UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field 

Operations (MS 5231)

Public Information copy of Exploration Plan

Control # - N-09849

Type - Initial Exploration Plan

Lease(s) - OCS-G35431 Block - 198 Atwater Valley Area

Operator - Freeport-McMoRan Oil & Gas LLC

Subsea wells A, B, C, D, E (AT198)

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.

Tommy Hoke

Plan Coordinator

Description -

Rig Type -

Subject:

From:

December 30, 2014
PUBLIC COPY

December 4, 2014

INITIAL

EXPLORATION PLAN

Atwater Valley Block 198

OCS-G 35431

Prospect Name: Sun

Affected States: Louisiana and Mississippi

Estimated Startup Date: February 26, 2018

SUBMITTED BY:

Freeport-McMoRan Oil & Gas LLC

400 E. Kaliste Saloom, Suite 1100

Lafayette, Louisiana 70508

Paul Landry

Office: 337-354-5065, Cell: 337-349-7781

paul_landry@fmi.com

AUTHORIZED REPRESENTATIVE:

Callie Hutchinson

J. Connor Consulting, Inc.

16225 Park Ten Place, Suite 700

Houston, Texas 77084

(281) 698-8545

callie.hutchinson@jccteam.com
TOC Pg 1 of 3

TABLE OF CONTENTS

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

1.1 PLAN INFORMATION ...................................................................................................... 1

1.2 LOCATION....................................................................................................................... 1

1.3 SAFETY AND POLLUTION PREVENTION FEATURES .................................................. 1

1.4 STORAGE TANKS AND PRODUCTION VESSELS......................................................... 1

1.5 POLLUTION PREVENTION MEASURES ........................................................................ 2

1.6 ADDITIONAL MEASURES ............................................................................................... 2

1.7 COST RECOVERY FEE................................................................................................... 2

SECTION 2 GENERAL INFORMATION....................................................................................3

2.1 APPLICATIONS AND PERMITS ...................................................................................... 3

2.2 DRILLING FLUIDS ........................................................................................................... 3

2.3 NEW OR UNUSUAL TECHNOLOGY............................................................................... 3

2.4 BONDING STATEMENT .................................................................................................. 3

2.5 OIL SPILL FINANCIAL RESPONSIBILITY (OSFR) .......................................................... 3

2.6 DEEPWATER WELL CONTROL STATEMENT................................................................ 3

2.7 BLOWOUT SCENARIO AND WORST CASE DISCHARGE CALCULATIONS................. 4

SECTION 3 GEOLOGICAL AND GEOPHYSICAL INFORMATION ..........................................7

3.1 GEOLOGICAL DESCRIPTION......................................................................................... 7

3.2 STRUCTURE CONTOUR MAPS...................................................................................... 7

3.3 INTERPRETED SEISMIC LINES ..................................................................................... 7

3.4 GEOLOGICAL STRUCTURE CROSS-SECTIONS .......................................................... 7

3.5 SHALLOW HAZARDS REPORT ...................................................................................... 7

3.6 SHALLOW HAZARDS ASSESSMENT............................................................................. 7

3.7 HIGH-RESOLUTION SEISMIC LINES ............................................................................. 7

3.8 STRATIGRAPHIC COLUMN ............................................................................................ 7

3.9 TIME VERSUS DEPTH TABLES...................................................................................... 7

SECTION 4 HYDROGEN SULFIDE INFORMATION ................................................................8

4.1 CONCENTRATION .......................................................................................................... 8

4.2 CLASSIFICATION............................................................................................................ 8

SECTION 5 BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION...................9
TOC Pg 2 of 3

5.1 DEEPWATER BENTHIC COMMUNITIES ........................................................................ 9

5.2 TOPOGRAPHIC FEATURES (BANKS)............................................................................ 9

5.3 TOPOGRAPHIC FEATURES STATEMENT (SHUNTING) ............................................... 9

5.4 LIVE BOTTOMS (PINNACLE TREND FEATURES) ......................................................... 9

5.5 LIVE BOTTOMS (LOW RELIEF) ...................................................................................... 9

5.6 POTENTIALLY SENSITIVE BIOLOGICAL FEATURES MAP........................................... 9

5.7 REMOTELY OPERATED VEHICLE (ROV) SURVEYS .................................................... 9

5.8 THREATENED AND ENDANGERED SPECIES, CRITICAL HABITAT, AND MARINE 

MAMMAL INFORMATION ..............................................................................................10

5.9 ARCHAEOLOGICAL REPORT........................................................................................11

5.10 AIR AND WATER QUALITY INFORMATION ................................................................11

SECTION 6 WASTES AND DISCHARGES INFORMATION...................................................12

6.1 PROJECTED GENERATED WASTES............................................................................12

6.2 MODELING REPORT......................................................................................................12

SECTION 7 AIR EMISSIONS INFORMATION ........................................................................13

7.1 EMISSIONS WORKSHEETS AND SCREENING QUESTIONS ......................................13

7.2 SUMMARY INFORMATION ............................................................................................13

SECTION 8 OIL SPILL INFORMATION ..................................................................................14

8.1 OIL SPILL RESPONSE PLANNING ................................................................................14

8.2 SPILL RESPONSE SITES...............................................................................................14

8.3 OSRO INFORMATION....................................................................................................14

8.4 WORST CASE SCENARIO DETERMINATION...............................................................14

8.5 OIL SPILL RESPONSE DISCUSSION ............................................................................15

8.6 MODELING REPORT......................................................................................................15

SECTION 9 ENVIRONMENTAL MONITORING INFORMATION ............................................16

9.1 MONITORING SYSTEMS ...............................................................................................16

9.2 INCIDENTAL TAKES.......................................................................................................16

9.3 FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY....................................16

SECTION 10 LEASE STIPULATIONS INFORMATION ..........................................................17

10.1 MARINE PROTECTED SPECIES .................................................................................17

SECTION 11 ENVIRONMENTAL MITIGATION MEASURES INFORMATION .......................19

11.1 MEASURES TAKEN TO AVOID, MINIMIZE, AND MITIGATE IMPACTS ......................19

11.2 INCIDENTAL TAKES.....................................................................................................19
TOC Pg 3 of 3

SECTION 12 SUPPORT VESSELS AND AIRCRAFT INFORMATION ...................................20

12.1 GENERAL .....................................................................................................................20

2.2 DIESEL OIL SUPPLY VESSELS.....................................................................................20

12.3 DRILLING FLUID TRANSPORTATION .........................................................................20

12.4 SOLID AND LIQUID WASTE TRANSPORTATION .......................................................20

12.5 VICINITY MAP...............................................................................................................20

SECTION 13 ONSHORE SUPPORT FACILITIES INFORMATION.........................................21

13.1 GENERAL .....................................................................................................................21

13.2 SUPPORT BASE CONSTRUCTION OR EXPANSION .................................................21

13.3 SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE.............................21

13.4 WASTE DISPOSAL.......................................................................................................21

SECTION 14 COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION.....................22

SECTION 15 ENVIRONMENTAL IMPACT ANALYSIS...........................................................25

SECTION 16 ADMINISTRATIVE INFORMATION ...................................................................26

16.1 EXEMPTED INFORMATION DESCRIPTION................................................................26

16.2 BIBLIOGRAPHY............................................................................................................26
Attachments Pg 1 of 1

SECTION ATTACHMENTS

Section 1 Plan Contents

1-A OCS Plan Information Form

1-B Well Location Plat

1-C Bathymetry Map

1-D Pay.gov Receipt

Section 3 Geological, Geophysical Information

3-A Shallow Hazard Assessment

Section 5 Biological, Physical and Socioeconomic Information

5-A Biologically Sensitive Underwater Features and Areas Map

Section 6 Wastes and Discharges Information

6-A Wastes You Will Generate, Treat and Downhole Dispose or Discharge to 

the GOM 

Section 7 Air Emissions Information

7-A Emissions Worksheets

Section 8 Oil Spill Information

8-A Oil Spill Response Discussion

Section 12 Support Vessels and Aircraft Information

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

12-B Vicinity Map

Section 14 Coastal Zone Management Act Information

14-A Coastal Zone Consistency Certifications, Louisiana

14-B Coastal Zone Consistency Certifications, Mississippi

Section 15 Environmental Impact Analysis (EIA)

15-A Environmental Impact Analysis (EIA)
Freeport-McMoRan Oil & Gas LLC Section 1 – Pg. 1 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 1

PLAN CONTENTS

1.1 PLAN INFORMATION

Under this Exploration Plan, Freeport-McMoRan Oil & Gas LLC (FM O&G) proposes to drill, 

complete, test, flare and install subsea trees on five wells. The wells will be drilled with a 

dynamically positioned drillship MODU similar to the Transocean Deepwater Champion, and are 

located in approximately 4,855 feet of water.

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

1.2 LOCATION

A Well Location Plat depicting the proposed surface and bottomhole locations of the proposed 

wells, measured depth/true vertical depth and water depth for each location is included as 

Attachment 1-B.

A Bathymetry Map depicting the proposed surface locations and water depth of each proposed 

well is included as Attachment 1-C.

No anchors are associated with the proposed activities in this plan.

1.3 SAFETY AND POLLUTION PREVENTION FEATURES

FM O&G proposes to drill the wells with a dynamically positioned drillship which is equipped 

with a Subsea BOP. Once a rig is determined, BOP information and schematics will be 

included as a part of the Application for Permit to Drill.

The rig will be equipped with safety and fire-fighting equipment required to comply with United 

States Coast Guard (USCG) regulations. Appropriate life saving equipment such as life rafts, life 

jackets, ring buoys, etc. as prescribed by the USCG, will be maintained on the rig at all times. 

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

prevention equipment as described in BSEE regulations 30 CFR 250 C, D, E, O, Q and S; and 

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

BSEE, Environmental Protection Agency and the U.S. Coast Guard (USCG). 

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

drilling deck areas to collect all contaminants and debris. Compliance will be maintained with the 

EPA NPDES Permit. The rig will be monitored daily and any waste or fuel resulting in pollution 

of the Gulf waters will be reported to the representative in charge for immediate isolation and 

correction of the problem. Any spill will be reported to the appropriate governmental agencies. 

1.4 STORAGE TANKS AND PRODUCTION VESSELS

The table below provides storage tanks with capacity of 25 barrels or more that will store fuels, 

oil and lubricants.
Freeport-McMoRan Oil & Gas LLC Section 1 – Pg. 2 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

Type of

Storage Tank

Type of

Facility

Tank

Capacity 

(bbl)

Number

of Tanks

Total 

Capacity 

(bbl)

Fluid 

Gravity

(API)

Fuel Oil DPDS 4,135.6 2 8,271.2 33 ̊

Fuel Oil DPDS 9,340.4 2 18,680.8 33 ̊

Fuel Oil DPDS 9,048.5 1 9,048.5 33 ̊

Fuel Oil DPDS 9,043.5 1 9,043.5 33 ̊

Fuel Oil DPDS 445.3 2 830.6 33 ̊

Fuel Oil DPDS 320.2 2 640.3 33 ̊

Fuel Oil DPDS 359.8 1 359.8 33 ̊

Fuel Oil DPDS 435.3 1 435.3 33 ̊

Fuel Oil DPDS 59.8 1 59.8 33 ̊

Base Oil DPDS 3,683.9 1 3,683.9 31 ̊

Base Oil DPDS 3,687.1 1 3,687.1 31 ̊

Lube Oil DPDS 429.6 1 429.6 22.3o

Waste Oil DPDS 132.1 1 132.1 20o

Waste Oil DPDS 44 1 44 20o

Waste Oil DPDS 143.4 1 143.4 20o

Waste Oil DPDS 1,366.2 1 1,366.2 6.5o

1.5 POLLUTION PREVENTION MEASURES

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

1.6 ADDITIONAL MEASURES

FM O&G does not propose any additional safety, pollution prevention, or early spill detection 

measures beyond those required by 30 CFR 250.

1.7 COST RECOVERY FEE

Documentation of the $18,365.00 cost recovery fee payment is included as Attachment 1-D.
U.S. Department of the Interior

Bureau of Ocean Energy Management 

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

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

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

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

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

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

Proposed Activity Start Date End Date No. of Days

Drill, complete, test, flare Well Location A, install subsea trees 02/26/2018 08/12/2018 167

Drill, complete, test, flare Well Location B, install subsea trees 08/13/2018 01/29/2019 169

Drill, complete, test, flare Well Location C, install subsea trees 01/30/2019 07/13/2019 166

Drill, complete, test, flare Well Location D, install subsea trees 07/14/2019 12/31/2019 170

Drill, complete, test, flare Well Location E, install subsea trees 01/01/2020 06/19/2020 170

Description of Drilling Rig Description of Structure

Jackup X Drillship Caisson Tension leg platform

Gorilla Jackup Platform rig 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): Similar to Transocean Deepwater Champion

Description of Lease Term Pipelines

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

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

General Information

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

Company Name: Freeport-McMoRan Oil & Gas LLC BOEM Operator Number: 03280

Address: 400 E. Kaliste Saloom, Suite 1100

Lafayette, LA 70508 Contact Person: Paul Landry

Phone Number: (Office) 337-354-5065, (mobile) 337-349-7781

E-Mail Address: paul_landry@fmi.com

If a service fee is required under 30 CFR 550.125(a), provide the Amount paid $18,365.00 Receipt No. 25INIVIU

Project and Worst Case Discharge (WCD) Information

Lease: OCS-G 35431 Area: Atwater Valley Block: 198 Project Name (If Applicable): Sun

Objective(s) x Oil Gas Sulphur Salt Onshore Support Base(s): Fourchon, LA; Houma, LA

Platform / Well Name: E Total Volume of WCD: 196,060 bbl API Gravity: 27.1°

Distance to Closest Land (Miles): 87.0 miles Volume from uncontrolled blowout: 25,487,800 bbl

OCS PLAN INFORMATION FORM

OMB Control Number: 1010-0151

OMB Approval Expires: 12/31/14

ATTACHMENT 1-A
OCS PLAN INFORMATION FORM (CONTINUED)

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

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or 

structure, reference previous name): A

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. N/A

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

WCD Info For wells, volume of uncontrolled 

blowout (Bbls/Day): 196,060

For structures, volume of all storage and pipelines 

(Bbls): N/A

API Gravity of fluid 27.1°

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

separate lines)

Lease No. OCS-G-35431 OCS

OCS

Area Name Atwater Valley

Block No. 198

Blockline 

Departures 

(in feet)

N/S Departure 3,262' FNL N/S Departure 

N/S Departure F __ L

N/S Departure F __ L

N/S Departure F __ L

E/W Departure 3,578' FWL E/W Departure 

E/W Departure F __ L

E/W Departure F __ L

E/W Departure F __ L

Lambert X-Y 

coordinates

X: 1,033,178.00' X:

X:

X:

X:

Y: 10,086,818.00' Y: 

Y:

Y:

Y:

Latitude/

Longitude

Latitude: 27°47’00.745”N Latitude: 

Latitude

Latitude

Latitude

Longitude: 88°52’42.516”W Longitude: 

Longitude

Longitude

Longitude

Water Depth (Feet): 4,806’ MD (Feet): TVD (Feet): MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet): 

TVD (Feet): 

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

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y Coordinate Length of Anchor Chain on Seafloor

N/A X: Y:

X: Y:

X: Y:

X: Y:

X: Y:

X: Y:

X: Y:

X: Y:

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

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

Proposed Well/Structure Location

Well or Structure Name/Number (If renaming well or 

structure, reference previous name): B

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. N/A

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

WCD Info For wells, volume of uncontrolled 

blowout (Bbls/Day): 196,060

For structures, volume of all storage and pipelines 

(Bbls): N/A API Gravity of fluid 27.1°

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

separate lines)

Lease No. OCS-G-35431 OCS

OCS

Area Name Atwater Valley

Block No. 198

Blockline 

Departures 

(in feet)

N/S Departure 7,007' FNL N/S Departure 

N/S Departure F __ L

N/S Departure F __ L

N/S Departure F __ L

E/W Departure 6,964' FWL E/W Departure 

E/W Departure F __ L

E/W Departure F __ L

E/W Departure F __ L

Lambert X-Y 

coordinates

X: 1,036,564.00' X: 

X:

X:

X:

Y: 10,083,073.00' Y:

Y:

Y:

Y:

Latitude/

Longitude

Latitude: 27°46’24.177”N Latitude: 

Latitude

Latitude

Latitude

Longitude: 88°52’04.191”W Longitude: 

Longitude

Longitude

Longitude

Water Depth (Feet): 4,870’ MD (Feet): TVD (Feet): MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet): 

TVD (Feet): 

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

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y Coordinate Length of Anchor Chain on Seafloor

N/A 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): C

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. N/A

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

WCD Info For wells, volume of uncontrolled 

blowout (Bbls/Day): 196,060

For structures, volume of all storage and pipelines 

(Bbls): N/A API Gravity of fluid 27.1°

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

separate lines)

Lease No. OCS-G-35431 OCS

OCS

Area Name Atwater Valley

Block No. 198

Blockline 

Departures 

(in feet)

N/S Departure 5,711' FSL N/S Departure 

N/S Departure F __ L

N/S Departure F __ L

N/S Departure F __ L

E/W Departure 6,676' FWL E/W Departure 

E/W Departure F __ L

E/W Departure F __ L

E/W Departure F __ L

Lambert X-Y 

coordinates

X: 1,036,276.00' X: 

X:

X:

X:

Y: 10,079,951.00' Y:

Y:

Y:

Y:

Latitude/

Longitude

Latitude: 27°45’53.223”N Latitude: 

Latitude

Latitude

Latitude

Longitude: 88°52’06.868”W Longitude: 

Longitude

Longitude

Longitude

Water Depth (Feet): 4,906’ MD (Feet): TVD (Feet): MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet): 

TVD (Feet): 

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

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y Coordinate Length of Anchor Chain on Seafloor

N/A 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): D

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. N/A

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

WCD Info For wells, volume of uncontrolled 

blowout (Bbls/Day): 196,060

For structures, volume of all storage and pipelines 

(Bbls): N/A API Gravity of fluid 27.1°

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

separate lines)

Lease No. OCS-G-35431 OCS

OCS

Area Name Atwater Valley

Block No. 198

Blockline 

Departures 

(in feet)

N/S Departure 4,958' FNL N/S Departure 

N/S Departure F __ L

N/S Departure F __ L

N/S Departure F __ L

E/W Departure 5,058' FWL E/W Departure 

E/W Departure F __ L

E/W Departure F __ L

E/W Departure F __ L

Lambert X-Y 

coordinates

X: 1,034,658.00' X: 

X:

X:

X:

Y: 10,085,122.00' Y: 

Y:

Y:

Y:

Latitude/

Longitude

Latitude: 27°46’44.177”N Latitude: 

Latitude

Latitude

Latitude

Longitude: 88°52’25.753”W Longitude: 

Longitude

Longitude

Longitude

Water Depth (Feet): 4,835’ MD (Feet): TVD (Feet): MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet): 

TVD (Feet): 

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

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y Coordinate Length of Anchor Chain on Seafloor

N/A 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): 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. N/A

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

WCD Info For wells, volume of uncontrolled 

blowout (Bbls/Day): 196,060

For structures, volume of all storage and pipelines 

(Bbls): N/A API Gravity of fluid 27.1°

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

separate lines)

Lease No. OCS-G-35431 OCS

OCS

Area Name Atwater Valley

Block No. 198

Blockline 

Departures 

(in feet)

N/S Departure 5,423' FNL N/S Departure 

N/S Departure F __ L

N/S Departure F __ L

N/S Departure F __ L

E/W Departure 7,310' FWL E/W Departure 

E/W Departure F __ L

E/W Departure F __ L

E/W Departure F __ L

Lambert X-Y 

coordinates

X: 1,036,910.00' X: 

X:

X:

X:

Y: 10,084,657.00' Y:

Y:

Y:

Y:

Latitude/

Longitude

Latitude: 27°46’39.912”N Latitude: 

Latitude

Latitude

Latitude

Longitude: 88°52’00.607”W Longitude: 

Longitude

Longitude

Longitude

Water Depth (Feet): 4,860’ MD (Feet): TVD (Feet): MD (Feet):

MD (Feet):

MD (Feet):

TVD (Feet): 

TVD (Feet): 

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

Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y Coordinate Length of Anchor Chain on Seafloor

N/A 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-G-35431 FM O&G AT242

AT197AT198

AT199 

SHEET 1 of 1 INITIAL EXPLORATION PLAN OCS-G-35431 BLOCK 198, ATWATER VALLEY AREA PROPOSED SURFACE LOCATIONS BLOCK WELL CALLS X COORDINATE Y COORDINATE LATITUDE LONGITUDE AT198 "A" 3,262' FNL 3,578' FWL 1,033,178.00' 10,086,818.00' 
1 
: JOB No: REVISED: DATE: FILENAME: 140712 Oct. 24, 2014 PREPARED BY: 730 E. KALISTE SALOOM RD. LAFAYETTE, LA 70508 (337) 210-0000 LA Reg. No. 330 2000 0 2000 SCALE IN US SURVEY FEET 

WATER DEPTH 4,806'
OCS-G-35431 FM O&G AT242

AT197 AT198

AT199 

SHEET 1 of 1 INITIAL EXPLORATION PLAN OCS-G-35431 BLOCK 198, ATWATER VALLEY AREA PROPOSED SURFACE LOCATIONS BLOCK WELL CALLS X COORDINATE Y COORDINATE LATITUDE LONGITUDE AT198 "B" 7,007' FNL 6,964' FWL 1,036,564.00' 10,083,073.00' 
1 
: JOB No: REVISED: DATE: FILENAME: 140712 Oct. 24, 2014 PREPARED BY: 730 E. KALISTE SALOOM RD. LAFAYETTE, LA 70508 (337) 210-0000 LA Reg. No. 330 2000 0 2000 SCALE IN US SURVEY FEET Well "B" OCS-G-35431 

WATER DEPTH 4,870'
OCS-G-35431 FM O&G AT242

AT197 AT198

AT199 

SHEET 1 of 1 INITIAL EXPLORATION PLAN OCS-G-35431 BLOCK 198, ATWATER VALLEY AREA PROPOSED SURFACE LOCATIONS BLOCK WELL CALLS X COORDINATE Y COORDINATE LATITUDE LONGITUDE AT198 "C" 5,711' FSL 6,676' FWL 1,036,276.00' 10,079,951.00' 
1 
: JOB No: REVISED: DATE: FILENAME: 140712 Oct. 24, 2014 PREPARED BY: 730 E. KALISTE SALOOM RD. LAFAYETTE, LA 70508 (337) 210-0000 LA Reg. No. 330 2000 0 2000 SCALE IN US SURVEY FEET Well "C" OCS-G-35431 

WATER DEPTH 4,906'
OCS-G-35431 FM O&G AT242

AT197 AT198

AT199 

SHEET 1 of 1 INITIAL EXPLORATION PLAN OCS-G-35431 BLOCK 198, ATWATER VALLEY AREA PROPOSED SURFACE LOCATIONS BLOCK WELL CALLS X COORDINATE Y COORDINATE LATITUDE LONGITUDE AT198 "D" 4,958' FNL 5,058' FWL 1,034,658.00' 10,085,122.00' 
1 
: JOB No: REVISED: DATE: FILENAME: 140712 Oct. 24, 2014 PREPARED BY: 730 E. KALISTE SALOOM RD. LAFAYETTE, LA 70508 (337) 210-0000 LA Reg. No. 330 2000 0 2000 SCALE IN US SURVEY FEET Well "D" OCS-G-35431 

WATER DEPTH 4,835'
OCS-G-35431 FM O&G AT242

AT197AT198

AT199 

SHEET 1 of 1 INITIAL EXPLORATION PLAN OCS-G-35431 BLOCK 198, ATWATER VALLEY AREA PROPOSED SURFACE LOCATIONS BLOCK WELL CALLS X COORDINATE Y COORDINATE LATITUDE LONGITUDE AT198 "E" 5,423' FNL 7,310' FWL 1,036,910.00' 10,084,657.00' 
1 
: JOB No: REVISED: DATE: FILENAME: 140712 Nov. 18, 2014 PREPARED BY: 730 E. KALISTE SALOOM RD. LAFAYETTE, LA 70508 (337) 210-0000 LA Reg. No. 330 2000 0 2000 SCALE IN US SURVEY FEET 

WATER DEPTH 4,860' Well "E" OCS-G-35431
AT198

OCS-G-35431

FM O&G

X= 1,033,178.00'

Y= 10,086,818.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "A" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)

ATTACHMENT 1-C
AT198

OCS-G-35431

FM O&G

X= 1,036,564.00'

Y= 10,083,073.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "B" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
AT198

OCS-G-35431

FM O&G

X= 1,036,276.00'

Y= 10,079,951.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "C" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
AT198

OCS-G-35431

FM O&G

X= 1,034,658.00'

Y= 10,085,122.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "D" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
AT198

OCS-G-35431

FM O&G

X= 1,036,910.00'

Y= 10,084,657.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "E" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
1

Favaloro, Katharine

From: pay.gov.clev@clev.frb.org

Sent: Wednesday, December 03, 2014 3:44 PM

To: Favaloro, Katharine

Subject: Pay.gov Payment Confirmation: BOEM Exploration Plan - BF

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

payment, please contact Brenda Dickerson at (703) 787-1617 or by email at BseeAccountsReceivable@bsee.gov. 

 Application Name: BOEM Exploration Plan - BF 

 Pay.gov Tracking ID: 25INIVIU 

 Agency Tracking ID: 74716976793 

 Transaction Type: Sale 

 Transaction Date: 12/03/2014 04:43:55 PM EST 

 

 Account Holder Name: Douglas Begley 

 Transaction Amount: $18,365.00 

 Billing Address: 700 Milam, Suite 3100 

 Billing Address 2: 

 City: Houston 

 State/Province: TX 

 Zip/Postal Code: 77002 

 Country: USA 

 Card Type: MasterCard 

 Card Number: ************7057 

 Region: Gulf of Mexico 

 Contact: Paul Landry 337-354-5065 

 Company Name/No: Freeport-McMoRan Oil Gas LLC, 03280 

 Lease Number(s): 35431, , , , 

 Area-Block: Atwater Valley AT, 198: , : , : , : , 

 Surface Locations: 5 

THIS IS AN AUTOMATED MESSAGE. PLEASE DO NOT REPLY. 

ATTACHMENT 1-D
Freeport-McMoRan Oil & Gas LLC Section 2 – Pg. 3 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 2

GENERAL INFORMATION

2.1 APPLICATIONS AND PERMITS

The table below provides all additional applications to be filed covering operations proposed in 

this EP.

Application/Permit Issuing Agency Status

Applications for Permit to Drill BSEE To Be Submitted

Applications for Permit to Modify BSEE To Be Submitted

Emergency Evacuation Plans USCG To Be Submitted

2.2 DRILLING FLUIDS 

The table below provides the types and estimated volumes of the drilling fluids FM O&G plans

to use to drill the proposed wells. 

Type of Drilling Fluid Estimated Volume of Drilling Fluid to be

Used per Well (bbl)

Water-based (seawater, freshwater, barite) 60,000

Oil-based (diesel, mineral oil) 0

Synthetic-based (internal olefin, ester) 20,000

2.3 NEW OR UNUSUAL TECHNOLOGY

[PROPRIETARY]

2.4 BONDING STATEMENT

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

area-wide bond, furnished and maintained according to 30 CFR 556, Subpart I; NTL No. 2000-

G16, "Guidelines for General Lease Surety Bonds;" and a current BOEM-approved deferment 

from providing additional security under 30 CFR 556.53(d) and National NTL No. 2008-N07, 

“Supplemental Bond Procedures.” If at any point Freeport-McMoRan Oil & Gas LLC no longer 

qualifies for a supplemental bonding deferment, Freeport-McMoRan Oil & Gas LLC will either 

provide the required additional security or a third party guarantee within 60 days after such 

disqualification.

2.5 OIL SPILL FINANCIAL RESPONSIBILITY (OSFR)

Freeport-McMoRan Oil & Gas LLC (Company No. 03280) will demonstrate oil spill financial 

responsibility for the facilities proposed in this EP according to 30 CFR 553; and NTL No. 2008-

N05, "Guidelines for Oil Spill Financial Responsibility for Covered Facilities" prior to conducting 

operations covered in this EP.

2.6 DEEPWATER WELL CONTROL STATEMENT 

Freeport-McMoRan Oil & Gas LLC (Company No. 03280) has the financial capability to drill a 

relief well and conduct other emergency well control operations.
Freeport-McMoRan Oil & Gas LLC Section 2 – Pg. 4 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

2.7 BLOWOUT SCENARIO AND WORST CASE DISCHARGE CALCULATIONS

The Worst Case Discharge is defined as an uncontrolled blowout through the drilling string 

during drilling operations.

Estimated initial flow rate: The calculated Worst Case Discharge estimate for Atwater Valley 

Block 198 Well Location E is 196,060 bbl of crude. 

Maximum duration/total volume that could occur if the Atwater Valley Block 198 Well

Location E sustained a blowout:

Scenario Maximum Discharge 

Rate (bbl/day)

Discharge Duration 

(days)

Total Volume 

Condensate (bbl)

Relief well 196,060 130 25,487,800

Potential of wellbore to bridge over during a blowout:

While the sands anticipated to be encountered by the wells listed in this EP are expected to be 

somewhat consolidated, FM O&G does NOT assume that the proposed wells would bridge over 

in a blowout scenario. This assumption is based on work in association with Society of 

Petroleum Engineers (SPE) Paper # 163438 on the analysis of potential bridging scenarios 

during blowout events in the deep water GoM. FM O&G agrees with the conclusions of this 

SPE paper that the only instances in which a deep water well could potentially bridge over is a 

complete loss of the marine riser hydrostatic column resulting in a sharp pressure reduction 

downhole leading to wellbore collapse before a blowout can fully develop. This bridging would 

occur quickly before large volumes of hydrocarbons could escape. As FM O&G does not 

consider this bridging event to cover all blowout scenarios. The Worst Case Discharge 

calculations for this proposed well will be based upon a well flowing until a relief well can be 

completed.

Likelihood for surface intervention to stop blowout:

Location “E” will be drilled in the Atwater Valley Block 198 as a subsea well in ~4,860 feet of 

water with the wellhead and BOP equipment located on the seabed. Surface intervention would 

be the preferred method in an uncontrolled blowout; however, the technique used is contingent 

upon the rig condition, marine riser system and BOP equipment. Surface intervention is quicker 

than a relief well but actual well control operations would be determined based on site‐specific 

conditions.

Prior to surface intervention operations, a team of specialists would be mobilized immediately to 

assess the situation and determine a course of action. Well control specialists would assess the 

on-site conditions either by helicopter and/or surface vessel. FM O&G has Master Service 

Agreements with both Wild Well Control (a Superior Energy Services company) and Boots and 

Coots (a Halliburton company). Additionally a ROV capable of manipulating the rig’s BOP 

hot‐stab functions would be mobilized to location and, if appropriate, an attempt would be made 

to shut in the well by closing the blind shear rams, if not done previously. These actions would 

take place within 24 ‐ 48 hours of the incident. Initial assessment activities are projected to take 

3 – 5 days. During this period, the well control team would analyze the blowout situation, devise 

an intervention strategy and mobilize service company specialists, supplies and equipment. FM 
Freeport-McMoRan Oil & Gas LLC Section 2 – Pg. 5 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

O&G would establish a field support base and secondary command center in the company 

shore base facility in Fourchon, LA. Communications would be established with the support 

base and command center.

