21739 1049.9937 25199.85 24.00 107.00 15.32 70.29 526.72 15.80 114.92 19.67 9

PRIME MOVER>600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0PRIME MOVER>600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0PRIME MOVER>600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0

Vessels trips/wk BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

AUXILIARY EQUIP<600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0

2 VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 6.00 31.00 1.46 6.68 50.03 1.50 10.92 0.14 02 VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10.00 31.00 3.10 14.23 106.61 3.20 23.26 0.48 2

VESSELS>600hp diesel(tugs) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0

PIPELINE PIPELINE LAY BARGE diesel 45000 2173.5 52164.00 24 7 31.72 145.51 1090.31 32.71 237.89 2.66 1INSTALLATION SUPPORT VESSEL diesel 5479 264.6357 6351.26 24 7 3.86 17.72 132.75 3.98 28.96 0.32 1(One Pipelines) PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

SUPPORT VESSEL diesel 5479 264.6357 6351.26 8 5 3.86 17.72 132.75 3.98 28.96 0.08 0VESSELS>600hp diesel(crew) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0VESSELS>600hp diesel(supply) 5000 241.5 5796.00 10.00 5.00 3.52 16.17 121.15 3.63 26.43 0.09 0

FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

VESSELS>600hp diesel(crew) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0VESSELS>600hp diesel(supply) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0

PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 FLARE- 0 0 0 0.00 0.00 0.00 0.00 0PROCESS VENT- 0 0 0 0.00 FUGITIVES- 0.0 0 0.00 GLYCOL STILL VENT- 0 0 0 0.00 

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 0

2015 YEAR TOTAL 62.85 288.30 2160.31 64.81 471.34 23.44 10

EXEMPTION 

CALCULATION

DISTANCE FROM LAND IN 

MILES 1798.20 17

54.0

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 4 of 8
AIR EMISSIONS CALCULATIONS - THIRD YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

DGE II MC 727 G-24102 / G241 N/A A (MC771) & B (MC727) Kelley Pisciola 281-698-8519 #REF!

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR 

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 PM S

DRILLING PRIME MOVER>600hp diesel 21739 1049.9937 25199.85 24 229 15.32 70.29 526.72 15.80 114.92 42.11 19

PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

Vessels trips / wk BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

AUXILIARY EQUIP<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

2 VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 8 65 1.46 6.68 50.03 1.50 10.92 0.38 12 VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 65 3.10 14.23 106.61 3.20 23.26 1.01 4

VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

PIPELINE PIPELINE LAY BARGE diesel 45000 2173.5 52164.00 24 7 31.72 145.51 1090.31 32.71 237.89 2.66 1INSTALLATION SUPPORT VESSEL diesel 5479 264.6357 6351.26 24 7 3.86 17.72 132.75 3.98 28.96 0.32 1(One Pipeline) PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

SUPPORT VESSEL diesel 5479 264.6357 6351.26 8 5 3.86 17.72 132.75 3.98 28.96 0.08 0VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0VESSELS>600hp diesel(supply) 5000 241.5 5796.00 10 5 3.52 16.17 121.15 3.63 26.43 0.09 0

FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0

RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 FLARE- 0 0 0 0.00 0.00 0.00 0.00 0PROCESS VENT- 0 0 0 0.00 FUGITIVES- 0.0 0 0.00 GLYCOL STILL VENT- 0 0 0 0.00 

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 0

2016 YEAR TOTAL 62.85 288.30 2160.31 64.81 471.34 46.65 21

EXEMPTION 

CALCULATION

DISTANCE FROM LAND IN 

MILES 1798.20 17

54.0

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 5 of 8
AIR EMISSIONS CALCULATIONS - FOURTH YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

DGE II MC 727 G-24102 / G241 N/A A (MC771) & B (MC727) Kelley Pisciola 281-698-8519 #REF!

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR 

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 PM 

DRILLING PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 AUXILIARY EQUIP<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PIPELINE PIPELINE LAY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 INSTALLATION SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 

RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 MISC. BPD SCF/HR COUNT

TANK- 0 0 0 0.00 FLARE- 0 0 0 0.00 0.00 0.00 0.00 PROCESS VENT- 0 0 0 0.00 FUGITIVES- 0.0 0 0.00 GLYCOL STILL VENT- 0 0 0 0.00 

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 

2017 - 2025 YEAR TOTAL 0.00 0.00 0.00 0.00 0.00 0.00 

EXEMPTION 

CALCULATION

DISTANCE FROM LAND IN 

MILES 0.00 

0.0

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 6 of 8
AIR EMISSIONS CALCULATIONS

COMPANY AREA BLOCK LEASE PLATFORM WELLDGE II MC 727 G-24102 / G24107 (Ko N/A A (MC7

Emitted Substance

Year

 PM SOx NOx VOC 

2014 23.16 106.24 796.04 23.88 2015 23.44 107.55 805.90 24.18 2015 46.65 213.99 1603.49 48.10 3

2017-2025 0.00 0.00 0.00 0.00 

Allowable 1798.20 1798.20 1798.20 1798.20 48

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 8 of 
ACTUAL FUEL USAGE FACTORS ASSUMED FOR AQR EMISSION CALCULATIONS

Rig 1/1/2013

Fuel On Board, Bbl

7/1/2013

Fuel On Board, Bbl Fuel Taken On, Bbl Total Fuel Used, 

Bbl

Daily Ave. Fuel, 

Bbl

8500 6580.0 10836.0 50858.0 46602.0 257.47

8501 6870.0 9284.0 48936.0 46522.0 257.03

8503 11812.0 9295.0 39202.0 41719.0 230.49

8505 10618.0 10205.0 43477.0 43890.0 242.49

246.87 bbl/day

12.95 1 Std. deviation

8500, 8501, 8503, 8505 reported fuel-on-board at beginning (01 Jan. 2013) and ending (01 July 2013) dates, also all fuel taken onbaord that period

8502.0 36582.0 202.11

8506.0 40791.0 225.36

213.74 (bbl/day)

16.44 1 Std. deviation

8502 and 8506 reported total fuel consumption for the period 01 Jan. - 01 July 2013

Rig Total Fuel Used, Bbl Daily Ave. Fuel, Bbl

6 x 8500 

Series Rigs 256106.0 235.83 bbl/day

21.15 1 Std. Deviation

63.5 3 std. deviation

299.28 bbls/day, Mean + 3 std. 

deviations (99.73%)

0.0483 gal/hp-hr (diesel recip. 

Factor, AQE)

10843.47 HP

21686.94 HP x 2

21739.00 HP used in AQE 

reporting

600.00 bbl/day used in AQE 

reporting

257.47

257.03

230.49

242.49

202.11

225.36

Daily Fuel Consumption 8500 series January 1, 2013 to July 1, 2013 (181 days)
Deep Gulf Energy II, LLC Section 9 – Pg. 19 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

SECTION 9 

OIL SPILL INFORMATION 

9.1 OIL SPILL RESPONSE PLANNING 

All the proposed activities and facilities in the DOCD will be covered by the Regional Oil 

Spill Response Plan (OSRP) filed by Deep Gulf Energy LP (BOEM Operator No. 02815) 

and includes Deep Gulf Energy II, LLC (BOEM Operator No. 02985), dated May 2013, 

last approved December 9, 2013 (OSRP Control Number O-978). 

9.2 SPILL RESPONSE SITES 

Primary Response Equipment 

Location 

Preplanned Staging Location 

Houma, LA Houma, LA 

Harvey, LA Harvey, LA 

Leeville, LA Leeville, LA 

 Venice, LA 

9.3 OSRO INFORMATION 

DGE II’s primary equipment provider is Clean Gulf Associates (CGA), and it will provide 

the closest available personnel, as well as a supervisor to operate the equipment. 

9.4 WORST-CASE DISCHARGE SCENARIO DETERMINATION 

Category 

Drilling Production 

Regional

OSRP 

WCD 

DOCD 

WCD 

Regional 

OSRP 

WCD 

DOCD 

WCD 

Type of Activity Drilling Drilling 

<10 / > 10 

mile 

Production 

<10 / > 10 

mile 

Production

Facility Location (Area/Block) MC 771 MC 771 MC 771 MC 771 

Facility Designation #002 #002 #002 #002 

Distance to Nearest 

Shoreline (miles) 54 54 54 54 

Volume 

 Storage tanks & flowlines 

 Lease term pipelines 

 Uncontrolled blowout 

Total Volume (bbls) 107,728 107,728 25,224 25,224 
Deep Gulf Energy II, LLC Section 9 – Pg. 20 of 31 

Unit DOCD July, 2013 

Kodiak Development Unit 

Type of Oil(s) 

(crude, condensate, diesel) Oil Oil Oil Oil 

API Gravity 35 35 35 35 

The WCD calculations and assumptions for the Regional OSRP WCD, MC771 Well 

No.002 (107,728) were previously reviewed under Plan Control No. S-7624. 

