UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field 

Operations (MS 5231)

Public Information copy of DOCD

Control # - S-07643

Type - Supplemental Development Operations Coordinations Document

Lease(s) - OCS- 00599 Block - 63 South Timbalier Area

OCS- 00605 Block - 86 South Timbalier Area

Operator - Energy Resource Technology GOM, Inc.

Wells E006, E007, E008, E009, Install Platform M and Wells 

M001, M002, and M003

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.

Michelle Griffitt

Plan Coordinator

 00605/ST/86

 00599/ST/63

 00605/ST/86

 00599/ST/63

 00599/ST/63

 00605/ST/86

 00605/ST/86

24 FNL, 2798 FWL

1968 FNL, 7795 FEL

1999 FNL, 7789 FEL

1965 FNL, 7779 FEL

1959 FNL, 7783 FEL

24 FNL, 2798 FWL

24 FNL, 2798 FEL

24 FNL, 2798 FEL

 00605/ST/86

 00605/ST/86

 00605/ST/86

 00605/ST/86

 00605/ST/86

 00605/ST/86

 00605/ST/86

 00605/ST/86

FIXED/M

WELL/E006

WELL/E007

WELL/E008

WELL/E009

WELL/M001

WELL/M002

WELL/M003

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

Description -

Rig Type -

Subject:

From:

May 5, 2014
PUBLIC INFORMATION COPY 

November 20, 2013 

SUPPLEMENTAL DEVELOPMENT OPERATIONS 

COORDINATION DOCUMENT 

Lease Number: OCS-G 00599/00605 

Area/Block: South Timbalier Blocks 63/86 

Prospect Name: NA

Offshore: Louisiana 

Submitted by: Energy Resource Technology GOM, Inc. 

500 Dallas St., Suite 2000 

Houston, TX 77002-4800 

Melissa Logan 

 (713) 328-3016 

 Mlogan@talosenergyllc.com 

Estimated start-up date: July 1, 2014 

Authorized Representative: No. Copies Being Submitted: 

Cathy Thornton Proprietary: 1 + 1 CD

J. Connor Consulting, Inc. Public Info: 1 + 1 CD

16225 Park Ten Place, Suite 700

Houston, Texas 77084 For BOEM:

(281) 705-8020 Plan No.

cathy.thornton@jccteam.com Assigned to:
Record of Changes

Date Appendix Revision

12/19/2013 A Amended to include discussion for the installation of Platform M

12/19/2013 A Amended the Form BOEM-0138 Plan Information Form for the 

proposed wells to remove the anchor radius 

12/19/2013 A Included a Form BOEM-0138 providing for the installation of 

Platform M

12/19/2013 G Added Table 1 Wastes and Discharges Information

12/19/2013 N Amended Solid and Waste Transportation section to include 

reference that the wastes and discharges information was included in 

Appendix O

12/28/2013 A Amended the Form BOEM-0138 to correct the TD depth of Well 

Location B

01/16/2014 G Amended Table 1 Wastes and Discharges Information to remove 

cuttings from synthetic-based fluids and to provide estimated 

discharge rates for well treatment and completion fluids 

02/06/2014 G Recalculated discharges and amended Table 1 Wastes and 

Discharges Information

03/17/2014 D Amended Appendix D regarding H2S determination. This has been 

amended to reflect that the H2S is confined to the E platform. 

04/14/2014 A Amended the Form BOEM-0138 Plan Information Form to update 

the Activity Schedule with a estimated start date of 07/01/2014
U.S. Department of the Interior OMB Control Number: 1010-0151

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

OCS PLAN INFORMATION FORM

General Information

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

Company Name: Energy Resource Technology GOM, Inc. BOEM Operator Number: 02899

Address: 500 Dallas Street, Suite 2000 Contact Person: Cathy Thornton

 Houston, Texas 77002 Phone Number: 713-705-8020

Email Address: cathy.thornton@jccteam.com

If a service fee is required under 30 CFR 550.125(a), provide the Amount paid $29,666.00 Receipt No. 25D7IUEP

Project and Worst Case Discharge (WCD)Information

Lease(s): OCS 00599/00650 Area: ST Block(s): 63/86 Project Name (if applicable): 

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

Platform/Well Name: E-Aux/M Total Volume of WCD: 6705 API Gravity: 37°

Distance to Closest Land (Miles): 19.4 Volume from uncontrolled blowout: 4270

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

D&C Loc A & B; D&TA Loc E 07/01/2014 09/28/2014 90

D&C Loc F; Complete Loc E 03/01/2015 05/11/2015 72

D&C Loc C & D 03/01/2016 04/29/2016 60

D&C Loc G 03/01/2017 04/23/2017 54

Installation or modification of structure 06/01/2015 06/05/2015 5

Installation of production facilities 06/06/2015 09/11/2015 5

Installation of subsea wellheads and/or manifolds

Installation of lease term pipelines 06/20/2015 09/30/2015 10

Commence production 07/01/2014

Other (Specify and attach description)

Description of Drilling Rig Description of Structure

X Jackup Drillship Caisson Tension leg platform

Gorilla Jackup Platform Rig X Fixed platform Compliant tower

Semisubmersible Submersible Spar Guyed tower

DP Semisubmersible Other (attach description) Floating production 

system

Other (Attach Description)

Drilling Rig Name (if known):

Description of Lease Term Pipelines

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

ST86 M platform ST63 A platform 6-inches 10,500’

ST63 A platform ST86 M platform 3-inches 10,500’

FORM BOEM-0137 (December 2011 - Supersedes all previous editions of this form which may not be used. Page 1 of 4
Public Information Copy

November 20, 2013 

SUPPLEMENTAL DEVELOPMENT OPERATIONS 

COORDINATION DOCUMENT 

Lease Number: OCS-G 00599/00605 

Area/Block: South Timbalier Blocks 63/86 

Prospect Name: NA

Offshore: Louisiana 

Submitted by: Energy Resource Technology GOM, Inc. 

500 Dallas St., Suite 2000 

Houston, TX 77002-4800 

Melissa Logan 

 (713) 328-3016 

 Mlogan@talosenergyllc.com 

Estimated start-up date: April 1, 2014 

Authorized Representative: No. Copies Being Submitted: 

Cathy Thornton Proprietary: 1 + 1 CD

J. Connor Consulting, Inc. Public Info: 1 + 1 CD

16225 Park Ten Place, Suite 700

Houston, Texas 77084 For BOEM:

(281) 705-8020 Plan No.

cathy.thornton@jccteam.com Assigned to:
Record of Changes

Date Appendix Revision

12/19/2013 A Amended to include discussion for the installation of Platform M

12/19/2013 A Amended the Form BOEM-0138 Plan Information Form for the 

proposed wells to remove the anchor radius 

12/19/2013 A Included a Form BOEM-0138 providing for the installation of 

Platform M

12/19/2013 G Added Table 1 Wastes and Discharges Information

12/19/2013 N Amended Solid and Waste Transportation section to include 

reference that the wastes and discharges information was included in 

Appendix O

12/28/2013 A Amended the Form BOEM-0138 to correct the TD depth of Well 

Location B

01/16/2014 G Amended Table 1 Wastes and Discharges Information to remove 

cuttings from synthetic-based fluids and to provide estimated 

discharge rates for well treatment and completion fluids 

02/06/2014 G Recalculated discharges and amended Table 1 Wastes and 

Discharges Information

03/17/2014 D Amended Appendix D regarding H2S determination. This has been 

amended to reflect that the H2S is confined to the E platform. 
ENERGY RESOURCE TECHNOLOGY GOM, INC.

SUPPLEMENTAL

DEVELOPMENT OPERATIONS COORDINATON DOCUMENT

LEASES OCS-G 00599/00605

SOUTH TIMBALIER BLOCKS 63/86

APPENDIX A Plan Contents

APPENDIX B General Information

APPENDIX C Geological, Geophysical Information

APPENDIX D H2S Information

APPENDIX E Mineral Resources Conservation Information

APPENDIX F Biological, Physical and Socioeconomic Information

APPENDIX G Wastes and Discharge Information

APPENDIX H Air Emissions Information

APPENDIX I Oil Spills Information

APPENDIX J Environmental Monitoring Information

APPENDIX K Lease Stipulations Information

APPENDIX L Environmental Mitigation Measures Information

APPENDIX M Related Facilities and Operations Information

APPENDIX N Support Vessels and Aircraft Information

APPENDIX O Onshore Support Facilities Information

APPENDIX P Coastal Zone Management Act (CZMA) Information

APPENDIX Q Environmental Impact Analysis

APPENDIX R Administrative Information
Energy Resource Technology GOM, Inc. Page A-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX A

PLAN CONTENTS

(A) PLAN INFORMATION FORM

Under this DOCD, ERT proposes to drill, complete and produce Well Locations A, B, C and D

from the South Timbalier Block 86 E-Aux platform (to be designated Lease OCS 00605 Well 

Nos. E006 through E009), drill and complete Well Locations E (OCS 00599 Well No. 25), and F 

and G (Lease OCS 00650 Well Nos. 30 and 31), install proposed 4-pile 4-slot M platform over

the surface location of Well Locations E, F and G (to be renamed Well Nos. M001 through 

M003), and install a proposed 6-inch bulk gas lease term pipeline to be installed from the M 

platform to the South Timbalier Block 63 A platform and a proposed 3-inch supply lease term 

pipeline from South Timbalier Block 63 A platform to the proposed M platform. These 

development operations are located in approximately 90-100 feet of water. The wells will be 

drilled with a jack-up rig. 

Platforms E/E-Aux were installed in 1994 and 2011, respectively. Well Nos. E001 through E005 

were drilled, completed and produced from the E/E-Aux platforms under previously approved 

Plans.

See attached OCS Plan Information Form(s) – Form BOEM-137, included in Attachment A. 

 

(B) LOCATION

Included in Attachment A are location plats depicting the existing and proposed surface 

locations and water depth of each proposed well. 

The existing E/E-Aux platforms are 4-pile bridge connected structures. Each platform has 3 

decks and 6 slots. The proposed M platform will be a tripod structure which will be installed 

utilizing a derrick barge. Included in Attachment A is a schematic of the proposed M platform. 

(C) SAFETY AND POLLUTION PREVENTION FEATURES

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

specifications will be made part of each Application for Permit to Drill. There are no new 

pipelines or construction proposed under this Plan.

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

prevention equipment as described in Title 30 CFR Part 250, Subparts C, D, E, and F; and as 

further clarified by BOEM Notices to Lessees, and current policy making invoked by the BOEM,

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. 
Energy Resource Technology GOM, Inc. Page A-2

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

(D) 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 (Marine 

Diesel) MODU 600 4 2800 38°

Production PF E 300 1 300 37°

(E) ADDITIONAL MEASURES

ERT does not propose additional safety, pollution prevention, or early spill detection measures 

beyond those required by 30 CFR 250.

(F) COST RECOVERY FEE

Included in Attachment A is a pay.gov receipt in the amount of $29,666.00 to cover operations 

proposed in this plan.
Energy Resource Technology GOM, Inc. Page B-1 

Supplemental DOCD November 20, 2013 

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX B 

GENERAL INFORMATION 

(A) APPLICATIONS AND PERMITS 

Following is a table of the additional applications/permits which will require approval prior to 

conducting the operations as proposed in this plan. 

Application/Permit Issuing Agency Status

APD BSEE Pending

Surface Commingling and Measurement Application BSEE Pending

Lease Term Pipeline Application BSEE Pending

(B) DRILLING FLUIDS 

Wells A, B, C & D from E-Aux Platform 

Type of Drilling Fluid Estimated Volume of Drilling Fluid to be 

Used per Well (BBLS)

Water-based (Seawater, freshwater, barite) 9000

Oil-based (diesel, minerals, oil) 0

Synthetic-based (internal olefin, ester) 0

Wells E, F, G from open water location 

Type of Drilling Fluid Estimated Volume of Drilling Fluid to be 

Used per Well (BBLS)

Water-based (Seawater, freshwater, barite) 2500

Oil-based (diesel, minerals, oil) 0

Synthetic-based (internal olefin, ester) 0

 (C) PRODUCTION 

Anticipated Production: 

Type Average Production Rate Peak Production Rate Life of Reservoir

Oil

Gas

(D) OIL CHARACTERISTICS 

Oil characteristics are not required to be submitted with this plan. 
Energy Resource Technology GOM, Inc. Page B-2

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

(E) NEW OR UNUSUAL TECHNOLOGY

ERT does not propose to use any new or unusual technology to carry out the proposed

development activities. 