Relief Well

Rig type capable of drilling relief well at water depth and to TD:

There are more than 10 drilling rigs currently working or slated to begin work in the Gulf of 

Mexico that are capable of drilling a relief well at these locations.

The rig chosen to drill the relief well must be:

 Rated and equipped for water depths > 5,000 ft due to Atwater Valley Block locations.

 Dynamically‐ positioned to eliminate anchoring issues due to nearby subsea 

infrastructure.

 Have a BOP package acceptable and certified under current BSEE regulations.

Time to acquired rig, move onsite and drill relief well:

Activity Duration (days)

Assess the situation and obtain the optimum 

MODU

5

Secure the well at current location of MODU 14

Mobilization time to relief well location 3

Drill the relief well 80

Wellbore intersection (of blown out well) 21

Dynamic kill operations 7

Total anticipated time 130

Statement whether possibility of using nearby platform was considered:

There are no platforms located within proximity of this block with the capacity to support drilling 

operations.

Other measures to enhance ability to prevent a blowout:

 FM O&G will verify with the contractor that all BOPs have been certified, maintained and 

are capable of operating in the anticipated conditions required for operations.

 FM O&G representatives will review and witness the installation, testing, function testing 

and operation of the diverter system and diverter outlets.

 Key personnel on the rig will have a valid well control certificate.

 Wiper trips will be performed as hole conditions dictate in order to quantify the stability of 

the wellbore and to determine whether sufficient mud weights are being utilized.

 Connections will be simulated as needed while drilling into pressure transition areas in 

order to properly assess the current wellbore conditions.
Freeport-McMoRan Oil & Gas LLC Section 2 – Pg. 6 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

Measures to reduce the likelihood of a blowout:

 A liner top packer or equivalent expandable will be run on all liner laps as an additional 

barrier for well safety.

 Lost circulation material will be added to the mud system in order to assist the mud 

system’s ability to prevent lost circulation. Sweeps and concentrated pills will be used to 

prevent uncontrolled mud losses.

 Every effort will be made to review all offset and seismic data in order to prepare a mud 

weight schedule that will allow for safe drilling margin without putting excess hydrostatics 

pressures on known zones previously encountered.

 Mudloggers may be utilized during critical drilling operations to monitor gas content of 

mud returns, formation characteristics and abnormalities of cuttings and to estimate 

paleo aging of cuttings.

 Logging While Drilling (LWD) tools will be utilized as much as possible to evaluate 

formations, formation pressures and fluid content in the critical sections of the well.

 Log data will be continuously reviewed by FM O&G’s drilling and geological 

departments.

Measures to enhance ability to conduct effective and early intervention in event of a 

blowout: FM O&G is a member of the Helix Well Containment Group (HWCG) and has full 

access to a subsea capping stack and a complete suite of oil recovery equipment as required. 

This subsea capping stack has been deployed successfully to a well location with oversight from 

BSEE.

Arrangements for drilling relief wells: FM O&G has Master Service Agreements with both 

Wild Well Control (a Superior Energy Services company) and Boots and Coots (a Halliburton 

company) who would assist in detailed relief well planning including the identification of required 

equipment and services.

Any other measures: No
Freeport-McMoRan Oil & Gas LLC Section 3 – Pg. 7 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 3

GEOLOGICAL AND GEOPHYSICAL INFORMATION

3.1 GEOLOGICAL DESCRIPTION

[PROPRIETARY]

3.2 STRUCTURE CONTOUR MAPS

[PROPRIETARY]

3.3 INTERPRETED SEISMIC LINES

[PROPRIETARY]

3.4 GEOLOGICAL STRUCTURE CROSS-SECTIONS 

[PROPRIETARY]

3.5 SHALLOW HAZARDS REPORT

A shallow hazards survey was conducted over Atwater Valley Block 198. 

In accordance with NTL No. 2008-G05, “Shallow Hazards Program” (Extended by NTL NTL No. 

2014-G05, “Extension of Prior Notices to Lessees”), a shallow hazards survey evaluating 

seafloor and subsurface geological and manmade features and conditions that may adversely 

affect drilling operations, was conducted by C & C Technologies Survey Services. The shallow 

hazards report is provided with this plan.

3.6 SHALLOW HAZARDS ASSESSMENT 

In accordance with NTL No. 2008-G05, “Shallow Hazards Program,” (Extended by NTL No. 

2014-G05, “Extension of Prior Notices to Lessees”), a shallow hazards assessment has been 

prepared for each proposed surface location evaluating seafloor and subsurface geological and 

manmade features and conditions that may adversely affect drilling operations. The shallow 

hazards survey and archaeological assessment is included as Attachment 3-A.

3.7 HIGH-RESOLUTION SEISMIC LINES

[PROPRIETARY]

3.8 STRATIGRAPHIC COLUMN

[PROPRIETARY]

3.9 TIME VERSUS DEPTH TABLES 

[PROPRIETARY]
C&C Project No. 140712 

1

730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

October 21, 2014 

Freeport-McMoRan Oil & Gas 

717 Texas Avenue, Suite 2100 

Houston, TX 77002 

Attn: Mr. Terry Arcuri 

Site Clearance Letter 

Proposed Well “A”

Block 198 (OCS-G-35431) 

Atwater Valley Area 

Dear Mr. Arcuri, 

INTRODUCTION 

Freeport-McMoRan Oil & Gas (FMOG) contracted C & C Technologies, Inc. (C&C) to prepare 

a wellsite clearance letter for the proposed Well “A” location in Block 198 (OCS-G-35431), 

Atwater Valley (AT) Area. The data used for the site clearance letter is based on the 

interpretation of an exploration-quality 3D seismic volume and a high-resolution geophysical 

dataset collected with C&C’s Autonomous Underwater Vehicle (AUV) C-Surveyor VITM. C&C 

completed the geohazard assessment titled “3D Shallow Hazard Report, Sun Prospect, Blocks 

154 (OCS-G-35019), 197 (OCS-G-35430), 198 (OCS-G-35431), and Vicinity, Atwater Valley 

Area” in October, 2014. This site clearance letter is based on the findings provided within that 

report. 

This letter provides a top-hole drilling prognosis and addresses seafloor conditions within a 

2,000-foot radius of the proposed surface location. The depth limit of investigation is 

approximately 2.0 seconds of two-way traveltime (~5,000 feet) below the mud line (BML). The 

reporting and mapping presented in this letter comply with the BOEM/BSEE guidelines provided 

in NTL No. 2008-G05 (Shallow Hazards Program) and No. 2009-G40 (Deepwater Benthic 

Communities). 

METHODS 

AUV Survey Data 

C&C’s C-Surveyor VITM AUV provided multibeam bathymetric mapping, high-resolution side 

scan sonar imagery, and subbottom profiles. The AUV remote-sensing instruments include a 

Kongsberg EM 2040 Swath Multibeam Sonar (200, 300, and 400 kHz), an EdgeTech 2200-M 

Side Scan Sonar (410 and 120 kHz), and a custom EdgeTech Chirp DW106 Subbottom Profiler 

(1 - 6 kHz). All the raw digital data were logged utilizing proprietary software developed by 

C&C. The multibeam system delivered a 3-meter gridded dataset with relative vertical 

accuracies within 20 centimeters. 

The AUV survey grid in the study area consists of one-hundred sixty-seven (167) tracklines, 

including one-hundred fifty-five (155) primary lines (Line Nos. 101-155) running east-west at 

200-meter (656-foot) line spacing and twelve (12) tie lines (Line Nos. 201-212) running northsouth at 900-meter (2,953-foot) line spacing. Navigation fixes (event marks) were annotated at 

ATTACHMENT 3-A
C&C Project No. 140712

2

730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

125-meter (410-foot) intervals along all survey lines. The survey grid was designed to provide a 

representative sampling with the subbottom profiler system and overlapping coverage with side 

scan sonar and multibeam echosounder systems. 

3D Seismic Data

The 3D seismic data used for this assessment was provided in SEG-Y format. The data were 

loaded into IHS’ Kingdom Suite 2d/3dPAK for interpretation. The 3D data were acquired by 

CGGVeritas aboard the Symphony, and reprocessed with Post-Stack Time Migration (PSTM). 

The 3D data were provided at a four-millisecond sample rate and extend to the full data range of 

7.0 seconds. The inlines of the data run east-west and are spaced at 20-meter (65.62-foot) 

intervals, while the crosslines run north-south and are spaced at 12.5-meter (41.01-foot) 

intervals. Spectral whitening was applied to the 3D seismic dataset to amplify the higher 

frequencies. After applying the spectral whitening, a power spectrum generated at a few selected 

locations indicated the seismic data volume contains sufficiently high frequency content for a 

shallow hazards assessment (Figure 1). 

The 3D seismic data are zero phase, and the seafloor reflector is represented by a strong, positive 

amplitude peak flanked by troughs with absolute amplitude values of less than one-half of the 

peak value. The seismic data provided adequate screening of the regional seafloor and shallow 

geologic conditions, and large scale geohazards (faults, salt, high acoustic impedance, 

stratigraphic horizons, etc.).

WELL LOCATION

The coordinates and calls for the proposed Well “A” surface location are tabulated below:

Table 1. Proposed Well “A”

Well Easting 

(feet)

Northing

(feet)

Latitude Longitude Calls From Block 198,

Atwater Valley Area

“A” 1,033,178’ 10,086,818’ 27 47’ 00.745” N 88 52’ 42.516” W 3,578’ FWL 3,262’ FNL

A 2,000-foot clearance radius is required for assessing deepwater benthic communities in 

proximity to the proposed Well “A”.

The geodetic datum used for this project is the North American Datum 1927 (NAD27) with the 

Clarke 1866 Ellipsoid. The datum is projected using the Universal Transverse Mercator (UTM), 

Zone 16 North (16N) with a central meridian at 87° 00′W, a false easting of 1,640,416.67 feet at 

the central meridian, and a false northing of 0.00 feet at 00° 00′N. Mapping and reporting units 

are in U.S. Survey Feet.

REGIONAL GEOLOGY

The Gulf of Mexico is a semi-enclosed basin that has been receiving sediment influx dominated 

by the Mississippi River since the Late Jurassic. Mesozoic and Cenozoic sediments have 

attained a thickness in excess of 9 miles (Coleman et al., 1991). The prograded shelf sequence 

consists of intercalated coastal plain, delta, estuarine, and marine sediments. Sediment 

deposition along the northern rim of the Gulf of Mexico resulted in particularly thick Tertiary 
C&C Project No. 140712

3

730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

and Quaternary sections. These rapidly deposited sediments have prograded the Cretaceous 

shelf-edge up to 185 miles basinward. The exceptionally high rate of shelf-edge progradation is 

on the order of 3.0 to 3.7 miles per 1,000 years. 

The near surface geology across the Gulf Coast region is the product of fluctuating sea levels 

associated with climatic variations over the past 20,000 years. During this time, low sea levels 

left the continental shelf exposed to subaerial weathering and other erosional processes. Streams 

and rivers meandered and cut into the exposed landmass, depositing bedloads along the modernday shelf break. Fan systems were formed, and mass movement events were common as deltaic 

sediments were deposited on the steep upper continental slope. As the climate warmed, seas 

transgressed, and marine sediments were deposited on the shelf.

BATHYMETRY AND SEAFLOOR GRADIENTS

The water depth at the proposed Well “A” location is 4,806 feet below mean sea level (MSL). 

Within the 2,000-foot radius area centered at the proposed Well “A” location, the seafloor depth 

ranges from 4,784 feet in the northwest to 4,833 feet in the southeast (Sheet 1, Color Shaded 

Bathymetry Map).

The proposed Well “A” location is situated on a very smooth sloping seafloor located in the 

northeastern corner of AT198 (Figure 2). The seafloor in the area surrounding the proposed well 

location slopes southeast at a gradient of less than 1° (Sheet 2, Seafloor Gradient Map).

SEAFLOOR HAZARDS

Low to moderate sonar reflectivity occurs around the proposed wellsite indicating mostly finegrained sediments (Figure 3).

The 3D seafloor amplitude image displays a range of low to moderate acoustic amplitudes within 

the 2,000-foot radius area (Sheet 3, Seafloor Amplitude Map). These low to moderate seafloor 

amplitudes indicate finely textured seafloor sediments that are likely comprised of hemipelagic 

clay.

No sonar contacts are found within 2,000 feet of the proposed well location. 

There were no seafloor features or potential hazards identified at or in proximity to the proposed 

well location (Sheet 4, Seafloor and Subsurface Hazards Map).

POTENTIAL DEEPWATER BENTHIC COMMUNITIES

High or low-amplitude seismic seafloor anomalies are potential indicators of carbonates, benthic 

community habitats, and gas/fluid seepages. The seafloor at the proposed Well “A” and 

surrounding 2,000-foot radius contains no high or low positive seafloor amplitude anomalies 

associated with fluid expulsion or mounded carbonates representing potential benthic 

communities. The side scan sonar and multibeam backscatter agree with the seafloor amplitude 

image, and show no evidence of outcrops or fluid expulsion.
C&C Project No. 140712

4

730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

SUBSURFACE GEOHAZARDS AND STRATIGRAPHY

The AUV subbottom profiler data exhibit continuous, sharp bottom echoes with parallel to 

divergent, continuous reflectors throughout the wellsite area. The uppermost shallow sediments 

consist of a 20 to 25 foot thick acoustically semi-transparent hemipelagic clay drape. Sediments 

below this drape are characterized by parallel, low to moderate amplitude reflectors that 

represent cyclic deposition of hemipelagic clay and silty clays (Figure 4).

Five sedimentary units (Units A to E), each consisting of one or more distinctive sequences, 

were interpreted within the study area from the 3D seismic data to approximately 2 seconds of 

two-way traveltime (~5,000 feet) below the seafloor, the lower limit of investigation. Six

horizons mark the upper and/or lower contacts of each of the successive units (Figures 5 and 6). 

C&C was provided with a series of time-depth pairs for the sediment column. The following 

polynomial equation was derived from Total Vertical Depth (TVD) (feet) and the corresponding 

two-way traveltime (seconds) using the time-depth values to calculate depths below the seafloor:

D = 426.02T

2

+ 1,524.4T

where D = depth below seafloor in feet and T = time below seafloor in seconds.

A detailed description of the sequence units, beginning at the seafloor, can be found in the 2014

Geohazard Report. The Top-Hole Prognosis Chart (Figure 7) summarizes the stratigraphy.

Unit A (Seafloor to Horizon 1)

Unit A consists of mostly low amplitude, parallel, semi-continuous reflectors and measures 

1,280 feet thick at the proposed well location. The reflection patterns suggest the unit is 

comprised mostly of hemipelagic clay with interbedded fine-grained mass transport deposits. No 

high amplitude anomalies occur within Unit A near the proposed well location. 

Unit B (Horizon 1 to Horizon 2)

Unit B consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 1,891 feet thick at the proposed well location. Unit B is interpreted as fine-grained 

mass transport deposits atop an interbedded channel fill zone. No high amplitude anomalies 

occur within Unit B near the proposed well location.

Unit C (Horizon 2 to Horizon 3)

Unit C consists of low to moderate amplitude, semi-continuous to sub-parallel reflectors and 

measures 738 feet. This relatively thin unit is interpreted as mass transport deposits with a few 

interbedded channel fills. No high amplitude anomalies occur within Unit C near the proposed 

well location. 

Unit D (Horizon 3 to Horizon 4)

Unit D consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 2,111 feet thick at the proposed well location. The sediments in Unit D are interpreted 

as a coarser-grained channel fill between two finer-grained mass transport deposits. No high 
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amplitude anomalies occur within Unit D near the proposed well location. The coarser 

sediments found in the channel fill zone may represent low to moderate shallow water flow

potential. 

Unit E (Horizon 4 to Horizon 5)

Unit E consists of low to moderate amplitude, semi-continuous to subparallel reflectors and 

measures 1,415 feet thick at the proposed well location. The sediments in Unit E are interpreted 

as mostly channel fill sitting atop an interbedded mass transport deposit zone. No high 

amplitude anomalies occur within Unit E near the proposed well location. The coarser sediments 

found in the channel fill zone may represent low to moderate shallow water flow potential. 

Horizon 5 represents the salt/sediment interface at the proposed well location.

SHALLOW GAS

Anomalies of very high amplitude, commonly termed bright spots, are interpreted as potential 

regions of fluid saturation usually associated with porous sands. Seismic amplitude anomalies 

are mapped on a unit-by-unit basis to assess the potential risk of gas. Seismic amplitude 

anomalies are exhibited on the Seafloor & Subsurface Features Map.

The risk of gas refers to the risk of encountering shallow gas. The risk of gas is interpreted based 

on amplitude levels. Stratigraphic and structural settings may also be taken into account. The 

four risk levels of gas are:

 Negligible—No amplitude anomalies or other gas indicator present.

 Low risk of gas—Generally indicated by increased amplitude (2–3× background level) 

and phase reversal. This may also include diffuse areas of gas blanking.

 Moderate risk of gas—Generally indicated by high amplitude (3–4× background level) 

and phase reversal.

 High risk of gas—Generally indicated by the highest amplitudes (in excess of 4× 

background level), phase reversal, and a combination of other attributes indicative of the 

presence of gas, particularly velocity pull-down and masking of underlying sediments. 

There were no amplitude anomalies identified within 2,000 feet of the proposed Well “A” 

location. All units are interpreted as having a low risk of gas.

SHALLOW WATER FLOW

Several factors may contribute to shallow water flows. These include: high porosity and 

permeability, sand-prone aquifer, mechanism to pressurize, and seal. Additional details are 

described below:

 Water depth and burial depth. Significant water depths (> 500 feet below the seafloor) 

are required for the overpressure to occur. The seal must be deeply buried (> 500 feet 

below the seafloor) to become sufficiently strong.

 High deposition rates. Sedimentation rate needs to be greater than 1,500 feet/myr to 

effectively seal in sands. Sedimentation rates are expected to be high within a salt 

withdrawal basin. Rapid burial leads to pressure disequilibrium. In addition, if these 
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sediment ‘packets’ were formed through a sequence of turbidites or gravity flow, there is an 

increased likelihood of water saturation and overpressure (pore pressure rapidly increased 

and sealed by an impervious layer). 

 Suitably porous sediments. The sediment packets comprising the risk of shallow water 

flow are believed to contain clastic material and are thus porous.

 Impermeable seal. The overlying sediments are comprised of a clay facies.

All of these factors occur within the study area. Since there is presently no method for 

quantifying the risk of shallow water flow, caution is recommended when drilling through units 

with shallow water flow potential. Sands with SWF potential often occur in unconsolidated, 

overpressured sands that lie below a seal. This seal prevents dewatering and compaction after 

deposition. The pressure rises with overburden causing a potentially disastrous hazard for 

drilling operations. 

The nearest reported shallow water flow was in AT194, approximately 10 miles west of the 

survey area, according to information listed on the BOEM and BSEE website. This SWF event 

is listed as occurring 2,132 feet below mudline and was categorized as a moderate severity flow. 

The assessment of seismic profiles suggests that Units A and C exhibit a low risk of SWF, while 

the coarser-grained channel fills within Units B, D, and E exhibit a low to moderate risk. Due to 

the unpredictable nature of SWF, it is advised that caution be executed for any drilling operations 

through these sediments.

GAS HYDRATES

Gas hydrates are an ice crystalline form of gas hydrocarbons in deepwater marine environments 

where the conditions of pressure and temperature are favorable. The hydrate stability zone is the 

depth interval between the seafloor and the point where the hydrate is no longer stable in form. 

The thermal gradient of the seabed soils determines the depth of the hydrate stability zone base. 

The acoustic impedance contrast caused between the hydrate and free gas trapped at the base of 

the hydrate stability zone forms a Bottom Simulating Reflector (BSR) on seismic profiles. This 

BSR reflector cross cuts the normal seismic stratigraphy, much like a bottom multiple.

The areas where seafloor gas hydrates accumulate in the near-surface sediments of the Gulf of 

Mexico are generally unfavorable sites for drilling operations. Irregular seafloor topography, gas 

seeps, gas chimneys, seafloor hydrates and deepwater benthic communities may all be found in 

close association. No indication of BSRs was found in the vicinity of the proposed well.

CONCLUSIONS

The proposed Well “A” location is situated on a very smooth sloping seafloor at a water depth of 

4,806 feet MSL. The seabed slopes gently to the southeast at a gradient of less than 1°.

There were no potential hazardous features identified near the proposed Well “A” location.

No sonar contacts exist within 2,000 feet of the proposed Well “A” location. 
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No high or low seafloor amplitudes anomalies that may indicate the occurrence of hardgrounds, 

carbonates, benthic communities or potential expulsions are found within 2,000 feet of the 

proposed Well “A” location.

Five (5) subsurface units interpreted from the 3D seismic data were assessed to approximately 

5,000 feet BSF at the proposed Well “A” location (Units A to E). Unit A is comprised mostly of 

low amplitude, parallel to semi-continuous reflectors and consists of hemipelagic clays and mass 

transport deposits. Unit B is characterized by low to moderate amplitude, semi-continuous to 

chaotic reflectors and consists of fine-grained mass transport deposits atop an interbedded 

channel fill zone. Unit C is comprised of low to moderate amplitude, semi-continuous reflectors 

and is interpreted as mostly mass transport deposits with a few interbedded channel fills. Units 

D and E consist of low to moderate, semi-continuous to chaotic reflectors and consists of 

alternating layers of fine-grained mass transport deposits and coarser-grained channel fill zones. 

There were no amplitude anomalies indicative of shallow gas identified within any of the units at 

the proposed Well “A” location. All units are therefore assessed as having a low risk of gas. No 

indication of gas hydrates was found within the study area.

Units A and C are assessed as having a low risk of SWF. The coarser-grained channel fills 

within Units B, D, and E are assessed as having a low to moderate risk of SWF. 

Thank you for this opportunity to be of service. Please contact us if you have any questions 

concerning this assessment.

Sincerely,

___________________________

Christopher Baker

Senior Geologist

ENCLOSURES

Figure 1. Extracted wavelet and power spectrum at the proposed Well “A”.

Figure 2. AUV seafloor bathymetry surrounding the proposed Well “A”.

Figure 3. Side scan sonar mosaic at the proposed Well “A”.

Figure 4. Subbottom profiler Line 133 near the proposed Well “A”.

Figure 5. 3D seismic Inline 1675 through the proposed Well “A”.

Figure 6. 3D seismic Crossline 10208 through the proposed Well “A”.

Figure 7. Top-Hole Prognosis Chart for the proposed Well “A”.

Sheet 1. Color Shaded Bathymetry Map, Proposed Well “A” Location 1”=1,000’

Sheet 2. Seafloor Gradient Map, Proposed Well “A” Location 1”=1,000’

Sheet 3. Seafloor Amplitude Map, Proposed Well “A” Location 1”=1,000’

Sheet 4. Seafloor & Subsurface Hazard Map, Proposed Well “A” Location 1”=1,000’
C&C Project No. 140712

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October 21, 2014

Freeport-McMoRan Oil & Gas 

717 Texas Avenue, Suite 2100

Houston, TX 77002

Attn: Mr. Terry Arcuri

Site Clearance Letter

Proposed Well “B”

Block 198 (OCS-G-35431)

Atwater Valley Area

Dear Mr. Arcuri,

INTRODUCTION

Freeport-McMoRan Oil & Gas (FMOG) contracted C & C Technologies, Inc. (C&C) to prepare 

a wellsite clearance letter for the proposed Well “B” location in Block 198 (OCS-G-35431), 

Atwater Valley (AT) Area. The data used for the site clearance letter is based on the 

interpretation of an exploration-quality 3D seismic volume and a high-resolution geophysical 

dataset collected with C&C’s Autonomous Underwater Vehicle (AUV) C-Surveyor VITM. C&C 

completed the geohazard assessment titled “3D Shallow Hazard Report, Sun Prospect, Blocks 

154 (OCS-G-35019), 197 (OCS-G-35430), 198 (OCS-G-35431), and Vicinity, Atwater Valley 

Area” in October, 2014. This site clearance letter is based on the findings provided within that 

report.

This letter provides a top-hole drilling prognosis and addresses seafloor conditions within a 

2,000-foot radius of the proposed surface location. The depth limit of investigation is 

approximately 2.0 seconds of two-way traveltime (~5,000 feet) below the mud line (BML). The 

reporting and mapping presented in this letter comply with the BOEM/BSEE guidelines provided 

in NTL No. 2008-G05 (Shallow Hazards Program) and No. 2009-G40 (Deepwater Benthic 

Communities).

METHODS

AUV Survey Data

C&C’s C-Surveyor VITM AUV provided multibeam bathymetric mapping, high-resolution side 

scan sonar imagery, and subbottom profiles. The AUV remote-sensing instruments include a 

Kongsberg EM 2040 Swath Multibeam Sonar (200, 300, and 400 kHz), an EdgeTech 2200-M

Side Scan Sonar (410 and 120 kHz), and a custom EdgeTech Chirp DW106 Subbottom Profiler 

(1 - 6 kHz). All the raw digital data were logged utilizing proprietary software developed by 

C&C. The multibeam system delivered a 3-meter gridded dataset with relative vertical 

accuracies within 20 centimeters.

The AUV survey grid in the study area consists of one-hundred sixty-seven (167) tracklines, 

including one-hundred fifty-five (155) primary lines (Line Nos. 101-155) running east-west at 

200-meter (656-foot) line spacing and twelve (12) tie lines (Line Nos. 201-212) running northsouth at 900-meter (2,953-foot) line spacing. Navigation fixes (event marks) were annotated at 
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125-meter (410-foot) intervals along all survey lines. The survey grid was designed to provide a 

representative sampling with the subbottom profiler system and overlapping coverage with side 

scan sonar and multibeam echosounder systems. 

3D Seismic Data

The 3D seismic data used for this assessment was provided in SEG-Y format. The data were 

loaded into IHS’ Kingdom Suite 2d/3dPAK for interpretation. The 3D data were acquired by 

CGGVeritas aboard the Symphony, and reprocessed with Post-Stack Time Migration (PSTM). 

The 3D data were provided at a four-millisecond sample rate and extend to the full data range of 

7.0 seconds. The inlines of the data run east-west and are spaced at 20-meter (65.62-foot) 

intervals, while the crosslines run north-south and are spaced at 12.5-meter (41.01-foot) 

intervals. Spectral whitening was applied to the 3D seismic dataset to amplify the higher 

frequencies. After applying the spectral whitening, a power spectrum generated at a few selected 

locations indicated the seismic data volume contains sufficiently high frequency content for a 

shallow hazards assessment (Figure 1). 

The 3D seismic data are zero phase, and the seafloor reflector is represented by a strong, positive 

amplitude peak flanked by troughs with absolute amplitude values of less than one-half of the 

peak value. The seismic data provided adequate screening of the regional seafloor and shallow 

geologic conditions, and large scale geohazards (faults, salt, high acoustic impedance, 

stratigraphic horizons, etc.).

WELL LOCATION

The coordinates and calls for the proposed Well “B” surface location are tabulated below:

Table 1. Proposed Well “B”

Well Easting 

(feet)

Northing

(feet)

Latitude Longitude Calls From Block 198,

Atwater Valley Area

“B” 1,036,564’ 10,083,073’ 27 46’ 24.177” N 88 52’ 04.191” W 6,964’ FWL 7,007’ FNL

A 2,000-foot clearance radius is required for assessing deepwater benthic communities in 

proximity to the proposed Well “B”.

The geodetic datum used for this project is the North American Datum 1927 (NAD27) with the 

Clarke 1866 Ellipsoid. The datum is projected using the Universal Transverse Mercator (UTM), 

Zone 16 North (16N) with a central meridian at 87° 00′W, a false easting of 1,640,416.67 feet at 

the central meridian, and a false northing of 0.00 feet at 00° 00′N. Mapping and reporting units 

are in U.S. Survey Feet.

REGIONAL GEOLOGY

The Gulf of Mexico is a semi-enclosed basin that has been receiving sediment influx dominated 

by the Mississippi River since the Late Jurassic. Mesozoic and Cenozoic sediments have 

attained a thickness in excess of 9 miles (Coleman et al., 1991). The prograded shelf sequence 

consists of intercalated coastal plain, delta, estuarine, and marine sediments. Sediment 

deposition along the northern rim of the Gulf of Mexico resulted in particularly thick Tertiary 
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and Quaternary sections. These rapidly deposited sediments have prograded the Cretaceous 

shelf-edge up to 185 miles basinward. The exceptionally high rate of shelf-edge progradation is 

on the order of 3.0 to 3.7 miles per 1,000 years. 

The near surface geology across the Gulf Coast region is the product of fluctuating sea levels 

associated with climatic variations over the past 20,000 years. During this time, low sea levels 

left the continental shelf exposed to subaerial weathering and other erosional processes. Streams 

and rivers meandered and cut into the exposed landmass, depositing bedloads along the modernday shelf break. Fan systems were formed, and mass movement events were common as deltaic 

sediments were deposited on the steep upper continental slope. As the climate warmed, seas 

transgressed, and marine sediments were deposited on the shelf.

BATHYMETRY AND SEAFLOOR GRADIENTS

The water depth at the proposed Well “B” location is 4,870 feet below mean sea level (MSL). 

Within the 2,000-foot radius area centered at the proposed Well “B” location, the seafloor depth 

ranges from 4,844 feet in the northwest to 4,900 feet in the southeast (Sheet 1, Color Shaded 

Bathymetry Map).

The proposed Well “B” location is situated on a very smooth sloping seafloor located in the 

northeastern corner of AT198 (Figure 2). The seafloor in the area surrounding the proposed well 

location slopes southeast at a gradient of less than 1° (Sheet 2, Seafloor Gradient Map).

SEAFLOOR HAZARDS

Low to moderate sonar reflectivity occurs around the proposed wellsite indicating mostly finegrained sediments (Figure 3).

The 3D seafloor amplitude image displays a range of low to moderate acoustic amplitudes within 

the 2,000-foot radius area (Sheet 3, Seafloor Amplitude Map). These low to moderate seafloor 

amplitudes indicate finely textured seafloor sediments that are likely comprised of hemipelagic 

clay.

No sonar contacts are found within 2,000 feet of the proposed well location. 

There were no seafloor features or potential hazards identified at or in proximity to the proposed 

well location (Sheet 4, Seafloor and Subsurface Hazards Map).

POTENTIAL DEEPWATER BENTHIC COMMUNITIES

High or low-amplitude seismic seafloor anomalies are potential indicators of carbonates, benthic 

community habitats, and gas/fluid seepages. The seafloor at the proposed Well “B” and 

surrounding 2,000-foot radius contains no high or low positive seafloor amplitude anomalies 

associated with fluid expulsion or mounded carbonates representing potential benthic 

communities. The side scan sonar and multibeam backscatter agree with the seafloor amplitude 

image, and show no evidence of outcrops or fluid expulsion.
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SUBSURFACE GEOHAZARDS AND STRATIGRAPHY

The AUV subbottom profiler data exhibit continuous, sharp bottom echoes with parallel to 

divergent, continuous reflectors throughout the wellsite area. The uppermost shallow sediments 

consist of a 20 to 25 foot thick acoustically semi-transparent hemipelagic clay drape. Sediments 

below this drape are characterized by parallel, low to moderate amplitude reflectors that 

represent cyclic deposition of hemipelagic clay and silty clays (Figure 4).