Since DGE II has the capability to respond to the appropriate worst-case spill scenario 

included in its regional OSRP approved on December 9, 2013, and since the worst-case 

scenario determined for our DOCD does not replace the appropriate worst-case 

scenario in our regional OSRP, DGE II hereby certifies that DGE II has the capability to 

respond, to the maximum extent practicable, to a worst-case discharge, or a substantial 

threat of such a discharge, resulting from the activities proposed in our DOCD. 

The oil spill response discussion is included as Attachment 9-A. 

The Worst Case Discharge Volume calculations and assumptions used to determine the 

volume (daily discharge rate) of their WCD scenario were provided in the Proprietary 

Copy of this plan. 
ATTACHMENT 9-A 

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 107,728 barrels of crude oil with an API gravity of 35°. 

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 an 11% 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 

DGE II 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 21% or 

approximately 22,623 barrels of crude oil would be evaporated/dispersed within 24 hours, with 

approximately 85,105 barrels remaining. 

Spill Response MC 771, Well #002 Barrels of Oil 

WCD Volume 107,728 

Less 21% natural evaporation/dispersion 22,623 

Remaining volume 85,105 

Figure 2 outlines equipment, personnel, materials and support vessels as well as temporary 

storage equipment available to respond to a spill of approximately 85,105 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. 
DGE II’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) 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 47,000 barrel 

storage barge, three 23,000 barrel storage barges, and three 20,000 barrel storage barges 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 25,200 

barrels. Temporary storage associated with skimming equipment equals 590 barrels. If additional 

storage is needed, a 25,000 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. Master Service Agreements with AMPOL and 

OMI Environmental will ensure access to 147,000 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. DGE II’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, DGE II 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 

60 hours (based on the equipment’s Effective Daily Recovery Capacity (EDRC)). 
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 

DGE II 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 
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 
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 

T&T Koseq Skimming Systems 

 To the area of the thickest oil 

 Use as far off-shore as allowed 

 VOOs with a minimum of 2,000 bbls storage capacity 

 VOOs at least 200’ in length 

 VOOs with deck space of 100’ x 40’ to provide space for arms, tanks, and crane 

 VOOs for shallow water should be deck barges with 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 DGE II’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. 
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 DGE II’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 
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 
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 
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. 
FIGURE 1 

TRAJECTORY BY LAND SEGMENT 

Trajectory of a spill and the probability of it impacting a land segment have been projected 

utilizing DGE II’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 

Drill, Complete and 

Produce two well 

locations 

MC 771, Well #002 

54 miles from shore 

G24107 C59 Cameron, LA 

Vermilion, LA 

Terrebonne, LA 

Lafourche, LA 

Jefferson, LA 

Plaquemines, LA 

St. Bernard, LA 

Walton, FL 

Bay, FL 

1 

1 

2 

2 

1 

11 

2 

1 

1 
WCD Scenario– BASED ON WELL BLOWOUT DURING DRILLING OPERATIONS (54 miles from sh

85,105 bbls of crude oil (Volume considering natural weathering) 

API Gravity 35° 

FIGURE 2 – Equipment Response Time to MC 771, Well #002 

Dispersants/Surveillance

Dispersant/Surveillance Dispersant Capacity (gal) Storage Capacity Persons Req. From Hrs to Procure Hrs to Loadout Trav

to sit

CGA 

Basler 67T 2000 NA 2 Houma 1 1 0.7 

ASI 

DC 3 1200 NA 2 Houma 1 1 1 DC 3 1200 NA 2 Houma 1 1 1 Aero Commander NA NA 2 Houma 1 1 0.7 

Offshore Response

Offshore Equipment No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure Hrs to Loadout Hrs to GOM 

CGA 

HOSS Barge 43000 4000 3 Tugs 5 Harvey 7 0 5 Boom Barge (CGA-300) 42” Auto Boom (25000’) NA NA 1 Tug 50 Crew 4 (Barge) 2 (Per Crew) Leeville 4 0 6 

Recovered Oil Storage No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure Hrs to Loadout Hrs to GOM 

Enterprise Marine Services LLC (available through contract with CGA) 

CTCo 2604 NA 20000 1 Tug 6 Amelia 4 12 4 CTCo 2605 NA 20000 1 Tug 6 Amelia 4 12 4 CTCo 2606 NA 20000 1 Tug 6 Amelia 4 12 4 CTCo 2607 NA 23000 1 Tug 6 Amelia 4 12 4 CTCo 2608 NA 23000 1 Tug 6 Amelia 4 12 4 CTCo 2609 NA 23000 1 Tug 6 Amelia 4 12 4 CTCo 5001 NA 47000 1 Tug 6 Amelia 4 12 4 
Staging Area: Venice

Offshore Equipment With 

Staging EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging 

CGA 

FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Galveston 1 2 8 FRU (1) + 100 bbl Tank (1) 4251 100 1 Utility 6 Harvey 1 2 1.75 FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Ingleside 1 2 11 FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Lake Charles 1 2 5.5 FRU (2) + 100 bbl Tank (2) 8502 400 2 Utility 12 Leeville 1 2 3.5 FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Morgan City 1 2 3.25 FRU (2) + 100 bbl Tank (4) 8502 400 2 Utility 12 Venice 1 2 0 

T&T Marine (available through contract with CGA) 

Koseq Skimming Arms (3) 53487 6000 3 Utility 18 Leeville 24 24 3.5 Koseq Skimming Arms (1) 17829 2000 1 Utility 6 Fourchon 24 24 4 Koseq Skimming Arms (2) 35658 4000 2 Utility 12 Venice 24 24 0 

Offshore Equipment With 

Staging EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging 

CGA 

Hydro-Fire Boom NA NA 8 Utility 40 Harvey (HFB) 1 4 1.75 
Nearshore Response

Nearshore Equipment No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure Hrs to Loadout Hrs to GOM 

CGA 

46’ FRV 5000 65 NA 4 Venice 1 0 1 

Enterprise Marine Services LLC (available through contract with CGA) 

CTCo 2603 NA 25000 1 Tug 6 Amelia 4 12 4 

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 T

Dep

CGA 

SWS Egmopol 3000 100 NA 3 Galveston 1 2 8 SWS Egmopol 3000 100 NA 3 Morgan City 1 2 3.25 SWS Marco 3588 20 NA 3 Lake Charles 1 2 5.5 SWS Marco 3588 34 NA 3 Leeville 1 2 3.5 SWS Marco 3588 34 NA 3 Venice 1 2 0 Rope Mop 77 2 0 3 Harvey 1 2 8 Foilex Skim Package (TDS 150) 891 45 NA 3 Lake Charles 1 2 5.5 Foilex Skim Package (TDS 150) 891 45 NA 3 Galveston 1 2 8 Foilex Skim Package (TDS 150) 891 45 NA 3 Harvey 1 2 1.75 4 Drum Skimmer (Magnum 100) 686 100 1 Crew 3 Lake Charles 1 2 5.5 
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 Site 

AMPOL (available through MSA) 

42,000’ 18” Boom 16 Crew 40 New Iberia, LA 2 2 4 2 20,000’ 18” Boom 8 Crew 20 New Orleans, LA 2 2 2 2 

OMI Environmental (available through MSA) 

10,000’ 18” Boom 4 Crew 10 New Iberia, LA 1 1 4 2 10,000’ 18” Boom 4 Crew 10 Houston, TX 1 1 7.5 2 10,000’ 18” Boom 4 Crew 10 Port Arthur, TX 1 1 6.25 2 20,000’ 18” Boom 8 Crew 20 Belle Chasse, LA 1 1 1.75 2 10,000’ 18” Boom 4 Crew 10 Port Allen, LA 1 1 3.5 2 10,000’ 18” Boom 4 Crew 10 Houma, LA 1 1 3.5 2 15,000’ 18” Boom 6 Crew 14 Gretna, LA (Warehouse) 2 2 2 2 

Beach Boom EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging T

D

CGA 

Beach Boom (2000’) NA NA NA 6 Galveston 1 2 8 Beach Boom (1000’) NA NA NA 4 Ingleside 1 2 11 Beach Boom (2000’) NA NA NA 6 Pascagoula 1 2 4 
Wildlife Response EDRC Storage Capacity VOO Persons Req. From Hrs to Procure Hrs to Loadout Travel to Staging T

D

CGA 

Wildlife Support Trailer NA NA NA 2 Houma 1 2 3 Bird Scare Guns (24) NA NA NA 2 Belle Chasse 1 2 1.5 Bird Scare Guns (12) NA NA NA 2 Galveston 1 2 8 Bird Scare Guns (24) NA NA NA 2 Houma 1 2 3 Bird Scare Guns (12) NA NA NA 2 Ingleside 1 2 11 Bird Scare Guns (24) NA NA NA 2 Lake Charles 1 2 5.5 Bird Scare Guns (24) NA NA NA 2 Pascagoula 1 2 4 

Response Asset Total 

Offshore EDRC 188,233 

Offshore Recovered Oil Storage 193,700 

Nearshore / Shallow Water EDRC 25,200 

Nearshore / Shallow Water Recovered Oil Storage 25,590 
Deep Gulf Energy II, LLC Section 10– Pg. 21 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 10 

ENVIRONMENTAL MONITORING INFORMATION 

10.1 MONITORING SYSTEMS 

DGE II subscribes to Wilkens Weather Service which provides access to real time 

weather conditions and provides periodic updates on impending weather conditions 

such as tropical depressions, storms, and/or hurricanes entering the Gulf of Mexico. 