(F) BONDING STATEMENT

The bond requirements for the activities and facilities proposed in this EP are satisfied by a 

$3,000,000.00 areawide development bond, furnished and maintained according to 30 CFR 256, 

subpart I; NTL No. 2000-G16, "Guidelines for General Lease Surety Bonds;" and additional 

security under 30 CFR 256.53(d) and National NTL No. 2008-N07, “Supplemental Bond 

Procedures.” 

(G) OIL SPILL FINANCIAL RESPONSIBILITY (OSFR)

ERT, BOEM company number 02899 has demonstrated oil spill financial responsibility for the

facilities proposed in this DOCD according to 30 CFR Part 253; and NTL No. 99-N01, 

"Guidelines for Oil Spill Financial Responsibility for Covered Facilities".

(H) DEEPWATER WELL CONTROL STATEMENT

Operations proposed in this plan are located in water depths less than 300 meters (984 feet).

(I) SUSPENSION OF PRODUCTION

South Timbalier Blocks 63/86 are currently held by production. 

(J) BLOWOUT SCENARIO

Blowout Scenario:

The proposed well has drilled the production hole interval with all potential producible 

hydrocarbon sands (PPHS) exposed. A blowout occurs. As per NTL 2010 N06, the BOP is not 

connected to the wellhead and the wellbore is free of drill pipe, logging tools, or other similar 

equipment resulting in an unrestricted and uncontrolled blowout thru the borehole and wellbore. 

A wellbore schematic with the required data, plats and directional survey are included in this 

information package.

Worst Case Discharge: The calculated worst case discharge (WCD) rate for the scenario 

described above would be from 3 PPHS in the production hole interval. The calculated WCD 

from the exposed PPHS would be 4270 BOPD, 199 MMCFGPD and 0 BWPD. The WCD is 

based on nodal analysis using field analog reservoir data.

Maximum duration of the potential blowout: The maximum duration of an uncontrolled 

blowout depends on the time it takes for either the well to bridge over or killed by surface 

intervention or relief well intervention. Each scenario is described in the subsequent paragraphs 

below. The table below summarizes the maximum duration of a potential blowout for each 

scenario.
Energy Resource Technology GOM, Inc. Page B-3

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

Scenario Blowout Duration Oil Discharge*

Well Bridges Over 48 to 72 hrs 8540 bbls to 12,810 bbls

Surface Intervention 9 to 13 days 38,430 bbls to 55,510 bbls

Drill Relief Well 31 days 132,370 bbls

*Assumes no declining oil cut

Potential of well to bridge over: History has shown that most “open hole” blowouts bridge 

over in 48 to 72 hrs. BOEM reported that 49% of all blowout events during 1992 – 2006 stopped 

flowing in 24 hrs or less, 41% lasted between 1 to 7 days and the longest blowout lasted 11 days. 

Over 50% of blowouts were controlled by surface intervention, 36% of the blowouts bridged 

over and the rest depleted. Two relief wells were initiated but both blowouts were controlled by 

other means prior to completing the relief well. Shallow gas was associated with 49% of the 

blowouts. 16 of 20 shallow gas blowouts were successfully diverted until the well bridged over.

The PPHS in the ST 63 “B” well are normally pressured, unconsolidated and friable, therefore 

making “bridging” likely in a blowout event. The targeted unconsolidated sands are at a shallow 

depth on top of a salt dome cap rock feature. These unconsolidated PPHS have been 

encountered in other wells in the field, which is the primary motivation for drilling the well. The 

estimated bottom hole pressure of the 3700’ A Sand is 2074 psi, the 3700’ B Sand is 2136 psi 

and the 3800’ Sand is 2155 psi. The open hole interval with the hydrocarbon bearing sands will 

be drilled at 46.99oinclination. The objective sands are normally pressured with depletion and 

partial water drives as noted in the nodal analysis and require sand control completions to 

prevent them from sanding up. These PPHS characteristics facilitate formation collapse and 

bridging if an uncontrolled blowout event occurred

Likelihood of surface intervention: A blowout specialty company/well control team would be 

mobilized immediately. Well control specialists would conduct a “fly by” in a helicopter within 

12 hrs to assess conditions at the well site. Equipment and well control personnel would be 

mobilized to the rig site on boat and barge within 24 to 36 hrs after a blowout has been reported. 

After arriving on location, the well control team typically needs 2 to 3 days to analyze the 

blowout situation, devise an intervention strategy and mobilize additional service company 

specialists, supplies and equipment. A field support base or command center will be identified, 

set up and communications established.

Surface intervention would be very likely if the wellbore is intact and above the water. The 

intervention could include snuffing out the fire, installing specialized BOPE and performing a 

top kill. Many wells bridge over during this time and subsequently, BOPE equipment is installed 

to secure the well. If the well does not bridge over and continues to blowout, well control 

companies estimate an additional 7 to 10 days are typical to contain the flow and kill the well. 

Therefore, the estimated time to kill a blowout with surface intervention is 9 to 13 days. 
Energy Resource Technology GOM, Inc. Page B-4

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

ERT GOM has Master Service Contracts in place with Cudd Pressure Control, Wild Well 

Control and Boots & Coots, which are diversified well control services companies offering full 

general contracting services with strong engineering component resources. 

Relief well: In the event of an uncontrolled blowout, relief well planning and rig availability 

inquiries would commence immediately. The SHL of the ST 63 “B” well is on the ST 86 “EAux” platform in 98’ WD. There are 32 rigs in the GOM which are working and capable of 

drilling a relief well with an open water location in ST 86. ERT GOM has alliances with 

diversified engineering consulting firms which would provide ERT GOM relief well operations, 

engineering, logistical, materials management, QA/QC and well-site supervision support. Rig 

contracts are in place with all GOM jack-up rig contractors. 

There are no known rig package constraints for a relief well. Therefore, the rig choice would 

be first available, quickest to mobilize and move into position offsetting the blow out well. 

Typical GOM relief well rig open water location will be about 1500’ south or southeast of the 

blow out well. The final rig location will be influenced by operator, contractor and BSEE to 

insure safety of all personnel and equipment involved in the relief well effort.

There are no suitable platforms in the area which would provide an advantage for drilling 

the relief well. A relief well could not be drilled from an onshore location.

The estimated time to drill a relief is summarized in the table below:

Description Estimated 

Days

Cumulative Days

Conduct site assessment 3 3

Secure rig and Mobilize 6 9

Drive 30”. Install diverter. 3 12

Drill 26” hole to 800’ and set 20” conductor casing. 2 14

Drill surface hole and set 13-3/8” surface casing. 7 21

Drill to within 50’ MD of intercept and set 9-5/8” 

casing

5 26

Drill to intercept point of blowout well 2 28

R/U pumping equipment and kill well 3 31

Proposed measures to enhance the ability to prevent a blowout and reduce the likelihood of 

a blowout: 

Preventing a blowout starts with preventing a well control incident or “kick”. In order to prevent 

a “kick”, a thorough understanding of the geology, reservoir characteristics and field/area 

production history is needed. Key offset wells are identified and drilling records of these wells 

are studied in great detail and used in well planning. Specifically, this information is used for 

lithology correlation, abnormal pressure formation prediction, mud weight schedule, casing 

design, and other potential geological risk identification such as depleted or weak zones, 

ballooning formations, sloughing shale, gumbo and hole instability. This research reduces the 

risk of a well control incident.
Energy Resource Technology GOM, Inc. Page B-5

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

Hydrostatic control of the well will be maintained by utilizing a drilling fluid (mud) which exerts 

sufficient hydrostatic pressure to prevent the unintended flow of wellbore fluids or “kick” during 

drilling operations. All Drilling Fluid Requirements per 30 CFR 250 Subpart D 250.455 thru 

250.458 will be implemented while drilling ST 63 “B” location.

The ST 63 “B” well will be drilled using mud weights as per the well plan’s mud weight 

schedule. Mud weight adjustments will be made based on observed drilling parameters 

including rate of penetration, cuttings quantity and appearance, chloride contamination and gas 

monitoring. In the event drilling parameters indicate a potential for a “kick”, the drilling 

operations will cease and a flow check will be performed. Penetration rate will be controlled 

while drilling thru any hydrocarbon sand. Two mud engineers will work 12 hr shifts providing 

24 hr mud engineering support during drilling operations. Two “shaker” men working 12 hr 

shifts continuously monitor mud weight and returns at the shakers. Electronic PVT equipment 

will be utilized throughout all drilling operations. 

Mud properties including viscosity and gel strengths will be adequately maintained in an effort to 

reduce the possibility of swab and surge during tripping operations. Displacement volumes will 

be monitored and recorded during all tripping operations. A heavy slug will be pumped when 

possible before trips so that the pipe can be pulled dry and the hole more accurately monitored. 

As a minimum, a volume equal to the annular volume will be circulated before pulling out of the 

hole. Pipe trip speeds will also be adjusted as such not to cause swab or surge pressures. 

Adequate mud and chemicals will be kept on board the rig to ensure well control at all times. 

Sea water will be available and ready to pump down hole if a high volume loss circulation zone 

is encountered. This will enable immediate stabilization of the well until additional mud can be 

mixed. If lost circulation occurs and well conditions allow, pipe may be pulled up into the 

casing shoe.

Short trips and wiper trips will be performed as the hole conditions dictate or periodically during 

prolonged drilling intervals to monitor and assess any change in hole conditions. These trips also 

help reduce the risk of swab and surge related problems. 

Gas-detecting equipment will monitor all drilling fluid returns. Mudlogging services will 

commence below 2500’ and will be used to monitor wellbore conditions. Mudlogging service 

will include monitoring mud weights (in and out), drill gas, background gas, connection gas, trip 

gas, bottoms up gas and lithology description. This information will be used to assess any 

relative changes in hole conditions and aid in making mud weight adjustments.

LWD (GR/Res)/MWD services will also be utilized below 2500’ TVD. LWD will provide realtime directional surveying well, formation evaluation, reservoir fluid type, and formation 

pressures including abnormal pressure detection. LWD will enable the drilling team with realtime identification of unexpected and potential drilling hazards.
Energy Resource Technology GOM, Inc. Page B-6

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

All efforts will be made to avoid a loss returns event. This includes but not limited to 

identification of depleted zones and faults, high quality casing seats, controlled penetration rates, 

controlling trip in hole speeds, staging up pumps, cement placement models, controlling casing 

surge pressures and solids control. 

Cement programs will be designed to prevent gas influx during cement setting. All casing 

strings will be centralized across hydrocarbon bearing zones. Prior to cementing casing, the 

annulus will be circulated a minimum of 1.5 times its volume as long as mud returns are 

maintained. After cementing casing, the annulus will be monitored while the cement sets.

Diverter and BOP System Requirements as per 30 CFR 250 Subpart D 250.430 thru 250.451 will 

be in effect while drilling ST 63 “B”. The diverter equipment will be installed and tested prior to 

drilling conductor and surface holes. BOP equipment will be installed and tested while 

conducting operations below surface pipe. All BOPE will be tested every 14 days using water. 

Annular and ram BOP’s will be function tested every 7 days between pressure tests. BOP’s will 

include at least one set of blind/shear rams capable of shearing the drill pipe under MASP 

conditions. 

A minimum of two (2) offshore supervisors will be on the rig at all times to ensure 24 hour 

supervision of all drilling activities conducted on the ST 63 “B” well. These onsite supervisors 

will witness and review all BOP tests, casing tests and formation integrity tests. Formation 

integrity tests must be approved by the ERT GOM drilling superintendent, manager or drilling 

engineer prior to drilling ahead. ERT GOM also requires the contractor provide two toolpushers 

to ensure 24 hr supervision of the rig crew. 