Five sedimentary units (Units A to E), each consisting of one or more distinctive sequences, 

were interpreted within the study area from the 3D seismic data to approximately 2 seconds of 

two-way traveltime (~5,000 feet) below the seafloor, the lower limit of investigation. Six

horizons mark the upper and/or lower contacts of each of the successive units (Figures 5 and 6). 

C&C was provided with a series of time-depth pairs for the sediment column. The following 

polynomial equation was derived from Total Vertical Depth (TVD) (feet) and the corresponding 

two-way traveltime (seconds) using the time-depth values to calculate depths below the seafloor:

D = 426.02T

2

+ 1,524.4T

where D = depth below seafloor in feet and T = time below seafloor in seconds.

A detailed description of the sequence units, beginning at the seafloor, can be found in the 2014

Geohazard Report. The Top-Hole Prognosis Chart (Figure 7) summarizes the stratigraphy.

Unit A (Seafloor to Horizon 1)

Unit A consists of mostly low amplitude, parallel, semi-continuous reflectors and measures 

1,214 feet thick at the proposed well location. The reflection patterns suggest the unit is 

comprised mostly of hemipelagic clay with interbedded fine-grained mass transport deposits. No 

high amplitude anomalies occur within Unit A near the proposed well location. 

Unit B (Horizon 1 to Horizon 2)

Unit B consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 1,810 feet thick at the proposed well location. Unit B is interpreted as fine-grained 

mass transport deposits atop an interbedded channel fill zone. No high amplitude anomalies 

occur within Unit B near the proposed well location.

Unit C (Horizon 2 to Horizon 3)

Unit C consists of low to moderate amplitude, semi-continuous to sub-parallel reflectors and 

measures 625 feet. This relatively thin unit is interpreted as mass transport deposits with a few 

interbedded channel fills. No high amplitude anomalies occur within Unit C near the proposed 

well location. 

Unit D (Horizon 3 to Horizon 4)

Unit D consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 2,093 feet thick at the proposed well location. The sediments in Unit D are interpreted 

as a coarser-grained channel fill between two finer-grained mass transport deposits. No high 
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amplitude anomalies occur within Unit D near the proposed well location. The coarser 

sediments found in the channel fill zone may represent low to moderate shallow water flow

potential. 

Unit E (Horizon 4 to Horizon 5)

Unit E consists of low to moderate amplitude, semi-continuous to subparallel reflectors and 

measures 1,323 feet thick at the proposed well location. The sediments in Unit E are interpreted 

as mostly channel fill sitting atop an interbedded mass transport deposit zone. No high 

amplitude anomalies occur within Unit E near the proposed well location. The coarser sediments 

found in the channel fill zone may represent low to moderate shallow water flow potential. 

Horizon 5 represents the salt/sediment interface at the proposed well location.

SHALLOW GAS

Anomalies of very high amplitude, commonly termed bright spots, are interpreted as potential 

regions of fluid saturation usually associated with porous sands. Seismic amplitude anomalies 

are mapped on a unit-by-unit basis to assess the potential risk of gas. Seismic amplitude 

anomalies are exhibited on the Seafloor & Subsurface Features Map.

The risk of gas refers to the risk of encountering shallow gas. The risk of gas is interpreted based 

on amplitude levels. Stratigraphic and structural settings may also be taken into account. The 

four risk levels of gas are:

 Negligible—No amplitude anomalies or other gas indicator present.

 Low risk of gas—Generally indicated by increased amplitude (2–3× background level) 

and phase reversal. This may also include diffuse areas of gas blanking.

 Moderate risk of gas—Generally indicated by high amplitude (3–4× background level) 

and phase reversal.

 High risk of gas—Generally indicated by the highest amplitudes (in excess of 4× 

background level), phase reversal, and a combination of other attributes indicative of the 

presence of gas, particularly velocity pull-down and masking of underlying sediments. 

There were no amplitude anomalies identified within 2,000 feet of the proposed Well “B”

location. All units are interpreted as having a low risk of gas.

SHALLOW WATER FLOW

Several factors may contribute to shallow water flows. These include: high porosity and 

permeability, sand-prone aquifer, mechanism to pressurize, and seal. Additional details are 

described below:

 Water depth and burial depth. Significant water depths (> 500 feet below the seafloor) 

are required for the overpressure to occur. The seal must be deeply buried (> 500 feet 

below the seafloor) to become sufficiently strong.

 High deposition rates. Sedimentation rate needs to be greater than 1,500 feet/myr to 

effectively seal in sands. Sedimentation rates are expected to be high within a salt 

withdrawal basin. Rapid burial leads to pressure disequilibrium. In addition, if these 
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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

sediment ‘packets’ were formed through a sequence of turbidites or gravity flow, there is an 

increased likelihood of water saturation and overpressure (pore pressure rapidly increased 

and sealed by an impervious layer). 

 Suitably porous sediments. The sediment packets comprising the risk of shallow water 

flow are believed to contain clastic material and are thus porous.

 Impermeable seal. The overlying sediments are comprised of a clay facies.

All of these factors occur within the study area. Since there is presently no method for 

quantifying the risk of shallow water flow, caution is recommended when drilling through units 

with shallow water flow potential. Sands with SWF potential often occur in unconsolidated, 

overpressured sands that lie below a seal. This seal prevents dewatering and compaction after 

deposition. The pressure rises with overburden causing a potentially disastrous hazard for 

drilling operations. 

The nearest reported shallow water flow was in AT194, approximately 10 miles west of the 

survey area, according to information listed on the BOEM and BSEE website. This SWF event 

is listed as occurring 2,132 feet below mudline and was categorized as a moderate severity flow. 

The assessment of seismic profiles suggests that Units A and C exhibit a low risk of SWF, while 

the coarser-grained channel fills within Units B, D, and E exhibit a low to moderate risk. Due to 

the unpredictable nature of SWF, it is advised that caution be executed for any drilling operations 

through these sediments.

GAS HYDRATES

Gas hydrates are an ice crystalline form of gas hydrocarbons in deepwater marine environments 

where the conditions of pressure and temperature are favorable. The hydrate stability zone is the 

depth interval between the seafloor and the point where the hydrate is no longer stable in form. 

The thermal gradient of the seabed soils determines the depth of the hydrate stability zone base. 

The acoustic impedance contrast caused between the hydrate and free gas trapped at the base of 

the hydrate stability zone forms a Bottom Simulating Reflector (BSR) on seismic profiles. This 

BSR reflector cross cuts the normal seismic stratigraphy, much like a bottom multiple.

The areas where seafloor gas hydrates accumulate in the near-surface sediments of the Gulf of 

Mexico are generally unfavorable sites for drilling operations. Irregular seafloor topography, gas 

seeps, gas chimneys, seafloor hydrates and deepwater benthic communities may all be found in 

close association. No indication of BSRs was found in the vicinity of the proposed well.

CONCLUSIONS

The proposed Well “B” location is situated on a very smooth sloping seafloor at a water depth of 

4,870 feet MSL. The seabed slopes gently to the southeast at a gradient of less than 1°.

There were no potential hazardous features identified near the proposed Well “B” location.

No sonar contacts exist within 2,000 feet of the proposed Well “B” location. 
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No high or low seafloor amplitudes anomalies that may indicate the occurrence of hardgrounds, 

carbonates, benthic communities or potential expulsions are found within 2,000 feet of the 

proposed Well “B” location.

Five (5) subsurface units interpreted from the 3D seismic data were assessed to approximately 

5,000 feet BSF at the proposed Well “B” location (Units A to E). Unit A is comprised mostly of 

low amplitude, parallel to semi-continuous reflectors and consists of hemipelagic clays and mass 

transport deposits. Unit B is characterized by low to moderate amplitude, semi-continuous to 

chaotic reflectors and consists of fine-grained mass transport deposits atop an interbedded 

channel fill zone. Unit C is comprised of low to moderate amplitude, semi-continuous reflectors 

and is interpreted as mostly mass transport deposits with a few interbedded channel fills. Units 

D and E consist of low to moderate, semi-continuous to chaotic reflectors and consists of 

alternating layers of fine-grained mass transport deposits and coarser-grained channel fill zones. 

There were no amplitude anomalies indicative of shallow gas identified within any of the units at 

the proposed Well “B” location. All units are therefore assessed as having a low risk of gas. No 

indication of gas hydrates was found within the study area.

Units A and C are assessed as having a low risk of SWF. The coarser-grained channel fills 

within Units B, D, and E are assessed as having a low to moderate risk of SWF. 

Thank you for this opportunity to be of service. Please contact us if you have any questions 

concerning this assessment.

Sincerely,

___________________________

Christopher Baker

Senior Geologist

ENCLOSURES

Figure 1. Extracted wavelet and power spectrum at the proposed Well “B”.

Figure 2. AUV seafloor bathymetry surrounding the proposed Well “B”.

Figure 3. Side scan sonar mosaic at the proposed Well “B”.

Figure 4. Subbottom profiler Line 139 near the proposed Well “B”.

Figure 5. 3D seismic Inline 1618 through the proposed Well “B”.

Figure 6. 3D seismic Crossline 10290 through the proposed Well “B”.

Figure 7. Top-Hole Prognosis Chart for the proposed Well “B”.

Sheet 1. Color Shaded Bathymetry Map, Proposed Well “B” Location 1”=1,000’

Sheet 2. Seafloor Gradient Map, Proposed Well “B” Location 1”=1,000’

Sheet 3. Seafloor Amplitude Map, Proposed Well “B” Location 1”=1,000’

Sheet 4. Seafloor & Subsurface Hazard Map, Proposed Well “B” Location 1”=1,000’
C&C Project No. 140712

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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

October 21, 2014

Freeport-McMoRan Oil & Gas 

717 Texas Avenue, Suite 2100

Houston, TX 77002

Attn: Mr. Terry Arcuri

Site Clearance Letter

Proposed Well “C”

Block 198 (OCS-G-35431)

Atwater Valley Area

Dear Mr. Arcuri,

INTRODUCTION

Freeport-McMoRan Oil & Gas (FMOG) contracted C & C Technologies, Inc. (C&C) to prepare 

a wellsite clearance letter for the proposed Well “C” location in Block 198 (OCS-G-35431), 

Atwater Valley (AT) Area. The data used for the site clearance letter is based on the 

interpretation of an exploration-quality 3D seismic volume and a high-resolution geophysical 

dataset collected with C&C’s Autonomous Underwater Vehicle (AUV) C-Surveyor VITM. C&C 

completed the geohazard assessment titled “3D Shallow Hazard Report, Sun Prospect, Blocks 

154 (OCS-G-35019), 197 (OCS-G-35430), 198 (OCS-G-35431), and Vicinity, Atwater Valley 

Area” in October, 2014. This site clearance letter is based on the findings provided within that 

report.

This letter provides a top-hole drilling prognosis and addresses seafloor conditions within a 

2,000-foot radius of the proposed surface location. The depth limit of investigation is 

approximately 2.0 seconds of two-way traveltime (~5,000 feet) below the mud line (BML). The 

reporting and mapping presented in this letter comply with the BOEM/BSEE guidelines provided 

in NTL No. 2008-G05 (Shallow Hazards Program) and No. 2009-G40 (Deepwater Benthic 

Communities).

METHODS

AUV Survey Data

C&C’s C-Surveyor VITM AUV provided multibeam bathymetric mapping, high-resolution side 

scan sonar imagery, and subbottom profiles. The AUV remote-sensing instruments include a 

Kongsberg EM 2040 Swath Multibeam Sonar (200, 300, and 400 kHz), an EdgeTech 2200-M

Side Scan Sonar (410 and 120 kHz), and a custom EdgeTech Chirp DW106 Subbottom Profiler 

(1 - 6 kHz). All the raw digital data were logged utilizing proprietary software developed by 

C&C. The multibeam system delivered a 3-meter gridded dataset with relative vertical 

accuracies within 20 centimeters.

The AUV survey grid in the study area consists of one-hundred sixty-seven (167) tracklines, 

including one-hundred fifty-five (155) primary lines (Line Nos. 101-155) running east-west at 

200-meter (656-foot) line spacing and twelve (12) tie lines (Line Nos. 201-212) running northsouth at 900-meter (2,953-foot) line spacing. Navigation fixes (event marks) were annotated at 
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125-meter (410-foot) intervals along all survey lines. The survey grid was designed to provide a 

representative sampling with the subbottom profiler system and overlapping coverage with side 

scan sonar and multibeam echosounder systems. 

3D Seismic Data

The 3D seismic data used for this assessment was provided in SEG-Y format. The data were 

loaded into IHS’ Kingdom Suite 2d/3dPAK for interpretation. The 3D data were acquired by 

CGGVeritas aboard the Symphony, and reprocessed with Post-Stack Time Migration (PSTM). 

The 3D data were provided at a four-millisecond sample rate and extend to the full data range of 

7.0 seconds. The inlines of the data run east-west and are spaced at 20-meter (65.62-foot) 

intervals, while the crosslines run north-south and are spaced at 12.5-meter (41.01-foot) 

intervals. Spectral whitening was applied to the 3D seismic dataset to amplify the higher 

frequencies. After applying the spectral whitening, a power spectrum generated at a few selected 

locations indicated the seismic data volume contains sufficiently high frequency content for a 

shallow hazards assessment (Figure 1). 

The 3D seismic data are zero phase, and the seafloor reflector is represented by a strong, positive 

amplitude peak flanked by troughs with absolute amplitude values of less than one-half of the 

peak value. The seismic data provided adequate screening of the regional seafloor and shallow 

geologic conditions, and large scale geohazards (faults, salt, high acoustic impedance, 

stratigraphic horizons, etc.).

WELL LOCATION

The coordinates and calls for the proposed Well “C” surface location are tabulated below:

Table 1. Proposed Well “C”

Well Easting 

(feet)

Northing

(feet)

Latitude Longitude Calls From Block 198,

Atwater Valley Area

“C” 1,036,276’ 10,079,951’ 27 45’ 53.223” N 88 52’ 06.868” W 6,676’ FWL 5,711’ FSL

A 2,000-foot clearance radius is required for assessing deepwater benthic communities in 

proximity to the proposed Well “C”.

The geodetic datum used for this project is the North American Datum 1927 (NAD27) with the 

Clarke 1866 Ellipsoid. The datum is projected using the Universal Transverse Mercator (UTM), 

Zone 16 North (16N) with a central meridian at 87° 00′W, a false easting of 1,640,416.67 feet at 

the central meridian, and a false northing of 0.00 feet at 00° 00′N. Mapping and reporting units 

are in U.S. Survey Feet.

REGIONAL GEOLOGY

The Gulf of Mexico is a semi-enclosed basin that has been receiving sediment influx dominated 

by the Mississippi River since the Late Jurassic. Mesozoic and Cenozoic sediments have 

attained a thickness in excess of 9 miles (Coleman et al., 1991). The prograded shelf sequence 

consists of intercalated coastal plain, delta, estuarine, and marine sediments. Sediment 

deposition along the northern rim of the Gulf of Mexico resulted in particularly thick Tertiary 
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and Quaternary sections. These rapidly deposited sediments have prograded the Cretaceous 

shelf-edge up to 185 miles basinward. The exceptionally high rate of shelf-edge progradation is 

on the order of 3.0 to 3.7 miles per 1,000 years. 

The near surface geology across the Gulf Coast region is the product of fluctuating sea levels 

associated with climatic variations over the past 20,000 years. During this time, low sea levels 

left the continental shelf exposed to subaerial weathering and other erosional processes. Streams 

and rivers meandered and cut into the exposed landmass, depositing bedloads along the modernday shelf break. Fan systems were formed, and mass movement events were common as deltaic 

sediments were deposited on the steep upper continental slope. As the climate warmed, seas 

transgressed, and marine sediments were deposited on the shelf.

BATHYMETRY AND SEAFLOOR GRADIENTS

The water depth at the proposed Well “C” location is 4,906 feet below mean sea level (MSL). 

Within the 2,000-foot radius area centered at the proposed Well “C” location, the seafloor depth 

ranges from 4,875 feet in the northwest to 4,934 feet in the southeast (Sheet 1, Color Shaded 

Bathymetry Map).

The proposed Well “C” location is situated on a very smooth sloping seafloor located in the 

northeastern corner of AT198 (Figure 2). The seafloor in the area surrounding the proposed well 

location slopes southeast at a gradient of less than 1° (Sheet 2, Seafloor Gradient Map).

SEAFLOOR HAZARDS

Low to moderate sonar reflectivity occurs around the proposed wellsite indicating mostly finegrained sediments (Figure 3).

The 3D seafloor amplitude image displays a range of low to moderate acoustic amplitudes within 

the 2,000-foot radius area (Sheet 3, Seafloor Amplitude Map). These low to moderate seafloor 

amplitudes indicate finely textured seafloor sediments that are likely comprised of hemipelagic 

clay.

No sonar contacts are found within 2,000 feet of the proposed well location. 

There were no seafloor features or potential hazards identified at or in proximity to the proposed 

well location (Sheet 4, Seafloor and Subsurface Hazards Map).

POTENTIAL DEEPWATER BENTHIC COMMUNITIES

High or low-amplitude seismic seafloor anomalies are potential indicators of carbonates, benthic 

community habitats, and gas/fluid seepages. The seafloor at the proposed Well “C” and 

surrounding 2,000-foot radius contains no high or low positive seafloor amplitude anomalies 

associated with fluid expulsion or mounded carbonates representing potential benthic 

communities. The side scan sonar and multibeam backscatter agree with the seafloor amplitude 

image, and show no evidence of outcrops or fluid expulsion.
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SUBSURFACE GEOHAZARDS AND STRATIGRAPHY

The AUV subbottom profiler data exhibit continuous, sharp bottom echoes with parallel to 

divergent, continuous reflectors throughout the wellsite area. The uppermost shallow sediments 

consist of a 20 to 25 foot thick acoustically semi-transparent hemipelagic clay drape. Sediments 

below this drape are characterized by parallel, low to moderate amplitude reflectors that 

represent cyclic deposition of hemipelagic clay and silty clays (Figure 4).

Five sedimentary units (Units A to E), each consisting of one or more distinctive sequences, 

were interpreted within the study area from the 3D seismic data to approximately 2 seconds of 

two-way traveltime (~5,000 feet) below the seafloor, the lower limit of investigation. Six

horizons mark the upper and/or lower contacts of each of the successive units (Figures 5 and 6). 

C&C was provided with a series of time-depth pairs for the sediment column. The following 

polynomial equation was derived from Total Vertical Depth (TVD) (feet) and the corresponding 

two-way traveltime (seconds) using the time-depth values to calculate depths below the seafloor:

D = 426.02T

2

+ 1,524.4T

where D = depth below seafloor in feet and T = time below seafloor in seconds.

A detailed description of the sequence units, beginning at the seafloor, can be found in the 2014

Geohazard Report. The Top-Hole Prognosis Chart (Figure 7) summarizes the stratigraphy.

Unit A (Seafloor to Horizon 1)

Unit A consists of mostly low amplitude, parallel, semi-continuous reflectors and measures 

1,290 feet thick at the proposed well location. The reflection patterns suggest the unit is 

comprised mostly of hemipelagic clay with interbedded fine-grained mass transport deposits. No 

high amplitude anomalies occur within Unit A near the proposed well location. 

Unit B (Horizon 1 to Horizon 2)

Unit B consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 1,592 feet thick at the proposed well location. Unit B is interpreted as fine-grained 

mass transport deposits atop an interbedded channel fill zone. No high amplitude anomalies 

occur within Unit B near the proposed well location.

Unit C (Horizon 2 to Horizon 3)

Unit C consists of low to moderate amplitude, semi-continuous to sub-parallel reflectors and 

measures 634 feet. This relatively thin unit is interpreted as mass transport deposits with a few 

interbedded channel fills. No high amplitude anomalies occur within Unit C near the proposed 

well location. 

Unit D (Horizon 3 to Horizon 4)

Unit D consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 2,080 feet thick at the proposed well location. The sediments in Unit D are interpreted 

as a coarser-grained channel fill between two finer-grained mass transport deposits. No high 
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amplitude anomalies occur within Unit D near the proposed well location. The coarser 

sediments found in the channel fill zone may represent low to moderate shallow water flow

potential. 

Unit E (Horizon 4 to Horizon 5)

Unit E consists of low to moderate amplitude, semi-continuous to subparallel reflectors and 

measures 1,196 feet thick at the proposed well location. The sediments in Unit E are interpreted 

as mostly channel fill sitting atop an interbedded mass transport deposit zone. No high 

amplitude anomalies occur within Unit E near the proposed well location. The coarser sediments 

found in the channel fill zone may represent low to moderate shallow water flow potential. 

Horizon 5 represents the salt/sediment interface at the proposed well location.

SHALLOW GAS

Anomalies of very high amplitude, commonly termed bright spots, are interpreted as potential 

regions of fluid saturation usually associated with porous sands. Seismic amplitude anomalies 

are mapped on a unit-by-unit basis to assess the potential risk of gas. Seismic amplitude 

anomalies are exhibited on the Seafloor & Subsurface Features Map.

The risk of gas refers to the risk of encountering shallow gas. The risk of gas is interpreted based 

on amplitude levels. Stratigraphic and structural settings may also be taken into account. The 

four risk levels of gas are:

 Negligible—No amplitude anomalies or other gas indicator present.

 Low risk of gas—Generally indicated by increased amplitude (2–3× background level) 

and phase reversal. This may also include diffuse areas of gas blanking.

 Moderate risk of gas—Generally indicated by high amplitude (3–4× background level) 

and phase reversal.

 High risk of gas—Generally indicated by the highest amplitudes (in excess of 4× 

background level), phase reversal, and a combination of other attributes indicative of the 

presence of gas, particularly velocity pull-down and masking of underlying sediments. 

There were no amplitude anomalies identified within 2,000 feet of the proposed Well “C”

location. All units are interpreted as having a low risk of gas.

SHALLOW WATER FLOW

Several factors may contribute to shallow water flows. These include: high porosity and 

permeability, sand-prone aquifer, mechanism to pressurize, and seal. Additional details are 

described below:

 Water depth and burial depth. Significant water depths (> 500 feet below the seafloor) 

are required for the overpressure to occur. The seal must be deeply buried (> 500 feet 

below the seafloor) to become sufficiently strong.

 High deposition rates. Sedimentation rate needs to be greater than 1,500 feet/myr to 

effectively seal in sands. Sedimentation rates are expected to be high within a salt 

withdrawal basin. Rapid burial leads to pressure disequilibrium. In addition, if these 
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sediment ‘packets’ were formed through a sequence of turbidites or gravity flow, there is an 

increased likelihood of water saturation and overpressure (pore pressure rapidly increased 

and sealed by an impervious layer). 

 Suitably porous sediments. The sediment packets comprising the risk of shallow water 

flow are believed to contain clastic material and are thus porous.

 Impermeable seal. The overlying sediments are comprised of a clay facies.

All of these factors occur within the study area. Since there is presently no method for 

quantifying the risk of shallow water flow, caution is recommended when drilling through units 

with shallow water flow potential. Sands with SWF potential often occur in unconsolidated, 

overpressured sands that lie below a seal. This seal prevents dewatering and compaction after 

deposition. The pressure rises with overburden causing a potentially disastrous hazard for 

drilling operations. 

The nearest reported shallow water flow was in AT194, approximately 10 miles west of the 

survey area, according to information listed on the BOEM and BSEE website. This SWF event 

is listed as occurring 2,132 feet below mudline and was categorized as a moderate severity flow. 

The assessment of seismic profiles suggests that Units A and C exhibit a low risk of SWF, while 

the coarser-grained channel fills within Units B, D, and E exhibit a low to moderate risk. Due to 

the unpredictable nature of SWF, it is advised that caution be executed for any drilling operations 

through these sediments.

GAS HYDRATES

Gas hydrates are an ice crystalline form of gas hydrocarbons in deepwater marine environments 

where the conditions of pressure and temperature are favorable. The hydrate stability zone is the 

depth interval between the seafloor and the point where the hydrate is no longer stable in form. 

The thermal gradient of the seabed soils determines the depth of the hydrate stability zone base. 

The acoustic impedance contrast caused between the hydrate and free gas trapped at the base of 

the hydrate stability zone forms a Bottom Simulating Reflector (BSR) on seismic profiles. This 

BSR reflector cross cuts the normal seismic stratigraphy, much like a bottom multiple.

The areas where seafloor gas hydrates accumulate in the near-surface sediments of the Gulf of 

Mexico are generally unfavorable sites for drilling operations. Irregular seafloor topography, gas 

seeps, gas chimneys, seafloor hydrates and deepwater benthic communities may all be found in 

close association. No indication of BSRs was found in the vicinity of the proposed well.

CONCLUSIONS

The proposed Well “C” location is situated on a very smooth sloping seafloor at a water depth of 

4,906 feet MSL. The seabed slopes gently to the southeast at a gradient of less than 1°.

There were no potential hazardous features identified near the proposed Well “C” location.

No sonar contacts exist within 2,000 feet of the proposed Well “C” location. 
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No high or low seafloor amplitudes anomalies that may indicate the occurrence of hardgrounds, 

carbonates, benthic communities or potential expulsions are found within 2,000 feet of the 

proposed Well “C” location.

Five (5) subsurface units interpreted from the 3D seismic data were assessed to approximately 

5,000 feet BSF at the proposed Well “C” location (Units A to E). Unit A is comprised mostly of 

low amplitude, parallel to semi-continuous reflectors and consists of hemipelagic clays and mass 

transport deposits. Unit B is characterized by low to moderate amplitude, semi-continuous to 

chaotic reflectors and consists of fine-grained mass transport deposits atop an interbedded 

channel fill zone. Unit C is comprised of low to moderate amplitude, semi-continuous reflectors 

and is interpreted as mostly mass transport deposits with a few interbedded channel fills. Units 

D and E consist of low to moderate, semi-continuous to chaotic reflectors and consists of 

alternating layers of fine-grained mass transport deposits and coarser-grained channel fill zones. 

There were no amplitude anomalies indicative of shallow gas identified within any of the units at 

the proposed Well “C” location. All units are therefore assessed as having a low risk of gas. No 

indication of gas hydrates was found within the study area.

Units A and C are assessed as having a low risk of SWF. The coarser-grained channel fills 

within Units B, D, and E are assessed as having a low to moderate risk of SWF. 

Thank you for this opportunity to be of service. Please contact us if you have any questions 

concerning this assessment.

Sincerely,

___________________________

Christopher Baker

Senior Geologist

ENCLOSURES

Figure 1. Extracted wavelet and power spectrum at the proposed Well “C”.

Figure 2. AUV seafloor bathymetry surrounding the proposed Well “C”.

Figure 3. Side scan sonar mosaic at the proposed Well “C”.

Figure 4. Subbottom profiler Line 143 near the proposed Well “C”.

Figure 5. 3D seismic Inline 1571 through the proposed Well “C”.

Figure 6. 3D seismic Crossline 10283 through the proposed Well “C”.

Figure 7. Top-Hole Prognosis Chart for the proposed Well “C”.

Sheet 1. Color Shaded Bathymetry Map, Proposed Well “C” Location 1”=1,000’

Sheet 2. Seafloor Gradient Map, Proposed Well “C” Location 1”=1,000’

Sheet 3. Seafloor Amplitude Map, Proposed Well “C” Location 1”=1,000’

Sheet 4. Seafloor & Subsurface Hazard Map, Proposed Well “C” Location 1”=1,000’
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October 21, 2014

Freeport-McMoRan Oil & Gas 

717 Texas Avenue, Suite 2100

Houston, TX 77002

Attn: Mr. Terry Arcuri

Site Clearance Letter

Proposed Well “D”

Block 198 (OCS-G-35431)

Atwater Valley Area

Dear Mr. Arcuri,

INTRODUCTION

Freeport-McMoRan Oil & Gas (FMOG) contracted C & C Technologies, Inc. (C&C) to prepare 

a wellsite clearance letter for the proposed Well “D” location in Block 198 (OCS-G-35431), 

Atwater Valley (AT) Area. The data used for the site clearance letter is based on the 

interpretation of an exploration-quality 3D seismic volume and a high-resolution geophysical 

dataset collected with C&C’s Autonomous Underwater Vehicle (AUV) C-Surveyor VITM. C&C 

completed the geohazard assessment titled “3D Shallow Hazard Report, Sun Prospect, Blocks 

154 (OCS-G-35019), 197 (OCS-G-35430), 198 (OCS-G-35431), and Vicinity, Atwater Valley 

Area” in October, 2014. This site clearance letter is based on the findings provided within that 

report.

This letter provides a top-hole drilling prognosis and addresses seafloor conditions within a 

2,000-foot radius of the proposed surface location. The depth limit of investigation is 

approximately 2.0 seconds of two-way traveltime (~5,000 feet) below the mud line (BML). The 

reporting and mapping presented in this letter comply with the BOEM/BSEE guidelines provided 

in NTL No. 2008-G05 (Shallow Hazards Program) and No. 2009-G40 (Deepwater Benthic 

Communities).

METHODS

AUV Survey Data

C&C’s C-Surveyor VITM AUV provided multibeam bathymetric mapping, high-resolution side 

scan sonar imagery, and subbottom profiles. The AUV remote-sensing instruments include a 

Kongsberg EM 2040 Swath Multibeam Sonar (200, 300, and 400 kHz), an EdgeTech 2200-M

Side Scan Sonar (410 and 120 kHz), and a custom EdgeTech Chirp DW106 Subbottom Profiler 

(1 - 6 kHz). All the raw digital data were logged utilizing proprietary software developed by 

C&C. The multibeam system delivered a 3-meter gridded dataset with relative vertical 

accuracies within 20 centimeters.

The AUV survey grid in the study area consists of one-hundred sixty-seven (167) tracklines, 

including one-hundred fifty-five (155) primary lines (Line Nos. 101-155) running east-west at 

200-meter (656-foot) line spacing and twelve (12) tie lines (Line Nos. 201-212) running northsouth at 900-meter (2,953-foot) line spacing. Navigation fixes (event marks) were annotated at 
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125-meter (410-foot) intervals along all survey lines. The survey grid was designed to provide a 

representative sampling with the subbottom profiler system and overlapping coverage with side 

scan sonar and multibeam echosounder systems. 

3D Seismic Data

The 3D seismic data used for this assessment was provided in SEG-Y format. The data were 

loaded into IHS’ Kingdom Suite 2d/3dPAK for interpretation. The 3D data were acquired by 

CGGVeritas aboard the Symphony, and reprocessed with Post-Stack Time Migration (PSTM). 

The 3D data were provided at a four-millisecond sample rate and extend to the full data range of 

7.0 seconds. The inlines of the data run east-west and are spaced at 20-meter (65.62-foot) 

intervals, while the crosslines run north-south and are spaced at 12.5-meter (41.01-foot) 

intervals. Spectral whitening was applied to the 3D seismic dataset to amplify the higher 

frequencies. After applying the spectral whitening, a power spectrum generated at a few selected 

locations indicated the seismic data volume contains sufficiently high frequency content for a 

shallow hazards assessment (Figure 1). 