DGE II also relies on the National Weather Service to support the aforementioned 

subscribed service. During impending inclement weather conditions, DGE II closely 

coordinates the activity with our contractors and field personnel to ensure the safety of 

people for evacuation to ensure protection of the environment and the 

facility/equipment. 

DGE II will monitor loop currents per the requirements as set forth in NTL 2009-G02, 

“Ocean Current Monitoring.” 

10.2 INCIDENTAL TAKES 

There is no reason to believe that any of the endangered species or marine mammals 

as listed in the ESA will be “taken” as a result of the operations proposed under this 

plan. 

It has been documented that the use of explosives and/or seismic devices can affect 

marine life. Operations proposed in this plan will not be utilizing either of these devices. 

DGE II will adhere to the requirements as set forth in the following documents, as 

applicable, to avoid or minimize impacts to any of the species listed in the Endangered 

Species Act (ESA) as a result of the operations conducted herein: 

 NTL 2012-JOINT -G01, “Vessel Strike Avoidance and Injured/Dead Protected 

Species Reporting” 

 NTL 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures 

and Protected Species Observer Program” 

10.3 FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY 

MC Block 727 Unit (Kodiak Unit) is not located in the Flower Garden Banks National 

Marine Sanctuary; therefore, relevant information is not required in this DOCD. 
Deep Gulf Energy II, LLC Section 11– Pg. 22 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 11 

LEASE STIPULATIONS INFORMATION 

Development activities are subject to the following stipulation attached to Lease OCS-G

24102, Mississippi Canyon Block 727 and Lease OCS-G 24107, Mississippi Canyon 

Block 771. 

11.5 MARINE PROTECTED SPECIES 

The Marine Protected Species lease stipulation is meant to reduce the potential taking 

of marine protected species. DGE II will operate in accordance with NTL 2012-JOINTG01, “Vessel Strike Avoidance and Injured/Dead Protected Species Reporting,” to 

minimize the risk of vessel strikes to protected species and report observations of 

injured or dead protected species, and the prevention of intentional and/or accidental 

introduction of debris into the marine environment. 
Deep Gulf Energy II, LLC Section 12– Pg. 23 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 12 

ENVIRONMENTAL MITIGATION MEASURES INFORMATION 

12.1 MEASURES TAKEN TO AVOID, MINIMIZE, AND MITIGATE IMPACTS 

MC Block 727 Unit (Kodiak Unit) is not located within Florida; therefore, the relevant 

information requested is not required in this plan. 

12.2 INCIDENTAL TAKES 

DGE II will adhere to the requirements as set forth in the following documents, as 

applicable, to avoid or minimize impacts to any of the species listed in the Endangered 

Species Act (ESA) as a result of the operations conducted herein: 

 NTL 2012-JOINT-G01, “Vessel Strike Avoidance and Injured/Dead Protected 

Species Reporting” 

 NTL 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures 

and Protected Species Observer Program” 
Deep Gulf Energy II, LLC Section 13– Pg. 24 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 13 

RELATED FACILITIES AND OPERATIONS INFORMATION 

13.1 RELATED OCS FACILITIES AND OPERATIONS 

The subject wells will be protected by subsea trees, and will tie-in to the MC 727 FLET 

via two proposed 8-inch lease-term jumper pipelines (submittals pending) approximately 

85 feet in length in Mississippi Canyon Block 727. A proposed 8-inch right-of-way 

pipeline, approximately 6.25 miles in length, will be installed to transport produced 

hydrocarbons from the FLET to the existing A (Devil’s Tower) Platform located in 

Mississippi Canyon Block 773 with ultimate delivery of gas into Operations System MLX 

and ultimate delivery of liquids into Operations System No. 57.0. The maximum flow 

rate is 30,000 BOPD and 35 MMSCFD gas. The pipeline will have a shut-in time of 45 

seconds. 

13.2 TRANSPORTATION SYSTEM 

Production will flow from the host facility in Mississippi Canyon Block 773 via the Devils 

Tower export pipeline system. Gas will be processed, dehydrated and transported by 

Williams Field Services – Gulf Coast Company, L.P. (Williams) via the Williams’ Canyon 

Chief gas export pipeline and processed at Williams’ Mobile Bay gas plant. Oil will be 

exported through an existing Lease Automatic Transfer (LACT) to the Mountaineer oil 

export pipeline for ultimate delivery to shore. 

No new near shore or onshore pipelines or facilities will be constructed. 

13.3 PRODUCED LIQUID HYDROCARBONS TRANSPORTATION VESSELS 

There will not be any transfers of liquid hydrocarbons other than via pipeline. 
Deep Gulf Energy II, LLC Section 14– Pg. 25 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 14 

SUPPORT VESSELS AND AIRCRAFT INFORMATION 

14.1 GENERAL 

The most practical, direct route from the shore base as permitted by weather and traffic 

conditions will be utilized. 

Type Maximum Fuel 

Tank Capacity 

Maximum 

Number in Area 

at Any Time 

Trip Frequency or 

Duration 

High Speed Supply 

Vessel 

3000 gal 1 2 per week 

Marine Supply Vessel 

(MSV) 

400,000 gal 2 2 per week 

Crew Boat 500 bbls 1 2 per week 

Helicopters 600 gal 1 6 per week 

14.2 DIESEL OIL SUPPLY VESSELS 

Size of Fuel 

Supply Vessel 

Capacity of Fuel 

Supply Vessel 

Frequency of Fuel 

Transfers 

Route Fuel Supply 

Vessel Will Take 

Marine Supply 

Vessel (MSV) 

400,000 gal 1 per week Direct to Fourchon 

14.3 DRILLING FLUID TRANSPORTATION 

Drilling fluid transportation information is not required to be submitted with this plan. 

14.4 SOLID AND LIQUID WASTE TRANSPORTATION 

A table, “Wastes You Will Transport and/or Dispose of Onshore,” is included as 

Attachment 14-A. 

14.5 VICINITY MAP 

A vicinity map showing the location of the activities proposed herein relative to the 

shoreline with the distance of the proposed activities from the shoreline and the primary 

routes of the support vessels and aircraft that will be used when traveling between the 

onshore support facilities and the drilling unit is included as Attachment 14-B.
please specify whether the amount reported is a total or per well

Solid and Liquid Wastes 

transportation 

Type of Waste Composition Transport Method

Name/Location of Facility Amount 

Will drilling occur ? If yes, fill in the muds and cuttings.

Oil-based drilling fluid or mud N/A N/A N/A N/A Synthetic-based drilling fluid or mud internal olefin Below-deck storage tanks on offshore support vessels M-I Swaco, Port Fourchon, LA 20,000 bbls/wel

Cuttings wetted with Synthetic-based fluid Cuttings generated using synthetic based fluid Below-deck storage tanks on offshore support vessels Newport Environmental Services Inc., Ingleside, TX 1,000 bbls/well 

Cuttings wetted with oil-based fluids N/A N/A N/A N/A 

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

Produced sand N/A N/A N/A N/A Well Completion Fluids CaBr2 / ZnBr2 Below-deck storage tanks on offshore support vessels Newport Environmental Services Inc., Ingleside, TX 6,000 bbls/well Workover Fluids CaBr2 / ZnBr2 Below-deck storage tanks on offshore support vessels Newport Environmental Services Inc., Ingleside, TX 6,000 bbls/well Trash and debris Non-hazardous trash & debris (non- recyclables) Transport in DOT containers on supply vessels to shorebase Progressive Waste Solutions of LA, Houma, LA 700 lbs/well 

Used oil Used oil and glycol Transport in DOT containers on supply vessels to shorebase Safety Kleen System, Baton Rouge, LA 420 gal/well (10 bbls/well) 

Chemical product wastes Paints, solvents, unused chemicals, etc Transport in DOT containers on supply vessels to shorebase Safety Kleen System, Baton Rouge, LA 130 lbs/well NOTE: If you will not have a type of waste, enter NA in the row. 

