U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

OCS EIS/EA

BOEM 2017-009

Gulf of Mexico OCS 

Oil and Gas Lease Sales: 2017-2022

Gulf of Mexico Lease Sales 249, 250, 251, 252, 253, 

254, 256, 257, 259, and 261

Final Multisale Environmental Impact Statement

Volume I: Chapters 1-3 

U.S. Department of the Interior

Bureau of Ocean Energy Management Gulf of Mexico OCS Region

OCS EIS/EA

BOEM 2017-009

Gulf of Mexico OCS

Oil and Gas Lease Sales: 2017-2022

Gulf of Mexico Lease Sales 249, 250, 251, 252, 253, 

254, 256, 257, 259, and 261

Final Multisale Environmental Impact Statement

Volume I: Chapters 1-3 

Author

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

Published by

New Orleans

March 2017



v 

COVER SHEET

Gulf of Mexico Multisale Environmental Impact Statement 

for 

Proposed Gulf of Mexico OCS Oil and Gas 

Lease Sales 249, 250, 251, 252, 253, 254, 256, 257, 259, and 261

Draft ( ) Final (x) 

Type of Action: Administrative (x) Legislative ( ) 

Area of Potential Impact: Offshore Marine Environment and Coastal Counties/Parishes of 

Texas, Louisiana, Mississippi, Alabama, and northwestern Florida

Agency Headquarters’ Contact Region Contacts

U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

(GM 623E)

1201 Elmwood Park Boulevard

New Orleans, LA 70123-2394

Stephanie Fiori

U.S. Department of the Interior

Bureau of Ocean Energy Management

45600 Woodland Road (VAM-OEP) 

Sterling, VA 20166-9216

703-787-1832

Helen Rucker

504-736-2421

Tershara Matthews

504-736-2676

ABSTRACT

This Final Multisale Environmental Impact Statement (EIS) covers the proposed 2017-2022

Gulf of Mexico’s Outer Continental Shelf (OCS) oil and gas lease sales as scheduled in the 2017-

2022 Outer Continental Shelf Oil and Gas Leasing: Proposed Final Program (Five-Year Program).

The 10 proposed regionwide lease sales are Lease Sale 249 in 2017, Lease Sales 250 and 251 in 

2018, Lease Sales 252 and 253 in 2019, Lease Sales 254 and 256 in 2020, Lease Sales 257 and 

259 in 2021, and Lease Sale 261 in 2022.

The proposed actions are Federal actions requiring an environmental review. This document 

provides the following information in accordance with the National Environmental Policy Act and its 

implementing regulations, and it will be used in making decisions on the proposals. This document 

includes the purpose and background of the proposed actions, identification of the alternatives, 

description of the affected environment, and an analysis of the potential environmental impacts of 

the proposed actions, alternatives, and associated activities, including proposed mitigating measures 

and their potential effects. Potential contributions to cumulative impacts resulting from activities 

associated with the proposed actions are also analyzed.
vi

Hypothetical scenarios were developed on the levels of activities, accidental events (such as 

oil spills), and potential impacts that might result if the proposed actions are adopted. Activities and 

disturbances associated with the proposed actions on biological, physical, and socioeconomic 

resources are considered in the analyses.

This Final Multisale EIS analyzes the potential impacts of the proposed actions on air and 

water quality, coastal habitats, deepwater benthic communities, Sargassum, live bottom habitats, 

fishes and invertebrates, birds, protected species, commercial and recreational fisheries, 

recreational resources, archaeological resources, human resources, and land use. It is important to 

note that this Final Multisale EIS was prepared using the best information that was publicly available 

at the time the document was prepared. Where relevant information on reasonably foreseeable 

significant adverse impacts is incomplete or unavailable, the need for the information was evaluated 

to determine if it was essential to a reasoned choice among the alternatives and if so, was either 

acquired or in the event it was impossible or exorbitant to acquire the information, accepted scientific 

methodologies were applied in its place.

Additional copies of this Final Multisale EIS and the other referenced publications may be 

obtained from the Bureau of Ocean Energy Management, Gulf of Mexico OCS Region, Public 

Information Office (GM 335A), 1201 Elmwood Park Boulevard, New Orleans, Louisiana 

70123-2394, by telephone at 504-736-2519 or 1-800-200-GULF, or on the Internet at 

http://www.boem.gov/nepaprocess/. 
Executive Summary vii

EXECUTIVE SUMMARY

PURPOSE OF AND NEED FOR THE PROPOSED ACTIONS

The Bureau of Ocean Energy Management 

(BOEM) has issued the 2017-2022 Outer Continental 

Shelf Oil and Gas Leasing: Final Proposed Program: 

(Five-Year Program; USDOI, BOEM, 2016a). The

Five-Year Program schedules 10 regionwide Gulf of 

Mexico (GOM) oil and gas lease sales. Five 

regionwide lease sales are tentatively scheduled in 

August of each year from 2017 through 2021 and five

regionwide lease sales are tentatively scheduled in 

March of each year from 2018 through 2022. The 

lease sales proposed in the GOM in the Five-Year Program are regionwide lease sales comprised of 

the Western, Central, and a small portion of the Eastern Planning Areas (WPA, CPA, and EPA, 

respectively) not subject to Congressional moratorium (Figure 1).

Figure 1. Proposed Regionwide Lease Sale Area Combining the Western, Central, and Eastern 

Planning Areas. 