The 3D seismic data are zero phase, and the seafloor reflector is represented by a strong, positive 

amplitude peak flanked by troughs with absolute amplitude values of less than one-half of the 

peak value. The seismic data provided adequate screening of the regional seafloor and shallow 

geologic conditions, and large scale geohazards (faults, salt, high acoustic impedance, 

stratigraphic horizons, etc.).

WELL LOCATION

The coordinates and calls for the proposed Well “D” surface location are tabulated below:

Table 1. Proposed Well “D”

Well Easting 

(feet)

Northing

(feet)

Latitude Longitude Calls From Block 198,

Atwater Valley Area

“D” 1,034,658’ 10,085,122’ 27 46’ 44.177” N 88 52’ 25.753” W 5,058’ FWL 4,958’ FNL

A 2,000-foot clearance radius is required for assessing deepwater benthic communities in 

proximity to the proposed Well “D”.

The geodetic datum used for this project is the North American Datum 1927 (NAD27) with the 

Clarke 1866 Ellipsoid. The datum is projected using the Universal Transverse Mercator (UTM), 

Zone 16 North (16N) with a central meridian at 87° 00′W, a false easting of 1,640,416.67 feet at 

the central meridian, and a false northing of 0.00 feet at 00° 00′N. Mapping and reporting units 

are in U.S. Survey Feet.

REGIONAL GEOLOGY

The Gulf of Mexico is a semi-enclosed basin that has been receiving sediment influx dominated 

by the Mississippi River since the Late Jurassic. Mesozoic and Cenozoic sediments have 

attained a thickness in excess of 9 miles (Coleman et al., 1991). The prograded shelf sequence 

consists of intercalated coastal plain, delta, estuarine, and marine sediments. Sediment 

deposition along the northern rim of the Gulf of Mexico resulted in particularly thick Tertiary 
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and Quaternary sections. These rapidly deposited sediments have prograded the Cretaceous 

shelf-edge up to 185 miles basinward. The exceptionally high rate of shelf-edge progradation is 

on the order of 3.0 to 3.7 miles per 1,000 years. 

The near surface geology across the Gulf Coast region is the product of fluctuating sea levels 

associated with climatic variations over the past 20,000 years. During this time, low sea levels 

left the continental shelf exposed to subaerial weathering and other erosional processes. Streams 

and rivers meandered and cut into the exposed landmass, depositing bedloads along the modernday shelf break. Fan systems were formed, and mass movement events were common as deltaic 

sediments were deposited on the steep upper continental slope. As the climate warmed, seas 

transgressed, and marine sediments were deposited on the shelf.

BATHYMETRY AND SEAFLOOR GRADIENTS

The water depth at the proposed Well “D” location is 4,835 feet below mean sea level (MSL). 

Within the 2,000-foot radius area centered at the proposed Well “D” location, the seafloor depth 

ranges from 4,809 feet in the northwest to 4,860 feet in the southeast (Sheet 1, Color Shaded 

Bathymetry Map).

The proposed Well “D” location is situated on a very smooth sloping seafloor located in the 

northeastern corner of AT198 (Figure 2). The seafloor in the area surrounding the proposed well 

location slopes southeast at a gradient of less than 1° (Sheet 2, Seafloor Gradient Map).

SEAFLOOR HAZARDS

Low to moderate sonar reflectivity occurs around the proposed wellsite indicating mostly finegrained sediments (Figure 3).

The 3D seafloor amplitude image displays a range of low to moderate acoustic amplitudes within 

the 2,000-foot radius area (Sheet 3, Seafloor Amplitude Map). These low to moderate seafloor 

amplitudes indicate finely textured seafloor sediments that are likely comprised of hemipelagic 

clay.

One sonar contact was found within 2,000 feet of the proposed well location. Sonar Contact No. 

7 was found 930 feet southeast of the proposed location and measures 13.3 feet long, 3.1 feet 

wide, and has no measurable height.

There were no seafloor features or potential hazards identified at or in proximity to the proposed 

well location (Sheet 4, Seafloor and Subsurface Hazards Map).

POTENTIAL DEEPWATER BENTHIC COMMUNITIES

High or low-amplitude seismic seafloor anomalies are potential indicators of carbonates, benthic 

community habitats, and gas/fluid seepages. The seafloor at the proposed Well “D” and 

surrounding 2,000-foot radius contains no high or low positive seafloor amplitude anomalies 

associated with fluid expulsion or mounded carbonates representing potential benthic 

communities. The side scan sonar and multibeam backscatter agree with the seafloor amplitude 

image, and show no evidence of outcrops or fluid expulsion.
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SUBSURFACE GEOHAZARDS AND STRATIGRAPHY

The AUV subbottom profiler data exhibit continuous, sharp bottom echoes with parallel to 

divergent, continuous reflectors throughout the wellsite area. The uppermost shallow sediments 

consist of a 20 to 25 foot thick acoustically semi-transparent hemipelagic clay drape. Sediments 

below this drape are characterized by parallel, low to moderate amplitude reflectors that 

represent cyclic deposition of hemipelagic clay and silty clays (Figure 4).

Five sedimentary units (Units A to E), each consisting of one or more distinctive sequences, 

were interpreted within the study area from the 3D seismic data to approximately 2 seconds of 

two-way traveltime (~5,000 feet) below the seafloor, the lower limit of investigation. Six

horizons mark the upper and/or lower contacts of each of the successive units (Figures 5 and 6). 

C&C was provided with a series of time-depth pairs for the sediment column. The following 

polynomial equation was derived from Total Vertical Depth (TVD) (feet) and the corresponding 

two-way traveltime (seconds) using the time-depth values to calculate depths below the seafloor:

D = 426.02T

2

+ 1,524.4T

where D = depth below seafloor in feet and T = time below seafloor in seconds.

A detailed description of the sequence units, beginning at the seafloor, can be found in the 2014

Geohazard Report. The Top-Hole Prognosis Chart (Figure 7) summarizes the stratigraphy.

Unit A (Seafloor to Horizon 1)

Unit A consists of mostly low amplitude, parallel, semi-continuous reflectors and measures 

1,252 feet thick at the proposed well location. The reflection patterns suggest the unit is 

comprised mostly of hemipelagic clay with interbedded fine-grained mass transport deposits. No 

high amplitude anomalies occur within Unit A near the proposed well location. 

Unit B (Horizon 1 to Horizon 2)

Unit B consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 1,818 feet thick at the proposed well location. Unit B is interpreted as fine-grained 

mass transport deposits atop an interbedded channel fill zone. No high amplitude anomalies 

occur within Unit B near the proposed well location.

Unit C (Horizon 2 to Horizon 3)

Unit C consists of low to moderate amplitude, semi-continuous to sub-parallel reflectors and 

measures 690 feet. This relatively thin unit is interpreted as mass transport deposits with a few 

interbedded channel fills. No high amplitude anomalies occur within Unit C near the proposed 

well location. 

Unit D (Horizon 3 to Horizon 4)

Unit D consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 2,127 feet thick at the proposed well location. The sediments in Unit D are interpreted 

as a coarser-grained channel fill between two finer-grained mass transport deposits. No high 
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amplitude anomalies occur within Unit D near the proposed well location. The coarser 

sediments found in the channel fill zone may represent low to moderate shallow water flow 

potential. 

Unit E (Horizon 4 to Horizon 5)

Unit E consists of low to moderate amplitude, semi-continuous to subparallel reflectors and 

measures 1,367 feet thick at the proposed well location. The sediments in Unit E are interpreted 

as mostly channel fill sitting atop an interbedded mass transport deposit zone. No high 

amplitude anomalies occur within Unit E near the proposed well location. The coarser sediments 

found in the channel fill zone may represent low to moderate shallow water flow potential. 

Horizon 5 represents the salt/sediment interface at the proposed well location.

SHALLOW GAS

Anomalies of very high amplitude, commonly termed bright spots, are interpreted as potential 

regions of fluid saturation usually associated with porous sands. Seismic amplitude anomalies 

are mapped on a unit-by-unit basis to assess the potential risk of gas. Seismic amplitude 

anomalies are exhibited on the Seafloor & Subsurface Features Map.

The risk of gas refers to the risk of encountering shallow gas. The risk of gas is interpreted based 

on amplitude levels. Stratigraphic and structural settings may also be taken into account. The 

four risk levels of gas are:

 Negligible—No amplitude anomalies or other gas indicator present.

 Low risk of gas—Generally indicated by increased amplitude (2–3× background level) 

and phase reversal. This may also include diffuse areas of gas blanking.

 Moderate risk of gas—Generally indicated by high amplitude (3–4× background level) 

and phase reversal.

 High risk of gas—Generally indicated by the highest amplitudes (in excess of 4× 

background level), phase reversal, and a combination of other attributes indicative of the 

presence of gas, particularly velocity pull-down and masking of underlying sediments. 

There were no amplitude anomalies identified within 2,000 feet of the proposed Well “D”

location. All units are interpreted as having a low risk of gas.

SHALLOW WATER FLOW

Several factors may contribute to shallow water flows. These include: high porosity and 

permeability, sand-prone aquifer, mechanism to pressurize, and seal. Additional details are 

described below:

 Water depth and burial depth. Significant water depths (> 500 feet below the seafloor) 

are required for the overpressure to occur. The seal must be deeply buried (> 500 feet 

below the seafloor) to become sufficiently strong.

 High deposition rates. Sedimentation rate needs to be greater than 1,500 feet/myr to 

effectively seal in sands. Sedimentation rates are expected to be high within a salt 

withdrawal basin. Rapid burial leads to pressure disequilibrium. In addition, if these 
C&C Project No. 140712

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sediment ‘packets’ were formed through a sequence of turbidites or gravity flow, there is an 

increased likelihood of water saturation and overpressure (pore pressure rapidly increased 

and sealed by an impervious layer). 

 Suitably porous sediments. The sediment packets comprising the risk of shallow water 

flow are believed to contain clastic material and are thus porous.

 Impermeable seal. The overlying sediments are comprised of a clay facies.

All of these factors occur within the study area. Since there is presently no method for 

quantifying the risk of shallow water flow, caution is recommended when drilling through units 

with shallow water flow potential. Sands with SWF potential often occur in unconsolidated, 

overpressured sands that lie below a seal. This seal prevents dewatering and compaction after 

deposition. The pressure rises with overburden causing a potentially disastrous hazard for 

drilling operations. 

The nearest reported shallow water flow was in AT194, approximately 10 miles west of the 

survey area, according to information listed on the BOEM and BSEE website. This SWF event 

is listed as occurring 2,132 feet below mudline and was categorized as a moderate severity flow. 

The assessment of seismic profiles suggests that Units A and C exhibit a low risk of SWF, while 

the coarser-grained channel fills within Units B, D, and E exhibit a low to moderate risk. Due to 

the unpredictable nature of SWF, it is advised that caution be executed for any drilling operations 

through these sediments.

GAS HYDRATES

Gas hydrates are an ice crystalline form of gas hydrocarbons in deepwater marine environments 

where the conditions of pressure and temperature are favorable. The hydrate stability zone is the 

depth interval between the seafloor and the point where the hydrate is no longer stable in form. 

The thermal gradient of the seabed soils determines the depth of the hydrate stability zone base. 

The acoustic impedance contrast caused between the hydrate and free gas trapped at the base of 

the hydrate stability zone forms a Bottom Simulating Reflector (BSR) on seismic profiles. This 

BSR reflector cross cuts the normal seismic stratigraphy, much like a bottom multiple.

The areas where seafloor gas hydrates accumulate in the near-surface sediments of the Gulf of 

Mexico are generally unfavorable sites for drilling operations. Irregular seafloor topography, gas 

seeps, gas chimneys, seafloor hydrates and deepwater benthic communities may all be found in 

close association. No indication of BSRs was found in the vicinity of the proposed well.

CONCLUSIONS

The proposed Well “D” location is situated on a very smooth sloping seafloor at a water depth of 

4,835 feet MSL. The seabed slopes gently to the southeast at a gradient of less than 1°.

There were no potential hazardous features identified near the proposed Well “D” location.
C&C Project No. 140712

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One sonar contact was found within 2,000 feet of the proposed well location. Sonar Contact No. 

7 was found 930 feet southeast of the proposed location and measures 13.3 feet long, 3.1 feet 

wide, and has no measurable height.

No high or low seafloor amplitudes anomalies that may indicate the occurrence of hardgrounds, 

carbonates, benthic communities or potential expulsions are found within 2,000 feet of the 

proposed Well “D” location.

Five (5) subsurface units interpreted from the 3D seismic data were assessed to approximately 

5,000 feet BSF at the proposed Well “D” location (Units A to E). Unit A is comprised mostly of 

low amplitude, parallel to semi-continuous reflectors and consists of hemipelagic clays and mass 

transport deposits. Unit B is characterized by low to moderate amplitude, semi-continuous to 

chaotic reflectors and consists of fine-grained mass transport deposits atop an interbedded 

channel fill zone. Unit C is comprised of low to moderate amplitude, semi-continuous reflectors 

and is interpreted as mostly mass transport deposits with a few interbedded channel fills. Units 

D and E consist of low to moderate, semi-continuous to chaotic reflectors and consists of 

alternating layers of fine-grained mass transport deposits and coarser-grained channel fill zones. 

There were no amplitude anomalies indicative of shallow gas identified within any of the units at 

the proposed Well “D” location. All units are therefore assessed as having a low risk of gas. No 

indication of gas hydrates was found within the study area.

Units A and C are assessed as having a low risk of SWF. The coarser-grained channel fills 

within Units B, D, and E are assessed as having a low to moderate risk of SWF. 

Thank you for this opportunity to be of service. Please contact us if you have any questions 

concerning this assessment.

Sincerely,

___________________________

Christopher Baker

Senior Geologist
C&C Project No. 140712

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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

ENCLOSURES

Figure 1. Extracted wavelet and power spectrum at the proposed Well “D”.

Figure 2. AUV seafloor bathymetry surrounding the proposed Well “D”.

Figure 3. Side scan sonar mosaic at the proposed Well “D”.

Figure 4. Subbottom profiler Line 136 near the proposed Well “D”.

Figure 5. 3D seismic Inline 1649 through the proposed Well “D”.

Figure 6. 3D seismic Crossline 10244 through the proposed Well “D”.

Figure 7. Top-Hole Prognosis Chart for the proposed Well “D”.

Sheet 1. Color Shaded Bathymetry Map, Proposed Well “D” Location 1”=1,000’

Sheet 2. Seafloor Gradient Map, Proposed Well “D” Location 1”=1,000’

Sheet 3. Seafloor Amplitude Map, Proposed Well “D” Location 1”=1,000’

Sheet 4. Seafloor & Subsurface Hazard Map, Proposed Well “D” Location 1”=1,000’
C&C Project No. 140712

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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

October 21, 2014

Freeport-McMoRan Oil & Gas 

717 Texas Avenue, Suite 2100

Houston, TX 77002

Attn: Mr. Terry Arcuri

Site Clearance Letter

Proposed Well “E”

Block 198 (OCS-G-35431)

Atwater Valley Area

Dear Mr. Arcuri,

INTRODUCTION

Freeport-McMoRan Oil & Gas (FMOG) contracted C & C Technologies, Inc. (C&C) to prepare 

a wellsite clearance letter for the proposed Well “E” location in Block 198 (OCS-G-35431), 

Atwater Valley (AT) Area. The data used for the site clearance letter is based on the 

interpretation of an exploration-quality 3D seismic volume and a high-resolution geophysical 

dataset collected with C&C’s Autonomous Underwater Vehicle (AUV) C-Surveyor VITM. C&C 

completed the geohazard assessment titled “3D Shallow Hazard Report, Sun Prospect, Blocks 

154 (OCS-G-35019), 197 (OCS-G-35430), 198 (OCS-G-35431), and Vicinity, Atwater Valley 

Area” in October, 2014. This site clearance letter is based on the findings provided within that 

report.

This letter provides a top-hole drilling prognosis and addresses seafloor conditions within a 

2,000-foot radius of the proposed surface location. The depth limit of investigation is 

approximately 2.0 seconds of two-way traveltime (~5,000 feet) below the mud line (BML). The 

reporting and mapping presented in this letter comply with the BOEM/BSEE guidelines provided 

in NTL No. 2008-G05 (Shallow Hazards Program) and No. 2009-G40 (Deepwater Benthic 

Communities).

METHODS

AUV Survey Data

C&C’s C-Surveyor VITM AUV provided multibeam bathymetric mapping, high-resolution side 

scan sonar imagery, and subbottom profiles. The AUV remote-sensing instruments include a 

Kongsberg EM 2040 Swath Multibeam Sonar (200, 300, and 400 kHz), an EdgeTech 2200-M

Side Scan Sonar (410 and 120 kHz), and a custom EdgeTech Chirp DW106 Subbottom Profiler 

(1 - 6 kHz). All the raw digital data were logged utilizing proprietary software developed by 

C&C. The multibeam system delivered a 3-meter gridded dataset with relative vertical 

accuracies within 20 centimeters.

The AUV survey grid in the study area consists of one-hundred sixty-seven (167) tracklines, 

including one-hundred fifty-five (155) primary lines (Line Nos. 101-155) running east-west at 

200-meter (656-foot) line spacing and twelve (12) tie lines (Line Nos. 201-212) running northsouth at 900-meter (2,953-foot) line spacing. Navigation fixes (event marks) were annotated at 
C&C Project No. 140712

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125-meter (410-foot) intervals along all survey lines. The survey grid was designed to provide a 

representative sampling with the subbottom profiler system and overlapping coverage with side 

scan sonar and multibeam echosounder systems. 

3D Seismic Data

The 3D seismic data used for this assessment was provided in SEG-Y format. The data were 

loaded into IHS’ Kingdom Suite 2d/3dPAK for interpretation. The 3D data were acquired by 

CGGVeritas aboard the Symphony, and reprocessed with Post-Stack Time Migration (PSTM). 

The 3D data were provided at a four-millisecond sample rate and extend to the full data range of 

7.0 seconds. The inlines of the data run east-west and are spaced at 20-meter (65.62-foot) 

intervals, while the crosslines run north-south and are spaced at 12.5-meter (41.01-foot) 

intervals. Spectral whitening was applied to the 3D seismic dataset to amplify the higher 

frequencies. After applying the spectral whitening, a power spectrum generated at a few selected 

locations indicated the seismic data volume contains sufficiently high frequency content for a 

shallow hazards assessment (Figure 1). 

The 3D seismic data are zero phase, and the seafloor reflector is represented by a strong, positive 

amplitude peak flanked by troughs with absolute amplitude values of less than one-half of the 

peak value. The seismic data provided adequate screening of the regional seafloor and shallow 

geologic conditions, and large scale geohazards (faults, salt, high acoustic impedance, 

stratigraphic horizons, etc.).

WELL LOCATION

The coordinates and calls for the proposed Well “E” surface location are tabulated below:

Table 1. Proposed Well “E”

Well Easting 

(feet)

Northing

(feet)

Latitude Longitude Calls From Block 198,

Atwater Valley Area

“E” 1,036,910’ 10,084,657’ 27 46’ 39.912” N 88 52’ 00.607” W 7,310’ FWL 5,423’ FNL

A 2,000-foot clearance radius is required for assessing deepwater benthic communities in 

proximity to the proposed Well “E”.

The geodetic datum used for this project is the North American Datum 1927 (NAD27) with the 

Clarke 1866 Ellipsoid. The datum is projected using the Universal Transverse Mercator (UTM), 

Zone 16 North (16N) with a central meridian at 87° 00′W, a false easting of 1,640,416.67 feet at 

the central meridian, and a false northing of 0.00 feet at 00° 00′N. Mapping and reporting units 

are in U.S. Survey Feet.

REGIONAL GEOLOGY

The Gulf of Mexico is a semi-enclosed basin that has been receiving sediment influx dominated 

by the Mississippi River since the Late Jurassic. Mesozoic and Cenozoic sediments have 

attained a thickness in excess of 9 miles (Coleman et al., 1991). The prograded shelf sequence 

consists of intercalated coastal plain, delta, estuarine, and marine sediments. Sediment 

deposition along the northern rim of the Gulf of Mexico resulted in particularly thick Tertiary 
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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

and Quaternary sections. These rapidly deposited sediments have prograded the Cretaceous 

shelf-edge up to 185 miles basinward. The exceptionally high rate of shelf-edge progradation is 

on the order of 3.0 to 3.7 miles per 1,000 years. 

The near surface geology across the Gulf Coast region is the product of fluctuating sea levels 

associated with climatic variations over the past 20,000 years. During this time, low sea levels 

left the continental shelf exposed to subaerial weathering and other erosional processes. Streams 

and rivers meandered and cut into the exposed landmass, depositing bedloads along the modernday shelf break. Fan systems were formed, and mass movement events were common as deltaic 

sediments were deposited on the steep upper continental slope. As the climate warmed, seas 

transgressed, and marine sediments were deposited on the shelf.

BATHYMETRY AND SEAFLOOR GRADIENTS

The water depth at the proposed Well “E” location is 4,860 feet below mean sea level (MSL). 

Within the 2,000-foot radius area centered at the proposed Well “E” location, the seafloor depth 

ranges from 4,832 feet in the northwest to 4,890 feet in the southeast (Sheet 1, Color Shaded 

Bathymetry Map).

The proposed Well “E” location is situated on a very smooth sloping seafloor located in the 

northeastern corner of AT198 (Figure 2). The seafloor in the area surrounding the proposed well 

location slopes southeast at a gradient of less than 1° (Sheet 2, Seafloor Gradient Map).

SEAFLOOR HAZARDS

Low to moderate sonar reflectivity occurs around the proposed wellsite indicating mostly finegrained sediments (Figure 3).

The 3D seafloor amplitude image displays a range of low to moderate acoustic amplitudes within 

the 2,000-foot radius area (Sheet 3, Seafloor Amplitude Map). These low to moderate seafloor 

amplitudes indicate finely textured seafloor sediments that are likely comprised of hemipelagic 

clay.

One sonar contact was found within 2,000 feet of the proposed well location. Sonar Contact No. 

7 was found 1,382 feet west of the proposed location and measures 13.3 feet long, 3.1 feet wide, 

and has no measurable height.

There were no seafloor features or potential hazards identified at or in proximity to the proposed 

well location (Sheet 4, Seafloor and Subsurface Hazards Map).

POTENTIAL DEEPWATER BENTHIC COMMUNITIES

High or low-amplitude seismic seafloor anomalies are potential indicators of carbonates, benthic 

community habitats, and gas/fluid seepages. The seafloor at the proposed Well “E” and 

surrounding 2,000-foot radius contains no high or low positive seafloor amplitude anomalies 

associated with fluid expulsion or mounded carbonates representing potential benthic 

communities. The side scan sonar and multibeam backscatter agree with the seafloor amplitude 

image, and show no evidence of outcrops or fluid expulsion.
C&C Project No. 140712

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SUBSURFACE GEOHAZARDS AND STRATIGRAPHY

The AUV subbottom profiler data exhibit continuous, sharp bottom echoes with parallel to 

divergent, continuous reflectors throughout the wellsite area. The uppermost shallow sediments 

consist of a 20 to 25 foot thick acoustically semi-transparent hemipelagic clay drape. Sediments 

below this drape are characterized by parallel, low to moderate amplitude reflectors that 

represent cyclic deposition of hemipelagic clay and silty clays (Figure 4).

Five sedimentary units (Units A to E), each consisting of one or more distinctive sequences, 

were interpreted within the study area from the 3D seismic data to approximately 2 seconds of 

two-way traveltime (~5,000 feet) below the seafloor, the lower limit of investigation. Six

horizons mark the upper and/or lower contacts of each of the successive units (Figures 5 and 6). 

C&C was provided with a series of time-depth pairs for the sediment column. The following 

polynomial equation was derived from Total Vertical Depth (TVD) (feet) and the corresponding 

two-way traveltime (seconds) using the time-depth values to calculate depths below the seafloor:

D = 426.02T

2

+ 1,524.4T

where D = depth below seafloor in feet and T = time below seafloor in seconds.

A detailed description of the sequence units, beginning at the seafloor, can be found in the 2014

Geohazard Report. The Top-Hole Prognosis Chart (Figure 7) summarizes the stratigraphy.

Unit A (Seafloor to Horizon 1)

Unit A consists of mostly low amplitude, parallel, semi-continuous reflectors and measures 

1,161 feet thick at the proposed well location. The reflection patterns suggest the unit is 

comprised mostly of hemipelagic clay with interbedded fine-grained mass transport deposits. No 

high amplitude anomalies occur within Unit A near the proposed well location. 

Unit B (Horizon 1 to Horizon 2)

Unit B consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 1,874 feet thick at the proposed well location. Unit B is interpreted as fine-grained 

mass transport deposits atop an interbedded channel fill zone. No high amplitude anomalies 

occur within Unit B near the proposed well location.

Unit C (Horizon 2 to Horizon 3)

Unit C consists of low to moderate amplitude, semi-continuous to sub-parallel reflectors and 

measures 649 feet. This relatively thin unit is interpreted as mass transport deposits with a few 

interbedded channel fills. No high amplitude anomalies occur within Unit C near the proposed 

well location. 

Unit D (Horizon 3 to Horizon 4)

Unit D consists of low to moderate amplitude, semi-continuous to chaotic reflectors and 

measures 2,096 feet thick at the proposed well location. The sediments in Unit D are interpreted 

as a coarser-grained channel fill between two finer-grained mass transport deposits. No high 
C&C Project No. 140712

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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

amplitude anomalies occur within Unit D near the proposed well location. The coarser 

sediments found in the channel fill zone may represent low to moderate shallow water flow 

potential. 

Unit E (Horizon 4 to Horizon 5)

Unit E consists of low to moderate amplitude, semi-continuous to subparallel reflectors and 

measures 1,406 feet thick at the proposed well location. The sediments in Unit E are interpreted 

as mostly channel fill sitting atop an interbedded mass transport deposit zone. No high 

amplitude anomalies occur within Unit E near the proposed well location. The coarser sediments 

found in the channel fill zone may represent low to moderate shallow water flow potential. 

Horizon 5 represents the salt/sediment interface at the proposed well location.

SHALLOW GAS

Anomalies of very high amplitude, commonly termed bright spots, are interpreted as potential 

regions of fluid saturation usually associated with porous sands. Seismic amplitude anomalies 

are mapped on a unit-by-unit basis to assess the potential risk of gas. Seismic amplitude 

anomalies are exhibited on the Seafloor & Subsurface Features Map.

The risk of gas refers to the risk of encountering shallow gas. The risk of gas is interpreted based 

on amplitude levels. Stratigraphic and structural settings may also be taken into account. The 

four risk levels of gas are:

 Negligible—No amplitude anomalies or other gas indicator present.

 Low risk of gas—Generally indicated by increased amplitude (2–3× background level) 

and phase reversal. This may also include diffuse areas of gas blanking.

 Moderate risk of gas—Generally indicated by high amplitude (3–4× background level) 

and phase reversal.

 High risk of gas—Generally indicated by the highest amplitudes (in excess of 4× 

background level), phase reversal, and a combination of other attributes indicative of the 

presence of gas, particularly velocity pull-down and masking of underlying sediments. 

There were no amplitude anomalies identified within 2,000 feet of the proposed Well “E”

location. All units are interpreted as having a low risk of gas.

SHALLOW WATER FLOW

Several factors may contribute to shallow water flows. These include: high porosity and 

permeability, sand-prone aquifer, mechanism to pressurize, and seal. Additional details are 

described below:

 Water depth and burial depth. Significant water depths (> 500 feet below the seafloor) 

are required for the overpressure to occur. The seal must be deeply buried (> 500 feet 

below the seafloor) to become sufficiently strong.

 High deposition rates. Sedimentation rate needs to be greater than 1,500 feet/myr to 

effectively seal in sands. Sedimentation rates are expected to be high within a salt 

withdrawal basin. Rapid burial leads to pressure disequilibrium. In addition, if these 
C&C Project No. 140712

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730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

sediment ‘packets’ were formed through a sequence of turbidites or gravity flow, there is an 

increased likelihood of water saturation and overpressure (pore pressure rapidly increased 

and sealed by an impervious layer). 

 Suitably porous sediments. The sediment packets comprising the risk of shallow water 

flow are believed to contain clastic material and are thus porous.

 Impermeable seal. The overlying sediments are comprised of a clay facies.

All of these factors occur within the study area. Since there is presently no method for 

quantifying the risk of shallow water flow, caution is recommended when drilling through units 

with shallow water flow potential. Sands with SWF potential often occur in unconsolidated, 

overpressured sands that lie below a seal. This seal prevents dewatering and compaction after 

deposition. The pressure rises with overburden causing a potentially disastrous hazard for 

drilling operations. 

The nearest reported shallow water flow was in AT194, approximately 10 miles west of the 

survey area, according to information listed on the BOEM and BSEE website. This SWF event 

is listed as occurring 2,132 feet below mudline and was categorized as a moderate severity flow. 

The assessment of seismic profiles suggests that Units A and C exhibit a low risk of SWF, while 

the coarser-grained channel fills within Units B, D, and E exhibit a low to moderate risk. Due to 

the unpredictable nature of SWF, it is advised that caution be executed for any drilling operations 

through these sediments.

GAS HYDRATES

Gas hydrates are an ice crystalline form of gas hydrocarbons in deepwater marine environments 

where the conditions of pressure and temperature are favorable. The hydrate stability zone is the 

depth interval between the seafloor and the point where the hydrate is no longer stable in form. 

The thermal gradient of the seabed soils determines the depth of the hydrate stability zone base. 

The acoustic impedance contrast caused between the hydrate and free gas trapped at the base of 

the hydrate stability zone forms a Bottom Simulating Reflector (BSR) on seismic profiles. This 

BSR reflector cross cuts the normal seismic stratigraphy, much like a bottom multiple.

The areas where seafloor gas hydrates accumulate in the near-surface sediments of the Gulf of 

Mexico are generally unfavorable sites for drilling operations. Irregular seafloor topography, gas 

seeps, gas chimneys, seafloor hydrates and deepwater benthic communities may all be found in 

close association. No indication of BSRs was found in the vicinity of the proposed well.

CONCLUSIONS

The proposed Well “E” location is situated on a very smooth sloping seafloor at a water depth of 

4,860 feet MSL. The seabed slopes gently to the southeast at a gradient of less than 1°.

There were no potential hazardous features identified near the proposed Well “E” location.
C&C Project No. 140712

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One sonar contact was found within 2,000 feet of the proposed well location. Sonar Contact No. 

7 was found 1,382 feet west of the proposed location and measures 13.3 feet long, 3.1 feet wide, 

and has no measurable height.

No high or low seafloor amplitudes anomalies that may indicate the occurrence of hardgrounds, 

carbonates, benthic communities or potential expulsions are found within 2,000 feet of the 

proposed Well “E” location.

Five (5) subsurface units interpreted from the 3D seismic data were assessed to approximately 

5,000 feet BSF at the proposed Well “E” location (Units A to E). Unit A is comprised mostly of 

low amplitude, parallel to semi-continuous reflectors and consists of hemipelagic clays and mass 

transport deposits. Unit B is characterized by low to moderate amplitude, semi-continuous to 

chaotic reflectors and consists of fine-grained mass transport deposits atop an interbedded 

channel fill zone. Unit C is comprised of low to moderate amplitude, semi-continuous reflectors 

and is interpreted as mostly mass transport deposits with a few interbedded channel fills. Units 

D and E consist of low to moderate, semi-continuous to chaotic reflectors and consists of 

alternating layers of fine-grained mass transport deposits and coarser-grained channel fill zones. 