ERT GOM conducts rig safety and well control system audits on every rig contracted. These 

audits are conducted after the rig arrives on location and commences work. Each rig crew 

practices well control drills daily. These well control drills include pit drill, kick drill and trip 

drill. Each drill will emphasize “kick” recognition, confirmation, shut-in procedures and 

personnel assignments. 

Additional measures to enhance ERT’s ability to prevent and reduce the likelihood of a blowout 

are:

Management and Direct Supervision Processes:

 Drilling Supervisors, Completion Supervisors, MODU OIM’s, Drillers, and Tool 

Pushers, (including all personnel that may be acting in these capacities) must hold a valid 

well control certificate from an accredited IWCF or WellCAP organization.

 Compliance with all federal rules and regulations: CFRs, NTLs, and Final Rules

 Pursuant to wellbore cementing and zonal isolation techniques, all cementing operations 

will be modeled and designed under the guidelines set forth in API RP 65 Part I & II.
Energy Resource Technology GOM, Inc. Page B-7

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

 RP 53 for Blowout Prevention Equipment Systems for Drilling Wells will be used for 

installation, testing and maintenance of the surface BOP systems. 

 Utilization of ERT management systems: SEMS and MOC

 Adherence to Contractors Safety Management Systems

 Ensure proper physical barriers are in place to prevent uncontrolled flow

 Professionally certified and peer reviewed well design (casing and cementing)

 Contractor engagement meeting to gain alignment on well plan

 Specific procedures to execute well plan

Well and rig equipment:

 All rigs will meet all applicable rules and regulations per 30 CFR 250 and 550, as well as 

all Notice to Leases.

 Certified BOP equipment that is fit for purpose

 Utilize rig and equipment that is fit for purpose

 The working pressure and temperature rating of the BOPE and wellhead will exceed the 

maximum anticipated surface pressure and temperature. 

 Accumulator controls will always be left in the power position (i.e. opened/closed; not 

neutral).

 Rams installed & tested to fit all sizes of drill pipe, casing, and tubing to be used.

 A pressure tested fully opening safety valve (FOSV) and opening/closing wrench with 

appropriate threads or crossover subs for all connections will be available on the rig floor 

at all times. 

 A drill string float valve (ported acceptable) will be installed in all drilling bottom hole 

assemblies (BHA’s). Similar valves will be considered for well intervention and 

completion operations when reverse circulating is not required.

 MWD/LWD/PWD tools will be used accordingly to obtain real-time data on subsurface 

zones

 Circulating trip tanks are required for all drilling operations.

 PVT and gas detection equipment will be employed for all hole sections. 

Drilling Practices: 

 Volume measurements relative to the well will be monitored at all times. 
Energy Resource Technology GOM, Inc. Page B-8

Supplemental DOCD November 20, 2013

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 All critical pressure test charts (i.e. negative tests, casing tests, FIT/LOT) will be 

reviewed by Drilling Engineer/Drilling Supervisor prior to continuing with operations. 

 During drilling operations, slow circulating rates (SCR) will be taken and recorded for 

each mud pump at least after BHA or mud weight changes and 500 feet of formation 

drilled.

 Flow checks shall be conducted after drilling breaks, prior to tripping, after or during lost 

circulation events, pumping out, prior to nippling down BOP’s, and any other time when 

anomalous pit volume readings are observed. Minimum flow check duration shall be 5 

minutes.

 Drilling BOP space-out and tool joint space-out diagrams shall be posted on the rig floor 

at all times. 

 Kill sheets will be updated during each tour and posted on the rig floor.

 PVT and gas detection equipment will be employed for all hole sections. 

Effective and early blowout intervention:

In the event of a blowout, the ERT GOM OSRP will be activated. The first priority will be to 

quickly organize a focused team of operational and technical professionals including a blowout 

specialty company (BSC). The BSC will be immediately mobilized to the blowout site. The 

BSC will analyze the blowout situation and devise an intervention strategy. Site assessment will 

be used to assist in determining the relief well location options so that planning can be initiated.

Historical perspective of blowout occurrence and intervention:

MMS Article written by David Izon, E.P. Danenberger and Melinda Mayes for IADC 

presentation Aug 2007 states that 19 blowouts occurred during the drilling of 8722 wells in OCS 

water depths <200’ during years 1992 – 2006. The authors further say that 1 fatality and 2 

injuries resulted and environmental impacts were negligible during this same period in all OCS 

water depths. The total spillage of all blowouts during this period was 341 bbls oil/condensate 

and 982 bbls of synthetic-based mud. MMS article “OCS Oil Spill Facts”, September 2002, 

states that blowouts from drilling exploratory wells accounted for only 2 spills that were greater 

than 5 bbls – a 100-bbl spill in 1992 and a 200-bbl spill in 2000.

The study further states that 49% of all blowout events during 1992 – 2006 stopped flowing in 

24 hrs or less, 41% lasted between 1 to 7 days and the longest blowout lasted 11 days. Over 50% 

were controlled by surface intervention, 36% of the blowouts bridged over and the rest depleted. 

Two relief wells were initiated but both blowouts were controlled by other means prior to 

completing the relief well. Shallow gas was associated with 49% of the blowouts. 16 of 20 

shallow gas blowouts were successfully diverted until the well bridged over.

The DOI published Increased Safety Measures For Energy Development on the Outer 

Continental Shelf, May 27, 2010, states that oil spilled from OCS rigs and platforms over the 

past 30 years is about 27,000 bbls. The study documents 6 events from 1964 to 2009 which 
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blowouts exceeding 1000 bbls. Of the six, three were associated with drilling. Further noted is 

the last event over 1000 bbls occurred in 1970. In the past 40 years (since 1971), a total of 1800 

bbls was spilled on the Federal OCS as a result of blowout events. 

These are all noteworthy statistics when providing and justifying WCD scenarios and blowout 

intervention while drilling in OCS water depths <200’. The BP Oil Spill illustrates the 

significant challenges in intervention and containment of a blowout in deepwater using subsea 

BOPE as compared to intervention and containment in water depths <200’ using a jack up rig 

and surface BOPE. Since 1947, more than 50,000 wells have been drilled in Federal Gulf of 

Mexico. Until the BP Oil Spill, research did not find a single blowout in Federal Gulf of Mexico 

waters which required a relief well to kill the blowout.

Included in Attachment B is the NTL 2010-N06 Worst Case Discharge Analysis.
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APPENDIX C 

GEOLOGICAL AND GEOPHYSICAL INFORMATION 

NOTE: Two separate discussions were done. One for the H2S shallow A,B,C,D wells and one 

for the deep E,F,G sweet wells. 

PROPOSED WELL LOCATIONS A, B, C and D

 (A) GEOLOGICAL DESCRIPTION 

(B) STRUCTURE CONTOUR MAP(S) 

Structure contour maps on the 3700, 3700B, and 3800 sands are included in Attachment C for 

locations A,B,C,D, These maps are at a scale of 1”=2000’ and have the proposed wellbore paths 

shown. They have been generated by using the offset well control and 3-D seismic time data. 

(C) INTERPRETED 2-D AND/OR 3-D SEISMIC LINE(S) 

The seismic data used to interpret structure is a Western Geophysical Merge W/TauP Filter & 

Gain volume. Arbitrary seismic lines labeled A,B,C,D are included. They show the bottomhole locations of the proposed wells and portions. A time/depth curve for the Odeco ST86 #16 

well (API:177154028300) was used to convert target time to depth and is included in

Attachment C. 

(D) GEOLOGICAL STRUCTURE CROSS-SECTIONS 

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

wells and key horizons and the objective sands is included. The geologic age of the targeted 

sands is shown in biostratigraphic terms are included in Attachment C. 

(E) SHALLOW HAZARDS REPORT 

The proposed new wells will be drilled from an existing surface location (Platform E-Aux), 

therefore, a Shallow Hazards Report is not required. 
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(F) SHALLOW HAZARDS ASSESSMENT 

The proposed new wells (Well Locations A, B, C and D) will be drilled from an existing surface 

location (Platform E-Aux), therefore, a Shallow Hazards Assessment is not required. 

(G) HIGH-RESOLUTION SEISMIC LINES 

The proposed new wells (Well Locations A, B, C and D) will be from an existing surface 

location (Platform E-Aux), therefore High Resolution Seismic Lines are not required.

(H) STRATIGRAPHIC COLUMN

A generalized biostratigraphic/lithostratigraphic column depicting each well from the seafloor to 

total depth, with each objective horizon labeled, is included in Attachment C. 

 

(I) TIME VS DEPTH TABLES

Sufficient well control data for the target areas proposed in this DOCD exists; therefore, seismic 

time versus depth tables for the proposed well locations are not required. 

PROPOSED WELL LOCATIONS E, F and G

(A) GEOLOGICAL DESCRIPTION 

(B) STRUCTURE CONTOUR MAP(S) 

Structure contour maps on the “S” and “T” sands are included in Attachment C for locations 

E,F,G. These maps are at a scale of 1”=2000’ and have the proposed wellbore paths shown. 

They have been generated by using the offset well control and 3-D seismic time data. 

(C) INTERPRETED 2-D AND/OR 3-D SEISMIC LINE(S) 

The seismic data used to interpret structure is a Western Geophysical Merge W/TauP Filter & 

Gain volume. Arbitrary seismic lines labeled E,F,G are included. They show the bottom- hole 

locations of the proposed wells and portions. A time/depth curve for the Odeco ST86 #16 well 

(API:177154028300) was used to convert target time to depth and is included in Attachment C. 
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Supplemental DOCD November 20, 2013

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(D) GEOLOGICAL STRUCTURE CROSS-SECTIONS 

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

wells and key horizons and the objective sands is included. The geologic age of the targeted 

sands is shown in biostratigraphic terms are included in Attachment C.

(E) SHALLOW HAZARDS REPORT

ERT contracted Tesla Offshore LLC to conduct a shallow hazards survey across a portion of 

South Timbalier Blocks 63/86. Three copies of this report are being submitted on this date under 

separate cover.

(F) SHALLOW HAZARDS ASSESSMENT

A shallow hazards assessment has been prepared for the proposed surface location (Well 

Locations E, F and G), evaluating seafloor and subsurface geological and manmade features and 

conditions that may adversely affect drilling operations, and is included in Attachment C.

(G) HIGH-RESOLUTION SEISMIC LINES 

Included in Attachment C are annotated high-resolution survey lines closest to each of the 

proposed well locations.

(H) STRATIGRAPHIC COLUMN

A generalized biostratigraphic/lithostratigraphic column depicting each well from the seafloor to 

total depth, with each objective horizon labeled, is included in Attachment C.

(I) TIME VS DEPTH TABLES

Sufficient well control data for the target areas proposed in this DOCD exists; therefore, seismic 

time versus depth tables for the proposed well locations are not required.
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Supplemental DOCD November 20, 2013 

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APPENDIX D 

HYDROGEN SULFIDE INFORMATION 

(A) CONCENTRATION 

Hydrogen sulfide is expected in Well Locations A, B, C and D, drilled from the existing 

Platform E. A test on the E-4 well from a gas sample taken 10/12/2013 indicated 4500 ppm and 

0.4500 mole% hydrogen sulfide. A Sensidyne pump was used for the analytical method. 

Flowline vapor pressure was 435 psi @ a temp of 78 degrees. Gas rate for this well was 6718 

mcfpd. 

ERT will submit to the appropriate BOEM district office an H2S Contingency Plan prepared 

according to 30 CFR 250.490(f) before conducting the proposed development and production

activities. 

Please note that the H2S is confined to the E platform. This is the platform that handles all 

of the shallow production that has H2S, and it’s the only platform with H2S handling 

equipment and associated safety equipment. The H2S concentration on the E platform is 

approximately 4500 ppm. There is no H2S anywhere else. 