TABLE 2. WASTES YOU WILL TRANSPORT AND /OR DISPOSE OF ONSHORE 

Waste Di

Will you have additional wastes that are not permitted for discharge? If yes, fill in the appropriate rows. 

Projected generated waste
!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!! !!

!!

!!

Atwater Valley

Mississippi Canyon

Lloyd Ridge

Destin Dome

DeSoto Canyon

Lund

Mobile

Green Canyon

Main Pass

Viosca Knoll

West Delta

Pensacola

Grand Isle

Main Pass South & East

Henderson

Ewing Bank

Breton Sound

Chandeleur

West Delta South

Walker Ridge

Biloxi

Venice

Mobile

G Meraux retna Harvey

Lafitte

Hopedale

Gulfport

Fourchon

Galliano

St. Rose

Pascagoula

Grand Isle

River Ridge

New Orleans

Fort Jackson

Belle Chasse

Spanish Fort

Mobile

Pensacola

G Pascagoula

§ ̈¦ ulfport

§ ̈¦ 10 12

§ ̈¦59

§ ̈¦110

De Soto NF

Deep Gulf Energy II, LLC Vicinity Map

Mississippi Canyon 727

MC727

~101.4 Miles to Fourchon, LA Shorebase

~

1

45

Miles

to

MS

S

ho

re

~54

Miles

to

LA

Shore
Deep Gulf Energy II, LLC Section 15– Pg. 26 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 15 

ONSHORE SUPPORT FACILITIES INFORMATION 

15.1 GENERAL 

Name Location Existing/New/Modified 

Fourchon C-Port Fourchon, Louisiana Existing 

15.2 SUPPORT BASE CONSTRUCTION OR EXPANSION 

There will be no new construction of an onshore support base, nor will we expand the 

existing shore base as a result of the operations proposed in this DOCD. 

15.3 SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE 

A support base construction or expansion timetable is not required for this plan. 

15.4 WASTE DISPOSAL 

A table, “Wastes You Will Transport and/or Dispose of Onshore,” is included as 

Attachment 14-A. 
Deep Gulf Energy II, LLC Section 16– Pg. 27 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 16 

COASTAL ZONE MANAGEMENT (CZM) INFORMATION 

As authorized by the Federal Coastal Zone Management Act (CZMA), the State of 

Texas developed a Coastal Management Program (CMP) to allow for the review of 

proposed Federal license and permit activities affecting any coastal use or resource, in 

or outside of the Texas Coastal Zone.

The OCS related oil and gas exploratory and development activities having potential 

impact on the Texas Coastal Zone are based on the location of the proposed facilities, 

access to those sites, best practical techniques for drilling locations, drilling equipment 

guidelines for the prevention of adverse environmental effects, effective environmental 

protection, emergency plans and contingency plans. 

Below are topics found in other sections of the plan and have been cross referenced for 

ease in locating: 

Topic Cross Reference Comments 

Construction, Operation and 

Maintenance of Oil and Gas 

Exploration and Production 

Facilities 

1 Plan Contents 

2 General 

Discharges of Wastewater 

and Disposal of Waste from 

Oil and Gas Exploration and 

Production Activities 

7 Wastes and Discharges 

8 Air Emissions 

9 Oil Spill 

14 Support Vessels and Aircraft 

15 Onshore Support Facilities 

Construction and Operation 

of Solid Waste Treatment, 

Storage, and Disposal 

Facilities 

7 Wastes and Discharges 

14 Support Vessels and Aircraft 

15 Onshore Support Facilities 

Prevention, Response, and 

Remediation of Oil Spills 

9 Oil Spill 

6 Biological, Physical, 

Socioeconomic 

17 Environmental Impact Analysis 

Discharge of Municipal and 

Industrial Waste Water to 

Coastal Waters 

7 Wastes and Discharges 

Development in Critical 

Areas 

6 Biological, Physical and 

Socioeconomic 
Deep Gulf Energy II, LLC Section 16– Pg. 28 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

11 Lease Stipulations 

12 Environmental Mitigation 

15 Onshore Support Facilities 

17 Environmental Impact Analysis 

Construction of Waterfront 

Facilities and Other 

Structures on Submerge 

lands 

2 General 

8 Air Emissions 

15 Onshore Support Facilities 

17 Environmental Impact Analysis 

Dredging and Dredged 

Material Disposal and 

Placement 

15 Onshore Support Facilities 

Construction in the Beach / 

Dune System 

15 Onshore Support Facilities 

Alteration of Coastal 

Historic Areas 

6 Biological, Physical, and 

Socioeconomic 

17 Environmental Impact Analysis 

Transportation 15 Onshore Support Facilities 

Emission of Air Pollutants 8 Air Emissions 

9 Oil Spill 

17 Environmental Impact Analysis 

Appropriations of Water There will be no 

fresh water 

appropriations as a 

result of our 

operations 

Levee and Control Projects The proposed 

surface location in 

the Plan is located 

approximately 321 

miles from the 

nearest Texas 

shoreline; 

therefore, DGE II 

does not anticipate 

an impact to the 

Texas Coastal 

Zone Management 

Program policies. 

Marine Fishery 

Management 

17 Environmental Impact Analysis 

Policies for Major Actions For purposes of this 

category, “major 
Deep Gulf Energy II, LLC Section 16– Pg. 29 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

actions” means an 

individual action 

relating to an 

activity for which a 

federal 

environmental 

impact statement 

under the National 

Environmental 

Policy Act is 

required. The 

proposed surface 

location addressed 

in the Plan would 

not be classified as 

a major action. 

Relevant enforceable policies were considered in certifying consistency for Texas. A 

certificate of Coastal Zone Management Consistency for the state of Texas is included 

as Attachment 16-A. 

Deep Gulf Energy II, LLC Section 17– Pg. 30 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 17 

ENVIRONMENTAL IMPACT ANALYSIS (EIA) 

Included as Attachment 17-A is the Environmental Impact Analysis (EIA)
ATTACHMENT 17-A 

Deep Gulf Energy II, LLC (DGE II)

Initial Unit Development Operations Coordination Document 

Mississippi Canyon Block 727 and 771 

OCS-G 24102 / OCS-G 24107

(A) IMPACT PRODUCING FACTORS 

ENVIRONMENTAL IMPACT ANALYSIS WORKSHEET 

Environment 

Resources 

Impact Producing Factors (IPFs) 

Categories and Examples 

Refer to recent GOM OCS Lease Sale EIS for a more complete list of IPFs 

Emissions 

(air, noise, 

light, etc.) 

Effluents 

(muds, 

cutting, 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) 

Discarded 

Trash & 

Debris 

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) 

Benthic communities (4) 

Water quality X X 

Fisheries X X 

Marine Mammals X(8) X X(8) X 

Sea Turtles X(8) X X(8) X 

Air quality X(9) 

Shipwreck sites (known or 

potential) 

 (7) 

Prehistoric archaeological sites X(7) 

Vicinity of Offshore Location 

Essential fish habitat X X(6) 

Marine and pelagic birds X X 

Public health and safety (5) 

Coastal and Onshore 

Beaches X(6) X 

Wetlands X(6) 

Shore birds and coastal nesting 

birds 

 X6) 

Coastal wildlife refuges 

Wilderness areas 
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: 

o 4-mile zone of the Flower Garden Banks, or the 3-mile zone of Stetson Bank; 

o 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; 

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

o 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 (LowRelief) Stipulation attached to an OCS lease. 

4) Activities on blocks designated by the BOEM as being in water depths 300 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 

determine would impact these environmental resources. If the proposed action is located a sufficient distance 

from a resource that no impact would occur, the EIA can note that in a sentence or two. 

7) All activities that involve seafloor disturbances, including anchor emplacements, in any OCS block designated 

by the BOEM as having high-probability for the occurrence of shipwrecks or prehistoric sites, including such 

blocks that will be affected that are adjacent to the lease block in which your planned activity will occur. If the 

proposed activities are located a sufficient distance from a shipwreck or a 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. 
(B) Analysis 

Site-Specific at Mississippi Canyon Block 727 and 771 

Proposed operations consist of the drilling, completion and commencement of production on two 

wells (MC771 #2 and MC727 #3), both of which have surface locations in Mississippi Canyon 

Block 727. Operations also consist of the installation of lease term pipelines. 

The operations will be conducted with a dynamically positioned semi-submersible. 

1. Designated Topographic Features 

Potential IPFs on topographic features include effluents, and accidents. 