There were no amplitude anomalies indicative of shallow gas identified within any of the units at 

the proposed Well “E” location. All units are therefore assessed as having a low risk of gas. No 

indication of gas hydrates was found within the study area.

Units A and C are assessed as having a low risk of SWF. The coarser-grained channel fills 

within Units B, D, and E are assessed as having a low to moderate risk of SWF. 

Thank you for this opportunity to be of service. Please contact us if you have any questions 

concerning this assessment.

Sincerely,

___________________________

Christopher Baker

Senior Geologist
C&C Project No. 140712

8

730 EAST KALISTE SALOOM ROAD, LAFAYETTE, LA 70508

ENCLOSURES

Figure 1. Extracted wavelet and power spectrum at the proposed Well “E”.

Figure 2. AUV seafloor bathymetry surrounding the proposed Well “E”.

Figure 3. Side scan sonar mosaic at the proposed Well “E”.

Figure 4. Subbottom profiler Line 136 near the proposed Well “E”.

Figure 5. 3D seismic Inline 1642 through the proposed Well “E”.

Figure 6. 3D seismic Crossline 10299 through the proposed Well “E”.

Figure 7. Top-Hole Prognosis Chart for the proposed Well “E”.

Sheet 1. Color Shaded Bathymetry Map, Proposed Well “E” Location 1”=1,000’

Sheet 2. Seafloor Gradient Map, Proposed Well “E” Location 1”=1,000’

Sheet 3. Seafloor Amplitude Map, Proposed Well “E” Location 1”=1,000’

Sheet 4. Seafloor & Subsurface Hazard Map, Proposed Well “E” Location 1”=1,000’
Freeport-McMoRan Oil & Gas LLC Section 4 – Pg. 8 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 4

HYDROGEN SULFIDE INFORMATION

4.1 CONCENTRATION

FM O&G anticipates encountering 0 ppm H2S during the proposed operations.

4.2 CLASSIFICATION

In accordance with Title 30 CFR 250.490(c), FM O&G requests that the area of proposed 

operations be classified by the BOEM as H2S absent. 
Freeport-McMoRan Oil & Gas LLC Section 5 – Pg. 9 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 5

BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION

5.1 DEEPWATER BENTHIC COMMUNITIES 

The seafloor disturbing activities proposed in this plan are in water depths greater than 300 

meters (984’). C & C Technologies Survey Services was contracted to provide an assessment 

of the shallow conditions at the proposed surface locations. The purpose of the assessment 

was to address seafloor conditions that may impact exploratory drilling operations within 2,000 

feet of the proposed well sites. FM O&G will avoid all high-density deepwater benthic 

communities by 2,000 feet from each proposed mud and cuttings discharge location and 250 

feet from the location of all other seafloor disturbances. As per NTL No. 2009-G40, “Deepwater 

Benthic Communities,” a map showing the 2,000 foot radius around the well site is included as 

Attachment 5-A.

5.2 TOPOGRAPHIC FEATURES (BANKS)

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

Activity Zone;” therefore, no map is required per NTL No. 2009-G39, “Biologically Sensitive 

Underwater Features and Areas.”

5.3 TOPOGRAPHIC FEATURES STATEMENT (SHUNTING)

All activities proposed under this EP will be conducted outside all Topographic Feature 

Protective Zones; therefore shunting of drill cuttings and drilling fluids is not required per NTL 

No. 2009-G39, “Biologically Sensitive Underwater Features and Areas.”

5.4 LIVE BOTTOMS (PINNACLE TREND FEATURES)

Atwater Valley Block 198 is not located within 61 meters (200 feet) of any pinnacle trend 

feature; therefore, a separate bathymetric map is not required per NTL No. 2009-G39, 

“Biologically Sensitive Underwater Features and Areas.”

5.5 LIVE BOTTOMS (LOW RELIEF) 

Atwater Valley Block 198 is not located within 30 meters (100 feet) of any live bottom (low relief)

feature with vertical relief equal to or greater than 8 feet; therefore, live bottom (low relief) maps 

are not required per NTL No. 2009-G39, “Biologically Sensitive Underwater Features and 

Areas.”

5.6 POTENTIALLY SENSITIVE BIOLOGICAL FEATURES MAP

Atwater Valley Block 198 is not located within 30 meters (100 feet) of potentially sensitive 

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

5.7 REMOTELY OPERATED VEHICLE (ROV) SURVEYS 

BOEM has determined there is enough data gathered in Grid Area 16; therefore, FM O&G will 

not be conducting any ROV surveys either pre-spud or post-drill operations per NTL No. 2008-

G06, “Remotely Operated Vehicle Surveys in Deepwater” (Extended by NTL No. 2014-N01, 

“Elimination of Expiration Dates on Certain Notices to Lessees and Operators Pending Review 

and Reissuance”).
Freeport-McMoRan Oil & Gas LLC Section 5 – Pg. 10 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

5.8 THREATENED AND ENDANGERED SPECIES, CRITICAL HABITAT, AND MARINE 

MAMMAL INFORMATION

The federally listed endangered and threatened species potentially occurring in the lease area 

and along the Gulf Coast are provided in the table below. 

Species Scientific Name Status Potential 

Presence

Critical Habitat Designated 

in the Gulf of Mexico

Lease 

Area

Coastal

Marine Mammals

Manatee, West 

Indian

Trichechus manatus latirostris E -- X Florida (peninsular)

Whale, Blue Balaenoptera masculus E X

a

-- None

Whale, Finback Balaenoptera physalus E X

a

-- None

Whale, 

Humpback

Megaptera novaeangliae E X

a

-- None

Whale, North 

Atlantic Right

Eubalaena glacialis E X

a

-- None

Whale, Sei Balaenopiera borealis E X

a

-- None

Whale, Sperm Physeter catodon 

(=macrocephalus)

E X -- None

Terrestrial Mammals

Mouse, Beach 

(Alabama, 

Choctawatchee, 

Perdido Key, St. 

Andrew)

Peromyscus polionotus E - X Alabama, Florida 

(panhandle) beaches

Birds

Plover, Piping Charadrius melodus T - X Coastal Texas, Louisiana, 

Mississippi, Alabama and 

Florida (panhandle)

Crane, Whooping Grus Americana E - X Coastal Texas

Reptiles

Sea Turtle, 

Green 

Chelonia mydas T,Eb

X X None

Sea Turtle, 

Hawksbill 

Eretmochelys imbricata E X X None

Sea Turtle, 

Kemp’s Ridley 

Lepidochelys kempli E X X None

Sea Turtle, 

Leatherback 

Dermochelys coriacea E X X None

Sea Turtle, 

Loggerhead

Caretta caretta T X X Texas, Louisiana, 

Mississippi, Alabama, 

Florida

Fish

Sturgeon, Gulf Acipenser oxyrinchus 

(=oxyrhynchus) desotoi

T X X Coastal Louisiana, 

Mississippi, Alabama and 

Florida (p anhandle)

Corals

Coral, Elkhorn Acopora palmate T - X Florida Keys and Dry 

Tortugas

Coral, Staghorn Acopora cervicornis T - X Florida

Abbreviations: E = Endangered; T = Threatened

a

The Blue Fin, Humpback, North Atlantic Right, and Sei Whales are rare or extralimital in the Gulf of Mexico and are 

unlikely to be present in the lease area. 

b Green Sea turtle is threatened, except for the Florida breeding population, which is listed as endangered.
Freeport-McMoRan Oil & Gas LLC Section 5 – Pg. 11 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

5.9 ARCHAEOLOGICAL REPORT

Atwater Valley Block 198 has been determined to be located in an archaeological area where 

historic shipwrecks may exist. In accordance with NTL No. 2005-G07 “Archaeological Surveys 

and Reports,” and NTL No. 2011-JOINT-G01, “Revisions to the List of OCS Lease Blocks 

Requiring Archaeological Resource Surveys and Reports,” an Archaeological Survey Report is 

provided with this plan.

5.10 AIR AND WATER QUALITY INFORMATION

Air and water quality information is not required to be included in this plan per NTL No. 2008-

G04, “Information requirements for Exploration Plans and Development Operations 

Coordination Documents” (Extended by NTL No. BOEM 2014-G05, “Extension of Prior Notices 

to Lessees”).

5.11 SOCIOECONOMIC INFORMATION

Socioeconomic Information is not required to be included in this plan per NTL No. 2008-G04, 

“Information Requirements for Exploration Plans and Development Operations Coordination 

Documents” (Extended by NTL No. BOEM 2014-G05, “Extension of Prior Notices to Lessees”).
AT198

OCS-G-35431

FM O&G

X= 1,033,178.00'

Y= 10,086,818.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "A" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)

ATTACHMENT 5-A
-158'

AT198

OCS-G-35431

FM O&G

7

X= 1,033,178.00'

Y= 10,086,818.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

AUV navigation trackline with name, direction run, fix, and

fix number (Job No. 130826)

Inline number for 3D seismic data spacing = 20 meters

(65.62 feet)

Crossline number for 3D seismic data spacing = 12.5

meters (41.01 feet)

7 Sonar contact & reference number

Fault scarp with seafloor displacement

(Hachures on downthrown side)

Normal fault with depth of burial

 (Hachures on downthrown side) -158'

Amplitude anomaly within Unit E

(2.896 - 4.705 seconds BSL) 3,255 - 11,620 feet BML

SONAR CONTACT

NUM. DESCRIPTION X COORDINATE Y COORDINATE

7 13.3'x3.1'x0.0' 1,035,538' 10,084,822'

PROPOSED WELL "A" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area
AT198

OCS-G-35431

FM O&G

X= 1,036,564.00'

Y= 10,083,073.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "B" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
AT198

OCS-G-35431

FM O&G

7

X= 1,036,564.00'

Y= 10,083,073.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

AUV navigation trackline with name, direction run, fix, and

fix number (Job No. 130826)

Inline number for 3D seismic data spacing = 20 meters

(65.62 feet)

Crossline number for 3D seismic data spacing = 12.5

meters (41.01 feet)

7 Sonar contact & reference number

SONAR CONTACT

NUM. DESCRIPTION X COORDINATE Y COORDINATE

7 13.3'x3.1'x0.0' 1,035,538' 10,084,822'

PROPOSED WELL "B" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area
AT198

OCS-G-35431

FM O&G

X= 1,036,276.00'

Y= 10,079,951.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "C" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
-5200'

-5010'

-4800'

AT198

OCS-G-35431

FM O&G

9

X= 1,036,276.00'

Y= 10,079,951.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

AUV navigation trackline with name, direction run, fix, and

fix number (Job No. 130826)

Inline number for 3D seismic data spacing = 20 meters

(65.62 feet)

Crossline number for 3D seismic data spacing = 12.5

meters (41.01 feet)

9 Sonar contact & reference number

Normal fault with depth of burial

 (Hachures on downthrown side) -5010'

PROPOSED WELL "C" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

9 12.7'x5.8'x0.0' 1,038,552' 10,077,776'

SONAR CONTACT

NUM. DESCRIPTION X COORDINATE Y COORDINATE
AT198

OCS-G-35431

FM O&G

X= 1,034,658.00'

Y= 10,085,122.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "D" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
AT198

OCS-G-35431

FM O&G

7

X= 1,034,658.00'

Y= 10,085,122.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

AUV navigation trackline with name, direction run, fix, and

fix number (Job No. 130826)

Inline number for 3D seismic data spacing = 20 meters

(65.62 feet)

Crossline number for 3D seismic data spacing = 12.5

meters (41.01 feet)

7 Sonar contact & reference number

SONAR CONTACT

NUM. DESCRIPTION X COORDINATE Y COORDINATE

7 13.3'x3.1'x0.0' 1,035,538' 10,084,822'

PROPOSED WELL "D" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area
AT198

OCS-G-35431

FM O&G

X= 1,036,910.00'

Y= 10,084,657.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

PROPOSED WELL "E" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Contour interval = 10 feet

Zero datum = Mean Sea Level

Color shaded image

6XQD]LPXWK 

6XQHOHYDWLRQ 

Multibeam processing sequence

1. Water column velocity corrections applied

2. Tide corrections applied using Goddard Ocean Tide Model GOT99.2

3. Bin size= 3 meters (9.84 feet)

4. Median filter applied

5. Produced gridded-binned dataset using weighted-neighbor algorithm;

search radius = 9 meters (29.53 feet)
AT198

OCS-G-35431

FM O&G

7

X= 1,036,910.00'

Y= 10,084,657.00'


1


:

JOB No: REVISED: DATE:

FILENAME:

140712 Oct. 20, 2014

1,000' 0' 1,000'

SCALE IN US SURVEY FEET

AUV navigation trackline with name, direction run, fix, and

fix number (Job No. 130826)

Inline number for 3D seismic data spacing = 20 meters

(65.62 feet)

Crossline number for 3D seismic data spacing = 12.5

meters (41.01 feet)

7 Sonar contact & reference number

SONAR CONTACT

NUM. DESCRIPTION X COORDINATE Y COORDINATE

7 13.3'x3.1'x0.0' 1,035,538' 10,084,822'

PROPOSED WELL "E" LOCATION

lock 198 (OCS-G-35431)

Atwater Valley Area

Amplitude anomaly within Unit D

(2.499 - 3.702 seconds BSL) 1,734 - 6,947 feet BML
Freeport-McMoRan Oil & Gas LLC Section 6 – Pg. 12 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 6

WASTES AND DISCHARGES INFORMATION

6.1 PROJECTED GENERATED WASTES

“Wastes You Will Generate, Treat and Downhole Dispose or Discharge to the Gulf of Mexico” is 

included as Attachment 6-A.

6.2 MODELING REPORT 

Modeling reports are not required for the activities proposed in this plan. 
 Attachment 6-A. WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR DISCHARGE TO THE GOM

Projected

Projected generated waste Projected ocean discharges Downhole Disposal

Type of Waste Composition Projected Amount Discharge Rate Discharge Method

Cuttings wetted with water-based fluid Cuttings coated while drilling with WBM 2,700 BBLS/WELL 386 BBLS/DAY/WELL Discharged to mudline prior to riser installation. Based on seven total 

days of drilling with WBM. No

Answer yes or no

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

Water-based drilling fluid Water, NaCI (salt), PHPA polymer and Barium

Sulfate (Barite) 60,000 BBLS/WELL 8,571 BBLS/DAY/WELL

Discharge at the mudline prior to the riser installation.

Nominal amount of unused fluid may be discharged at the

surface. Based on seven days of drilling with WBM.

No

Will humans be there? If yes, expect conventional waste

26,860 BBLS/WELL 158 BBLS/DAY/WELL USCG approved MSD with chlorination

Cuttings wetted with synthetic-based fluid Cuttings coated with synthetic drilling fluids,

including drilled out cement 6,300 BBLS/WELL 73 BBLS/DAY/WELL

Discharged to surface. Treated cutting will be discharged

overboard during drilling of the SBM intervals. Discharge rate is based 

upon 86 days of drilling. Cuttings will

be processed through a cuttings dryer, substantially reducing

the ROC percentage.

No

Domestic waste

Sanitary

 All liquids are expressed in barrels and solids expressed in pounds. All volumes were calculated on a total per well basis, unless otherwise noted.

 All discharged wastes will be treated to comply with the requirements of the NPDES permit.

Gray water from living quarters 58,820 BBLS/WELL 346 BBLS/DAY/WELL Chlorinate and discharge overboard No

Sanitary waste from living quarters, control 

rooms and change rooms.

Will you conduct well treatment, completion, or workover?

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

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

N/A N/A N/A N/A N/A

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

Deck Drainage Deck drainage from drilling floor 850 BBLS/WELL 5 BBLS/DAY/WELL No drill floor drainage routed to sea. All retained on board and 

processed to <15ppm or sent to shore for disposal No

No

KCl/acid/xylene

N/A

Will you be covered by an individual or general NPDES permit? General NPDES Permit # GMG290534

Well treatment fluids

Well completion fluids

Workover fluids

Desalinization unit discharge

Blowout prevent fluid

Ballast water

Bilge water

Excess cement at seafloor

Fire water 

Cooling water Sea Water with no additional chemicals 100,699,330 BBLS/WELL 592,349 BBLS/DAY/WELL Hull discharge overboard No

N/A

N/A

N/A

Rejected water from the watermaker. 256,700 BBLS/WELL 1,510 BBLS/DAY/WELL Hull discharge overboard No

N/A

N/A

N/A

N/A

N/A

N/A

ZnBr2/CaBr2/CaCl2/KCL

ZnBr2/CaBr2/CaCl2/KCL

N/A

N/A

N/A

Sea Water with no additional chemicals 340 BBLS/WELL 2 BBLS/DAY/WELL Hull discharge overboard No

Cement Slurry 530 BBLS/WELL 530 BBLS/DAY/WELL Discharge at seafloor during riserless operations. Discharge rate based 

upon 1 day (22" cement returns) No

N/A N/A N/A N/A N/A

Potable Water with

4% Stack-Magic ECO-Fv2 1,200 BBLS/WELL 7 BBLS/DAY/WELL Discharge at the seafloor or with deck drainage when testedat surface No

Uncontaminated seawater used to maintain 

proper draft 27,000 BBLS/WELL 159 BBLS/DAY/WELL Hull discharge overboard. Based upon 5 major ballast operations, with rig at operating draft minimal ballast change is required No

ATTACHMENT 6-A
Freeport-McMoRan Oil & Gas LLC Section 7 – Pg. 13 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 7

AIR EMISSIONS INFORMATION

7.1 EMISSIONS WORKSHEETS AND SCREENING QUESTIONS

Screen Questions for EP’s Yes No

Is any calculated Complex Total (CT) Emission amount (tons) associated with 

your proposed exploration activities more than 90% of the amounts calculated 

using the following formulas: CT = 3400D2/3 for CO, and CT = 33.3D for the other 

air pollutants (where D = distance to shore in miles)?

X

Do your emission calculations include any emission reduction measures or 

modified emission factors?

X

Are your proposed exploration activities located east of 87.5° W longitude? X

Do you expect to encounter H2S at concentrations greater than 20 parts per 

million (ppm)?

X

Do you propose to flare or vent natural gas for more than 48 continuous hours 

from any proposed well? X

Do you propose to burn produced hydrocarbon liquids? X

7.2 SUMMARY INFORMATION

Included as Attachment 7-A are Air Emission Worksheets which show the emissions 

calculations. There are no existing facilities or activities co-located with the proposed activities; 

therefore, the Plan Emissions are the same as the Complex Total Emissions.

This information was calculated by: Callie Hutchinson

281-698-8545

callie.hutchinson@jccteam.com
EXPLORATION PLAN (EP)

AIR QUALITY SCREENING CHECKLIST

OMB Control No. 1010-0151

OMB Approval Expires: 12/31/2011

COMPANY Freeport-McMoRan Oil & Gas LLC

AREA Atwater Valley

BLOCK 198

LEASE OCS-G 35431

PLATFORM NA

WELL Locations A, B, C, D, E

COMPANY CONTACT Callie Hutchinson

TELEPHONE NO. 281-578-3388

REMARKS Drill, complete, test, flare and install subsea trees. FM O&G will use a 

drillship similar to the Deepwater Champion. Total horsepower is 

calculated at 82% of actual horsepower of Deepwater Champion (Total 

horsepower = 60,348 hp). Actual fuel usage calculated at highest monthly 

average in 6 month fuel usage data for Deepwater Champion.

MMS FORM MMS-138 (December 2008 - Supersedes all previous versions of form MMS-138 which may not be used). Page 1 of 8

ATTACHMENT 7-A
EMISSIONS FACTORS

Fuel Usage Conversion Factors Natural Gas Turbines Natural Gas Engines Diesel Recip. Engine REF. DATE

SCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483 AP42 3.2-1 4/76 & 8/84

Equipment/Emission Factors units PM SOx NOx VOC CO REF. DATE

NG Turbines gms/hp-hr 0.00247 1.3 0.01 0.83 AP42 3.2-1& 3.1-1 10/96

NG 2-cycle lean gms/hp-hr 0.00185 10.9 0.43 1.5 AP42 3.2-1 10/96

NG 4-cycle lean gms/hp-hr 0.00185 11.8 0.72 1.6 AP42 3.2-1 10/96

NG 4-cycle rich gms/hp-hr 0.00185 10 0.14 8.6 AP42 3.2-1 10/96

Diesel Recip. < 600 hp. gms/hp-hr 1 1.468 14 1.12 3.03 AP42 3.3-1 10/96

Diesel Recip. > 600 hp. gms/hp-hr 0.32 1.468 11 0.33 2.4 AP42 3.4-1 10/96

Diesel Boiler lbs/bbl 0.084 2.42 0.84 0.008 0.21 AP42 1.3-12,14 9/98

NG Heaters/Boilers/Burners lbs/mmscf 7.6 0.593 100 5.5 84 AP42 1.4-1, 14-2, & 14-3 7/98

NG Flares lbs/mmscf 0.593 71.4 60.3 388.5 AP42 11.5-1 9/91

Liquid Flaring lbs/bbl 0.42 6.83 2 0.01 0.21 AP42 1.3-1 & 1.3-3 9/98

Tank Vapors lbs/bbl 0.03 E&P Forum 1/93

Fugitives lbs/hr/comp. 0.0005 API Study 12/93

Glycol Dehydrator Vent lbs/mmscf 6.6 La. DEQ 1991

Gas 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

MMS FORM MMS-138 (December 2008 - Supersedes all previous versions of form MMS-138 which may not be used). Page 2 of 8
EMISSIONS CALCULATIONS 1ST YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

Freeport-McMoRan Oil & Gas LLC Atwater Valley 198 OCS-G 35431 NA Locations A, B, C, D, E Callie Hutchinson 281-578-3388

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR ESTIMATED TONS

Diesel Engines HP GAL/HR GAL/D

Nat. Gas Engines HP SCF/HR SCF/D

Burners MMBTU/HR SCF/HR SCF/D HR/D DAYS PM SOx NOx VOC CO PM SOx NOx VOC CO

DRILLING PRIME MOVER>600hp diesel 49486 2390.1738 14179.00 24 307 34.88 160.01 1199.00 35.97 261.60 31.76 145.71 1091.80 32.75 238.21

PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 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 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 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 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 0.00 0.00 0.00 0.00

VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 6 132 1.46 6.68 50.03 1.50 10.92 0.57 2.64 19.75 0.59 4.31

VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 132 3.10 14.23 106.61 3.20 23.26 2.04 9.36 70.13 2.10 15.30

VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 132 3.10 14.23 106.61 3.20 23.26 2.04 9.36 70.13 2.10 15.30

VESSELS>600hp diesel(tugs) 0 0 0.00 0 0.00 0.00 0.00 0.00 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 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 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 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 0.00 0.00 0.00 0.00

MISC. BPD SCF/HR COUNT

TANK- 0 0 0 0.00 0.00

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

WELL TEST GAS FLARE 208333.33 24 2 0.12 14.87 12.56 80.94 0.00 0.36 0.30 1.94

2018 YEAR TOTAL 42.54 195.27 1477.12 56.43 399.97 36.42 167.06 1252.17 37.86 275.07

EXEMPTION CALCULATION DISTANCE FROM LAND IN 

MILES 2897.10 2897.10 2897.10 2897.10 66756.22

87.0

MMS FORM MMS-138 (December 2008 - Supersedes all previous versions of form MMS-138 which may not be used). Page 3 of 8
EMISSIONS CALCULATIONS 2ND YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

Freeport-McMoRan Oil & Gas LLC Atwater Valley 198 OCS-G 35431 NA Locations A, B, C, D, E Callie Hutchinson 281-578-3388

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR ESTIMATED TONS

Diesel Engines HP GAL/HR GAL/D

Nat. Gas Engines HP SCF/HR SCF/D

Burners MMBTU/HR SCF/HR SCF/D HR/D DAYS PM SOx NOx VOC CO PM SOx NOx VOC CO

DRILLING PRIME MOVER>600hp diesel 49486 2390.1738 14179.00 24 365 34.88 160.01 1199.00 35.97 261.60 37.76 173.23 1298.07 38.94 283.22

PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 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 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 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 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 0.00 0.00 0.00 0.00

VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 6 156 1.46 6.68 50.03 1.50 10.92 0.68 3.13 23.48 0.70 5.12

VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 156 3.10 14.23 106.61 3.20 23.26 2.43 11.13 83.38 2.50 18.19

VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 156 3.10 14.23 106.61 3.20 23.26 2.43 11.13 83.38 2.50 18.19

VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 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 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 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 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 0.00 0.00 0.00 0.00

MISC. BPD SCF/HR COUNT

TANK- 0 0 0 0.00 0.00

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

WELL TEST GAS FLARE 208333.33 24 2 0.12 14.87 12.56 80.94 0.00 0.36 0.30 1.94

2019 YEAR TOTAL 42.54 195.27 1477.12 56.43 399.97 43.30 198.63 1488.67 44.95 326.67

EXEMPTION CALCULATION DISTANCE FROM LAND IN 

MILES 2897.10 2897.10 2897.10 2897.10 66756.22

87.0

MMS FORM MMS-138 (December 2008 - Supersedes all previous versions of form MMS-138 which may not be used). Page 4 of 8
EMISSIONS CALCULATIONS 3RD YEAR

COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKS

Freeport-McMoRan Oil & Gas LLC Atwater Valley 198 OCS-G 35431 NA Locations A, B, C, D, E Callie Hutchinson 281-578-3388

OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR ESTIMATED TONS

Diesel Engines HP GAL/HR GAL/D

Nat. Gas Engines HP SCF/HR SCF/D

Burners MMBTU/HR SCF/HR SCF/D HR/D DAYS PM SOx NOx VOC CO PM SOx NOx VOC CO

DRILLING PRIME MOVER>600hp diesel 49486 2390.1738 14179.00 24 170 34.88 160.01 1199.00 35.97 261.60 17.59 80.68 604.58 18.14 131.91

PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 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 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 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 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 0.00 0.00 0.00 0.00

VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 6 73 1.46 6.68 50.03 1.50 10.92 0.32 1.46 10.94 0.33 2.39

VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 73 3.10 14.23 106.61 3.20 23.26 1.13 5.18 38.84 1.17 8.47

VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 73 3.10 14.23 106.61 3.20 23.26 1.13 5.18 38.84 1.17 8.47

VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 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 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 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 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 0.00 0.00 0.00 0.00

MISC. BPD SCF/HR COUNT

TANK- 0 0 0 0.00 0.00

DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

WELL TEST GAS FLARE 208333.33 24 2 0.12 14.87 12.56 80.94 0.00 0.36 0.30 1.94

2020 YEAR TOTAL 42.54 195.27 1477.12 56.43 399.97 20.17 92.51 693.54 21.10 153.18

EXEMPTION CALCULATION DISTANCE FROM LAND IN 

MILES 2897.10 2897.10 2897.10 2897.10 66756.22

87.0

MMS FORM MMS-138 (December 2008 - Supersedes all previous versions of form MMS-138 which may not be used). Page 5 of 8
SUMMARY

COMPANY AREA BLOCK LEASE PLATFORM WELL

Freeport-McMoRan Oil & Gas LLC Atwater Valley 198 OCS-G 35431 NA Locations A, B, C, D, E

Emitted Substance

Year

PM SOx NOx VOC CO

2018 36.42 167.06 1252.17 37.86 275.07

2019 43.30 198.63 1488.67 44.95 326.67

2020 20.17 92.51 693.54 21.10 153.18

Allowable 2897.10 2897.10 2897.10 2897.10 66756.22

MMS FORM MMS-138 (December 2008 - Supersedes all previous versions of form MMS-138 which may not be used). Page 8 of 8
Freeport-McMoRan Oil & Gas LLC Section 8 – Pg. 14 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 8

OIL SPILL INFORMATION

8.1 OIL SPILL RESPONSE PLANNING

All the proposed activities and facilities in this EP will be covered by the Oil Spill Response Plan 

(OSRP) filed by Freeport-McMoRan Oil & Gas LLC (Company No. 03280) dated January 10, 

2014, revised on January 31, 2014 and last approved on February 4, 2014 (OSRP Control No.

O-713).

8.2 SPILL RESPONSE SITES

Primary Response Equipment Location Preplanned Staging Location

Houma, LA

Harvey, LA

Venice, LA

Houma, LA

Harvey, LA

Venice, LA

8.3 OSRO INFORMATION

FM O&G’s primary equipment providers are Clean Gulf Associates (CGA) and Marine Spill 

Response Corporation (MSRC), and National Response Corporation (NRCC). Clean Gulf 

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

supervisor to operate the equipment. MSRC personnel are responsible for operating MSRC 

response equipment. Through its Independent Contractor Network (ICN), NRCC will also 

provide closest available personnel, as well as an NRCC ICN supervisor to operate the 

equipment.

8.4 WORST CASE SCENARIO DETERMINATION 

Category Regional OSRP

WCD - Drilling

EP

WCD - Drilling

Type of activity Exploratory Drilling Exploratory Drilling

Facility location (area/block) GC 393 AT 198

Facility designation Well Location B Well Location E

Distance to nearest shoreline (miles) 96.5 Miles 87.0 Miles

Storage tanks (bbl) 0 0

Uncontrolled blowout (bbl) 400,000 196,060

Total volume (bbl) 400,000 196,060

Type of oil(s)

(crude, condensate, diesel)

Crude Crude

API gravity 25° 27.1°

The Regional OSRP Drilling WCD calculations were accepted under Plan Control No. N-9739

approved March 31, 2014. 

FM O&G has determined that the worst-case scenario from the activities proposed in this EP 

does not supersede the worst-case scenario from our approved Regional OSRP.

Since Freeport-McMoRan Oil & Gas LLC has the capability to respond to the worst-case spill 

scenario included in our Regional OSRP approved on February 4, 2014, and since the worst-
Freeport-McMoRan Oil & Gas LLC Section 8 – Pg. 15 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

case scenario determined for our EP does not replace the worst-case scenario in our Regional 

OSRP, Freeport-McMoRan Oil & Gas LLC hereby certifies that Freeport-McMoRan Oil & Gas 

LLC 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 

this EP.

8.5 OIL SPILL RESPONSE DISCUSSION

The Oil Spill Response Discussion is included as Attachment 8-A.

8.6 MODELING REPORT

Modeling reports are not required for the activities proposed in this plan.
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 196,060 barrels of crude oil with an API gravity of 27.1°. 

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 BOEM Oil Spill Risk Analysis Model (OSRAM) for the Central and 

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

The BOEM OSRAM identifies a 6% probability of impact to the shorelines of Plaquemines 

Parish, Louisiana within 30 days. Plaquemines Parish includes Barataria Bay, the Mississippi 

River Delta, Breton Sound and the affiliated islands and bays. This region is an extremely 

sensitive habitat and serves as a migratory, breeding, feeding and nursery habitat for numerous 

species of wildlife. Beaches in this area vary in grain particle size and can be classified as fine 

sand, shell or perched shell beaches. Sandy and muddy tidal flats are also abundant. 

Response

FM O&G 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 11% or 

approximately 21,567 barrels of crude oil would be evaporated/dispersed within 24 hours, with 

approximately 174,493 barrels remaining. 

Spill Response AT 198, Well Location E Barrels of Oil 

WCD Volume 196,060

Less 11% natural evaporation/dispersion 21,567

Remaining volume 174,493

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. 