 (B) CLASSIFICATION 

In accordance with Title 30 CFR 550.490(c), ERT requests that the South Timbalier Blocks 

63/86 Well Locations E, F, and G (drilled from the proposed South Timbalier Block 63 Platform 

H be classified by the BOEM as H2S absent. 
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Supplemental DOCD November 20, 2013 

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APPENDIX E 

MINERAL RESOURCE CONSERVATION INFORMATION 

(A) TECHNOLOGY & RESERVOIR ENGINEERING PRACTICES AND PROCEDURES

 (B) TECHNOLOGY AND RECOVERY PRACTICES AND PROCEDURES 

 

(C) RESERVOIR DEVELOPMENT 
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APPENDIX F

BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION

(A) DEEPWATER BENTHIC COMMUNITIES 

Activities proposed in this DOCD will not disturb seafloor areas in water depths of 300 meters 

(984 feet) or greater; therefore, information as outlined in Attachment A of NTL No. 2009-G40, 

"Deepwater Benthic Communities", is not provided.. 

(B) TOPOGRAPHIC FEATURES MAP 

Activities proposed in this DOCD do not fall within 305 meters (1000 feet) of a topographic “no 

activity zone”.

(C) 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 

(D) LIVE BOTTOMS (PINNACLE TREND) MAP

South Timbalier Blocks 63/86 are not located within 61 meters (200 feet) of any pinnacle trend 

feature; therefore a separate bathymetric map is not required. 

(E) LIVE BOTTOMS (LOW RELIEF) STIPULATION 

South Timbalier Blocks 63/86 are not located within 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.

(F) POTENTIALLY SENSITIVE BIOLOGICAL FEATURES

South Timbalier Blocks 63/86 are not located within 30 meters (100 feet) of potentially sensitive 

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

(G) REMOTELY OPERATED VEHICLE (ROV) SURVEYS 

BOEM has determined there is enough data gathered in this grid area, therefore, we will not be 

conducting any ROV surveys either pre-spudding or post-drilling operations.

(H)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 the 30 CFR 250, Subpart B, effective May 14, 2007, and further outlined in 

Notice to Lessees (NTL) 2008-G04 (extended by NTL 2013-G02), 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.
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NOAA Fisheries currently lists the Sperm Whale, Leatherback Turtle, Green Turtle, Hawksbill 

Turtle, and the Kemp’s Ridley Turtle as endangered and the Loggerhead Turtle and Gulf 

Sturgeon as 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 of our operations.

(I) ARCHAEOLOGICAL REPORT

South Timbalier Blocks 63/86 have been determined as potentially containing prehistoric 

archaeological properties. Therefore, an Archaeological Survey Report has been prepared in 

accordance with NTL 2005-G07 "Archaeological Surveys and Reports" and is being submitted 

under separate cover.

(J) AIR AND WATER QUALITY INFORMATION

Air and water quality information is not required by BOEM to be included in this plan.

(K) SOCIOECONOMIC INFORMATION

Socioeconomic information is not required by BOEM to be included in this plan.
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APPENDIX G

WASTES AND DISCHARGES INFORMATION

(A) PROJECTED GENERATED WASTES

please specify if the amount reported is a total or per well amount

Projected generated waste Projected ocean discharges 

Type of Waste Composition Projected Amount Discharge rate Discharge Method Answer yes or no

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

EXAMPLE: Cuttings wetted with synthetic based fluid 

Cuttings generated while 

using synthetic based drilling 

fluid. X bbl/well X bbl/day/well discharge overboard No

Water-based drilling fluid Water based drilling fluids 13,000 bbls/well 433 bbls/day/well discharge overboard No

Cuttings wetted with water-based fluid

Cuttings generated while 

using water based drilling 

fluids 2500 bbls/well 83.3 bbls/day/well discharge overboard No

Cuttings wetted with synthetic-based fluid NA NA NA NA NA

Will humans be there? If yes, expect conventional waste

EXAMPLE: Sanitary waste water

Sanitary waste from living 

quarters X bbl/well X bbl/hr/well

chlorinate and discharge 

overboard No

Domestic waste grey water 4800 bbls/well 4.2 bbls/hr/well

remove floating solids and 

discharge No

Sanitary waste treated sanitary waste 1200 bbls/well 1.04 bbls/hr/well chlorinate and discharge No

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

Deck Drainage

washwater and deck 

drainage 2400 bbls/well 2.08 bbls/hr/well discharge overboard No

Will you conduct well treatment, completion, or workover? 

Well treatment fluids NA NA NA NA NA

Well completion fluids 8.8 ppg KCl 200 bbls/well 0.83 bbls/hr/well discharge overboard NA

Workover fluids NA NA NA NA NA

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

Desalinization unit discharge NA NA NA NA NA

Blowout prevent fluid NA NA NA NA NA

Ballast water NA NA NA NA NA

Bilge water Uncontaminated seawater 24 bbls/well 0.5 bbls/day/well discharge overboard NA

Excess cement at seafloor Class H cement slurry 150 bbls/well

75 bbls/day for 2 

days/well discharge overboard NA

Fire water Seawater NA NA discharge overboard NA

Cooling water Seawater 1,440,000 bbls/well 30,000 bbls/day/well discharge overboard NA

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

Produced water formation water 200 bbls/day/well <500 bbls/day discharge overboard NA

Will you be covered by an individual or general NPDES permit ? General Permit 

TABLE 1. WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR 

DISCHARGE TO THE GOM

Projected 

Downhole 

Disposal
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APPENDIX H

AIR EMISSIONS INFORMATION

(A) EMISSIONS WORKSHEETS AND SCREENING QUESTIONS

(1) 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 or criteria set for the 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

Enclosed in Attachment H are Air Emission Worksheets showing the emissions calculations for 

the Plan Emissions, and if different, a set of worksheets showing the emissions calculations for 

the Complex Total emissions.

This information was calculated by: Cathy Thornton 

(713) 705-8020

cathy.thornton@jccteam.com
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APPENDIX I

OIL SPILLS INFORMATION

(A) OIL SPILL RESPONSE PLANNING

Energy Resource Technology GOM, Inc.’s (MMS Operator Number 02899) Regional Oil Spill 

Response Plan (OSRP) was submitted in April, 2012 with the latest modification of the Regional 

OSRP approved on July 26, 2013. The next Biennial Oil Spill Response Plan is due by April 30, 

2014. The activities proposed in this DOCD will be covered by the Regional OSRP in 

accordance with 30 CFR 254.

(B) SPILL RESPONSE SITES

Primary Response Equipment Location Preplanned Staging Location

Houma, LA

Harvey, LA

Venice, LA

Houma, LA

Harvey, LA

Venice, LA

(C) OSRO INFORMATION

ERT’s primary equipment provider is Clean Gulf Associates (CGA). The Marine Spill Response 

Corporation’s (MSRC) STARS network will provide closest available personnel, as well as an 

MSRC supervisor to operate the equipment. 

(D) WORST-CASE SCENARIO DETERMINATION

Category

Drilling Production

Regional 

OSRP

WCD

DOCD

WCD

Regional 

OSRP

WCD

DOCD

WCD

Type of Activity Drilling Drilling >10 mile 

Production

>10 mile 

Production

Facility Location 

(Area/Block) GC237 ST 86 GC 282 SM130

Facility Designation Well No. 005 Well No. E007

(Well Loc. B)

SS Well No. 1 

(ST03BP01) PF E

Distance to Nearest 

Shoreline (miles) 91 20 91 20

Volume

 Storage tanks & flowlines

 Lease term pipelines

 Uncontrolled blowout

Total Volume (bbls)

212,891

212,891

4270

4270

43,280

43,280

300

 275

1860 

2435

Type of Oil(s)

(crude, condensate, diesel) Crude Crude Crude Crude

API Gravity 33° 37° 32° 37°
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ERT has determined that the worst-case scenario from the activities proposed in this DOCD does

not supersede the worst-case scenario from our approved regional OSRP for far-shore activities.

Since ERT has the capability to respond to the worst-case spill scenario included in our regional 

OSRP currently pending approval, and since the worst-case scenario determined for our DOCD

does not replace the worst-case scenario in our regional OSRP, I hereby certify that ERT 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.

(E) OIL 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 4270 barrels of crude oil with an API gravity of 37°.

Land Segment and Resource Identification

Trajectories of a spill and the probability of it impacting a land segment have been projected 

utilizing information in the BSEE Oil Spill Risk Analysis Model (OSRAM) for the Central and 

Western Gulf of Mexico available on the BSEE website. The results are shown in Figure 1. The 

BSEE OSRAM identifies a 10% probability of impact to the shorelines of Cameron and/or 

Terrebonne Parish, Louisiana within 30 days. Cameron Parish includes the east side of Sabine 

Lake, Sabine National Wildlife Refuge, Calcasieu Lake, Lacassine National Wildlife Refuge 

(inland) and Grand Lake. Cameron Parish also includes the area along the coastline from Sabine 

Pass to Big Constance Lake in Rockefeller Wildlife Refuge. This region is composed of open 

public beaches, marshlands and swamps. It serves as a habitat for numerous birds, finfish and 

other animals, including several rare, threatened and endangered species. Terrebonne Parish 

includes the eastern portion of Atchafalaya National Wildlife Refuge across to Timbalier Bay. 

The Terrebonne parish also includes the area along the Gulf Coast including Caillou Bay, Isles 

Dernieres and Terrebonne Bay. The entire parish is classified as an EPA National Estuary. This 

area is primarily marshland, broken up by numerous small bays and freshwater lakes.

Response

ERT 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 45% or 

approximately 1922 barrels of crude oil would be evaporated/dispersed within 24 hours, with 

approximately 2348 barrels remaining.
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Spill Response ST 86, Well E007 Barrels of Oil 

WCD Volume 4270

Less 45% natural evaporation/dispersion 1922

Remaining volume 2348

Figure 2 outlines equipment, personnel, materials and support vessels as well as temporary 

storage equipment available to respond to the worst case discharge. 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. 

ERT’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 (9600 gallons) from two 

of the DC-3 aircrafts and 4 sorties (8000 gallons) from the Basler aircraft would provide a daily 

dispersant capability of 7540 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 and the R/V Grand Bay, with a total derated skimming capacity of 48,000 barrels. 

Temporary storage associated with skimming equipment equals 4065 barrels. If additional 

storage is needed, a 25,000 barrel storage barge and a 20,000 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. 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 Cameron and/or Terrebonne 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 7,176 barrels. Temporary storage associated with skimming equipment equals 54 barrels. If 

additional storage is needed, a 20,000 barrel storage barge may be mobilized and centrally 

located to provide temporary storage allowing the skimmers to stay in the area of operations as 

much as possible. Onshore response may include the deployment of shoreline boom on beach 

areas, or protection and sorbent boom on vegetated areas. A Letter of Intent from OMI 

Environmental will ensure access to 85,000 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 Cameron and Terrebonne 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 
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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. ERT’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, ERT 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 

31 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

ERT 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.
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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 
Energy Resource Technology GOM, Inc. Page I-6

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

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

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 ERT’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
Energy Resource Technology GOM, Inc. Page I-7

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

 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)
Energy Resource Technology GOM, Inc. Page I-8

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

 Operate with aerial spotter directing systems to observed oil slicks

VOO

 Use ERT’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
Energy Resource Technology GOM, Inc. Page I-9

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

 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
Energy Resource Technology GOM, Inc. Page I-10

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

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.
Energy Resource Technology GOM, Inc. Page I-11

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

FIGURE 1

TRAJECTORY BY LAND SEGMENT

Trajectory of a spill and the probability of it impacting a land segment have been projected 

utilizing ERT’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 7 wells (4 

from PF E and 3 from 

proposed PF M), and 

install one tripod 

structure and 2 lease 

term pipelines.