Effluents: Mississippi Canyon Block 727 and 771 are approximately 50 miles from the closest 

designated Topographic Features Stipulation Block (Sackett Bank); therefore, no adverse 

impacts are expected. 

Accidents: It is unlikely that an accidental surface or subsurface spill would occur from the 

proposed activities (refer to statistics in Item 5, Water Quality). Oil spills cause damage to 

benthic organisms only if the oil contacts the organisms. Oil from a surface spill can be driven 

into the water column; measurable amounts have been documented down to a 10 m depth. At 

this depth, the oil is found only at concentrations several orders of magnitude lower than the 

amount shown to have an effect on corals. Because the crests of topographic features in the 

Northern Gulf of Mexico are found below 10 m, no oil from a surface spill could reach their 

sessile biota. Oil from a subsurface spill is not applicable due to the distance of these blocks from 

a topographic area. The activities proposed in this plan will be covered by DGE II’s Regional 

OSRP (refer to information submitted in Section 9). 

There are no other IPFs (including emissions, physical disturbances to the seafloor and wastes 

sent to shore for disposal) from the proposed activities, which could impact topographic features. 

2. Pinnacle Trend Area Live Bottoms 

Potential IPFs on pinnacle trend area live bottoms include effluents and accidents. 

Effluents: Mississippi Canyon Block 727 and 771 are approximately 70 miles from the closest 

live bottom (pinnacle trend) area; therefore, no adverse impacts are expected. 

Accidents: It is unlikely that an accidental surface or subsurface spill would occur from the 

proposed activities (refer to statistics in Item 5, Water Quality). Oil spills have the potential to 

foul benthic communities and cause lethal and sublethal effects on live bottom organisms. Oil 

from a surface spill can be driven into the water column; measurable amounts have been 
documented down to a 10 m depth. At this depth, the oil is found only at concentrations several 

orders of magnitude lower than the amount shown to have an effect on marine organisms. Oil 

from a subsurface spill is not applicable due to the distance of these blocks from a live bottom 

(pinnacle trend) area. The activities proposed in this plan will be covered by DGE II’s Regional 

OSRP (refer to information submitted in Section 9). 

There are no other IPFs (including emissions, physical disturbances to the seafloor and wastes 

sent to shore for disposal) from the proposed activities which could impact a live bottom 

(pinnacle trend) area. 

3. Eastern Gulf Live Bottoms 

Potential IPFs on Eastern Gulf live bottoms include effluents and accidents. 

Effluents: Mississippi Canyon Block 727 and 771 are not located in an area characterized by 

the existence of live bottoms; therefore, no adverse impacts are expected. 

Accidents: It is unlikely that an accidental surface or subsurface spill would occur from the 

proposed activities (refer to statistics in Item 5, Water Quality). Oil spills cause damage to live 

bottom organisms only if the oil contacts the organisms. Oil from a surface spill can be driven 

into the water column; measurable amounts have been documented down to a 10 m depth. At 

this depth, the oil is found only at concentrations several orders of magnitude lower than the 

amount shown to have an effect on marine invertebrates. Oil from a subsurface spill is not 

applicable due to the distance of these blocks from a live bottom area. The activities proposed in 

this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 

9). 

There are no other IPFs (including emissions, physical disturbances to the seafloor and wastes 

sent to shore for disposal) from the proposed activities which could impact an Eastern Gulf live 

bottom area. 

4. Benthic Communities 

There are no IPFs (including emissions, physical disturbances to the seafloor, wastes sent to 

shore for disposal, or accidents) from the proposed activities that could cause impacts to benthic 

communities. 

A dynamically positioned semi-submersible is being used for the proposed activities; therefore, 

only an insignificant amount of seafloor will be disturbed. Because physical disturbances to the 

seafloor will be minimized by the use of a dynamically positioned semi-submersible, DGE II’s 

proposed operations in Mississippi Canyon Block 727 and 771 would not cause impacts to 

benthic communities. 
5. Water Quality 

IPFs that could result in water quality degradation from the proposed operations in Mississippi 

Canyon Block 727 and 771 include effluents and accidents. 

 

Effluents: Levels of contaminants in drilling muds and cuttings and produced water discharges, 

discharge-rate restrictions and monitoring and toxicity testing are regulated by the EPA NPDES 

permit, thereby eliminating many significant biological or ecological effects. Operational 

discharges are not expected to cause significant adverse impacts to water quality. 

Accidents: Oil spills have the potential to alter offshore water quality; however, it is unlikely 

that an accidental surface or subsurface spill would occur from the proposed activities. Between 

1980 and 2000, OCS operations produced 4.7 billion barrels of oil and spilled only 0.001 percent 

of this oil, or 1 bbl for every 81,000 bbl produced. The spill risk related to a diesel spill from 

drilling operations is even less. Between 1976 and 1985, (years for which data were collected), 

there were 80 reported diesel spills greater than one barrel associated with drilling activities. 

Considering that there were 11,944 wells drilled, this is a 0.7 percent probability of an 

occurrence. If a spill were to occur, the water quality of marine waters would be temporarily 

affected by the dissolved components and small oil droplets. Dispersion by currents and 

microbial degradation would remove the oil from the water column and dilute the constituents to 

background levels. Historically, changes in offshore water quality from oil spills have only been 

detected during the life of the spill and up to several months afterwards. Most of the components 

of oil are insoluble in water and therefore float. The activities proposed in this plan will be 

covered by DGE II’s Regional Oil Spill Response Plan (refer to information submitted in 

Section 9). 

There are no other IPFs (including emissions, physical disturbances to the seafloor, and wastes 

sent to shore for disposal) from the proposed activities which could cause impacts to water 

quality. 

6. Fisheries 

IPFs that could cause impacts to fisheries as a result of the proposed operations in Mississippi 

Canyon Block 727 and 771 include effluents and accidents. 

Effluents: Effluents such as drilling fluids and cuttings discharges contain components and 

properties which are detrimental to fishery resources. Moderate petroleum and metal 

contamination of sediments and the water column can occur out to several hundred meters downcurrent from the discharge point. Offshore discharges are expected to disperse and dilute to very 

near background levels in the water column or on the seafloor within 3,000 m of the discharge 

point, and are expected to have negligible effect on fisheries. 

Accidents: An accidental oil spill has the potential to cause some detrimental effects on 

fisheries; however, it is unlikely that such an event would occur from the proposed activities 
(refer to Item 5, Water Quality). The effects of oil on mobile adult finfish or shellfish would 

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

shellfish to avoid the spill, to metabolize hydrocarbons, and to excrete both metabolites and 

parent compounds. The activities proposed in this plan will be covered by DGE II’s Regional 

OSRP (refer to information submitted in Section 9). 

There are no IPFs from emissions, physical disturbances to the seafloor or wastes sent to shore 

for disposal from the proposed activities which could cause impacts to fisheries. 

7. Marine Mammals 

GulfCet II studies revealed that cetaceans of the continental shelf and shelf-edge were almost 

exclusively bottlenose dolphin and Atlantic spotted dolphin. Squid eaters, including dwarf and 

pygmy killer whale, Risso’s dolphin, rough-toothed dolphin, and Cuvier’s beaked whale, 

occurred most frequently along the upper slope in areas outside of anticyclones. IPFs that could 

cause impacts to marine mammals as a result of the proposed operations in Mississippi Canyon 

Block 727 and 771 include emissions, effluents, discarded trash and debris, and accidents. 

Emissions: Noises from drilling activities, support vessels and helicopters may elicit a startle 

reaction from marine mammals. This reaction may lead to disruption of marine mammals’ 

normal activities. Stress may make them more vulnerable to parasites, disease, environmental 

contaminants, and/or predation (Majors and Myrick, 1990). There is little conclusive evidence 

for long-term displacements and population trends for marine mammals relative to noise. 

Effluents: Drilling fluids and cuttings discharges contain components which may be detrimental 

to marine mammals. Most operational discharges are diluted and dispersed upon release. Any 

potential impact from drilling fluids would be indirect, either as a result of impacts on prey items 

or possibly through ingestion in the food chain (API, 1989). 

Discarded trash and debris: Both entanglement in, and ingestion of debris have caused the 

death or serious injury of marine mammals (Laist, 1997; MMC, 1999). The limited amount of 

marine debris, if any, resulting from the proposed activities is not expected to substantially harm 

marine mammals. Operators are prohibited from deliberately discharging debris as mandated by 

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

imposed by various agencies including the United States Coast Guard (USCG) and the 

Environmental Protection Agency (EPA). 

DGE II will operate in accordance with the regulations and also avoid accidental loss of solid 

waste items by maintaining waste management plans, manifesting trash sent to shore, and using 

special precautions such as covering outside trash bins to prevent accidental loss of solid waste. 