FM O&G’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 an 

operations safety analysis, the size of the spill, weather and potential impacts. If aerial 

dispersants are utilized, 8 sorties (9,600 gallons) from two of the DC-3 aircrafts and 4 sorties 

ATTACHMENT 8-A
(8,000 gallons) from the Basler aircraft would provide a daily dispersant capability of 7,540 

barrels. If the conditions are favorable for in-situ burning, the proper approvals have been 

obtained and the proper planning is in place, in-situ burning of oil may be attempted. Slick 

containment boom would be immediately called out and on-scene as soon as possible. Offshore 

response strategies may include attempting to skim utilizing CGA’s, MSRC’s, and NRCC’s spill 

response equipment, with a total derated skimming capacity of 1,022,754 barrels. Temporary 

storage associated with skimming equipment equals 296,795 barrels. If additional storage is 

needed, various tank barges with a total of 1.4 million+ barrels of storage capacity may be 

mobilized and centrally located to provide temporary storage and minimize off-loading time. 

Safety is first priority. Air monitoring will be accomplished and operations deemed safe 

prior to any containment/skimming attempts. 

If the spill went unabated, shoreline impact in Plaquemines Parish, Louisiana would depend 

upon existing environmental conditions. Shoreline protection would include the use of CGA’s 

and NRCC’s near shore and shallow water skimmers with a totaled derated skimming capacity of 

147,605 barrels. Temporary storage associated with skimming equipment equals 2,393 barrels. If 

additional storage is needed, a 47,000 barrel storage barge, a 25,000 barrel storage barge, three 

20,000 barrel storage barges, and three 23,000 barrel storage barges may be mobilized and 

centrally located to provide temporary storage and minimize off-loading time. Onshore response 

may include the deployment of shoreline boom on beach areas, or protection and sorbent boom 

on vegetated areas. Letters of Intent from AMPOL and OMI Environmental will ensure access to 

147,000 feet of 18” shoreline protection boom. Figure 2 outlines individual times needed for 

procurement, load out, travel time to the site and deployment. Strategies would be based upon 

surveillance and real time trajectories that depict areas of potential impact given actual sea and 

weather conditions. The State of Louisiana Initial Oil Spill Response Plan, applicable Area 

Contingency and Geographical Response Plans and Unified Command would be consulted to 

ensure that environmental and special economic resources would be correctly identified and 

prioritized to ensure optimal protection. Shoreline protection strategies depict the protection 

response modes applicable for oil spill clean-up operations. The State of Louisiana Initial Oil 

Spill Response Plan provides detailed shoreline protection strategies for this area, and it 

describes necessary action to keep the oil spill from entering Louisiana’s coastal wetlands, based 

on the assumption that removal of the released oil will be much easier and less damaging to 

fragile coastal ecosystems if done in the open waters of the Gulf of Mexico. Supervisory 

personnel have the option to modify the deployment and operation of equipment allowing a more 

effective response to site-specific circumstances. FM O&G’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, FM O&G 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 

78 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 to include but not 

be 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

FM O&G will take action to provide a safe, aggressive response to contain and recover as much 

of the spilled oil as quickly as it is safe to do so. In an effort to protect the environment, response 

actions will be designed to provide an “in-depth” protection strategy meant to recover as much 

oil as possible as far from environmentally sensitive areas as possible. Safety will take 

precedence over all other considerations during these operations. 

Coordination of response assets will be supervised by the designation of a SIMOPS group as 

necessary for close quarter vessel response activities. Most often, this group will be used during 

source control events that require a significant number of large vessels operating independently, 

but in coordination to complete a common objective, in a small area and in close coordination 

and support of each other. This group must also monitor the subsurface activities of each vessel 

(ROV, dispersant application, well control support, etc.). The SIMOPS group leader reports to 

the Source Control Section Chief.

In addition, these activities will be monitored by the spill management team (SMT) and Unified 

Command via a structured Common Operating Picture (COP) established to track resource and 

slick movement in real time.

Upon notification of a spill, the following actions will be taken:

 Information will be confirmed

 An assessment will be made and initial objectives set

 OSROs and appropriate agencies will be notified 

 ICS 201, Initial Report Form 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
Offshore Response Actions

Equipment Deployment

Surveillance

 Surveillance Aircraft: within two hours of 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 aerial dispersant providers on standby

 With the FOSC, conduct analysis to determine appropriateness of dispersant application 

(refer to Section 18)

 Gain FOSC approval for use of dispersants on the surface

 Deploy aircraft in accordance with a plan developed for the actual situation

 Coordinate movement of dispersants, aircraft, and support equipment and personnel 

 Confirm dispersant availability for current and long range operations

 Start ordering dispersant stocks required for expected operations 

Containment boom

 Call out early and expedite deployment to be on scene ASAP

 Ensure boom handling and mooring equipment is deployed with boom

 Provide continuing reports to vessels to expedite their arrival at sites that will provide for 

their most effective containment 

 Use Vessels of Opportunity (VOO) to deploy and maintain boom 

Dedicated off-shore skimming systems

General

 Deployed to the highest concentration of oil

 Assets deployed at safe distance from aerial dispersant and in-situ burn operations

CGA HOSS Barge

 Use in areas with heaviest oil concentrations

 Consider for use in areas of known debris (seaweed, and other floating materials)

CGA 95’ Fast Response Vessels (FRVs)

 Designed to be a first vessel on scene

 Capable of maintaining the initial Command and Control function for on water recovery 

operations

 24 hour oil spill detection capability
 Highly mobile and efficient skimming capability

 Use as far off-shore as safely possible

CGA FRUs

 To the area of the thickest oil

 Use as far off-shore as allowed

T&T Koseq Skimming Systems

 To the area of the thickest oil

 Use as far off-shore as allowed

MSRC PSV-VOO Skimming Systems

 To the area of the thickest oil

 Use as near-shore as allowed by draft of vessel

 Use as far off-shore as needed

 Expected 24-hour mobilization

 Expected length of 200 foot or greater

 PSV-VOO with deck space of 150’ x 40’ to provide space for skimmer, marine storage 

tanks and boom

 PSV-VOO with 2,000-20,000 bbl below deck storage supplemented with 2 or more 500 

bbl marine portable tanks, if necessary, depending on below deck storage

MSRC Oil Spill Response Vessels (OSRV)

 Use in areas with heaviest oil concentrations

 Use as near-shore as allowed by draft of vessel

 Consider for use in areas of known debris (seaweed, and other floating materials)

 Use as far off-shore as needed

MSRC Fast Response Vessels (FRV)

 Use in areas with heaviest oil concentrations

 Use as far off-shore as allowed

MSRC Responders

 Use in areas with heaviest oil concentrations

 Consider for use in areas of known debris (seaweed, and other floating materials)

NRCC Oil Spill Response Barge (OSRB)

 Use in areas with heaviest oil concentrations

NRCC Oil Spill Response Vessel (OSRV)

 To the area of the thickest oil

 Use as far off-shore as allowed
NRCC Vessel of Opportunity Skimming System (VOSS)

 To the area of the thickest oil

 Use as far off-shore as allowed

 VOOs minimum 110’ in length

 VOOs with minimum of 8x15 of optimum deck space

 VOOs with 200-400 ft of boom

 Storage tanks of 100 bbls or more

Storage Vessels

 Establish availability of contracted assets (See Appendix E)

 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 FM O&G’s contracted resources as applicable

 Industry vessels are ideal 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/ABS for vessel inspections

 Place VOOs in Division or Groups as needed

 Use organic on-board storage if appropriate

 Maximize non-organic storage appropriate to vessel limitations

 Decant as appropriate after approval to do so has been granted

 Assign bulk storage barges to each Division/Group

 Position bulk storage barges as close to skimming units as possible

 Utilize large skimming vessel (e.g. barges) storage for smaller vessel offloading 

 Maximize skimming area (swath) to the optimum width given sea conditions and 

available equipment

 Maximize use of oleophilic skimmers in all operations, but especially offshore

 Nearshore, use shallow water barges and shuttle to skimming units to minimize 

offloading time

 Plan and equip to use all offloading capabilities of the storage vessel to minimize 

offloading time 

In-situ Burn assets

 Determine appropriateness of in-situ burn operation in coordination with the FOSC and 

affected SOSC

 Determine availability of fire boom and selected ignition systems

 Start ordering fire boom stocks required for expected operations

 Ensure VOO crew members are trained prior to operations
 Determine assets to perform on water operation

 Build operations into safety plan

 Conduct operations in accordance with an approved plan

 Initial test burn to ensure effectiveness

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.

Surface Oil Recovery Considerations and Tactics 

(Offshore and Near-shore Operations)

Maximization of skimmer-oil encounter rate

 Place barges in skimming task forces, groups, etc., to reduce recovered oil offloading 

time

 Place barges alongside skimming systems for immediate offloading of recovered oil 

when practicable 

 Use two vessels, each with heavy sea boom, in an open-ended “V” configuration to 

funnel surface oil into a trailing skimming unit’s organic, V-shaped boom and skimmer 

(see page 7, CGA Equipment Guide Book and Tactic Manual (CGATM)

 Use secondary vessels and heavy sea boom to widen boom swath beyond normal 

skimming system limits (see page 15, CGATM)

 Consider night-time operations, first considering safety issues

 Utilize all available advanced technology systems ( IR, X-Band Radar, etc.) to determine 

the location of, and move to, recoverable oil

 Confirm the presence of recoverable oil prior to moving to a new location

Maximize skimmer system efficiency

 Place weir skimming systems in areas of calm seas and thick oil

 Maximize the use of oleophilic skimming systems in heavier seas

 Place less mobile, high EDRC skimming systems (e.g. HOSS Barge) in the largest 

pockets of the heaviest oil

 Maximize onboard recovered oil storage for vessels. 

 Obtain authorization for decanting of recovered water as soon as possible

 Use smaller, more agile skimming systems to recover streamers of oil normally found 

farther from the source. Place recovered oil barges nearby

Recovered Oil Storage

 Smaller barges in larger quantities will increase flexibility for multi-location skimming 

operations
 Place barges in skimming task forces, groups, etc., to reduce recovered oil offloading 

time

 Procure and deploy the maximum number of portable tanks to support Vessel of 

Opportunity Skimming Systems if onboard storage is not available

 Maximize use of the organic recovered oil storage capacity of the skimming vessel

Command, Control, and Communications (C3)

 Publish, implement, and fully test an appropriate communications plan

 Design an operational scheme, maintaining a manageable span of control

 Designate and mark C3vessels for easy aerial identification

 Designate and employ C3aircraft for task forces, groups, etc.

 Use reconnaissance air craft and Rapid Response Teams (RAT) to confirm the presence 

of recoverable oil

On Water Recovery Group

When the first skimming vessel arrives on scene, a complete site assessment will be conducted 

before recovery operations begin. Once it is confirmed that the air monitoring readings for O2, 

LEL, H2S, CO, VOC, and Benzene are all within the permissible limits, oil recovery operations 

may begin.

As skimming vessels arrive, they will be organized to work in areas that allow for the most 

efficient vessel operation and free vessel movement in the recovery of oil. Vessel groups will 

vary in structure as determined by the Operations Section of the Unified Command, but will 

generally consist, at a minimum, of the following dedicated assets:

 3 to 5 – Offshore skimming vessels (recovery)

 1 – Tank barge (temporary storage)

 1 – Air asset (tactical direction)

 2 – Support vessels (crew/utility for supply)

 6 to 10 – Boom vessels (enhanced booming )

Example (Note: Actual organization of TFs will be dependent on several factors including, asset 

availability, weather, spilled oil migration, currents, etc.) 

The 95’ FRV Breton Island out of Venice arrives on scene and conducts an initial site 

assessment. Air monitoring levels are acceptable and no other visual threats have been observed. 

The area is cleared for safe skimming operations. The Breton Island assumes command and 

control (CoC) of on-water recovery operations until a dedicated non-skimming vessel arrives to 

relieve it of those duties. 

A second 95’ FRV arrives and begins recovery operations alongside the Breton Island. Several 

more vessels begin to arrive, including a third 95’ FRV out of Galveston, the HOSS Barge (High 

Volume Open Sea Skimming System) out of Harvey, a boom barge (CGA 300) with 25,000’ of 
42” auto boom out of Leeville, and 9 Fast Response Units (FRUs) from the load-out location at 

C-Port in Port Fourchon. 

As these vessels set up and begin skimming, they are grouped into task forces (TFs) as directed 

by the Operations Section of the Unified Command located at the command post. 

Initial set-up and potential actions:

 A 1,000 meter safety zone has been established around the incident location for vessels 

involved in Source Control 

 The HOSS Barge is positioned facing the incident location just outside of this safety zone 

or at the point where the freshest oil is reaching the surface

 The HOSS Barge engages its Oil Spill Detection (OSD) system to locate the heaviest oil 

and maintains that ability for 24-hour operations 

 The HOSS Barge deploys 1,320’ of 67” Sea Sentry boom on each side, creating a swath 

width of 800’ 

 The Breton Island and H.I. Rich skim nearby, utilizing the same OSD systems as the 

HOSS Barge to locate and recover oil

 Two FRUs join this group and it becomes TF1

 The remaining 7 FRUs are split into a 2 and 3 vessel task force numbered TF2 and TF3

 A 95’ FRV is placed in each TF

 The boom barge (CGA 300) is positioned nearby and begins deploying auto boom in 

sections between two utility vessels (1,000’ to 3,000’ of boom, depending on conditions) 

with chain-link gates in the middle to funnel oil to the skimmers 

 The initial boom support vessels position in front of TF2 and TF3 

 A 100,000+ barrel offshore tank barge is placed with each task force as necessary to 

facilitate the immediate offload of skimming vessels

The initial task forces (36 hours in) may be structured as follows:

TF 1

 1 – 95’ FRV

 1 – HOSS Barge with 3 tugs

 2 – FRUs

 1 – 100,000+ barrel tank barge and associated tug(s)

 1 – Dedicated air asset for tactical direction

 8 – 500’ sections of auto boom with gates

 8 – Boom-towing vessels 

 2 – Support vessels (crew/utility)

TF 2

 1 – 95’ FRV 

 4 – FRUs

 1 – 100,000+ barrel tank barge and associated tug(s)
 1 – Dedicated air asset for tactical direction

 10 – 500’ sections of auto boom with gates

 10 – Boom-towing vessels

 2 – Support vessels (crew/utility)

TF 3

 1 – 95’ FRV 

 3 – FRUs

 1 – 100,000+ barrel tank barge and associated tug(s)

 1 – Dedicated air asset for tactical direction

 8 – 500’ sections of auto boom with gates

 8 – Boom-towing vessels

 2 – Support vessels (crew/utility)

Offshore skimming equipment continues to arrive in accordance with the ETA data listed in 

figure H.3a; this equipment includes 2 AquaGuard skimmers and 11 sets of Koseq Rigid 

Skimming Arms. These high volume heavy weather capable systems will be divided into 

functional groups and assigned to specific areas by the Operations Section of the Unified 

Command. 

At this point of the response, the additional TFs may assume the following configurations:

TF 4 

 2 – Sets of Koseq Rigid Skimming Arms w/ associated 200’+ PIDVs

 1 – AquaGuard Skimmer

 1 – 100,000+ barrel tank barge and associated tug(s)

 1 – Dedicated air asset for tactical direction

 2 – Support vessels (crew/utility)

 6 – 500’ sections of auto boom with gates 

 6 – Boom-towing vessels

TF 5 

 3 – Sets of Koseq Rigid Skimming Arms w/ associated 200’+ PIDVs

 1 – AquaGuard Skimmer

 1 – 100,000+ barrel tank barge and associated tug(s)

 1 – Dedicated air asset for tactical direction

 2 – Support vessels (crew/utility)

 8 – 500’ sections of auto boom with gates 

 8 – Boom-towing vessels

TF 6 

 3 – Sets of Koseq Rigid Skimming Arms w/ associated 200’+ PIDVs

 1 – 100,000+ barrel tank barge and associated tug(s)
 1 – Dedicated air asset for tactical direction

 2 – Support vessels (crew/utility)

 6 – 500’ sections of auto boom with gates 

 6 – Boom-towing vessels

TF 7 

 3 – Sets of Koseq Rigid Skimming Arms w/ associated 200’+ PIDVs

 1 – 100,000+ barrel tank barge and associated tug(s)

 1 – Dedicated air asset for tactical direction

 2 – Support vessels (crew/utility)

 6 – 500’ sections of auto boom with gates

 6 – Boom-towing vessels

CGA Minimum Acceptable Capabilities for Vessels of Opportunity (VOO)

Minimum acceptable capabilities of Petroleum Industry Designed Vessels (PIDV) for conducting 

Vessel of Opportunity (VOO) skimming operations are shown in the table below. PIDVs are 

“purpose-built” to provide normal support to offshore oil and gas operators. They include but 

are not limited to utility boats, offshore supply vessels, etc. They become VOOs when tasked 

with oil spill response duties.

Capability FRU KOSEQ AquaGuard

Type of Vessel Utility Boat Offshore Supply 

Vessel Utility Boat

Operating parameters

Sea State 3-5 ft max 9.8 ft max 3-5 ft max

Skimming speed ≤1 kt ≤3 kts ≤1 kt

Vessel size

Minimum Length 100 ft 200 ft 100 ft

Deck space for:

 Tank(s)

 Crane(s)

 Boom Reels

 Hydraulic Power Units

 Equipment Boxes

18x32 ft 100x40 ft 18x32 ft

Communication Assets Marine Band 

Radio Marine Band Radio Marine Band Radio

Tactical use of Vessels of Opportunity (VOO): FM O&G will take all possible measures to 

maximize the oil-to-skimmer encounter rate of all skimming systems, to include VOOs, as 

discussed in this section. VOOs will normally be placed within an On-water recovery unit as 

shown in figures below.
Skimming Operations: PIDVs are the preferred VOO skimming platform. OSROs are more 

versed in operating on these platforms and the vessels are generally large enough with crews 

more likely versed in spill response operations. They also have a greater possibility of having 

on-board storage capacity and the most likely vessels to be under contract, and therefore more 

readily available to the operator. These vessels would normally be assigned to an on-water 

recovery group/division (see figure below) and outfitted with a VOSS suited for their size and 

capabilities. Specific tactics used for skimming operations would be dependent upon many 

parameters which include, but are not limited to, safety concerns, weather, type VOSS on board, 

product being recovered, and area of oil coverage. Planners would deploy these assets with the 

objective of safely maximizing oil- to-skimmer encounter rate by taking actions to minimize 

non-skimming time and maximizing boom swath. Specific tactical configurations are shown in 

figures below.

The Fast Response Unit (FRU): A self-contained, skid based, skimming system that is 

deployed from the right side of a vessel of opportunity (VOO). An outrigger holds a 75’ long 

section of air inflatable boom in place that directs oil to an apex for recovery via a Foilex 250 

weir skimmer. The outrigger creates roughly a 40’ swath width dependent on the VOO beam. 

The lip of the collection bowl on the skimmer is placed as close to the oil and water interface as 

possible to maximize oil recovery and minimize water retention. The skimmer then pumps all 

fluids recovered to the storage tank where it is allowed to settle, and with the approval of the 

Coast Guard, the water is decanted from the bottom of the tank back into the water ahead of the 

containment boom to be recycled through the system. Once the tank is full of as much pure 

recovered oil as possible it is offloaded to a storage barge for disposal in accordance with an 

approved disposal plan. A second 100 barrel storage tank can be added if the appropriate 

amount of deck space is available to use as secondary storage. 

Tactical Overview

Mechanical Recovery – The FRU is designed to provide fast response skimming capability in the 

offshore and nearshore environment in a stationary or advancing mode. It provides a rated daily 

recovery capacity of 4,100 barrels. An additional boom reel with 440’ of offshore boom can be 

deployed along with the FRU, and a second support vessel for boom towing, to extend the swath 

width when attached to the end of the fixed boom. The range and sustainability offshore is 

dependent on the VOO that the unit is placed on, but generally these can stay offshore for 

extended periods. The FRU works well independently or assigned with other on-water recovery 

assets in a task force. In either case, it is most effective when a designated aircraft is assigned to 

provide tactical direction to ensure the best placement in recoverable oil. 

Maximum Sea Conditions – Under most circumstances the FRU can maintain standard oil spill 

recovery operations in 2’ to 4’ seas. Ultimately, the Coast Guard licensed Captain in charge of 

the VOO (with input from the CGAS Supervisor assigned) will be responsible to determine when 

the sea conditions have surpassed the vessel’s safe operating capabilities. 

Possible Task Force Configuration (Multiple VOOs can be deployed in a task force)

1 – VOO (100’ to 165’ Utility or Supply Vessel) 

1 – Boom reel w/support vessel for towing
1 – Tank barge (offshore) for temporary storage

1 – Utility/Crewboat (supply)

1 – Designated spotter aircraft

The VOSS (yellow) is being deployed and connected to an out-rigged arm. This is 

suitable for collection in both large pockets of oil and for recovery of streaming oil. 

The oil-to-skimmer encounter rate is limited by the length of the arm. Skimming 

pace is < 1 knot.

Through the use of an additional VOO, and using extended sea boom, the swath of 

the VOSS is increased therefore maximizing the oil-to-skimmer encounter rate. 

Skimming pace is < 1 knot.

The Koseq Rigid Sweeping Arm: A skimming system deployed on a vessel of opportunity. It 

requires a large Offshore or Platform Supply Vessel (OSV/PSV), greater than 200’ with at least 

100’ x 50’ of free deck space. On each side of the vessel, a 50’ long rigid framed Arm is 

deployed that consists of pontoon chambers to provide buoyancy, a smooth nylon face, and a 

hydraulically adjustable mounted weir skimmer. The Arm floats independently of the vessel and 

is attached by a tow bridle and a lead line. The movement of the vessel forward draws the rubber 

end seal of the arm against the hull to create a collection point for free oil directed to the weir by 

the Arm face. The collection weir is adjusted to keep the lip as close to the oil water interface as 

possible to maximize oil recovery while attempting to minimize excess water collection. A 

transfer pump (combination of positive displacement, screw type and centrifuge suited for highly 

viscous oils) pump the recovered liquid to portable tanks and/or dedicated fixed storage tanks 

onboard the vessel. After being allowed to sit and separate, with approval from the Coast Guard, 

the water can be decanted (pumped off) in front of the collection arm to be reprocessed through 

the system. Once full with as much pure recovered oil as possible, the oil is transferred to a 
temporary storage barge where it can be disposed of in accordance with an approved disposal 

plan. 

Tactical Overview

Mechanical Recovery – Deployed on large vessels of opportunity (VOO) the Koseq Rigid 

Sweeping Arms are high volume surge capacity deployed to increase recovery capacity at the 

source of a large oil spill in the offshore and outer nearshore environment of the Gulf of Mexico. 

They are highly mobile and sustainable in rougher sea conditions than normal skimming vessels 

(9.8’ seas). The large Offshore Supply Vessels (OSV) required to deploy the Arms are able to 

remain on scene for extended periods, even when sea conditions pick up. Temporary storage on 

deck in portable tanks usually provides between 1,000 and 3,000 bbls. In most cases, the OSV 

will be able to pump 20% of its deadweight into the liquid mud tanks in accordance with the 

vessels Certificate of Inspection (COI). All storage can be offloaded utilizing the vessels liquid 

transfer system. 

Maximum Sea Conditions - Under most circumstances the larger OSVs are capable of remaining 

on scene well past the Skimming Arms maximum sea state of 9.8’. Ultimately it will be the 

decision of the VOO Captain, with input from the T&T Supervisor onboard, to determine when 

the sea conditions have exceeded the safe operating conditions of the vessel. 

Command and Control – The large OSVs in many cases have state of the art communication and 

electronic systems, as well as the accommodations to support the function of directing all 

skimming operations offshore and reporting back to the command post. 

Possible Task Force Configuration (Multiple Koseq VOOs can be deployed in a task force)

1 – > 200’ Offshore Supply Vessels (OSV) with set of Koseq Arms 

2 to 4 portable storage tanks (500 bbl)

1 – Modular Crane Pedestal System set (MCPS) or 30 cherry picker (crane) for deployment

1 – Tank barge (offshore) for temporary storage

1 – Utility/Crewboat (supply)

1 – Designated spotter aircraft

4 – Personnel (4 T&T OSRO)
Scattered oil is “caught” by two VOO and collected at the apex of the towed sea 

boom. The oil moves thought a “gate” at that apex, forming a larger stream of oil 

which moves into the boom of the skimming vessel. Operations are paced at >1. A 

recovered oil barge stationed nearby to minimize time taken to offload recovered 

oil.

This is a depiction of the same operation as above but using KOSEQ Arms. In this 

configuration, the collecting boom speed dictates the operational pace at > 1 knot to 

minimize entrainment of the oil.

Clean Gulf Associates (CGA) Procedure for Accessing Member-Contracted and other 

Vessels of Opportunity (VOOs) for Spill Response

 CGA has procedures in place for CGA member companies to acquire vessels of 

opportunity (VOOs) from an existing CGA member’s contracted fleet or other sources 

for the deployment of CGA portable skimming equipment including Koseq Arms, Fast 

Response Units (FRUs) and any other portable skimming system(s) deemed appropriate 

for the response for a potential or actual oil spill, WCD oil spill or a Spill of National 

Significance (SONS). 

 CGA uses Port Vision, a web-based vessel and terminal interface that empowers CGA to 

track vessels through Automatic Identification System (AIS) and terminal activities using 

a Geographic Information System (GIS). It provides live AIS/GIS views of waterways 

showing current vessel positions, terminals, created vessel fleets, and points-of-interest. 

Through this system, CGA has the ability to get instant snapshots of the location and 

status of all vessels contracted to CGA members, day or night, from any web-enabled PC.
Near Shore Response Actions

Timing

 Put near shore assets on standby and deployment 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) 

Dedicated Near Shore skimming systems

 FRVs 

 Egmopol and Marco SWS 

 Operate with aerial spotter directing systems to observed oil slicks

VOO

 Use FM O&G’s contracted resources as applicable

 Industry vessel 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 ACP, 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 time lines to minimize waste

 Staging of equipment and housing of response personnel as close to the job site as 

possible to maximize on-site work time

 Boom tending, repair, replacement and security (use of local assets may be advantageous) 

 Constant awareness of weather and oil movement for resource redeployment as necessary 

 In-situ burn may be considered when marshes have been impacted 

 Passive clean up of marshes should considered and appropriate stocks of sorbent boom 

and/or sweep obtained

 Earthen berms and shoreline protection boom may be considered to protect sensitive 

inland areas 
Decanting Strategy

Recovered oil and water mixtures will typically separate into distinct phases when left in a 

quiescent state. When separation occurs, the relatively clean water phase can be siphoned or 

decanted back to the recovery point with minimal, if any, impact. Decanting therefore increases 

the effective on-site oil storage capacity and equipment operating time. FOSC/SOSC approval 

will be requested prior to decanting operations. This practice is routinely used for oil spill 

recovery.

CGA Equipment Limitations

The capability for any spill response equipment, whether a dedicated or portable system, to 

operate in differing weather conditions will be directly in relation to the capabilities of the vessel 

the system in placed on. Most importantly, however, the decision to operate will be based on the 

judgment of the Unified Command and/or the Captain of the vessel, who will ultimately have the 

final say in terminating operations. Skimming equipment listed below may have operational 

limits which exceed those safety thresholds. As was seen in the Deepwater Horizon (DWH) oil 

spill response, vessel skimming operations ceased when seas reached 5-6 feet and vessels were 

often recalled to port when those conditions were exceeded. Systems below are some of the 

most up-to-date systems available and were employed during the DWH spill. 

Boom 3 foot seas, 20 knot winds

Dispersants Winds more than 25 knots

Visibility less than 3 nautical miles

Ceiling less than 1,000 feet.

FRU 8 foot seas

HOSS Barge/OSRB 8 foot seas

Koseq Arms 8 foot seas

OSRV 4 foot seas
Environmental Conditions in the GOM

Louisiana is situated between the easterly and westerly wind belts, and therefore, experiences 

westerly winds during the winter and easterly winds in the summer. Average wind speed is 

generally 14-15 mph along the coast. Wave heights average 4 and 5 feet. However, during 

hurricane season, Louisiana has recorded wave heights ranging from 40 to 50 feet high and 

winds reaching speeds of 100 mph. Because much of southern Louisiana lies below sea level, 

flooding is prominent. 

Surface water temperature ranges between 70 and 80 ̊F during the summer months. During the 

winter, the average temperature will range from 50 and 60 ̊F. 

The Atlantic and Gulf of Mexico hurricane season is officially from 1 June to 30 November. 