ST 86, Well E007

20 miles from shore

00605 C39 Matagorda, TX

Brazoria, TX

Galveston, TX

Jefferson, TX

Cameron, LA

Vermilion, LA

Iberia, La

Terrebonne, LA

Lafourche, LA

Jefferson, LA

Plaquemines, LA

2

1

2

3

10

4

1

10

5

2

8
Energy Resource Technology GOM, Inc. Page I-12

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

WCD Scenario– BASED ON WELL BLOWOUT DURING DRILLING OPERATIONS (20 miles from shore)

2,348 bbls of crude oil (Volume considering natural weathering)

API Gravity 37°

FIGURE 2 – Equipment Response Time to ST 86, Well E007

Dispersants/Surveillance

Dispersant/Surveillance Dispersant 

Capacity (gal)

Storage 

Capacity Persons Req. From Hrs to Procure

Hrs to 

Loadout

Travel to 

site Total Hrs

ASI

Basler 67T 2000 NA 2 Houma 1 1 0.3 2.3

DC 3 1200 NA 2 Houma 1 1 0.4 2.4

DC 3 1200 NA 2 Houma 1 1 0.4 2.4

Aero Commander NA NA 2 Houma 1 1 0.3 2.3

Offshore Response

Offshore Equipment No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure

Hrs to 

Loadout

Hrs to 

GOM

Travel to 

Spill Site

Hrs to 

Deploy

Total 

Hrs

CGA

HOSS Barge 43000 4000 3 Tugs 5 Harvey 7 0 5 4.4 1 17.4

46’ FRV 5000 65 NA 4 Venice 1 0 1 2 0 4

Boom Barge (CGA-300)

42” Auto Boom (25000’) NA NA 1 Tug50 Crew

4 (Barge)

2 (Per Crew) Leeville 4 0 6 3.6 1.5 15.1

Recovered Oil Storage No 

Staging EDRC

Storage 

Capacity VOO Persons Required From Hrs to Procure

Hrs to 

Loadout

Hrs to 

GOM

Travel to 

Spill Site

Hrs to 

Deploy

Total 

Hrs

Enterprise Marine Services LLC (available through contract with CGA)

CTCo 2603 NA 25000 1 Tug 6 Amelia 4 12 4 10 1 31

CTCo 2604 NA 20000 1 Tug 6 Amelia 4 12 4 10 1 31

Staging Area: Fourchon

Offshore Equipment With 

Staging EDRC Storage Capacity VOO Persons Req. From Hrs to Procure

Hrs to 

Loadout

Travel to 

Staging

Travel to 

Site

Hrs to 

Deploy

Total 

Hrs

CGA

Hydro-Fire Boom NA NA 8 Utility 40 Harvey 1 4 2 2.1 6 15.1
Energy Resource Technology GOM, Inc. Page I-13

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

Nearshore Response

Nearshore Equipment No 

Staging EDRC Storage Capacity VOO Persons Required From Hrs to Procure

Hrs to 

Loadout

Hrs to 

GOM

Travel to 

Spill Site

Hrs to 

Deploy

Total 

Hrs

Enterprise Marine Services LLC (available through contract with CGA)

CTCo 2605 NA 20000 1 Tug 6 Amelia 4 12 4 12.5 1 33.5

Staging Area: Fourchon

Nearshore and Inland 

Skimmers With Staging EDRC Storage Capacity VOO Persons Req. From Hrs to Procure

Hrs to 

Loadout

Travel to 

Staging

Travel to 

Deployment

Hrs to 

Deploy Total Hrs

CGA

SWS Marco 3588 20 NA 3 Lake Charles 1 2 4 2 0 9

SWS Marco 3588 34 NA 3 Leeville 1 2 0.25 2 0 5.25
Energy Resource Technology GOM, Inc. Page I-14

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

Shoreline Protection

Staging Area: Fourchon

Shoreline Protection 

Boom VOO Persons Req. 

Storage/Warehouse

Location

Hrs to 

Procure

Hrs to 

Loadout

Travel to 

Staging

Travel to 

Deployment Site

Hrs to 

Deploy Total Hrs

OMI Environmental (available through Letter of Intent)

10,000’ 18” Boom 4 Crew 10 New Iberia, LA 1 1 3.5 2 3 10.5

10,000’ 18” Boom 4 Crew 10 Houston, TX 1 1 7 2 3 14

10,000’ 18” Boom 4 Crew 10 Port Arthur, TX 1 1 5.75 2 3 12.75

20,000’ 18” Boom 8 Crew 20 Belle Chasse, LA 1 1 3 2 6 13

10,000’ 18” Boom 4 Crew 10 Port Allen, LA 1 1 3.5 2 3 10.5

10,000’ 18” Boom 4 Crew 10 Houma, LA 1 1 2 2 3 9

15,000’ 18” Boom 6 Crew 14 Gretna, LA (Warehouse) 2 2 2.75 2 4 12.75

Wildlife Response EDRC Storage 

Capacity VOO Persons Req. From Hrs to Procure

Hrs to 

Loadout

Travel to 

Staging

Travel to 

Deployment

Hrs to 

Deploy Total Hrs

CGA

Wildlife Support Trailer NA NA NA 2 Harvey 1 2 2 1 2 8

Bird Scare Guns (48) NA NA NA 2 Harvey 1 2 2 1 2 8

Bird Scare Guns (12) NA NA NA 2 Galveston 1 2 7 1 2 13

Bird Scare Guns (12) NA NA NA 2 Aransas Pass 1 2 9.5 1 2 15.5

Bird Scare Guns (24) NA NA NA 2 Lake Charles 1 2 4 1 2 10

Bird Scare Guns (24) NA NA NA 2 Venice 1 2 4 1 2 10

Response Asset Total

Offshore EDRC 48,000

Offshore Recovered Oil Storage 49,065

Nearshore / Shallow Water EDRC 7,176

Nearshore / Shallow Water Recovered Oil Storage 20,054
Energy Resource Technology GOM, Inc. Page J-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX J

ENVIRONMENTAL MONITORING INFORMATION

(A) MONITORING SYSTEMS

There are no environmental monitoring systems currently in place or planned for the proposed 

activities.

(B) 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. 

To date, 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.

(C) FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY

South Timbalier Blocks 63/86 are not located in the Flower Garden Banks National Marine 

Sanctuary; therefore, the requested information is not required in this DOCD.
Energy Resource Technology GOM, Inc. Page K-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX K

LEASE STIPULATIONS INFORMATION

The BOEM did not invoke lease stipulations for Leases OCS-G 00599/00605,South Timbalier 

Blocks 63/86.
Energy Resource Technology GOM, Inc. Page L-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX L

ENVIRONMENTAL MITIGATION MEASURES INFORMATION

(A) MITIGATION MEASURES TAKEN TO MINIMIZE IMPACT TO MARINE AND 

COASTAL ENVIRONMENT 

Mitigation measures taken to minimize impact to marine and coastal environment is not required 

for this DOCD.

(B) INCIDENTAL TAKES

ERT 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 ESA as a result of the operations 

conducted herein:

 NTL 2012-G02-JOINT, “Vessel Strike Avoidance and Injured/Dead Protected Species 

Reporting

 NTL 2012-G01, “Marine Trash and Debris Awareness and Elimination”

 NTL 2012-G02-JOINT, “Implementation of Seismic Survey Mitigation Measures and 

Protected Species Observer Program”
Energy Resource Technology GOM, Inc. Page M-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX M

RELATED FACILITIES AND OPERATIONS INFORMATION

(A) RELATED OCS FACILITIES AND OPERATIONS

Well Locations A, B, C and D will be drilled and produced from the existing South Timbalier 

Block 86 Platform E-Aux. Well Locations E, F and G will be drilled and will be produced from 

the proposed M platform. A 6-inch bulk gas lease term pipeline approximately 10,500 feet in 

length will be installed to transport produced bulk gas to the South Timbalier Block 63 A 

platform for processing. Additionally, a 3-inch lease term supply pipeline approximately 10,500

feet in length will be installed from the South Timbalier Block 63 A platform to the proposed 

South Timbalier Block 86 M platform. All hydrocarbon handling equipment installed for testing 

and production operations will be designed, installed and operated to prevent pollution.

(B) TRANSPORTATION SYSTEM

Full well stream production from the proposed South Timbalier Block 86 M platform will flow 

to the South Timbalier Block 63 A platform for processing. Separated gas production will depart 

the South Timbalier Block 63 A platform via Trunkline’s existing 12-inch pipeline (Segment No. 

01655) to the Trunkline-operated South Timbalier Block 63 Manifold platform (ROW No. OCSG 01693) prior to delivery into Operations System No. 25.0/XE0. Separated liquid hydrocarbon 

production will depart the South Timbalier Block 63 A/Aux platform via Energy XXI Pipeline, 

LLC's existing 10-inch pipeline (Segment No. 04305) for ultimate delivery to shore via 

Operations System No. 36.0.

(C) PRODUCED LIQUID HYDROCARBONS TRANSPORTATION VESSELS

There will not be any transfers of liquid hydrocarbons other than via pipeline.
Energy Resource Technology GOM, Inc. Page N-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX N

SUPPORT VESSELS AND AIRCRAFT INFORMATION

(A) GENERAL

Type Maximum Fuel 

Tank Capacity

Maximum 

Number in Area at 

Any Time

Trip 

Frequency or 

Duration

Tug Boats 3000 bbls 2 2 days

Anchor Handling Boat 1500 bbls 2 NA

Crew Boat 500 bbls 1 Daily

Supply Boat 500 bbls 1 Three times per 

week

Helicopter 800 lbs

100-120 gallons

1 Two trips daily

average

The most practical, direct route from the shorebase as permitted by weather and traffic 

conditions will be utilized.

(B) DIESEL OIL SUPPLY VESSELS

Size of Fuel Supply 

Vessel

Capacity of Fuel 

Supply Vessel

Frequency of Fuel 

Transfers

Route Fuel Supply 

Vessel Will Take

180 feet 1500 bbls Weekly From shorebase in 

Fourchon to ST63/86 

then back to shorebase.

(C) DRILLING FLUID TRANSPORTATION

Drilling fluid transportation information is not required by BOEM to be included in this plan. 

(D) SOLID AND LIQUID WASTE TRANSPORTATION

For solid and liquid waste transportation refer to Table 2 under Waste Disposal in Appendix O 

Section D of this Plan.

(E) VICINITY MAP

Enclosed in Attachment N is 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 route(s) of the support vessels and aircraft that will be used when traveling between 

the onshore support facilities and the platform.
Energy Resource Technology GOM, Inc. Page O-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX O

ONSHORE SUPPORT FACILITIES INFORMATION

(A) GENERAL

Name Location Existing/New/Modified

Martin Terminal North Fourchon, LA Existing

(B) SUPPORT BASE CONSTRUCTION OR EXPANSION

There will be no new construction of an onshore support base, nor will we expand the existing 

shorebase as a result of the operations proposed in this DOCD.

(C) SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE

There will be no new construction of an onshore support base, nor will we expand the existing 

shorebase as a result of the operations proposed in this DOCD.

(D) WASTE DISPOSAL
Energy Resource Technology GOM, Inc. Page P-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX P

COASTAL ZONE MANAGEMENT (CZMA) INFORMATION

Relevant enforceable policies were considered in certifying consistency for Louisiana. A certificate of 

Coastal Zone Management Consistency for the state of Louisiana is enclosed in Attachment P. 
Energy Resource Technology GOM, Inc. Page Q-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX Q

ENVIRONMENTAL IMPACT ANALYSIS (EIA) 

(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 X

Fisheries X 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 X(6)

Marine and pelagic birds X X X

Public health and safety (5)

Coastal and Onshore

Beaches X(6) X

Wetlands X(6)

Shore birds and coastal nesting 

birds

X(6) X

Coastal wildlife refuges X

Wilderness areas X
Energy Resource Technology GOM, Inc. Page Q-2

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

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 (Low-Relief) 

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.
Energy Resource Technology GOM, Inc. Page Q-3

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

(B) ANALYSIS

Site-Specific at South Timbalier Block 63 and South Timbalier Block 86

Proposed operations consist of the drilling, completion and commencement of production from Well 

locations A, B, C and D from the South Timbalier Block 86 E-Aux platform (to be designated Well 

Nos. E006 through E009, under OCS-G 00605); the drilling and completion of Well Locations E (to be 

designated Well No. 25, under OCS-G 00599), F and G (to be designated Well Nos. 30 and 31, under 

OCS-G 00605); the installation of proposed 4-pile 4-slot M platform over the surface location of Well 

Locations E, F and G (to be renamed Well Nos. M001 through M003); and the installation of a 

proposed 6-inch bulk gas lease term pipeline to be installed from the M platform to the South 

Timbalier Block 63 A platform and a proposed 3-inch supply lease term pipeline from South Timbalier 

Block 63 A platform to the proposed M platform.

Operations will be conducted with a Jack-up Rig.