Special caution will be exercised when handling and disposing of small items and packaging 

materials, particularly those made of non-biodegradable, environmentally persistent materials 

such as plastic or glass. 
Informational placards will be posted on all vessels and facilities having sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

Accidents: Collisions between support vessels and cetaceans would be unusual events, however 

should one occur, death or injury to marine mammals is possible. Contract vessel operators can 

avoid marine mammals and reduce potential deaths by maintaining a vigilant watch for marine 

mammals and maintaining a safe distance when they are sighted. Vessel crews should use a 

reference guide to help identify the twenty-eight species of whales and dolphins, and the single 

species of manatee that may be encountered in the Gulf of Mexico OCS. Vessel crews must 

report sightings of any injured or dead protected marine mammal species immediately, 

regardless of whether the injury or death is caused by their vessel, to the Marine Mammal and 

Sea Turtle Stranding Hotline at (888) 404-3922, the NMFS Southeast Regional Office at (727) 

824-5312, or the Marine Mammal Stranding Network at (305) 862-2850. In addition, if the 

injury or death was caused by a collision with a contract vessel, the BOEM must be notified 

within 24 hours of the strike by email to protectedspecies@boemre.gov. If the vessel is the 

responsible party, it is required to remain available to assist the respective salvage and stranding 

network as needed. 

Oil spills have the potential to cause sublethal oil-related injuries and spill-related deaths to 

marine mammals. However, it is unlikely that an accidental oil spill would occur from the 

proposed activities (refer to Item 5, Water Quality). Oil spill response activities may increase 

vessel traffic in the area, which could add to changes in cetacean behavior and/or distribution, 

thereby causing additional stress to the animals. The effect of oil dispersants on cetaceans is not 

known. The acute toxicity of oil dispersant chemicals included in DGE II’s OSRP is considered 

to be low when compared with the constituents and fractions of crude oils and diesel products. 

The activities proposed in this plan will be covered by DGE II’s OSRP (refer to information 

submitted in accordance with Section 9). 

There are no other IPFs (including physical disturbances to the seafloor) from the proposed 

activities which could impact marine mammals. 

8. Sea Turtles 

IPFs that could cause impacts to sea turtles as a result of the proposed operations include 

emissions, effluents, discarded trash and debris, and accidents. GulfCet II studies sighted most 

loggerhead, Kemp’s ridley and leatherback sea turtles over shelf waters. Historically these 
species have been sighted up to the shelf’s edge. They appear to be more abundant east of the 

Mississippi River than they are west of the river (Fritts et al., 1983b; Lohoefener et al., 1990). 

Deep waters may be used by all species as a transitory habitat. 

Emissions: Noise from drilling activities, support vessels, and helicopters may elicit a startle 

reaction from sea turtles, but this is a temporary disturbance. 

Effluents: Drilling fluids and cuttings discharges are not known to be lethal to sea turtles. Most 

operational discharges are diluted and dispersed upon release. Any potential impact from 

drilling fluids would be indirect, either as a result of impacts on prey items or possibly through 

ingestion in the food chain (API, 1989). 

Discarded trash and debris: Both entanglement in, and ingestion of, debris have caused the 

death or serious injury of sea turtles (Balazs, 1985). The limited amount of marine debris, if any, 

resulting from the proposed activities is not expected to substantially harm sea turtles. Operators 

are prohibited from deliberately discharging debris as mandated by MARPOL-Annex V and the 

Marine Plastic Pollution Research and Control Act, and regulations imposed by various agencies 

including the United States Coast Guard (USCG) and the Environmental Protection Agency 

(EPA). DGE II will operate in accordance with the regulations and also avoid accidental loss of 

solid waste items by maintaining waste management plans, manifesting trash sent to shore, and 

using special precautions such as covering outside trash bins to prevent accidental loss of solid 

waste. Special caution will be exercised when handling and disposing of small items and 

packaging materials, particularly those made of non-biodegradable, environmentally persistent 

materials such as plastic or glass. 

Informational placards will be posted on all vessels and facilities having sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

Accidents: Collisions between support vessels and sea turtles would be unusual events, however 

should one occur, death or injury to sea turtles is possible. Contract vessel operators can avoid 

sea turtles and reduce potential deaths by maintaining a vigilant watch for sea turtles and 

maintaining a safe distance when they are sighted. Vessel crews should use a reference guide to 

help identify the five species of sea turtles that may be encountered in the Gulf of Mexico OCS. 

Vessel crews must report sightings of any injured or dead protected sea turtle species 

immediately, regardless of whether the injury or death is caused by their vessel, to the Marine 

Mammal and Sea Turtle Stranding Hotline at (888) 404-3922, the NMFS Southeast Regional 
Office at (727) 824-5312, or the Marine Mammal Stranding Network at (305) 862-2850. In 

addition, if the injury or death was caused by a collision with a contract vessel, the BOEM must 

be notified within 24 hours of the strike by email to protectedspecies@boemre.gov. If the vessel 

is the responsible party, it is required to remain available to assist the respective salvage and 

stranding network as needed. 

All sea turtle species and their life stages are vulnerable to the harmful effects of oil through 

direct contact or by fouling of their food. Exposure to oil can be fatal, particularly to juveniles 

and hatchlings. However, it is unlikely that an accidental oil spill would occur from the proposed 

activities (refer to Item 5, Water Quality). Oil spill response activities may increase vessel traffic 

in the area, which could add to the possibility of collisions with sea turtles. The activities 

proposed in this plan will be covered by DGE II’s Regional Oil Spill Response Plan (refer to 

information submitted in accordance with Section 9). 

There are no other IPFs (including physical disturbances to the seafloor) from the proposed 

activities which could impact sea turtles. 

9. Air Quality 

Mississippi Canyon Block 727 and 771 are located approximately 85 from the Breton 

Wilderness Area and approximately 55 miles from shore. Applicable emissions data is included 

in Section 8 of the Plan. 

There would be a limited degree of air quality degradation in the immediate vicinity of the 

proposed activities. Plan Emissions for the proposed activities do not exceed the annual 

exemption levels as set forth by BOEM. Accidents and blowouts can release hydrocarbons or 

chemicals, which could cause the emission of air pollutants. However, these releases would not 

impact onshore air quality because of the prevailing atmospheric conditions, emission height, 

emission rates, and the distance of Mississippi Canyon Block 727 and 771 from the coastline. 

There are no other IPFs (including effluents, physical disturbances to the seafloor, wastes sent to 

shore for treatment or disposal) from the proposed activities which would impact air quality. 

10. Shipwreck Sites (known or potential) 

Potential IPFs that could impact known or unknown shipwreck sites as a result of the proposed 

operations in Mississippi Canyon Block 727 and 771 include disturbances to the seafloor. 

Physical disturbances to the seafloor: A dynamically positioned semi-submersible is being 

used for the proposed activities; therefore, only an insignificant amount of seafloor will be 

disturbed. Because physical disturbances to the seafloor will be minimized by the use of a 

dynamically positioned semi-submersible, DGE II’s proposed operations in Mississippi Canyon 

Block 727 and 771 would not cause impacts to shipwreck sites. 
Additionally, Mississippi Canyon Block 727 and 771 are not located in or adjacent to an OCS 

block designated by BOEM as having a high probability for occurrence of shipwrecks, therefore, 

no adverse impacts are expected. 

According to the BOEM Grid Environmental Assessment (EA) and ROV Status Report 

(http://www.data.boem.gov/homepg/data_center/other/ea_grid/ea_grid.asp), Mississippi Canyon 

Block 727 has adequate ROV coverage due to its inclusion in Deepwater Grid 16. Therefore, 

DGE II will not perform an AUV/ROV survey of the proposed well location(s) prior to or upon 

commencement of operations. Should an historic shipwreck be encountered, DGE II will contact 

the BOEM immediately and make every reasonable effort to preserve and protect that cultural 

resource. 

There are no other IPFs (including emissions, effluents, wastes sent to shore for treatment or 

disposal, or accidents) from the proposed activities that could cause impacts to shipwreck sites. 

11. Prehistoric Archaeological Sites 

IPFs that could cause impacts to prehistoric archaeological sites as a result of the proposed 

operations in Mississippi Canyon Block 727 and 771 are physical disturbances to the seafloor 

and accidents (oil spills). 

Physical Disturbances to the seafloor: Although the operations proposed will be conducted by 

utilizing a dynamically positioned semi-submersible, which would cause only an insignificant 

amount of seafloor to be disturbed, Mississippi Canyon Block 727 and 771 are located inside the 

Archaeological Prehistoric high probability lines. DGE II will report to BOEM the discovery of 

any object of prehistoric archaeological significance and make every reasonable effort to 

preserve and protect that cultural resource. 