97% of all tropical activity occurs within this window. The Atlantic basin shows a very peaked 

season from August through October, with 78% of the tropical storm days, 87% of the minor 

(Saffir-Simpson Scale categories 1 and 2) hurricane days, and 96% of the major (Saffir-Simpson 

categories 3, 4 and 5) hurricane days occurring then. Maximum activity is in early to mid

September. Once in a few years there may be a hurricane occurring "out of season" - primarily in 

May or December. Globally, September is the most active month and May is the least active 

month.
FIGURE 1

TRAJECTORY BY LAND SEGMENT

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

utilizing FM O&G’s WCD and information in the BOEM Oil Spill Risk Analysis Model 

(OSRAM) for the Central and Western Gulf of Mexico available on the BOEM 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, test, complete, 

flare & install subsea 

trees for Well 

Locations A-E

AT 198, 

Well Location E

87 miles from shore

G35431 C61 Cameron, LA

Vermilion, LA

Terrebonne, LA

Lafourche, LA

Plaquemines, LA

St. Bernard, LA

1

1

2

1

6

1
WCD Scenario– BASED ON WELL BLOWOUT DURING DRILLING OPERATIONS (87 miles from shore)

174,493 bbls of crude oil (Volume considering natural weathering)

API Gravity 27.1°

FIGURE 2 – Equipment Response Time to AT 198, Well Location E

Dispersants/Surveillance

Dispersant/Surveillance Dispersant 

Capacity (gal)

Persons 

Req. From Hrs to Procure

Hrs to 

Loadout Travel to site Total Hrs

ASI

Basler 67T 2000 2 Houma, LA 2 2 0.8 4.8

DC 3 1200 2 Houma, LA 2 2 1.1 5.1

DC 3 1200 2 Houma, LA 2 2 1.1 5.1

Aero Commander NA 2 Houma, LA 2 2 0.8 4.8

MSRC

C-130 Spray AC 3,250 2 Kiln, MS 3 0.2 0.5 3.7

King Air BE90 Spray AC 250 2 Kiln, MS 3 0.3 0.9 4.2

Offshore Response

Offshore Equipment 

Pre-Determined 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

95’ FRV 12342 249 NA 4 Venice, LA 2 0 2 4 0 8

95’ FRV 12342 249 NA 4 Leeville, LA 2 0 2 6 0 10

95’ FRV 12342 249 NA 4 Galveston, TX 2 0 1 18.5 0 21.5

HOSS Barge 43000 4000 3 Tugs 8 Harvey, LA 7 0 5 10 1 23

Boom Barge (CGA-300)

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

4 (Barge)

2 (Per Crew) Leeville, LA 4 0 6 17 1.5 28.5
Recovered Oil Storage PreDetermined 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

Kirby Offshore (available through contract with CGA)

RO Barge NA 80000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 80000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 80000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 80000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 100000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 100000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 100000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 100000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 110000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 130000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 140000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 150000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

RO Barge NA 150000+ 1 Tug 6 Venice, LA 48 0 2 10 0 60

Offshore Equipment 

Pre-determined Staging EDRC Storage Capacity VOO Persons Req From Hrs to Procure

Hrs to 

Loadout

Hrs to 

GOM

Travel to 

Spill Site

Hrs to 

Deploy

Total 

Hrs

NRCC

OSRV Energy

Vikoma Sea 50 1509 300 NA 4-6 Grand Isle, LA 2 2 1 14 1 20

OSRV Admiral

Marco Class XI AB

8 Band Rope Mop

24000

2283

300 NA 4-6 Galveston, TX 2 2 1 41 1 47

OSRB Defender

Marco Class XI AB

Vikoma Cascade

24000

5520

16500 2 Tugs 4-6 Bayou La Batre, AL 4 2 3 30 1 40

OSRB Valor N/A 19000 2 Tugs 4-6 Tampa, FL 4 2 7 64 1 78
Offshore Equipment 

Pre-determined 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

MSRC

Louisiana Responder 

Transrec 350 + OSRV

2,640’ 67” Curtain Pressure Boom

10567 4000 NA 14 Fort Jackson, LA20 4.5 111 18.5

MSRC 452 Offshore Barge

1 Crucial Disk 88/30

1 Desmi Ocean

2,640‘ 67” Curtain Pressure Boom

11122

3017 45000 3 Tugs

6 Fort Jackson, LA 2.506 201 29.5

Mississippi Responder 

Transrec 350 + OSRV 2,640’ 67” Curtain Pressure Boom

10567 4000 NA 14 Pascagoula, MS202 141 18

MSRC 402 Offshore Barge

2 Crucial Disk 88/30

2,640‘ 67” Curtain Pressure Boom

22244 40300 3 Tugs6 Pascagoula, MS 2.503 251 31.5

Deep Blue Responder 

LFF 100 Brush + OSRV

2,640’ 67” Curtain Pressure Boom

18086 4000 NA 14 Fourchon, LA201 101 14

Gulf Coast Responder 

Transrec 350 + OSRV

2,640’ 67” Curtain Pressure Boom

10567 4000 NA 14 Lake Charles, LA204 231 30

Texas Responder 

Transrec 350 + OSRV

2,640’ 67” Curtain Pressure Boom

10567 4000 NA 14 Galveston, TX201 291 33

MSRC 570 Offshore Barge

2 Crucial Disk 88/30

2,640’ 67” Curtain Pressure Boom

22244 56900 3 Tugs6 Galveston, TX 2.502 531 58.5

Southern Responder 

Transrec 350 + OSRV

2,640’ 67” Curtain Pressure Boom

10567 4000 NA 14 Ingleside, TX201 381 42

MSRC 403 Offshore Barge

1 Crucial Disk 88/30

2,640’ 67” Curtain Pressure Boom

11122 40300 3 Tugs6 Ingleside, TX 2.502 701 75.5
Staging Area: Venice

Offshore Equipment 

Preferred 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

T&T Marine (available through direct contract with CGA)

Aqua Guard Triton RBS (2) 45560 4000 2 Utility 12 Galveston, TX 4 12 13 7 2 38

Koseq Skimming Arms (6) 106974 12000 6 Utility 36 Galveston, TX 24 24 13 7 2 70

Koseq Skimming Arms (3) 53487 6000 3 Utility 18 Galliano, LA 24 24 1 7 2 58

Koseq Skimming Arms (2) 35658 4000 2 Utility 12 Harvey, LA 24 24 2 7 2 59

CGA

FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Morgan City, LA 2 2 5 7 1 17

FRU (1) + 100 bbl Tank (1) 4251 100 1 Utility 6 Harvey, LA 2 2 2 7 1 14

FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Galveston, TX 2 2 13 7 1 25

FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Aransas Pass, TX 2 2 18 7 1 30

FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Lake Charles, LA 2 2 8 7 1 20

FRU (2) + 100 bbl Tank (4) 8502 400 2 Utility 12 Leeville, LA 2 2 5 7 1 17

FRU (2) + 100 bbl Tank (4) 8502 400 2 Utility 12 Venice, LA 2 2 0 7 1 12

Offshore Equipment Preferred 

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

MSRC

WP 1 Skimmer (1) 3017 400 1 Utility 6 Ingleside, TX 1 2 18 7 1 29

Stress I Skimmer (1) 15840 400 1 Utility 6 Ingleside, TX 1 2 18 7 1 29

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Ingleside, TX 1 2 18 7 1 29

Foilex 250 Skimmer (1) 3977 400 1 Utility 6 Ingleside, TX 1 2 18 7 1 29

Crucial Disk 56/30 Skimmer (1) 5671 400 1 Utility 6 Ingleside, TX 1 2 18 7 1 29

GT-185 Skimmer w Adaptor (2) 2742 400 2 Utility 12 Galveston, TX 1 2 13 7 1 24

Walosep 4 Skimmer (1) 3017 400 1 Utility 6 Galveston, TX 1 2 13 7 1 24

Queensboro Skimmer (1) 905 400 1 Utility 6 Galveston, TX 1 2 13 7 1 24

Foilex 250 Skimmer (1) 3977 400 1 Utility 6 Galveston, TX 1 2 13 7 1 24

Stress I Skimmer (1) 15840 400 1 Utility 6 Galveston, TX 1 2 13 7 1 24

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Port Arthur, TX 1 2 10 7 1 21

Queensboro Skimmer (5) 4525 400 5 Utility 30 Lake Charles, LA 1 2 8 7 1 19

Desmi Skimmer (1) 3017 400 1 Utility 6 Lake Charles, LA 1 2 8 7 1 19

Foilex 250 Skimmer (1) 3977 400 1 Utility 6 Lake Charles, LA 1 2 8 7 1 19
Offshore Equipment Preferred 

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

MSRC

Stress I Skimmer (1) 15840 400 1 Utility 6 Lake Charles, LA 1 2 8 7 1 19

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Lake Charles, LA 1 2 8 7 1 19

AardVac Skimmer (1) 3840 400 1 Utility 6 Lake Charles, LA 1 2 8 7 1 19

Transrec 350 Skimmer (1) 10567 400 1 Utility 6 Lake Charles, LA 1 2 8 7 1 19

Crucial Disk 88/30 Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 11122 400 1 PSV 14 Lake Charles, LA 1 2 8 7 1 19

Crucial Disk 88/30 Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 11122 400 1 PSV 14 Lake Charles, LA 1 2 8 7 1 19

Transrec 350 Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 11122 400 1 PSV 14 Lake Charles, LA 1 2 8 7 1 19

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Baton Rouge, LA 1 2 5 7 1 16

Transrec 350 Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 10567 400 1 PSV 14 Houma, LA 1 2 4 7 1 15

Stress I Skimmer (1) 15840 400 1 Utility 6 Port Fourchon, LA 1 2 5 7 1 16

LFF 100 Brush Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 18086 400 1 PSV 14 Port Fourchon, LA 1 2 5 7 1 16

LFF 100 Brush Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 18086 400 1 PSV 14 Port Fourchon, LA 1 2 5 7 1 16

LFF 100 Brush Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 18086 400 1 PSV 14 Port Fourchon, LA 1 2 5 7 1 16

LFF 100 Brush Skimmer (1)

1,320‘ 67” Curtain Pressure Boom 18086 400 1 PSV 14 Port Fourchon, LA 1 2 5 7 1 16

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Walosep W4 Skimmer (1) 3017 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Foilex 250 Skimmer (1) 3977 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Stress I Skimmer (1) 15840 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Queensboro Skimmer (1) 905 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Foilex 200 Skimmer (1) 1989 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Crucial Disk 56/30 Skimmer (1) 5671 400 1 Utility 6 Belle Chasse, LA 1 2 2 7 1 13

Stress I Skimmer (1) 15840 400 1 Utility 6 Pascagoula, MS 1 2 6 7 1 17

GT-185 Skimmer (1) 1371 400 1 Utility 6 Pascagoula, MS 1 2 6 7 1 17

AardVac Skimmer (1) 3840 400 1 Utility 6 Pascagoula, MS 1 2 6 7 1 17

WP 1 Skimmer (1) 3017 400 1 Utility 6 Pascagoula, MS 1 2 6 7 1 17

Queensboro Skimmer (1) 905 400 1 Utility 6 Pascagoula, MS 1 2 6 7 1 17
Offshore Equipment Preferred 

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

MSRC

Stress II Skimmer (1) 3017 400 1 Utility 6 Pascagoula, MS 1 2 6 7 1 17

Stress I Skimmer (1) 15840 400 1 Utility 6 Tampa, FL 1 2 21 7 1 32

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Tampa, FL 1 2 21 7 1 32

WP 1 Skimmer (1) 3017 400 1 Utility 6 Tampa, FL 1 2 21 7 1 32

Crucial Disk 56/30 Skimmer (1) 5671 400 1 Utility 6 Tampa, FL 1 2 21 7 1 32

GT-185 Skimmer w Adaptor (1) 1371 400 1 Utility 6 Miami, FL 1 2 27 7 1 38

Stress I Skimmer (1) 15840 400 1 Utility 6 Miami, FL 1 2 27 7 1 38

Walosep W4 Skimmer (1) 3017 400 1 Utility 6 Miami, FL 1 2 27 7 1 38

AardVac Skimmer (2) 7680 400 2 Utility 12 Miami, FL 1 2 27 7 1 38

WP 1 Skimmer (1) 3017 400 1 Utility 6 Miami, FL 1 2 27 7 1 38

Desmi Skimmer (1) 3017 400 1 Utility 6 Miami, FL 1 2 27 7 1 38

Offshore Equipment Preferred 

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

NRCC

Marco Class XI AB 24000 100 1 Offshore 

Vessel 4-8 Ft. Lauderdale, FL 4 4 26 17 1 52

Marco Class XI AB 24000 100 1 Offshore 

Vessel 4-8 Belle Chasse, LA 4 4 2 17 1 28

Marco Class XI AB 24000 100 1 Offshore 

Vessel 4-8 New Iberia, LA 4 4 6 17 1 32

Action 48 Skimmer 2414 100 1 Offshore 

Vessel 4-8 Key West, FL 4 4 31 17 1 57

Hoyle Disc Skimmer 1632 100 1 Offshore 

Vessel 4-8 Tampa, FL 4 4 21 17 1 47

4-Band Rope Mop Skimmer 1509 100 1 Offshore 

Vessel 4-8 Ft. Lauderdale, FL 4 4 26 17 1 52

4-Band Rope Mop Skimmer 1509 100 1 Offshore 

Vessel 4-8 Mobile, AL 4 4 7 17 1 33

4-Band Rope Mop Skimmer (2) 3018 200 1 Offshore 

Vessel 8-16 New Iberia, LA 4 4 6 17 1 32

4-Band Rope Mop Skimmer (2) 3018 200 1 Offshore 

Vessel 8-16 Corpus Christi, TX 4 4 18 17 1 44

Vikoma Cascade Skimmer 5520 100 1 Offshore 

Vessel 4-8 Baytown, TX 4 4 12 17 1 38

Vikoma Cascade Skimmer 5520 100 1 Offshore 

Vessel 4-8 Sulphur, LA 4 4 9 17 1 35

VTU w/weir head skimmer 6857 24 1 Offshore 

Vessel 4-8 Port Arthur, TX 4 4 10 17 1 36

VTU w/weir head skimmer 6857 24 1 Offshore 

Vessel 4-8 La Porte, TX 4 4 12 17 1 38
Offshore Equipment Preferred 

Staging EDRC StorageCapacity VOO Persons Req. From Hrs to Procure

Hrs to 

Loadout

Travel to 

Staging

Travel to 

Site

Hrs to 

Deploy

Total 

Hrs

CGA

1000’ Hydro-Fire Boom NA NA 8 Utility 40 Harvey, LA 1 4 2.1 7 6 20

MSRC

67” Curtain Pressure Boom (18480’) NA NA 14* 7 Lake Charles, LA 1 2 8 7 1 19

67” Curtain Pressure Boom (8895’) NA NA 12* 6 Pascagoula, MS 1 2 5.5 7 1 16

2000’ Hydro Fire Boom NA NA 8* 8 Lake Charles, LA 1 4 8 7 6 19

NRCC

42” Boom (1000’) NA NA 1 Offshore 

Vessel 4-8 Bayou La Batre, AL 4 4 6 7 1 22

42” Boom (3300’) NA NA 2 Offshore 

Vessels 8-16 Tampa, FL 4 4 21 7 1 37

42” Boom (2000’) NA NA 1 Offshore 

Vessel 4-8 Baytown, TX 4 4 12 7 1 28

42” Boom (1000’) NA NA 1 Offshore 

Vessel 4-8 Port Arthur, TX 4 4 10 7 1 26

42” Boom (4000’) NA NA 2 Offshore 

Vessels 8-16 Corpus Christi, TX 4 4 18 7 1 34

1000’ Hydro-Fire Boom NA NA 6 Utility 20 New Iberia, LA 4 4 6 7 1 22

* Utility Boats, Crew Boats, Supply Boats, or Fishing Vessels
Nearshore Response

Nearshore Equipment 

Pre-determined 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

Trinity SWS 21500 249 NA 4 Galveston, TX 2 6 N/A 48 1 57

Trinity SWS 21500 249 NA 4 Morgan City, LA 2 6 N/A 48 1 57

Trinity SWS 21500 249 NA 4 Leeville, LA 2 6 N/A 48 1 57

Trinity SWS 21500 249 NA 4 Venice, LA 2 6 N/A 48 1 57

46’ FRV 5000 65 NA 4 Aransas Pass, TX 2 0 2 25 0 29

46’ FRV 5000 65 NA 4 Morgan City, LA 2 0 2 6 0 10

46’ FRV 5000 65 NA 4 Lake Charles, LA 2 0 1 12 0 15

46’ FRV 5000 65 NA 4 Venice, LA 2 0 1 3 0 6

Enterprise Marine Services LLC (Available through contract with CGA)

CTCo 2603 NA 25000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 2604 NA 20000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 2605 NA 20000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 2606 NA 20000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 2607 NA 23000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 2608 NA 23000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 2609 NA 23000 1 Tug 6 Amelia, LA 4 12 4 15 1 36

CTCo 5001 NA 47000 1 Tug 6 Amelia, LA 4 12 4 15 1 36
Staging Area: Venice

Nearshore Equipment With Staging EDRC Storage 

Capacity VOO Persons Req. From Hrs to Procure

Hrs to 

Load Out

Travel to 

Staging

Travel to 

Deployment

Hrs to 

Deploy

Total 

Hrs

CGA

SWS Egmopol 3000 100 NA 3 Galveston, TX 2 2 12.7 2 0 18.7

SWS Egmopol 3000 100 NA 3 Morgan City, LA 2 2 4.9 2 0 10.9

SWS Marco 3588 20 NA 3 Lake Charles, LA 2 2 8 2 0 14

SWS Marco 3588 34 NA 3 Leeville, LA 2 2 4.4 2 0 10.4

SWS Marco 3588 34 NA 3 Venice, LA 2 2 0 2 0 6

Rope Mop 77 2 0 3 Harvey, LA 2 2 2.1 2 0 8.1

Foilex Skim Package (TDS 150) 891 45 NA 3 Lake Charles, LA 2 2 8 2 0 14

Foilex Skim Package (TDS 150) 891 45 NA 3 Galveston, TX 2 2 12.7 2 0 18.7

Foilex Skim Package (TDS 150) 891 45 NA 3 Harvey, LA 2 2 2.1 2 0 8.1

4 Drum Skimmer (Magnum 100) 686 100 1 Crew 3 Lake Charles, LA 2 2 8 2 0 14

4 Drum Skimmer (Magnum 100) 686 100 1 Crew 3 Harvey, LA 2 2 2.1 2 0 8.1

2 Drum Skimmer (TDS 118) 240 100 1 Crew 3 Lake Charles, LA 2 2 8 2 0 14

2 Drum Skimmer (TDS 118) 240 100 1 Crew 3 Harvey, LA 2 2 2.1 2 0 8.1
Nearshore Equipment With 

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

Hrs to 

Load Out

Travel to 

Staging

Travel to 

Deployment

Hrs to 

Deploy

Total 

Hrs

NRCC

Action 24 Skimmer 823 24 1 Nearshore Vessel4-8 Baytown, TX44 1221 23

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Tampa, FL44 2121 32

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Ft. Lauderdale, FL44 2621 37

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8New Iberia, LA44621 17

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Corpus Christi, TX44 1921 30

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Pasadena, TX44 1221 23

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Port Arthur, TX44 1021 21

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Cocoa, FL44 2221 33

NRC Weir Disk Skimmer 1371 24 1 Nearshore 

Vessel

4-8 Pensacola, FL44821 19

Vikoma Fasflo Skimmer 2112 24 1 Nearshore 

Vessel

4-8 Belle Chasse, LA44221 13

Vikoma Fasflo Skimmer 2112 24 1 Nearshore 

Vessel

4-8 New Iberia, LA44621 17

Vikoma Fasflo Skimmer 2112 24 1 Nearshore 

Vessel

4-8 Sulphur, LA44821 19

Vikoma Fasflo Skimmer 2112 24 1 Nearshore 

Vessel

4-8 Atlantic Beach, FL44 182129
Shoreline Protection

Staging Area: Venice

Shoreline Protection 

Boom VOO Persons Req. 

Storage/Warehouse

Location

Hrs to 

Procure

Hrs to 

Loadout

Travel to 

Staging

Travel to 

Deployment Site

Hrs to 

Deploy Total Hrs

AMPOL (available through Letter of Intent)

42,000’ 18” Boom 16 Crew 40 New Iberia, LA 2 2 6 2 12 24

20,000’ 18” Boom 8 Crew 20 New Orleans, LA 2 2 2.2 2 6 14.2

OMI Environmental (available through Letter of Intent)

10,000’ 18” Boom 4 Crew 10 New Iberia, LA 1 1 6 2 3 13

10,000’ 18” Boom 4 Crew 10 Houston, TX 1 1 12.1 2 3 19.1

10,000’ 18” Boom 4 Crew 10 Port Arthur, TX 1 1 9.7 2 3 16.7

20,000’ 18” Boom 8 Crew 20 Belle Chasse, LA 1 1 1.9 2 6 11.9

10,000’ 18” Boom 4 Crew 10 Port Allen, LA 1 1 4.5 2 3 11.5

10,000’ 18” Boom 4 Crew 10 Houma, LA 1 1 3.8 2 3 10.8

15,000’ 18” Boom 6 Crew 14 Gretna, LA (Warehouse) 2 2 2.1 2 4 12.1

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, LA 2 2 2.1 1 2 9.1

Bird Scare Guns (48) NA NA NA 2 Harvey, LA 2 2 2.1 1 2 9.1

Bird Scare Guns (12) NA NA NA 2 Galveston, TX 2 2 12.7 1 2 19.7

Bird Scare Guns (12) NA NA NA 2 Aransas Pass, TX 2 2 17.7 1 2 24.7

Bird Scare Guns (24) NA NA NA 2 Lake Charles, LA 2 2 8 1 2 15

Bird Scare Guns (24) NA NA NA 2 Leeville, LA 2 2 4.4 1 2 11.4

Response Asset Total

Offshore EDRC 1,022,754

Offshore Recovered Oil Capacity 1,696,795+

Nearshore / Shallow Water EDRC 147,605

Nearshore / Shallow Water Recovered Oil Capacity 203,393
Freeport-McMoRan Oil & Gas LLC Section 9 – Pg. 16 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 9

ENVIRONMENTAL MONITORING INFORMATION

9.1 MONITORING SYSTEMS

FM O&G will monitor loop currents per the requirements as set forth in NTL No. 2009-G02,

“Ocean Current Monitoring” (Extended by NTL No. 2014-G05, “Extension of Prior Notices to 

Lessees”). FM O&G subscribes to Wilkens Weather Technologies for weather forecasts and 

monitoring. Horizon Marine, Inc. provides Gulf of Mexico loop and eddy current forecasts.

9.2 INCIDENTAL TAKES

There is no reason to believe that any of the endangered species or marine mammals as listed 

in the ESA will be “taken” as a result of the operations proposed under this plan. 

It has been documented that the use of explosives and or seismic devices can affect marine life. 

Operations proposed in this plan will not be utilizing either of these devices. 

FM O&G will adhere to the requirements as set forth in the following documents, as applicable, 

to avoid or minimize impacts to any of the species listed in the Endangered Species Act (ESA) 

as a result of the operations conducted herein:

 NTL No. 2012-BSEE-G01, “Marine Trash and Debris Awareness and Elimination”

 NTL No. 2012-JOINT-G01, “Vessel Strike Avoidance and Injured/Dead Protected 

Species Reporting”

 NTL No. 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures and 

Protected Species Observer Program”

9.3 FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY

Atwater Valley Block 198 is not located in the Flower Garden Banks National Marine Sanctuary; 

therefore, relevant information is not required in this EP. 
Freeport-McMoRan Oil & Gas LLC Section 10 – Pg. 17 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 10

LEASE STIPULATIONS INFORMATION

10.1 MARINE PROTECTED SPECIES

In accordance with the Federal Endangered Species Act and the Marine Mammal Protection 

Act, FM O&G will: 

(a) Collect and remove flotsam resulting from activities related to exploration, development, and 

production of this lease; 

(b) Post signs in prominent places on all vessels and platforms used as a result of activities 

related to exploration, development, and production of this lease detailing the reasons (legal 

and ecological) why release of debris must be eliminated; 

(c) Observe for marine mammals and sea turtles while on vessels, reduce vessel speed to 10 

knots or less when assemblages of cetaceans are observed, and maintain a distance of 90 

meters or greater from whales, and a distance of 45 meters or greater from small cetaceans and 

sea turtles; 

(d) Employ mitigation measures prescribed by BOEM/BSEE or the National Marine Fisheries 

Service (NMFS) for all seismic surveys, including the use of an “exclusion zone” based upon the 

appropriate water depth, ramp-up and shutdown procedures, visual monitoring, and reporting; 

(e) Identify important habitats, including designated critical habitat, used by listed species (e.g., 

sea turtle nesting beaches, piping plover critical habitat), in oil spill contingency planning and 

require the strategic placement of spill cleanup equipment to be used only by personnel trained 

in less-intrusive cleanup techniques on beaches and bay shores; and 

(f) Immediately report all sightings and locations of injured or dead protected species (e.g., 

marine mammals and sea turtles) to the appropriate stranding network. If oil and gas industry 

activity is responsible for the injured or dead animal (e.g., because of a vessel strike), the 

responsible parties should remain available to assist the stranding network. If the injury or death 

was caused by a collision with the lessee’s vessel, the lessee must notify BOEM within 24 hours 

of the strike. 

BOEM and BSEE issue Notices to Lessees (NTLs), which more fully describe measures 

implemented in support of the above-mentioned implementing statutes and regulations, as well 

as measures identified by the U.S. Fish and Wildlife Service and NMFS arising from, among 

others, conservation recommendations, rulemakings pursuant to the MMPA, or consultation. 

The lessee and its operators, personnel, and subcontractors, while undertaking activities 

authorized under this lease, must implement and comply with the specific mitigation measures 

outlined in NTL No. 2012-JOINT-G01, “Vessel Strike Avoidance and Injured/Dead Protected 

Species Reporting;” NTL No. 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation 

Measures and Protected Species Observer Program;” and NTL No. 2012-BSEE-G01, “Marine 

Trash and Debris Awareness and Elimination.” At the lessee’s option, the lessee, its operators, 
Freeport-McMoRan Oil & Gas LLC Section 10 – Pg. 18 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

personnel, and contractors may comply with the most current measures to protect species in 

place at the time an activity is undertaken under this lease, including but not limited to new or 

updated versions of the NTLs identified in this paragraph. The lessee and its operators, 

personnel, and subcontractors will be required to comply with the mitigation measures, identified 

in the above referenced NTLs, and additional measures in the conditions of approvals for their 

plans or permits.
Freeport-McMoRan Oil & Gas LLC Section 11 – Pg. 19 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 11

ENVIRONMENTAL MITIGATION MEASURES INFORMATION

11.1 MEASURES TAKEN TO AVOID, MINIMIZE, AND MITIGATE IMPACTS

Atwater Valley Block 198 is not located within Florida; therefore, mitigation information is not 

required for the activities proposed in this plan. 

11.2 INCIDENTAL TAKES

FM O&G will adhere to the requirements as set forth in the following documents, as applicable, 

to avoid or minimize impacts to any of the species listed in the Endangered Species Act (ESA) 

as a result of the operations conducted herein:

 NTL No. 2012-BSEE-G01, “Marine Trash and Debris Awareness and Elimination”

 NTL No. 2012-JOINT-G01, “Vessel Strike Avoidance and Injured/Dead Protected 

Species Reporting”

 NTL No. 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures and 

Protected Species Observer Program”
Freeport-McMoRan Oil & Gas LLC Section 12 – Pg. 20 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 12

SUPPORT VESSELS AND AIRCRAFT INFORMATION

12.1 GENERAL

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

conditions will be utilized. Information regarding the vessels and aircraft to be used to support 

the proposed activities is provided in the table below. 

Type Maximum Fuel 

Tank Capacity

Maximum Number 

in Area at Any 

Time

Trip Frequency or 

Duration

Crew boat 1,800 bbl 1 3/Week

Supply boat 9,000 bbl 1 3/Week

Supply boat 5,800 bbl 1 3/Week

Helicopter 950 gal 1 2/Day

2.2 DIESEL OIL SUPPLY VESSELS

Information regarding vessels to be used to supply diesel oil for fuel and other purposes is 

provided in the table below.

Size of Fuel Supply 

Vessel (ft)

Capacity of Fuel 

Supply Vessel

Frequency of Fuel 

Transfers

Route Fuel Supply 

Vessel Will Take

245 9,000 bbl Bi-weekly Shortest route from 

Fourchon, LA to Atwater 

Valley 198

312 5,800 bbl Bi-weekly Shortest route from 

Fourchon, LA to Atwater 

Valley 198

12.3 DRILLING FLUID TRANSPORTATION

Drilling fluid transportation information is not required to be submitted with this plan.

12.4 SOLID AND LIQUID WASTE TRANSPORTATION

A table, “Wastes You Will Transport and/or Dispose of Onshore,” is included as Attachment 12-

A.

12.5 VICINITY MAP

A vicinity map showing the location of the activities proposed herein relative to the shoreline 

with the distance of the proposed activities from the shoreline and the primary routes of the 

support vessels and aircraft that will be used when traveling between the onshore support 

facilities and the drilling unit is included as Attachment 12-B.
OBM/ZnBr2/CaBr2 & KCl/ZnBr2/CaBr2 Vessel to truck or MPT tanks Newpark Environmental Services

Fourchon, LA 500 bbl All will go to a disposal well

Recycled or Incinerated

N/A N/A N/A N/A N/A

N/A N/A N/A N/A N/A

Wash water

Chemical product wastes

N/A

N/A

N/A

Cuttings wetted with oil-based fluids

Will you produce hydrocarbons? If yes fill in produced sand.

Cuttings wetted with Synthetic-based

fluid

N/A N/A

N/A N/A

N/A

N/A

N/A

N/A

N/A

Well completion fluids

Produced sand

Will you have additional wastes that are not permitted for discharge? If yes, fill in the appropriate rows.

Trash and debris

Used oil

N/A N/A

No production is proposed under this Initial Exploration Plan

Refuse generated during operations: 

paper, cardboard, metal, and glass

Compactor bags in storage bins on 

Supply/Crew Boat

Gulf Offshore Logistics

Fourchon, LA

310,000 lbs/Well

Recycled if possible, 

transported to landfill 

otherwise

Used Engine Oil Proper DOT containers on supply boat Univar

Carencro, LA

100 bbl/Well

Will drilling occur? If yes, fill in the muds and cuttings.

Composition

Projected Generated

Wastes

Oil-based drilling fluid or mud N/A N/A N/A N/A

Synthetic-based drilling fluid

Cuttings wetted with Water-based fluid

Recycled

N/A

N/A

SBM Cuttings Boxes on Supply Boat Newpark Environmental Services

Fourchon, LA 1,500 BBLS/Well

Attachment 12-A. WASTE YOU WILL TRANSPORT AND/OR DISPOSE OF ONSHORE

Transport Method Name/Location of

Facility

Amount Disposal

Method

Solid and Liquid

Wastes

Transportation

Waste Disposal

ATTACHMENT 12-A
!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!!

!! !!

!!

!!

Atwater Valley

Mississippi Canyon

Green Canyon

Main Pass

Mobile

South Timbalier

West Delta

Grand Isle

Ewing Bank

Viosca Knoll

Main Pass South & East

South Timbalier South

Breton Sound

Chandeleur

West Delta South

South Pelto

Houma

Dulac

Biloxi

Venice

Gretna Meraux

Harvey

Lutcher

Lafitte

Hopedale

Gulfport

Fourchon

Galliano

St. Rose

Cocodrie

Garyville

Pascagoula

Grand Isle

River Ridge

New Orleans

Fort Jackson

Belle Chasse

Pascagoula

 Gulfport



10

12

59

110

De Soto NF

Freeport-McMoran Oil & Gas LLC Vicinity Map

Atwater 198

AT198

~162 Miles to Houma, LA Aircraft Shorebase

~116 Miles to Fourchon, LA Vessle Shorebase

~87

Miles

to

LA Shore

~17

7

9. Mi el s to

M

S

S

h

ore

ATTACHMENT 12-B
Freeport-McMoRan Oil & Gas LLC Section 13 – Pg. 21 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 13

ONSHORE SUPPORT FACILITIES INFORMATION

13.1 GENERAL

The onshore facilities that will be used to provide supply and service support for the proposed 

activities is provided in the table below.

Name Location Existing/New/Modified

Freeport-McMoRan Oil & 

Gas LLC Shorebase

Fourchon, Louisiana Existing

MI-Swaco Mud Plants Fourchon, Louisiana Existing

13.2 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 EP.

13.3 SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE

A support base construction or expansion timetable is not required for the activities proposed in 

this plan. 

13.4 WASTE DISPOSAL

The Table, “Wastes You Will Transport and/or Dispose of Onshore, “is included as Attachment 

12-A.
Freeport-McMoRan Oil & Gas LLC Section 14 – Pg. 22 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 14

COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION

Under direction of the Coastal Zone Management Act (CZMA), the states of Louisiana and 

Mississippi developed a Coastal Zone Management Programs (CZMP) to allow for the 

supervision of significant land and water use activities that take place within or that could 

significantly affect their respective coastal zones. 

Proposed activities are 87 miles from the Louisiana shore, and 177.9 miles from the Mississippi

shore. Measures will be taken to avoid or mitigate the probable impacts. FM O&G will operate in

compliance with existing federal and state laws, regulations, and resultant enforceable program 

policies in Louisiana’s and Mississippi’s Coastal Zone Management Programs. 

The OCS related oil and gas exploratory and development activities having potential impact on 

the Louisiana and Mississippi Coastal Zones are based on the location of the proposed 

facilities, access to those sites, best practical techniques for drilling locations, drilling equipment 

guidelines for the prevention of adverse environmental effects, effective environmental 

protection, emergency plans and contingency plans.