1. Designated Topographic Features

Potential IPFs on topographic features include physical disturbances to the seafloor, effluents, and 

accidents. 

Physical disturbances to the seafloor: South Timbalier Block 63 and South Timbalier Block 86 are 

approximately 40 miles from the closest designated Topographic Features Stipulation Block (Sackett 

Bank); therefore, no adverse impacts are expected. 

Effluents: South Timbalier Block 63 and South Timbalier Block 86 are approximately 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 ERT’s Regional OSRP (refer to information submitted in Section 9). 

There are no other IPFs (including emissions and wastes sent to shore for disposal) from the proposed 

activities, which could impact topographic features.
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2. Pinnacle Trend Area Live Bottoms

Potential IPFs on pinnacle trend area live bottoms include physical disturbances to the seafloor, 

effluents, and accidents. 

Physical disturbances to the seafloor: South Timbalier Block 63 and South Timbalier Block 86 are 

approximately 108 miles from the closest live bottom (pinnacle trend) area; therefore, no adverse 

impacts are expected. 

Effluents: South Timbalier Block 63 and South Timbalier Block 86 are approximately 108 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 ERT’s Regional OSRP (refer to information submitted in Section 9). 

There are no other IPFs (including emissions 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 physical disturbances to the seafloor, effluents, and 

accidents.

Physical disturbances to the seafloor: South Timbalier Block 63 and South Timbalier Block 86 are 

not located in an area characterized by the existence of live bottoms, and this lease does not contain a 

Live-Bottom Stipulation requiring a photo documentation survey and survey report.

Effluents: South Timbalier Block 63 and South Timbalier Block 86 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 
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blocks from a live bottom area. The activities proposed in this plan will be covered by ERT’s Regional 

OSRP (refer to information submitted in Section 9). 

There are no other IPFs (including emissions 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.

Operations proposed in this plan are in water depths ranging from 94 feet to 100 feet. High-density 

benthic communities are found only in water depths greater than 984 feet (300 meters); therefore, 

ERT’s proposed operations in South Timbalier Block 63 and South Timbalier Block 86 would not 

cause impacts to benthic communities.

5. Water Quality

IPFs that could result in water quality degradation from the proposed operations in South Timbalier 

Block 63 and South Timbalier Block 86 include disturbances to the seafloor, effluents and accidents. 

Physical disturbances to the seafloor: Bottom area disturbances resulting from the emplacement of 

drill rigs, the drilling of wells and the installation of platforms and pipelines would increase watercolumn turbidity and re-suspension of any accumulated pollutants, such as trace metals and excess 

nutrients. This would cause short-lived impacts on water quality conditions in the immediate vicinity 

of the emplacement operations.

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. 
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Most of the components of oil are insoluble in water and therefore float. The activities proposed in this 

plan will be covered by ERT’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 South Timbalier 

Block 63 and South Timbalier Block 86 include physical disturbances to the seafloor, effluents and 

accidents. 

Physical disturbances to the seafloor: The emplacement of a structure or drilling rig results in 

minimal loss of bottom trawling area to commercial fishermen. Pipelines cause gear conflicts which 

result in losses of trawls and shrimp catch, business downtime and vessel damage. Most financial 

losses from gear conflicts are covered by the Fishermen’s Contingency Fund (FCF). The emplacement 

and removal of facilities are not expected to cause significant adverse impacts to fisheries.

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 down-current 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 ERT’s Regional OSRP (refer to information submitted in 

Section 9). 

There are no IPFs from emissions, 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 
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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 South Timbalier Block 63 and South 

Timbalier Block 86 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).

ERT 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 ERT 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 
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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@BOEM.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 ERT’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 ERT’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 
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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). ERT 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 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 ERT 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@BOEM.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 ERT’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.
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9. Air Quality

South Timbalier Block 63 and South Timbalier Block 86 are located approximately 75 miles from the 

Breton Wilderness Area and 20 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 distances of South 

Timbalier Block 63 and South Timbalier Block 86 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)

IPFs that could impact known or unknown shipwreck sites as a result of the proposed operations in 

South Timbalier Block 63 and South Timbalier Block 86 include disturbances to the seafloor and 

accidents (oil spill). South Timbalier Block 63 and South Timbalier Block 86 are not located in or 

adjacent to an OCS block designated by BOEM as having a high probability for occurrence of 

shipwrecks. ERT will report to BOEM the discovery of any evidence of a shipwreck 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 which could impact shipwreck sites.

Accidents: An accidental oil spill has the potential to cause some detrimental effects to shipwreck 

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 ERT’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 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 South Timbalier Block 63 and South Timbalier Block 86 are physical disturbances to the seafloor 

and accidents (oil spills). 

Physical Disturbances to the seafloor: South Timbalier Block 63 and South Timbalier Block 86 are 

located inside the Archaeological Prehistoric high probability lines. ERT 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.
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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 ERT’s Regional Oil Spill Response Plan (refer to information submitted 

in accordance with Section 9).

There are no other IPFs (including emissions, effluents, wastes sent to shore for treatment or disposal) 

from the proposed activities that could cause impacts to prehistoric archaeological 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 South Timbalier Block 

63 and South Timbalier Block 86 include physical disturbances to the seafloor, effluents and accidents. 

EFH includes all estuarine and marine waters and substrates in the Gulf of Mexico. 

Physical disturbances to the seafloor: 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 bottom disturbing activities (e.g., 

anchoring, structure emplacement and removal).

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 livebottom 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 ERT’s Regional OSRP (refer to information submitted in Section 9).

There are no other IPFs (including emissions, or wastes sent to shore for treatment or disposal) from 

the proposed activities which could impact essential fish habitat.
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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 ERT’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 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). ERT 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 servicesrelated 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 ERT 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.
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3. Public Health and Safety Due to Accidents.

In accordance with NTL No.’s 2008-G04, 2009-G27, and 2009-G31, information has been included in 

Section 4 to verify the presence of H2S for Well Locations A – D (to be designated Well Nos. E006 

through E009, under OCS-G 00605 and drilled from the South Timbalier Block 86 E-Aux platform).

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 releases) from the proposed activities 

for Well Locations E – G (Well Nos. to be designated as stated at the beginning of this Environmental 

Impact Analysis and ultimately renamed as Well Nos. M001 through M003), 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 

for these Wells 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 response capabilities that would be implemented, no significant 

adverse impacts are expected. The activities proposed in this plan will be covered by ERT’s Regional 

OSRP (refer to information submitted in Section 9). 

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). ERT 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 
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training video annually. Offshore personnel will also receive an explanation from ERT 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

Salt marshes and seagrass beds fringe the coastal areas of the Gulf of Mexico. Due to the distance from 

shore (20 miles), accidents (oil spills) and discarded trash and debris represent IPFs which could 

impact these resources. 

Accidents: Level of impact from an oil spill will depend on oil concentrations contacting vegetation, 

kind of oil spilled, types of vegetation affected, season of the year, pre-existing stress level of the 

vegetation, soil types, and numerous other factors. Light-oiling impacts will cause plant die-back with 

recovery within two growing seasons without artificial replanting. However, it is unlikely that an oil 

spill would occur from the proposed activities (refer to Item 5, Water quality). If a spill were to occur, 

response capabilities as outlined in ERT’s Regional OSRP (refer to information submitted in Section 

9) would be implemented. 

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). ERT 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 ERT 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 wetlands.
Energy Resource Technology GOM, Inc. Page Q-15

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

3. Shore Birds and Coastal Nesting Birds

WMA Wisner (27.5 miles from South Timbalier Block 63 and South Timbalier Block 86) is a highly 

productive habitat for wildlife. Thousands of shore birds use the refuge as a wintering area. Also, 

wading birds nest on the refuge. The WMA provides habitat for colonies of nesting wading birds and 

seabirds as well as wintering shorebirds and waterfowl. The most abundant nesters are brown 

pelicans, laughing gulls, and royal, Caspian, and sandwich terns. IPFs from the proposed activities that 

could cause impacts to shore birds and coastal nesting birds are accidents (oil spills) and discarded 

trash and debris. 

Accidents: Oil spills could cause impacts to shore birds and coastal nesting birds. The birds most 

vulnerable to direct effects of oiling include those species that spend most of their time swimming on 

and under the sea surface, and often aggregate in dense flocks (Piatt et al., 1990; Vauk et al., 1989). 

Coastal birds, including shorebirds, waders, marsh birds, and certain water fowl, may be the hardest hit 

indirectly through destruction of their feeding habitat and/or food source (Hansen, 198l; Vermeer and 

Vermeer, 1975). Direct oiling of coastal birds and certain seabirds is usually minor; many of these 

birds are merely stained as a result of their foraging behaviors. Birds can ingest oil when feeding on 

contaminated food items or drinking contaminated water.

Oil-spill cleanup operations will result in additional disturbance of coastal birds after a spill. 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 being 20 miles, ERT would immediately implement the response 

capabilities outlined in their Regional OSRP (refer to information submitted in Section 9). 

Discarded trash and debris: Shore birds and coastal nesting 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). ERT 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 servicesrelated 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 ERT management or the designated lease operator management that emphasizes their 

commitment to waste management in accordance with NTL No. 2012-G01.
Energy Resource Technology GOM, Inc. Page Q-16

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

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

South Timbalier Block 63 and South Timbalier Block 86 are approximately 27.5 miles from the WMA 

Wisner. Management goals of the WMA are waterfowl habitat management, marsh restoration, 

providing sanctuary for nesting and wintering seabirds, and providing sandy beach habitat for a variety 

of wildlife species. IPFs from the proposed activities that could cause impacts to this coastal wildlife 

refuge are accidents (oil spills) and discarded trash and debris. 

Impacts to shore birds and coastal nesting birds and to the beach, was covered in previous sections. 

Other wildlife species found on the refuges include nutria, rabbits, raccoons, alligators, and loggerhead 

turtles. Impacts to loggerhead turtles were also covered under a previous section.

Accidents: It is unlikely that an oil spill would occur from the proposed activities (refer to Item 5, 

Water quality). Response capabilities would be implemented, no impacts are expected. The activities 

proposed in this plan will be covered by ERT’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). ERT 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 servicesrelated 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 ERT 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.
Energy Resource Technology GOM, Inc. Page Q-17

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

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 (75 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 ERT’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). ERT 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 servicesrelated 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 ERT 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.
Energy Resource Technology GOM, Inc. Page Q-18

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

(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, South Timbalier Block 63 and South Timbalier Block 86 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 / Structure 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. 
Energy Resource Technology GOM, Inc. Page Q-19

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

(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-TMNMFS-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. BLM-YK-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.
Energy Resource Technology GOM, Inc. Page Q-20

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

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. MMS 2000-001 

o GOM Central and Western Planning Areas Sales 166 and 168 Final Environmental Impact 

Statement. MMS 96-0058.
Energy Resource Technology GOM, Inc. Page R-1

Supplemental DOCD November 20, 2013

South Timbalier Blocks 63/86 (OCS-G 00599/00605)

APPENDIX R

ADMINISTRATIVE INFORMATION

(A) EXEMPTED INFORMATION DESCRIPTION

The proposed bottom-hole locations of the planned well(s) 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.