According to the BOEM Grid Environmental Assessment (EA) and ROV Status Report 

(http://www.data.boem.gov/homepg/data_center/other/ea_grid/ea_grid.asp), Mississippi Canyon 

Block 727 and 771 have adequate ROV coverage due to their inclusion in Deepwater Grid 16. 

Therefore, DGE II will not perform an AUV/ROV survey of the proposed well location(s) prior 

to or upon commencement of operations. Should a seafloor archaeological resource be 

encountered, DGE II will contact the BOEM immediately and make every reasonable effort to 

preserve and protect that cultural resource. 

Accidents: An accidental oil spill has the potential to cause some detrimental effects to 

prehistoric archaeological sites if the release were to occur subsea. However, it is unlikely that 

an accidental oil spill would occur from the proposed activities (refer to Item 5, Water Quality). 

The activities proposed in this plan will be covered by DGE II’s Regional Oil Spill Response 

Plan (refer to information submitted in accordance with Section 9). 

There are no other IPFs (including emissions, effluents or wastes sent to shore for treatment or 

disposal) from the proposed activities which could impact prehistoric archeological sites. 
Vicinity of Offshore Location 

1. Essential Fish Habitat (EFH) 

IPFs that could cause impacts to EFH as a result of the proposed operations in Mississippi 

Canyon Block 727 and 771 include effluents and accidents. EFH includes all estuarine and 

marine waters and substrates in the Gulf of Mexico. 

Effluents: The Live Bottom Low Relief Stipulation, the Live Bottom (Pinnacle Trend) 

Stipulation, and the Eastern Gulf Pinnacle Trend Stipulation would prevent most of the potential 

impacts on live-bottom communities and EFH from operational waste discharges. Levels of 

contaminants in drilling muds and cuttings and produced-water discharges, discharge-rate 

restrictions, and monitoring and toxicity testing are regulated by the EPA NPDES permit, 

thereby eliminating many significant biological or ecological effects. Operational discharges are 

not expected to cause significant adverse impacts to EFH. 

Accidents: An accidental oil spill has the potential to cause some detrimental effects on EFH. 

Oil spills that contact coastal bays and estuaries, as well as OCS waters when pelagic eggs and 

larvae are present, have the greatest potential to affect fisheries. However, it is unlikely that an 

oil spill would occur from the proposed activities (refer to Item 5, Water Quality). The activities 

proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information 

submitted in Section 9). 

There are no other IPFs (including emissions, physical disturbances to the seafloor and wastes 

sent to shore for treatment or disposal) from the proposed activities which could impact essential 

fish habitat. 

2. Marine and Pelagic Birds 

IPFs that could impact marine birds as a result of the proposed activities include air emissions, 

accidental oil spills, and discarded trash and debris from vessels and the facilities. 

Emissions: Emissions of pollutants into the atmosphere from these activities are far below 

concentrations which could harm coastal and marine birds. 

Accidents: An oil spill would cause localized, low-level petroleum hydrocarbon contamination. 

However, it is unlikely that an oil spill would occur from the proposed activities (refer to Item 5, 

Water Quality). Marine and pelagic birds feeding at the spill location may experience chronic, 

nonfatal, physiological stress. It is expected that few, if any, coastal and marine birds would 

actually be affected to that extent. The activities proposed in this plan will be covered by DGE 

II’s Regional OSRP (refer to information submitted in Section 9). 
Discarded trash and debris: Marine and pelagic birds could become entangled and snared in 

discarded trash and debris, or ingest small plastic debris, which can cause permanent injuries and 

death. Operators are prohibited from deliberately discharging debris as mandated by MARPOLAnnex V and the Marine Plastic Pollution Research and Control Act, and regulations imposed by 

various agencies including the United States Coast Guard (USCG) and the Environmental 

Protection Agency (EPA). DGE II will operate in accordance with the regulations and also avoid 

accidental loss of solid waste items by maintaining waste management plans, manifesting trash 

sent to shore, and using special precautions such as covering outside trash bins to prevent 

accidental loss of solid waste. Special caution will be exercised when handling and disposing of 

small items and packaging materials, particularly those made of non-biodegradable, 

environmentally persistent materials such as plastic or glass. Informational placards will be 

posted on all vessels and facilities having sleeping or food preparation capabilities. All offshore 

personnel, including contractors and other support services-related personnel (e.g. helicopter 

pilots, vessel captains and boat crews) will be indoctrinated on waste procedures, and will view 

the video (or Microsoft PowerPoint presentation), “Think About It” (previously “All Washed 

Up: The Beach Litter Problem”). Thereafter, all personnel will view the marine trash and debris 

training video annually. Offshore personnel will also receive an explanation from DGE II 

management or the designated lease operator management that emphasizes their commitment to 

waste management in accordance with NTL No. 2012-G01. Debris, if any, from these proposed 

activities will seldom interact with marine and pelagic birds; therefore, the effects will be 

negligible. 

There are no other IPFs (including effluents, physical disturbances to the seafloor, or wastes sent 

to shore for treatment or disposal) from the proposed activities which could impact marine and 

pelagic birds. 

3. Public Health and Safety Due to Accidents. 

There are no IPFs (emissions, effluents, physical disturbances to the seafloor, wastes sent to 

shore for treatment or disposal or accidents, including an accidental H2S release) from the 

proposed activities which could cause impacts to public health and safety. In accordance with 

NTL No.’s 2008-G04, 2009-G27, and 2009-G31, sufficient information is included in Section 4

to justify our request that our proposed activities be classified by BSEE as H2S absent. 

Coastal and Onshore 

1. Beaches 

IPFs from the proposed activities that could cause impacts to beaches include accidents (oil 

spills) and discarded trash and debris. 

Accidents: Oil spills contacting beaches would have impacts on the use of recreational beaches 

and associated resources. Due to the distance from shore (55 miles) and the response capabilities 

that would be implemented, no significant adverse impacts are expected. The activities proposed 
in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in 

Appendix I). 

Discarded trash and debris: Trash on the beach is recognized as a major threat to the 

enjoyment and use of beaches. There will only be a limited amount of marine debris, if any, 

resulting from the proposed activities. Operators are prohibited from deliberately discharging 

debris as mandated by MARPOL-Annex V and the Marine Plastic Pollution Research and 

Control Act, and regulations imposed by various agencies including the United States Coast 

Guard (USCG) and the Environmental Protection Agency (EPA). DGE II will operate in 

accordance with the regulations and also avoid accidental loss of solid waste items by 

maintaining waste management plans, manifesting trash sent to shore, and using special 

precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special 

caution will be exercised when handling and disposing of small items and packaging materials, 

particularly those made of non-biodegradable, environmentally persistent materials such as 

plastic or glass. 

Informational placards will be posted on all vessels and facilities having sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities which could impact beaches. 

2. Wetlands 

IPFs from the proposed activities that could cause impacts to wetlands include accidents (oil 

spills) and discarded trash and debris. 

Accidents: It is unlikely that an oil spill would occur from the proposed activities (refer to Item 

5, Water Quality). Due to the distance from shore (55 miles) and the response capabilities that 

would be implemented, no impacts are expected. The activities proposed in this plan will be 

covered by DGE II’s Regional OSRP (refer to information submitted in Section 9). 

Discarded trash and debris: There will only be a limited amount of marine debris, if any, 

resulting from the proposed activities. Operators are prohibited from deliberately discharging 

debris as mandated by MARPOL-Annex V and the Marine Plastic Pollution Research and 

Control Act, and regulations imposed by various agencies including the United States Coast 
Guard (USCG) and the Environmental Protection Agency (EPA). DGE II will operate in 

accordance with the regulations and also avoid accidental loss of solid waste items by 

maintaining waste management plans, manifesting trash sent to shore, and using special 

precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special 

caution will be exercised when handling and disposing of small items and packaging materials, 

particularly those made of non-biodegradable, environmentally persistent materials such as 

plastic or glass. 

Informational placards will be posted on all vessels and facilities having sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities which could impact 

wetlands. 

3. Shore Birds and Coastal Nesting Birds 

Accidents: Oil spills could cause impacts to shore birds and coastal nesting birds. However, it is 

unlikely that an oil spill would occur from the proposed activities (refer to Item 5, Water 

Quality). Given the distance from shore (55 miles) and the response capabilities that would be 

implemented, no impacts are expected. The activities proposed in this plan will be covered by 

DGE II’s Regional OSRP (refer to information submitted in Section 9). 

Discarded trash and debris: Coastal and marine birds are highly susceptible to entanglement 

in floating, submerged, and beached marine debris: specifically plastics. Operators are prohibited 

from deliberately discharging debris as mandated by MARPOL-Annex V and the Marine Plastic 

Pollution Research and Control Act, and regulations imposed by various agencies including the 

United States Coast Guard (USCG) and the Environmental Protection Agency (EPA). DGE II 

will operate in accordance with the regulations and also avoid accidental loss of solid waste 

items by maintaining waste management plans, manifesting trash sent to shore, and using special 

precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special 

caution will be exercised when handling and disposing of small items and packaging materials, 

particularly those made of non-biodegradable, environmentally persistent materials such as 

plastic or glass. 