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

certificate of Coastal Zone Management Consistency for the state of Louisiana is included as 

Attachment 14-A.
ATTACHMENT 14-A
Freeport-McMoRan Oil & Gas LLC Section 14 – Pg. 23 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

The policies and corresponding sections within this Exploration Plan identified by the State of 

Mississippi Coastal Program (MCP) as being related to OCS Plans are provided in the table 

below.

Enforceable Program Policies of the Mississippi Coastal Program (MCP) 

Goal 1: To provide for reasonable industrial expansion in the coastal area and to ensure 

the efficient utilization of waterfront industrial sites so that suitable sites are conserved 

for water dependent industry.

Goal 1 is addressed in Section 13. The proposed activities provide no industrial expansion in 

the coastal area of Mississippi; therefore, Mississippi coastal areas will be conserved for water 

dependent industry.

Goal 2: To favor the preservation of the coastal wetlands and ecosystems, except where 

a specific alteration of specific coastal wetlands would serve a higher public interest in 

compliance with the public purposes of the public trust in which the coastal wetlands are 

held.

Goal 2 is addressed in Section 15. All proposed activities shall avoid to the maximum extent 

practicable significant impact to Mississippi’s coastal wetlands and ecosystems.

Goal 3: To protect, propagate and conserve the state’s seafood and aquatic life in 

connection with the revitalization of the seafood industry of the State of Mississippi.

Goal 3 is addressed in Section 15. All proposed activities shall avoid to the maximum extent 

practicable significant impact to Mississippi’s seafood industry. 

Goal 4: To conserve the air and waters of the state, and to protect, maintain and improve 

the quality thereof for public use, for the propagation of wildlife, fish and aquatic life, and 

for domestic, agricultural, industrial, recreational and other legitimate beneficial uses.

Goal 4 is addressed in Sections 2, 7 and 15. All proposed activities shall avoid to the maximum 

extent practicable significant impact to Mississippi’s seafood industry.

Goal 5: To put to beneficial use to the fullest extent of which they are capable the water 

resources of the state, and to prevent the waste, unreasonable use, or unreasonable 

method of use of water.

The proposed activities are supported by a shorebase located in Louisiana and shall avoid to 

the maximum extent practicable significant impact to Mississippi’s water resources. 

Goal 6: To preserve the state’s historical and archaeological resources, to prevent their 

destruction, and to enhance these resources wherever possible.

Goal 6 is addressed in Sections 2 and 15. All proposed activities shall avoid to the maximum 

extent practicable significant impact to Mississippi’s historical and archaeological resources.
Freeport-McMoRan Oil & Gas LLC Section 14 – Pg. 24 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

Goal 7: To encourage the preservation of natural scenic qualities in the coastal area.

Goal 7 is addressed in Sections 6, 7, 8 and 15. All proposed activities shall avoid to the 

maximum extent practicable significant impact to Mississippi’s natural scenic qualities in the 

coastal area.

Goal 8: To assist local governments in the provision of public facilities services in a 

manner consistent with the coastal program.

All proposed activities are supported by a shorebase in Louisiana and shall avoid to the 

maximum extent practicable significant impact to Mississippi’s local governments.

A certificate of Coastal Zone Management Consistency for the state of Mississippi is included as 

Attachment 14-B.
ATTACHMENT 14-B
Freeport-McMoRan Oil & Gas LLC Section 15 – Pg. 25 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 15

ENVIRONMENTAL IMPACT ANALYSIS 

The Environmental Impact Analysis is included as Attachment 15-A.
Freeport-McMoRan Oil & Gas, LLC (FM O&G)

Initial Exploration Plan 

Atwater Valley Block 198 

OCS-G 35431

(A) IMPACT PRODUCING FACTORS 

ENVIRONMENTAL IMPACT ANALYSIS WORKSHEET 

Environment

Resources

Impact Producing Factors (IPFs)

Categories and Examples

Refer to recent GOM OCS Lease Sale EIS for a more complete list of IPFs

Emissions 

(air, noise, 

light, etc.)

Effluents 

(muds, 

cutting, other 

discharges to 

the water 

column or 

seafloor)

Physical 

disturbances to the 

seafloor (rig or 

anchor 

emplacements, 

etc.)

Wastes sent 

to shore for 

treatment 

or disposal

Accidents 

(e.g., oil 

spills, 

chemical 

spills, H2S 

releases)

Discarded

Trash &

Debris

Site-specific at Offshore 

Location

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

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

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

Benthic communities (4)

Water quality X X

Fisheries X X

Marine Mammals X(8) X X(8) X

Sea Turtles X(8) X X(8) X

Air quality X(9)

Shipwreck sites (known or 

potential)

(7)

Prehistoric archaeological sites (7)

Vicinity of Offshore Location

Essential fish habitat X X(6)

Marine and pelagic birds X X

Public health and safety (5)

Coastal and Onshore

Beaches X(6) X

Wetlands X(6)

Shore birds and coastal nesting 

birds

X6)

Coastal wildlife refuges

Wilderness areas

ATTACHMENT 15-A
Footnotes for Environmental Impact Analysis Matrix

1) Activities that may affect a marine sanctuary or topographic feature. Specifically, if the well or platform site or 

any anchors will be on the seafloor within the:

o 4-mile zone of the Flower Garden Banks, or the 3-mile zone of Stetson Bank;

o 1000-m, 1-mile or 3-mile zone of any topographic feature (submarine bank) protected by the Topographic 

Features Stipulation attached to an OCS lease;

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

o Proximity of any submarine bank (500 ft. buffer zone) with relief greater than 2 meters that is not protected 

by the Topographic Features Stipulation attached to an OCS lease.

2) Activities with any bottom disturbance within an OCS lease block protected through the Live Bottom (Pinnacle 

Trend) Stipulation attached to an OCS lease.

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

4) Activities on blocks designated by the BOEM as being in water depths 300 meters or greater.

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

6) All activities that could result in an accidental spill of produced liquid hydrocarbons or diesel fuel that you 

determine would impact these environmental resources. If the proposed action is located a sufficient distance 

from a resource that no impact would occur, the EIA can note that in a sentence or two.

7) All activities that involve seafloor disturbances, including anchor emplacements, in any OCS block designated 

by the BOEM as having high-probability for the occurrence of shipwrecks or prehistoric sites, including such 

blocks that will be affected that are adjacent to the lease block in which your planned activity will occur. If the 

proposed activities are located a sufficient distance from a shipwreck or a prehistoric site that no impact would 

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

8) All activities that you determine might have an adverse effect on endangered or threatened marine mammals or 

sea turtles or their critical habitats.

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

Site-Specific at Atwater Valley Block 198

Proposed operations consist of the drilling, testing, completion, flaring, and installation of subsea 

trees for Well Locations A-E. The operations will be conducted with a dynamically-positioned 

drillship.

1. Designated Topographic Features

Potential IPFs on topographic features include effluents, and accidents. 

Effluents: Atwater Valley Block 198 is 72 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 FM O&G’s Regional 

OSRP (refer to information submitted in Section 8). 

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

sent to shore for disposal) from the proposed activities, which could impact topographic features.

2. Pinnacle Trend Area Live Bottoms

Potential IPFs on pinnacle trend area live bottoms include effluents and accidents. 

Effluents: Atwater Valley Block 198 is 102 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 FM O&G’s

Regional OSRP (refer to information submitted in Section 8). 

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

sent to shore for disposal) from the proposed activities which could impact a live bottom 

(pinnacle trend) area. 

3. Eastern Gulf Live Bottoms

Potential IPFs on Eastern Gulf live bottoms include effluents and accidents.

Effluents: Atwater Valley Block 198 is not located in an area characterized by the existence of 

live bottoms; therefore, no adverse impacts are expected.

Accidents: It is unlikely that an accidental surface or subsurface spill would occur from the 

proposed activities (refer to statistics in Item 5, Water Quality). Oil spills cause damage to live 

bottom organisms only if the oil contacts the organisms. Oil from a surface spill can be driven 

into the water column; measurable amounts have been documented down to a 10 m depth. At 

this depth, the oil is found only at concentrations several orders of magnitude lower than the 

amount shown to have an effect on marine invertebrates. Oil from a subsurface spill is not 

applicable due to the distance of these blocks from a live bottom area. The activities proposed in 

this plan will be covered by FM O&G’s Regional OSRP (refer to information submitted in 

Section 8). 

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

sent to shore for disposal) from the proposed activities which could impact an Eastern Gulf live 

bottom area. 

4. Benthic Communities 

There are no IPFs (including emissions, physical disturbances to the seafloor, wastes sent to 

shore for disposal, or accidents) from the proposed activities that could cause impacts to benthic 

communities.

A dynamically-positioned drillship is being used for the proposed activities; therefore, only an 

insignificant amount of seafloor will be disturbed. Because physical disturbances to the seafloor 

will be minimized by the use of a dynamically-positioned drillship, FM O&G’s proposed 

operations in Atwater Valley Block 198 would not cause impacts to benthic communities.

5. Water Quality

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

Valley Block 198 include effluents and accidents.
Effluents: Levels of contaminants in drilling muds and cuttings and produced water discharges, 

discharge-rate restrictions and monitoring and toxicity testing are regulated by the EPA NPDES 

permit, thereby eliminating many significant biological or ecological effects. Operational 

discharges are not expected to cause significant adverse impacts to water quality.

Accidents: Oil spills have the potential to alter offshore water quality; however, it is unlikely 

that an accidental surface or subsurface spill would occur from the proposed activities. Between 

1980 and 2000, OCS operations produced 4.7 billion barrels of oil and spilled only 0.001 percent 

of this oil, or 1 bbl for every 81,000 bbl produced. The spill risk related to a diesel spill from 

drilling operations is even less. Between 1976 and 1985, (years for which data were collected), 

there were 80 reported diesel spills greater than one barrel associated with drilling activities. 

Considering that there were 11,944 wells drilled, this is a 0.7 percent probability of an 

occurrence. If a spill were to occur, the water quality of marine waters would be temporarily 

affected by the dissolved components and small oil droplets. Dispersion by currents and 

microbial degradation would remove the oil from the water column and dilute the constituents to 

background levels. Historically, changes in offshore water quality from oil spills have only been 

detected during the life of the spill and up to several months afterwards. Most of the components 

of oil are insoluble in water and therefore float. The activities proposed in this plan will be 

covered by FM O&G’s Regional Oil Spill Response Plan (refer to information submitted in 

Section 8).

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 Atwater 

Valley Block 198 include effluents and accidents. 

Effluents: Effluents such as drilling fluids and cuttings discharges contain components and 

properties which are detrimental to fishery resources. Moderate petroleum and metal 

contamination of sediments and the water column can occur out to several hundred meters downcurrent from the discharge point. Offshore discharges are expected to disperse and dilute to very 

near background levels in the water column or on the seafloor within 3,000 m of the discharge 

point, and are expected to have negligible effect on fisheries.

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

fisheries; however, it is unlikely that such an event would occur from the proposed activities 

(refer to Item 5, Water Quality). The effects of oil on mobile adult finfish or shellfish would 

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

shellfish to avoid the spill, to metabolize hydrocarbons, and to excrete both metabolites and 

parent compounds. The activities proposed in this plan will be covered by FM O&G’s Regional 

OSRP (refer to information submitted in Section 8). 
There are no IPFs from emissions, physical disturbances to the seafloor or wastes sent to shore 

for disposal from the proposed activities which could cause impacts to fisheries.

7. Marine Mammals

GulfCet II studies revealed that cetaceans of the continental shelf and shelf-edge were almost 

exclusively bottlenose dolphin and Atlantic spotted dolphin. Squid eaters, including dwarf and 

pygmy killer whale, Risso’s dolphin, rough-toothed dolphin, and Cuvier’s beaked whale, 

occurred most frequently along the upper slope in areas outside of anticyclones. IPFs that could 

cause impacts to marine mammals as a result of the proposed operations in Atwater Valley Block 

198 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).

FM O&G 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 FM O&G management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01.

Accidents: Collisions between support vessels and cetaceans would be unusual events, however 

should one occur, death or injury to marine mammals is possible. Contract vessel operators can 

avoid marine mammals and reduce potential deaths by maintaining a vigilant watch for marine 

mammals and maintaining a safe distance when they are sighted. Vessel crews should use a 

reference guide to help identify the twenty-eight species of whales and dolphins, and the single 

species of manatee that may be encountered in the Gulf of Mexico OCS. Vessel crews must 

report sightings of any injured or dead protected marine mammal species immediately, 

regardless of whether the injury or death is caused by their vessel, to the Marine Mammal and 

Sea Turtle Stranding Hotline at (888) 404-3922, the NMFS Southeast Regional Office at (727) 

824-5312, or the Marine Mammal Stranding Network at (305) 862-2850. In addition, if the 

injury or death was caused by a collision with a contract vessel, the BOEM must be notified 

within 24 hours of the strike by email to protectedspecies@bsee.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 FM O&G’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 FM O&G’s OSRP (refer to 

information submitted in accordance with Section 8).

There are no other IPFs (including physical disturbances to the seafloor) from the proposed 

activities which could impact marine mammals.

8. Sea Turtles

IPFs that could cause impacts to sea turtles as a result of the proposed operations include 

emissions, effluents, discarded trash and debris, and accidents. GulfCet II studies sighted most 

loggerhead, Kemp’s ridley and leatherback sea turtles over shelf waters. Historically these 

species have been sighted up to the shelf’s edge. They appear to be more abundant east of the 

Mississippi River than they are west of the river (Fritts et al., 1983b; Lohoefener et al., 1990).

Deep waters may be used by all species as a transitory habitat.
Emissions: Noise from drilling activities, support vessels, and helicopters may elicit a startle 

reaction from sea turtles, but this is a temporary disturbance.

Effluents: Drilling fluids and cuttings discharges are not known to be lethal to sea turtles. Most 

operational discharges are diluted and dispersed upon release. Any potential impact from 

drilling fluids would be indirect, either as a result of impacts on prey items or possibly through 

ingestion in the food chain (API, 1989).

Discarded trash and debris: Both entanglement in, and ingestion of, debris have caused the 

death or serious injury of sea turtles (Balazs, 1985). The limited amount of marine debris, if any, 

resulting from the proposed activities is not expected to substantially harm sea turtles. Operators 

are prohibited from deliberately discharging debris as mandated by MARPOL-Annex V and the 

Marine Plastic Pollution Research and Control Act, and regulations imposed by various agencies 

including the United States Coast Guard (USCG) and the Environmental Protection Agency 

(EPA). FM O&G 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 FM O&G 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@bsee.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 FM O&G’s Regional Oil Spill Response Plan (refer to 

information submitted in accordance with Section 8).

There are no other IPFs (including physical disturbances to the seafloor) from the proposed 

activities which could impact sea turtles.

9. Air Quality

Atwater Valley Block 198 is located 118 miles from the Breton Wilderness Area and 87 miles 

from shore. Applicable emissions data is included in Section 7 of the Plan.

There would be a limited degree of air quality degradation in the immediate vicinity of the 

proposed activities. Plan Emissions for the proposed activities do not exceed the annual 

exemption levels as set forth by BOEM. Accidents and blowouts can release hydrocarbons or 

chemicals, which could cause the emission of air pollutants. However, these releases would not 

impact onshore air quality because of the prevailing atmospheric conditions, emission height, 

emission rates, and the distance of Atwater Valley Block 198 from the coastline. There are no 

other IPFs (including effluents, physical disturbances to the seafloor, wastes sent to shore for 

treatment or disposal) from the proposed activities which would impact air quality.

10. Shipwreck Sites (known or potential)

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

operations in Atwater Valley Block 198 include disturbances to the seafloor.

Physical disturbances to the seafloor: A dynamically-positioned drillship is being used for the 

proposed activities; therefore, only an insignificant amount of seafloor will be disturbed. 

Because physical disturbances to the seafloor will be minimized by the use of a dynamicallypositioned drillship, FM O&G’s proposed operations in Atwater Valley Block 198 would not 

cause impacts to shipwreck sites.

Additionally, Atwater Valley Block 198 is not located in or adjacent to an OCS block designated 

by BOEM as having a high probability for occurrence of shipwrecks, therefore, no adverse 

impacts are expected.

FM O&G will perform an AUV/ROV survey imaging 100% of the seafloor with sector scanning 

sonar within a minimum 500’ radius of the proposed well location(s) prior to or upon 
commencement of operations. These locations will be certified by an authorized marine 

archaeologist and by FM O&G to be clear of seafloor archaeological resources, including 

historic shipwrecks. Copies of the certifications and a circle radius plat of the survey area will be 

submitted to the BOEM. Should a resource be encountered, FM O&G will contact the BOEM 

immediately and make every reasonable effort to preserve and protect that cultural resource.

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

disposal, or accidents) from the proposed activities that could cause impacts to shipwreck sites.

11. Prehistoric Archaeological Sites

Potential IPFs that could cause impacts to prehistoric archaeological sites as a result of the 

proposed operations in Atwater Valley Block 198 include disturbances to the seafloor.

Physical disturbances to the seafloor: A dynamically-positioned drillship is being used for the 

proposed activities; therefore, only an insignificant amount of seafloor will be disturbed. 

Because physical disturbances to the seafloor will be minimized by the use of a dynamicallypositioned drillship, FM O&G’s proposed operations in Atwater Valley Block 198 would not 

cause impacts to prehistoric archaeological sites.

FM O&G will perform an AUV/ROV survey imaging 100% of the seafloor with sector scanning 

sonar within a minimum 500’ radius of the proposed well location(s) prior to or upon 

commencement of operations. These locations will be certified by an authorized marine 

archaeologist and by FM O&G to be clear of seafloor archaeological resources. Copies of the 

certifications and a circle radius plat of the survey area will be submitted to the BOEM. Should 

a resource be encountered, FM O&G will contact the BOEM immediately and make every 

reasonable effort to preserve and protect that cultural resource.

Additionally, Atwater Valley Block 198 is located outside the Archaeological Prehistoric high 

probability line, therefore, no adverse impacts are expected.

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 prehistoric archeological 

sites.

Vicinity of Offshore Location

1. Essential Fish Habitat (EFH)

IPFs that could cause impacts to EFH as a result of the proposed operations in Atwater Valley 

Block 198 include effluents and accidents. EFH includes all estuarine and marine waters and 

substrates in the Gulf of Mexico. 
Effluents: The Live Bottom Low Relief Stipulation, the Live Bottom (Pinnacle Trend) 

Stipulation, and the Eastern Gulf Pinnacle Trend Stipulation would prevent most of the potential 

impacts on live-bottom communities and EFH from operational waste discharges. Levels of 

contaminants in drilling muds and cuttings and produced-water discharges, discharge-rate 

restrictions, and monitoring and toxicity testing are regulated by the EPA NPDES permit, 

thereby eliminating many significant biological or ecological effects. Operational discharges are 

not expected to cause significant adverse impacts to EFH.

Accidents: An accidental oil spill has the potential to cause some detrimental effects on EFH. 

Oil spills that contact coastal bays and estuaries, as well as OCS waters when pelagic eggs and 

larvae are present, have the greatest potential to affect fisheries. However, it is unlikely that an 

oil spill would occur from the proposed activities (refer to Item 5, Water Quality). The activities 

proposed in this plan will be covered by FM O&G’s Regional OSRP (refer to information 

submitted in Section 8).

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

sent to shore for treatment or disposal) from the proposed activities which could impact essential 

fish habitat.

2. Marine and Pelagic Birds 

IPFs that could impact marine birds as a result of the proposed activities include air emissions, 

accidental oil spills, and discarded trash and debris from vessels and the facilities.

Emissions: Emissions of pollutants into the atmosphere from these activities are far below 

concentrations which could harm coastal and marine birds.

Accidents: An oil spill would cause localized, low-level petroleum hydrocarbon contamination. 

However, it is unlikely that an oil spill would occur from the proposed activities (refer to Item 5, 

Water Quality). Marine and pelagic birds feeding at the spill location may experience chronic, 

nonfatal, physiological stress. It is expected that few, if any, coastal and marine birds would 

actually be affected to that extent. The activities proposed in this plan will be covered by FM 

O&G’s Regional OSRP (refer to information submitted in Section 8).

Discarded trash and debris: Marine and pelagic birds could become entangled and snared in 

discarded trash and debris, or ingest small plastic debris, which can cause permanent injuries and 

death. Operators are prohibited from deliberately discharging debris as mandated by MARPOLAnnex V and the Marine Plastic Pollution Research and Control Act, and regulations imposed by 

various agencies including the United States Coast Guard (USCG) and the Environmental 

Protection Agency (EPA). FM O&G 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 FM O&G

management or the designated lease operator management that emphasizes their commitment to 

waste management in accordance with NTL No. 2012-G01. Debris, if any, from these proposed 

activities will seldom interact with marine and pelagic birds; therefore, the effects will be 

negligible.

There are no other IPFs (including effluents, physical disturbances to the seafloor, or wastes sent 

to shore for treatment or disposal) from the proposed activities which could impact marine and 

pelagic birds.

3. Public Health and Safety Due to Accidents.

There are no IPFs (emissions, effluents, physical disturbances to the seafloor, wastes sent to 

shore for treatment or disposal or accidents, including an accidental H2S release) from the 

proposed activities which could cause impacts to public health and safety. In accordance with 

NTL No.’s 2008-G04, 2009-G27, and 2009-G31, sufficient information is included in Section 4

to justify our request that our proposed activities be classified by BSEE as H2S absent. 

Coastal and Onshore

1. Beaches

IPFs from the proposed activities that could cause impacts to beaches include accidents (oil 

spills) and discarded trash and debris. 

Accidents: Oil spills contacting beaches would have impacts on the use of recreational beaches 

and associated resources. Due to the distance from shore (87 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 FM O&G’s Regional OSRP (refer to information submitted in 

Section 8). 

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). FM O&G 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 FM O&G management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01.

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities which could impact beaches.

2. Wetlands

IPFs from the proposed activities that could cause impacts to wetlands include accidents (oil 

spills) and discarded trash and debris. 

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

5, Water Quality). Due to the distance from shore (87 miles) and the response capabilities that 

would be implemented, no impacts are expected. The activities proposed in this plan will be 

covered by FM O&G’s Regional OSRP (refer to information submitted in Section 8). 

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). FM O&G 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 FM O&G management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01.

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities which could impact 

wetlands.

3. Shore Birds and Coastal Nesting Birds

Accidents: Oil spills could cause impacts to shore birds and coastal nesting birds. However, it is 

unlikely that an oil spill would occur from the proposed activities (refer to Item 5, Water 

Quality). Given the distance from shore (87 miles) and the response capabilities that would be 

implemented, no impacts are expected. The activities proposed in this plan will be covered by 

FM O&G’s Regional OSRP (refer to information submitted in Section 8). 

Discarded trash and debris: Coastal and marine birds are highly susceptible to entanglement 

in floating, submerged, and beached marine debris: specifically plastics. Operators are prohibited 

from deliberately discharging debris as mandated by MARPOL-Annex V and the Marine Plastic 

Pollution Research and Control Act, and regulations imposed by various agencies including the 

United States Coast Guard (USCG) and the Environmental Protection Agency (EPA). FM O&G

will operate in accordance with the regulations and also avoid accidental loss of solid waste 

items by maintaining waste management plans, manifesting trash sent to shore, and using special 

precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special 

caution will be exercised when handling and disposing of small items and packaging materials, 

particularly those made of non-biodegradable, environmentally persistent materials such as 

plastic or glass.

Informational placards will be posted on vessels and every facility that has sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from FM O&G management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01.
There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities that could cause impacts to 

shore birds and coastal nesting birds.

4. Coastal Wildlife Refuges

Accidents: An accidental oil spill from the proposed activities could cause impacts to coastal 

wildlife refuges. However, it is unlikely that an oil spill would occur from the proposed activities 

(refer to Item 5, Water Quality). Due to the distance from shore (87 miles) and the response 

capabilities that would be implemented, no impacts are expected. The activities proposed in this 

plan will be covered by FM O&G’s Regional OSRP (refer to information submitted in Section 

8).

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). FM O&G will operate in accordance with the 

regulations and also avoid accidental loss of solid waste items by maintaining waste management 

plans, manifesting trash sent to shore, and using special precautions such as covering outside 

trash bins to prevent accidental loss of solid waste. Special caution will be exercised when 

handling and disposing of small items and packaging materials, particularly those made of nonbiodegradable, environmentally persistent materials such as plastic or glass.

Informational placards will be posted on vessels and every facility that has sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from FM O&G management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01.

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities that could cause impacts to 

coastal wildlife refuges.

5. Wilderness Areas

Accidents: An accidental oil spill from the proposed activities could cause impacts to wilderness 

areas. However, it is unlikely that an oil spill would occur from the proposed activities (refer to 

Item 5, Water Quality). Due to the distance from the nearest designated Wilderness Area (118

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 FM O&G’s Regional OSRP 

(refer to information submitted in Section 8).
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). FM O&G will operate in accordance with the 

regulations and also avoid accidental loss of solid waste items by maintaining waste management 

plans, manifesting trash sent to shore, and using special precautions such as covering outside 

trash bins to prevent accidental loss of solid waste. Special caution will be exercised when 

handling and disposing of small items and packaging materials, particularly those made of nonbiodegradable, environmentally persistent materials such as plastic or glass.

Informational placards will be posted on vessels and every facility that has sleeping or food 

preparation capabilities. All offshore personnel, including contractors and other support 

services-related personnel (e.g. helicopter pilots, vessel captains and boat crews) will be 

indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint 

presentation), “Think About It” (previously “All Washed Up: The Beach Litter Problem”). 

Thereafter, all personnel will view the marine trash and debris training video annually. Offshore 

personnel will also receive an explanation from FM O&G management or the designated lease 

operator management that emphasizes their commitment to waste management in accordance 

with NTL No. 2012-G01.

There are no other IPFs (emissions, effluents, physical disturbances to the seafloor, or wastes 

sent to shore for treatment or disposal) from the proposed activities that could cause impacts to 

wilderness areas.

6. Other Environmental Resources Identified

There are no other environmental resources identified for this impact assessment.

(C) IMPACTS ON PROPOSED ACTIVITIES

The site–specific environmental conditions have been taken into account for the proposed 

activities. No impacts are expected on the proposed activities from site-specific environmental 

conditions.

(D) ENVIRONMENTAL HAZARDS

During the hurricane season, June through November, the Gulf of Mexico is impacted by an 

average of ten tropical storms (39-73 mph winds), of which six become hurricanes ( > 74 mph 

winds). Due to its location in the gulf, Atwater Valley Block 198 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. Structure Installation

Operator will not conduct structure installation operations during Tropical Storm or 

Hurricane threat.

(E) ALTERNATIVES

No alternatives to the proposed activities were considered to reduce environmental impacts.

(F) MITIGATION MEASURES

No mitigation measures other than those required by regulation will be employed to avoid, 

diminish, or eliminate potential impacts on environmental resources. 

(G) CONSULTATION

No agencies or persons were consulted regarding potential impacts associated with the proposed 

activities. Therefore, a list of such entities has not been provided. 

(H) PREPARER(S)

Evan Connolly

J. Connor Consulting, Inc.

16225 Park Ten Place, Suite 700

Houston, TX 77084

(281) 578-3388

evan.connolly@jccteam.com

(I) REFERENCES

Authors: 

American Petroleum Institute (API). 1989. Effects of offshore petroleum operations on cold 

water marine mammals: a literature review. Washington, DC: American Petroleum 

Institute. 385 pp.
Balazs, G.H. 1985. Impact of ocean debris on marine turtles: entanglement and ingestion. In: 

Shomura, R.S. and H.O. Yoshida, eds. Proceedings, Workshop on the Fate and Impact of

Marine Debris, 26-29 November 1984, Honolulu, HI. U.S. Dept. of Commerce. NOAA 

Tech. Memo. NOAA-TM-NMFS-SWFC-54. Pp 387-429.

Burke, C.J. and J.A. Veil. 1995. Potential benefits from regulatory consideration of synthetic 

drilling muds. Environmental Assessment Division, Argonne National Laboratory, 

ANL/EAD/TM-43.

Daly, J.M. 1997. Controlling the discharge of synthetic-based drilling fluid contaminated 

cuttings in waters of the United States. U.S. Environmental Protection Agency, Office of 

Water. Work Plan, June 24, 1997.

Hansen, D.J. 198l. The relative sensitivity of seabird populations in Alaska to oil pollution. U.S. 

Dept. of the Interior, Bureau of Land Management, Alaska OCS Region, Anchorage. BLMYK-ES-81-006-1792.

Laist, D.W. 1997. Impacts of marine debris: entanglement of marine life in marine debris 

including a comprehensive list of species with entanglement and ingestion records. In: Coe, 

J.M. and D.B. Rogers, eds. Marine debris: sources, impacts, and solutions. New York, NY: 

Springer-Verlag. Pp. 99-139.

Majors, A.P. and A.C. Myrick, Jr. 1990. Effects of noise on animals: implications for dolphins 

exposed to seal bombs in the eastern tropical Pacific purse-seine fishery–an annotated 

bibliography. NOAA Administrative Report LJ-90-06.

Marine Mammal Commission. 1999. Annual report to Congress – 1998.

Piatt, J.F., C.J. Lensink, W. Butler, M. Kendziorek, and D.R. Nysewander. 1990. Immediate 

impact of the Exxon Valdez oil spill on marine birds. The Auk. 107 (2): 387-397

Vauk , G., E. Hartwig, B. Reineking, and E. Vauk-Hentzelt. 1989. Losses of seabirds by oil 

pollution at the German North Sea coast. Topics in Marine Biology. Ros, J.D, ed. Scient. 

Mar. 53 (2-3): 749-754.

Vermeer, K. and R. Vermeer, 1975 Oil threat to birds on the Canadian west coast. The Canadian 

Field-Naturalist. 89:278-298.

Although not cited, the following were utilized in preparing this EIA:

 Hazard Surveys

 BOEM EIS’s:

o GOM Deepwater Operations and Activities. Environmental Assessment. BOEM 2000-

001 

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

Impact Statement. BOEM 96-0058.
Freeport-McMoRan Oil & Gas LLC Section 16 – Pg. 26 of 26

Initial EP December, 2014

Atwater Valley 198 (OCS-G 35431)

SECTION 16

ADMINISTRATIVE INFORMATION

16.1 EXEMPTED INFORMATION DESCRIPTION

The proposed bottomhole locations of the planned wells have been removed from the Public 

Information copy of this EP as well as any discussions of the target objectives, geologic or 

geophysical data, and any interpreted geology.

16.2 BIBLIOGRAPHY

1. C & C Technologies Survey Services. 3D/AUV Seismic Shallow Geohazard Report: 

“Sun” Prospect Block 154 (OCS-G-35019), 197 (OCS-G-35430) and 198 (OCS-G35431) Atwater Valley Area October, 2014, C & C Project: #140712.

2. C & C Technologies Survey Services. Archaeological Assessment Report: Blocks 154 

(OCS-G-35019), 197 (OCS-G-35430) and 198 (OCS-G-35431) Atwater Valley Area 

September, 2014, C & C Project: #140712.

3. C & C Technologies Survey Services. Well Site Clearance Proposed Well Locations “A,” 

“B,” “C,” “D,” and “E” Block 198 (OCS-G-35431) Atwater Valley Area October, 2014, C & 

C Project: #140712.

4. Regional Oil Spill Response Plan, Freeport-McMoRan Oil & Gas LLC (Control Number 

O-713).