(B) BIBLIOGRAPHY

Not applicable.
Attachment A
U.S. Department of the Interior OMB Control Number: 1010-0151

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

OCS PLAN INFORMATION FORM

General Information

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

Company Name: Energy Resource Technology GOM, Inc. BOEM Operator Number: 02899

Address: 500 Dallas Street, Suite 2000 Contact Person: Cathy Thornton

 Houston, Texas 77002 Phone Number: 713-705-8020

Email Address: cathy.thornton@jccteam.com

If a service fee is required under 30 CFR 550.125(a), provide the Amount paid $29,666.00 Receipt No. 25D7IUEP

Project and Worst Case Discharge (WCD)Information

Lease(s): OCS 00599/00650 Area: ST Block(s): 63/86 Project Name (if applicable): 

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

Platform/Well Name: E-Aux/M Total Volume of WCD: 6705 API Gravity: 37°

Distance to Closest Land (Miles): 19.4 Volume from uncontrolled blowout: 4270

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

D&C Loc A & B; D&TA Loc E 04/01/2014 06/29/2014 90

D&C Loc F; Complete Loc E 03/01/2015 05/11/2015 72

D&C Loc C & D 03/01/2016 04/29/2016 60

D&C Loc G 03/01/2017 04/23/2017 54

Installation or modification of structure 06/01/2015 06/05/2015 5

Installation of production facilities 06/06/2015 09/11/2015 5

Installation of subsea wellheads and/or manifolds

Installation of lease term pipelines 06/20/2015 09/30/2015 10

Commence production 07/01/2014

Other (Specify and attach description)

Description of Drilling Rig Description of Structure

X Jackup Drillship Caisson Tension leg platform

Gorilla Jackup Platform Rig X Fixed platform Compliant tower

Semisubmersible Submersible Spar Guyed tower

DP Semisubmersible Other (attach description) Floating production 

system

Other (Attach Description)

Drilling Rig Name (if known):

Description of Lease Term Pipelines

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

ST86 M platform ST63 A platform 6-inches 10,500’

ST63 A platform ST86 M platform 3-inches 10,500’

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

E006 (Well Location A)

Previously reviewed under an approved EP or 

DOCD?

Yes X No

Is this an existing well or 

structure?

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

Complex ID or API No.

24161-2

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

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid 37°

Surface Location Bottom-Hole Location (For 

Wells)

Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 1967.99’ FNL

E/W Departure: 7795.34’ FEL

Lambert X-Y 

coordinates

X: 2,356,339.92’

Y: 43,813.77’

Latitude / 

Longitude

Latitude: 28°46’56.601”N

Longitude: 90°13’16.225”W

Water Depth (Feet):

98’

Anchor Radius (if applicable) in 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) 

E007 (Well Location B)

Previously reviewed under an approved EP or 

DOCD?

Yes X No

Is this an existing well or 

structure?

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

Complex ID or API No.

24161-2

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

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid 37°

Surface Location Bottom-Hole Location (For 

Wells)

Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 1999.73’ FNL

E/W Departure: 7789.41’ FEL

Lambert X-Y 

coordinates

X: 2,356,338.85’

Y: 43,818.36’

Latitude / 

Longitude

Latitude: 28°46’56.646”N

Longitude: 90°13’16.158”W

Water Depth (Feet):

98’

Anchor Radius (if applicable) in 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) 

E008 (Well Location C)

Previously reviewed under an approved EP or 

DOCD?

Yes X No

Is this an existing well or 

structure?

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

Complex ID or API No.

24161-2

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

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid 37°

Surface Location Bottom-Hole Location (For

Wells)

Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 1964.75’ FNL

E/W Departure: 7778.89’ FEL

Lambert X-Y 

coordinates

X: 2,356,349.37’

Y: 43,817.01’

Latitude / 

Longitude

Latitude: 28°46’56.632”N

Longitude: 90°13’16.04”W

Water Depth (Feet):

98’

Anchor Radius (if applicable) in 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) 

E009 (Well Location D)

Previously reviewed under an approved EP or 

DOCD?

Yes X No

Is this an existing well or 

structure?

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

Complex ID or API No.

24161-2

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

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid 37°

Surface Location Bottom-Hole Location (For 

Wells)

Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 1958.82’ FNL

E/W Departure: 7783.47’ FEL

Lambert X-Y 

coordinates

X: 2,356,344.79’

Y: 43,822.94’

Latitude / 

Longitude

Latitude: 28°46’56.691”N

Longitude: 90°13’16.091”W

Water Depth (Feet):

98’

Anchor Radius (if applicable) in 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)

#025 (Well Location E)

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? Yes X No

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid

37°

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 24’ FNL

E/W Departure: 2798’ FWL

Lambert X-Y 

coordinates

X: 2,352,168.22

Y: 45,757.76

Latitude / 

Longitude

Latitude: 28°47’16.242”N

Longitude: 90°14’02.808”W

Water Depth (Feet):

94’

Anchor Radius (if applicable) in 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=

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

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

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

protect proprietary data according to the Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, 

and a person is not required to respond to, a collection of information unless it displays a currently valid Office of Management and 

Budget Control Number. Responses are mandatory (43 U.S.C. 1334). The public reporting burden for this form is included in the

burden for preparing Exploration Plans and Development Operations Coordination Documents. We estimate that burden to average 

600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, including the time for reviewing 

instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart B. Direct comments 

regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of Ocean 

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

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

#030 (Well Location F)

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? Yes X No

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid

37°

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 24’ FNL

E/W Departure: 2798’ FWL

Lambert X-Y 

coordinates

X: 2,352,168.22

Y: 45,757.76

Latitude / 

Longitude

Latitude: 28°47’16.242”N

Longitude: 90°14’02.808”W

Water Depth (Feet):

94’

Anchor Radius (if applicable) in 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=

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

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

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

protect proprietary data according to the Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, 

and a person is not required to respond to, a collection of information unless it displays a currently valid Office of Management and 

Budget Control Number. Responses are mandatory (43 U.S.C. 1334). The public reporting burden for this form is included in the

burden for preparing Exploration Plans and Development Operations Coordination Documents. We estimate that burden to average 

600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, including the time for reviewing 

instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart B. Direct comments 

regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of Ocean 

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

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

#031 (Well Location G)

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? Yes X No

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid

37°

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 24’ FNL

E/W Departure: 2798’ FWL

Lambert X-Y 

coordinates

X: 2,352,168.22

Y: 45,757.76

Latitude / 

Longitude

Latitude: 28°47’16.242”N

Longitude: 90°14’02.808”W

Water Depth (Feet):

94’

Anchor Radius (if applicable) in 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=

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

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

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

protect proprietary data according to the Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, 

and a person is not required to respond to, a collection of information unless it displays a currently valid Office of Management and 

Budget Control Number. Responses are mandatory (43 U.S.C. 1334). The public reporting burden for this form is included in the

burden for preparing Exploration Plans and Development Operations Coordination Documents. We estimate that burden to average 

600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, including the time for reviewing 

instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart B. Direct comments 

regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of Ocean 

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

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

Platform M

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? Yes X No

WCD info For wells, volume of uncontrolled 

blowout (Bbls/day) 4270

For structures, volume of all storage 

and pipelines (Bbls) 2435

API Gravity of 

fluid

37°

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple 

completions, enter separate lines)

Lease No. OCS 00605

Area Name ST

Block No. 86

Block Line 

Departures 

(in feet)

N/S Departure: 24’ FNL

E/W Departure: 2798’ FWL

Lambert X-Y 

coordinates

X: 2,352,168.22

Y: 45,757.76

Latitude / 

Longitude

Latitude: 28°47’16.242”N

Longitude: 90°14’02.808”W

Water Depth (Feet):

94’

Anchor Radius (if applicable) in feet:

3500’

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=

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

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

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

protect proprietary data according to the Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, 

and a person is not required to respond to, a collection of information unless it displays a currently valid Office of Management and 

Budget Control Number. Responses are mandatory (43 U.S.C. 1334). The public reporting burden for this form is included in the

burden for preparing Exploration Plans and Development Operations Coordination Documents. We estimate that burden to average 

600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, including the time for reviewing 

instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart B. Direct comments 

regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of Ocean 

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

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 2 of 4






Online Payment

Step 3: Confirm Payment 1 | 2 | 3

Thank you.

Your transaction has been successfully completed.

Pay.gov Tracking Information

Application Name: BOEM Development/DOCD Plan - BD

Pay.gov Tracking ID: 25D7IUEP

Agency Tracking ID: 74532354522

Transaction Date and Time: 11/20/2013 13:38 EST

Payment Summary

Address Information

Account Holder 

Name: Melissa Logan 

Billing Address:

500 Dallas 

Street 

Billing Address 2: Suite 2000 

City: Houston 

State / Province: TX 

Zip / Postal Code: 77002 

Country: USA 

Account Information

Card Type: Master Card 

Card 

Number: ************9587 

Region: Gulf of Mexico

Contact:

Cathy Thornton 713-

705-8020

Company 

Name/No:

Energy Resource 

Technology GOM, 

Inc., 02899

Lease 

Number(s): 00599, 00605, , , 

Area-Block:

South Timbalier ST, 

63: , 86: , : , : , 

Type-Wells: Supplemental Plan, 7

Payment Information

Payment Amount: $29,666.00

Transaction Date 

and Time:

11/20/2013 

13:38 EST

Pay.gov - Online Payment Page 1 of 1

https://www.pay.gov/paygov/payments/authorizePlasticCardPayment.html 11/20/2013
Attachment B
Attachment C
 36499 Perkins Road

Prairieville, Louisiana 70769

Telephone: 225.673.2163

Fax: 225.744.3116

www.teslaoffshore.com

November 12, 2013 Job No. 13-017-11

Bureau of Ocean Energy Management (MS 5230)

Gulf of Mexico OCS Region

1201 Elmwood Park Blvd.

New Orleans, LA 70123-2394

RE: Energy Resources Technology GOM, Inc.

Proposed Wells E, F, and G, OCS 00605

Block 86, South Timbalier Area

Shallow Hazards and Archaeological Assessment 

Energy Resources Technology GOM, Inc. (ERT) proposes to drill Wells E, F, and G from 

the following common surface location: 

Datum: 

NAD 27

 Spheroid: 

Clarke 1866

Projection: 

LAMBERT

 Zone:

 LAS

Central Meridian:

 91° 20’ West

 Latitude: 28° 47' 16.242” N Longitude: 90° 14' 02.808” W

 X: 2,352,168.22 Y: 45,757.76

 FNL: 24’ FWL: 2,798’

Tesla Offshore, LLC conducted a high-resolution geophysical survey covering all of Block 

63 and the northern half of Block 86 with 300m extensions run in adjacent blocks to the 

south, east, and west, South Timbalier Area between May 6 and June 3, 2013, using 

300-meter primary grid spacing and 900-meter tie lines. ERT selected Tesla Offshore, 

LLC to prepare this shallow hazard and archaeological assessment for the proposed drill 

site to comply with NTL No. 2008-G05 and NTL No. 2005-G07 from the Bureau of Ocean 

Energy Management (BOEM), Gulf of Mexico Region. Geophysical record copies are 

enclosed for the magnetometer, side scan sonar, subbottom profiler, echo sounder, and 

processed seismic sections from the survey line nearest the proposed common well site 

as required by the BOEM in NTL No. 2008-G04. 

Water depth is slightly less than 94 feet BSL surrounding the proposed surface 

location. Water depths increase to the southeast at an approximate rate of 6.8 feet 

per mile.

Seafloor sediments are reportedly silty clay (USDI MMS Visual No. 3, 1983). 

Seafloor installations located within 1,000 feet of the proposed well site include the 

Block 63 P&A Well No. 17 located approximately 360 feet NE, the 4” ERT pipeline 

(Segment No. 10831) located approximately 360 feet NE at its closest point, the 4” 

and 6” ERT pipeline bundle (Segments No. 9633 and 9632) located approximately 

360 feet NE at its closest point, the 10” Trunkline pipeline (Segment No. 7963) 

located approximately 500 feet east at its closest point, the Block 86 Platform ‘F’

located approximately 835 feet to the SSW, and the 4” and 3” ERT pipeline bundle 

(Segments No. 9385 and 9441) located approximately 835 feet SSW at its closest 

point.
TESLA OFFSHORE

Energy Resources Technology GOM, Inc.

Proposed Wells E, F, and G, OCS 00605

Block 86, South Timbalier Area

Shallow Hazards and Archaeological Assessment 

Page 2

Magnetic anomalies are not located within 1,000 feet of the proposed surface 

location due to the overwhelming magnetic signature of P&A Well No. 17 and its 

associated pipelines. The closest discernable anomaly is no. 23, located 

approximately 1,400 feet to the SE. This anomaly is a 22 nT dipole with a 387 foot 

duration and has been designated for avoidance by 195 feet as a potential hazard 

only. 

Side scan sonar verified that the seafloor immediately surrounding the proposed 

well site was clear of protruding obstructions. No sonar targets were observed within 

1,000 feet of the proposed surface location. The nearest recorded sonar target is 

target no. 12, located approximately 1,025 feet to the west. This target is an irregular

feature measuring approximately 23 feet in length, 5 feet in width with no observed

relief above the surrounding seafloor. This target has been recommended for 

avoidance by 50 feet as a potential hazard only. 