 

Informational placards will be posted on vessels and every facility that has sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 
indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities that could cause impacts to 

shore birds and coastal nesting birds. 

4. Coastal Wildlife Refuges 

Accidents: An accidental oil spill from the proposed activities could cause impacts to coastal 

wildlife refuges. However, it is unlikely that an oil spill would occur from the proposed activities 

(refer to Item 5, Water Quality). Due to the distance from shore (55 miles) and the response 

capabilities that would be implemented, no impacts are expected. The activities proposed in this 

plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9). 

Discarded trash and debris: Operators are prohibited from deliberately discharging debris as 

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

regulations imposed by various agencies including the United States Coast Guard (USCG) and 

the Environmental Protection Agency (EPA). DGE II will operate in accordance with the 

regulations and also avoid accidental loss of solid waste items by maintaining waste management 

plans, manifesting trash sent to shore, and using special precautions such as covering outside 

trash bins to prevent accidental loss of solid waste. Special caution will be exercised when 

handling and disposing of small items and packaging materials, particularly those made of nonbiodegradable, environmentally persistent materials such as plastic or glass. 

 

Informational placards will be posted on vessels and every facility that has sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities that could cause impacts to 

coastal wildlife refuges. 
5. Wilderness Areas 

Accidents: An accidental oil spill from the proposed activities could cause impacts to wilderness 

areas. However, it is unlikely that an oil spill would occur from the proposed activities (refer to 

Item 5, Water Quality). Due to the distance from the nearest designated Wilderness Area (85 

miles) and the response capabilities that would be implemented, no significant adverse impacts 

are expected. The activities proposed in this plan will be covered by DGE II’s Regional OSRP 

(refer to information submitted in Section 9).

Discarded trash and debris: Operators are prohibited from deliberately discharging debris as 

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

regulations imposed by various agencies including the United States Coast Guard (USCG) and 

the Environmental Protection Agency (EPA). DGE II will operate in accordance with the 

regulations and also avoid accidental loss of solid waste items by maintaining waste management 

plans, manifesting trash sent to shore, and using special precautions such as covering outside 

trash bins to prevent accidental loss of solid waste. Special caution will be exercised when 

handling and disposing of small items and packaging materials, particularly those made of nonbiodegradable, environmentally persistent materials such as plastic or glass. 

 

Informational placards will be posted on vessels and every facility that has sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from DGE II management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01. 

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities that could cause impacts to 

wilderness areas. 

6. Other Environmental Resources Identified 

There are no other environmental resources identified for this impact assessment. 

(C) IMPACTS ON PROPOSED ACTIVITIES 

The site–specific environmental conditions have been taken into account for the proposed 

activities. No impacts are expected on the proposed activities from site-specific environmental 

conditions. 

(D) ENVIRONMENTAL HAZARDS 

During the hurricane season, June through November, the Gulf of Mexico is impacted by an 

average of ten tropical storms (39-73 mph winds), of which six become hurricanes ( > 74 mph 
winds). Due to their location in the gulf, Mississippi Canyon Block 727 and 771 may experience 

hurricane and tropical storm force winds, and related sea currents. These factors can adversely 

impact the integrity of the operations covered by this plan. A significant storm may present 

physical hazards to operators and vessels, damage exploration or production equipment, or result 

in the release of hazardous materials (including hydrocarbons). Additionally, the displacement of 

equipment may disrupt the local benthic habitat and pose a threat to local species. 

The following preventative measures included in this plan may be implemented to mitigate these 

impacts: 

1. Drilling & completion 

a. Secure well 

b. Secure rig / platform 

c. Evacuate personnel 

Drilling activities will be conducted in accordance with NTL No.’s 2008-G09, 2009-G10, and 

2010-N10. 

2. Platform / Strucure Installation 

 Operator will not conduct platform / structure installation operations during Tropical 

 Storm or Hurricane threat. 

3. Pipeline Installation 

 Operator will not conduct pipeline installation operations during Tropical Storm or 

 Hurricane threat. 

(E) ALTERNATIVES 

No alternatives to the proposed activities were considered to reduce environmental impacts. 

(F) MITIGATION MEASURES 

No mitigation measures other than those required by regulation will be employed to avoid, 

diminish, or eliminate potential impacts on environmental resources. 

(G) CONSULTATION 

No agencies or persons were consulted regarding potential impacts associated with the proposed 

activities. Therefore, a list of such entities has not been provided. 
(H) PREPARER(S) 

Matt Harlan 

J. Connor Consulting, Inc. 

16225 Park Ten Place, Suite 700 

Houston, TX 77084 

(281) 578-3388 

matt.harlan@jccteam.com 

(I) REFERENCES 

Authors: 

American Petroleum Institute (API). 1989. Effects of offshore petroleum operations on cold 

water marine mammals: a literature review. Washington, DC: American Petroleum 

Institute. 385 pp. 

Balazs, G.H. 1985. Impact of ocean debris on marine turtles: entanglement and ingestion. In: 

Shomura, R.S. and H.O. Yoshida, eds. Proceedings, Workshop on the Fate and Impact of 

Marine Debris, 26-29 November 1984, Honolulu, HI. U.S. Dept. of Commerce. NOAA 

Tech. Memo. NOAA-TM-NMFS-SWFC-54. Pp 387-429. 

Burke, C.J. and J.A. Veil. 1995. Potential benefits from regulatory consideration of synthetic 

drilling muds. Environmental Assessment Division, Argonne National Laboratory, 

ANL/EAD/TM-43. 

Daly, J.M. 1997. Controlling the discharge of synthetic-based drilling fluid contaminated 

cuttings in waters of the United States. U.S. Environmental Protection Agency, Office of 

Water. Work Plan, June 24, 1997. 

Hansen, D.J. 198l. The relative sensitivity of seabird populations in Alaska to oil pollution. U.S. 

Dept. of the Interior, Bureau of Land Management, Alaska OCS Region, Anchorage. BLMYK-ES-81-006-1792. 

Laist, D.W. 1997. Impacts of marine debris: entanglement of marine life in marine debris 

including a comprehensive list of species with entanglement and ingestion records. In: Coe, 

J.M. and D.B. Rogers, eds. Marine debris: sources, impacts, and solutions. New York, NY: 

Springer-Verlag. Pp. 99-139. 

Majors, A.P. and A.C. Myrick, Jr. 1990. Effects of noise on animals: implications for dolphins 

exposed to seal bombs in the eastern tropical Pacific purse-seine fishery–an annotated 

bibliography. NOAA Administrative Report LJ-90-06. 

Marine Mammal Commission. 1999. Annual report to Congress – 1998. 
Piatt, J.F., C.J. Lensink, W. Butler, M. Kendziorek, and D.R. Nysewander. 1990. Immediate 

impact of the Exxon Valdez oil spill on marine birds. The Auk. 107 (2): 387-397 

Vauk , G., E. Hartwig, B. Reineking, and E. Vauk-Hentzelt. 1989. Losses of seabirds by oil 

pollution at the German North Sea coast. Topics in Marine Biology. Ros, J.D, ed. Scient. 

Mar. 53 (2-3): 749-754. 

Vermeer, K. and R. Vermeer, 1975 Oil threat to birds on the Canadian west coast. The Canadian 

Field-Naturalist. 89:278-298. 

Although not cited, the following were utilized in preparing this EIA: 

 Hazard Surveys 

 BOEM EIS’s: 

o GOM Deepwater Operations and Activities. Environmental Assessment. BOEM 2000-

001 

o GOM Central and Western Planning Areas Sales 166 and 168 Final Environmental 

Impact Statement. BOEM 96-0058. 
Deep Gulf Energy II, LLC Section 18– Pg. 31 of 31 

Unit DOCD July, 2013

Kodiak Development Unit 

SECTION 18 

ADMINISTRATIVE INFORMATION 

18.1 EXEMPTED INFORMATION DESCRIPTION 

The proposed bottom-hole locations of the planned wells have been removed from the 

Public Information copy of the DOCD as well as any discussions of the target 

objectives, geologic or geophysical data, and any interpreted geology. 

18.2 BIBLIOGRAPHY 

1. Development Operations Coordination Document (N-8279) 

2. Supplemental Exploration Plan (S-6804) 

3. Supplemental Exploration Plan (S-7135) 

4. Regional Oil Spill Response Plan (O-578) 

5. Supplemental Development Operations Coordination Document (S-7624)