Subbottom data indicates that the seafloor at the proposed well location is 

moderately reflecting, and overlies approximately 16 feet of moderately stratified, 

parallel bedded sediments of low to moderate reflectivity. These stratified sediments 

parallel the seafloor and are underlain by a zone of acoustically amorphous deposits 

approximately 4 feet thick, which in turn overlies an apparent migrating gas front at a 

depth of approximately 23 ft BML; the subbottom signal is completely attenuated 

below the interpreted gas front. Drilling engineers should be aware of the underlying 

gas front and take appropriate precautions to mitigate the risk of fluid expulsion. 

Although near-seabed conditions are not interpreted as problematic based on the 

available data, it is not possible to determine the physical characteristics of the nearseafloor sediments (such as bearing shear strength) from the subbottom data; 

therefore, geotechnical testing would be required to quantify near-seafloor sediment 

properties.

Processed seismic data (3.0 seconds) recorded approximately 2.95 seconds BML

of usable subsurface data except where a salt dome attenuated the data within the 

south-central portion of the grid. The seismic data display a moderately reflecting 

disrupted parallel and subparallel general reflection pattern throughout the entire 

record. Several normal faults were observed throughout the area, the closest of 

which were first observed on the seismic records approximately 3,105 feet to the 

east of the proposed surface location at a depth of 442 ms BSL and 3,685 feet to the 

SSW at a depth of 364 ms BSL. The well path may intersect the fault located to the 

SSW at approximately 1,650 ms BSL, although it is difficult to determine because the 

possible intersection occurs near where the fault becomes attenuated adjacent to the 

salt. The operator will carefully assess their 3D data in the area surrounding the salt 

to assure adequate precautions are taken if the fault is intersected. Amplitude 

anomalies were observed throughout the survey area, the closest of which was

observed approximately 935 feet to the east of the proposed surface location at a 

depth of 885 ms BSL.
TESLA OFFSHORE

Energy Resources Technology GOM, Inc.

Proposed Wells E, F, and G, OCS 00605

Block 86, South Timbalier Area

Shallow Hazards and Archaeological Assessment

Page 3

The operator has identified the primary hazards to rig movements, any ancillary anchor 

and/or mooring deployments, and drilling. The proposed surface location will be marked 

with DGPS during rig moves and drilling to comply with the BOEM On-Site 

Requirements specified in NTL No. 2008-G05, Section VI, Item B-2(a).

No sonar targets, magnetic anomalies, or other features on the geophysical data were 

recorded which were interpreted as possible shipwrecks, or possible high probability 

areas for prehistoric habitation within 1,000 feet of the proposed well location. Pursuant 

to 30 CFR 550.194 (c), 30 CFR 550.101 (c), and NTL No. 2005-G07, if any 

archaeological or potentially historically significant materials are observed during lease 

development, operations will immediately cease in that area and appropriate 

BOEM/BSEE personnel will be notified within 48 hours of discovery. 

ERT and subcontractors will apply the safest and best available technologies during rig 

moves and drilling operations.

Sincerely,

John Allen Amanda Evans, PhD, RPA

Marine Geologist Senior Marine Archaeologist
Attachment H
DOCD AIR QUALITY SCREENING CHECKLIST 

OM

COMPANY Energy Resource Technology GOM, Inc.AREA South TimbalierBLOCK 86LEASE OCS 00605PLATFORM E/E-Aux and MWELL Well Locations A-GCOMPANY CONTACT Cathy ThorntonTELEPHONE NO. 713 705 8020REMARKSLEASE TERM PIPELINE CONSTRUCTION INFORMATION:

YEAR NUMBER OF TOTAL NUMBER OF CONSTRUCTION DAYS

PIPELINES

20132014 2 10201520162017201820192020

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

Energy Resource Techno South Timbalier 86 OCS 00605 E/E-Aux and M Well Locations A-G Cathy Thornton 713 705 8020 #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 16975 819.8925 19677.42 24 90 11.96 54.89 411.29 12.34 89.74 12.92 

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) 2065 99.7395 2393.75 8 90 1.46 6.68 50.03 1.50 10.92 0.52 VESSELS>600hp diesel(supply) 2065 99.7395 2393.75 10 39 1.46 6.68 50.03 1.50 10.92 0.28 VESSELS>600hp diesel(tugs) 12600 608.58 14605.92 24 2 8.88 40.74 305.29 9.16 66.61 0.21 

PIPELINE PIPELINE LAY 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 

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 crane PF E 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

PF E/E-Aux RECIP.<600hp diesel crane PFE-Aux 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 SUPPORT VESSEL diesel shared 2065 99.7395 2393.75 8 156 1.46 6.68 50.03 1.50 10.92 0.91 

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 PF E-Aux 1000 7143 171432.00 24 365 0.00 22.03 0.31 18.94 

BURNER nat gas PF E 2.5 2380.95 57142.86 24 84 0.02 0.00 0.24 0.01 0.20 0.02 

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- 1250.0 365 0.63 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 25.89 116.64 898.19 27.69 210.24 14.91 

EXEMPTION 

CALCULATION DISTANCE FROM LAND IN MILES 646.02 

19.4

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

Energy Resource Techno South Timbalier 86 OCS 00605 E/E-Aux and M Well Locations A-G Cathy Thornton 713 705 8020 #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 16975 819.8925 19677.42 24 72 11.96 54.89 411.29 12.34 89.74 10.34 

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) 2065 99.7395 2393.75 8 72 1.46 6.68 50.03 1.50 10.92 0.42 VESSELS>600hp diesel(supply) 2065 99.7395 2393.75 10 31 1.46 6.68 50.03 1.50 10.92 0.22 VESSELS>600hp diesel(tugs) 12600 608.58 14605.92 24 2 8.88 40.74 305.29 9.16 66.61 0.21 

PIPELINE PIPELINE LAY BARGE diesel 1500 72.45 1738.80 24 10 1.06 4.85 36.34 1.09 7.93 0.13 INSTALLATION MATERIAL TUG diesel 4200 202.86 4868.64 24 10 2.96 13.58 101.76 3.05 22.20 0.36 

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) 2065 99.7395 2393.75 10 2 1.46 6.68 50.03 1.50 10.92 0.01 

FACILITY DERRICK BARGE diesel 2500 120.75 2898.00 24 10 1.76 8.08 60.57 1.82 13.22 0.21 INSTALLATION MATERIAL TUG diesel 4200 202.86 4868.64 24 10 2.96 13.58 101.76 3.05 22.20 0.36 

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) 2065 99.7395 2393.75 10 2 1.46 6.68 50.03 1.50 10.92 0.01 

PRODUCTION RECIP.<600hp diesel crane PF E 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

PF E/E-Aux & M RECIP.<600hp diesel crane PFE-Aux 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

RECIP.<600hp diesel crane PF M 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 SUPPORT VESSEL diesel shared 2065 99.7395 2393.75 8 156 1.46 6.68 50.03 1.50 10.92 0.91 

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 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 PF E-Aux 1000 7143 171432.00 24 365 0.00 22.03 0.31 18.94 

BURNER nat gas PF E 2.5 2380.95 57142.86 24 84 0.02 0.00 0.24 0.01 0.20 0.02 

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- 1875.0 365 0.94 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 

2015 YEAR TOTAL 37.87 170.57 1303.32 40.38 298.62 13.26 

EXEMPTION 

CALCULATION DISTANCE FROM LAND IN MILES 646.02 

19.4

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

Energy Resource Techno South Timbalier 86 OCS 00605 E/E-Aux and M Well Locations A-G Cathy Thornton 713 705 8020 #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 16975 819.8925 19677.42 24 72 11.96 54.89 411.29 12.34 89.74 10.34 

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) 2065 99.7395 2393.75 8 72 1.46 6.68 50.03 1.50 10.92 0.42 VESSELS>600hp diesel(supply) 2065 99.7395 2393.75 10 31 1.46 6.68 50.03 1.50 10.92 0.22 VESSELS>600hp diesel(tugs) 12600 608.58 14605.92 24 2 8.88 40.74 305.29 9.16 66.61 0.21 

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 crane PF E 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

PF E/E-Aux & M RECIP.<600hp diesel crane PFE-Aux 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

RECIP.<600hp diesel crane PF M 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 SUPPORT VESSEL diesel shared 2065 99.7395 2393.75 8 156 1.46 6.68 50.03 1.50 10.92 0.91 

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 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 PF E-Aux 1000 7143 171432.00 24 365 0.00 22.03 0.31 18.94 

BURNER nat gas PF E 2.5 2380.95 57142.86 24 84 0.02 0.00 0.24 0.01 0.20 0.02 

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- 1875.0 0 0.94 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 

2016 YEAR TOTAL 26.22 117.12 902.82 28.37 211.24 12.18 

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 5 of 8
AIR EMISSIONS CALCULATIONS - FOURTH YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

Energy Resource Techno South Timbalier 86 OCS 00605 E/E-Aux and M Well Locations A-G Cathy Thornton 713 705 8020 #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 16975 819.8925 19677.42 24 54 11.96 54.89 411.29 12.34 89.74 7.75 

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) 2065 99.7395 2393.75 8 54 1.46 6.68 50.03 1.50 10.92 0.31 VESSELS>600hp diesel(supply) 2065 99.7395 2393.75 10 23 1.46 6.68 50.03 1.50 10.92 0.17 VESSELS>600hp diesel(tugs) 12600 608.58 14605.92 24 2 8.88 40.74 305.29 9.16 66.61 0.21 

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 crane PF E 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

PF E/E-Aux & M RECIP.<600hp diesel crane PFE-Aux 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

RECIP.<600hp diesel crane PF M 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 SUPPORT VESSEL diesel shared 2065 99.7395 2393.75 8 156 1.46 6.68 50.03 1.50 10.92 0.91 

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 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 PF E-Aux 1000 7143 171432.00 24 365 0.00 22.03 0.31 18.94 

BURNER nat gas PF E 2.5 2380.95 57142.86 24 84 0.02 0.00 0.24 0.01 0.20 0.02 

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- 1875.0 0 0.94 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 YEAR TOTAL 26.22 117.12 902.82 28.37 211.24 9.44 

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 - FIFTH YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

Energy Resource Techno South Timbalier 86 OCS 00605 E/E-Aux and M Well Locations A-G Cathy Thornton 713 705 8020 #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 crane PF E 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

PF E/E-Aux & M RECIP.<600hp diesel crane PFE-Aux 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 

RECIP.<600hp diesel crane PF M 150 7.245 173.88 2 60 0.33 0.49 4.63 0.37 1.00 0.02 SUPPORT VESSEL diesel shared 2065 99.7395 2393.75 8 156 1.46 6.68 50.03 1.50 10.92 0.91 

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 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 PF E-Aux 1000 7143 171432.00 24 365 0.00 22.03 0.31 18.94 

BURNER nat gas PF E 2.5 2380.95 57142.86 24 84 0.02 0.00 0.24 0.01 0.20 0.02 

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- 1875.0 0 0.94 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 

2018 YEAR TOTAL 2.46 8.14 86.17 3.87 33.06 0.99 

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 7 of 8
AIR EMISSIONS CALCULATIONS

COMPANY AREA BLOCK LEASE PLATFORM WELLEnergy ResourceSouth Timbalier 86 OCS 00605 E/E-Aux and M Well Lo

Emitted Substance

Year

 PM SOx NOx VOC 

2014 14.91 68.20 607.76 19.46 2015 13.26 60.58 550.72 19.13 2016 12.18 55.64 513.66 13.91 2017 9.44 43.04 419.29 11.08 2018 0.99 4.28 128.85 2.37 2019 0.99 4.28 128.85 2.37 2020 0.99 4.28 128.85 2.37 2021 0.99 4.28 128.85 2.37 2022 0.99 4.28 128.85 2.37 2023 0.99 4.28 128.85 2.37 

Allowable 646.02 646.02 646.02 646.02 24

FORM BOEM-0139 (December 2011 - Supersedes all previous versions of this form which may not be used). Page 8 o
Attachment N

Attachment P