The development of the Five-Year Program also triggers region-specific National 

Environmental Policy Act (NEPA) reviews for the proposed lease sales. Region-specific reviews are 

conducted by Program Area (e.g., the Gulf of Mexico and Alaska OCS Regions) prior to lease sale 

decisions for those areas that are included in the Five-Year Program. Even though the Five-Year 

Program includes regionwide lease sales, any individual lease sale could still be scaled back during 

the prelease sale process to conform more closely to the separate planning area model used in the 

2017-2022 Schedule of Proposed

Gulf of Mexico OCS Region 

Lease Sales

Lease Sale Number Year

249 2017

250 and 251 2018

252 and 253 2019

254 and 256 2020

257 and 259 2021

261 2022
viii Gulf of Mexico Multisale EIS

“It is hereby declared to be the 

policy of the United States that . . . 

the Outer Continental Shelf is a 

vital national resource held by the 

Federal Government for the public, 

which should be made available for 

expeditious and orderly 

development, subject to 

environmental safeguards, in a 

manner which is consistent with 

the maintenance of competition 

and other national needs."

OCSLA, 43 U.S.C. §§ 1331 et seq.

Proposed Final Outer Continental Shelf Oil & Gas Leasing Program: 2012-2017 (2012-2017 

Five-Year Program; USDOI, BOEM, 2012a), should circumstances warrant.

Purpose of the Proposed Actions

The Outer Continental Shelf Lands Act of 1953, as 

amended (43 U.S.C. §§ 1331 et seq. [1988]), hereafter 

referred to as the OCSLA, establishes the Nation’s policy 

for managing the vital energy and mineral resources of the 

Outer Continental Shelf (OCS). Section 18 of the OCSLA 

requires the Secretary of the Interior to prepare and 

maintain a schedule of proposed OCS oil and gas lease 

sales determined to “best meet national energy needs for 

the 5-year period following its approval or reapproval”

(43 U.S.C. § 1344). The Five-Year Program establishes a 

schedule that the U.S. Department of the Interior (USDOI

or DOI) will use as a basis for considering where and when 

leasing might be appropriate over a 5-year period.

The purpose of the proposed Federal actions in this 2017-2022 Gulf of Mexico Multisale 

Environmental Impact Statement (Multisale EIS) is to offer for lease those areas that may contain 

economically recoverable oil and gas resources in accordance with the OCSLA, which specifically 

states “should be made available for expeditious and orderly development, subject to environmental 

safeguards” (OCSLA, 43 U.S.C. §§ 1331 et seq.). The proposed lease sales would provide qualified 

bidders the opportunity to bid upon and lease acreage in the Gulf of Mexico OCS in order to explore, 

develop, and produce oil and natural gas.

Need for the Proposed Actions

The need for the proposed actions is to further the orderly development of OCS resources in

an environmentally and economically responsible manner. Oil serves as the feedstock for liquid 

hydrocarbon products, including gasoline, aviation and diesel fuel, and various petrochemicals. Oil 

from the Gulf of Mexico OCS contributes to meeting domestic demand and enhances national 

economic security. 

THE DECISION TO BE MADE

BOEM will make an individual decision on whether and how to proceed with each proposed 

lease sale in the Five-Year Program. After completion of this Multisale EIS, BOEM will make a 

decision on proposed Lease Sale 249 (i.e., prepare a Record of Decision for Lease Sale 249 only). 

As discussed in Chapter 1.3.1, individual decisions will be made on each subsequent lease sale 

after completion of the appropriate supplemental NEPA documents.
Executive Summary ix

PUBLIC INVOLVEMENT

BOEM conducted a public scoping process that extended from April 29 to June 1, 2015. 

Public scoping meetings were held in five cities (New Orleans, Louisiana; Houston, Texas; Panama 

City, Florida; Mobile, Alabama; and Gulfport, Mississippi). In addition to accepting oral and written 

comments at each public meeting, BOEM accepted written comments by mail, email, and through 

the regulations.gov web portal (http://www.regulations.gov). BOEM received a total of 10 comments

in response to the Notice of Intent to Prepare an EIS. Many of the comments cited broad 

environmental concerns or specific concern about impacts on marine wildlife in general or on 

protected species such as marine mammals and sea turtles. Others cited concerns about impacts to 

critical habitats, fish and fisheries, sensitive benthic communities, and pelagic resources. Several of 

the comments had concerns with the effects of oil spills and the safety of offshore operations. Within 

the broad category of socioeconomics, comments focused on impacts on fisheries, recreation, 

tourism, and local jobs. Some of the comments provided recommendations for inclusion of particular 

alternatives or mitigation in this Multisale EIS analysis. Some comments recommended the 

implementation of specific analysis methodologies, while others recommended that recent industry 

technology and safety advances be taken into consideration.

Pursuant to the OCSLA, the Bureau of Ocean Energy Management published a Call for 

Information (Call) to request and gather information to determine the Area Identification (Area ID) for 

each lease sale. The Call was published in the Federal Register (2015a) on September 4, 2015. 

The Call invited potential bidders to nominate areas of interest within the program area(s) included in 

the 2017-2022 Outer Continental Shelf Oil and Gas Leasing: Draft Proposed Program (Draft 

Proposed Program). The Call was also an opportunity for the public to provide information on 

environmental, socioeconomic, and other considerations relevant to determining the Area ID. The 

comment period for the Call closed on October 5, 2015. BOEM received one comment letter in 

response to the Call from the Louisiana Department of Natural Resources. The Louisiana Office of 

Coastal Management requested that BOEM consider secondary and cumulative impacts of OCS 

lease sales on coastal environments as well as identify, quantify, and mitigate (e.g., compensatory 

mitigation) secondary and cumulative harm that occurs to Louisiana’s coastal wetlands, and 

implement plans for validating predictions of social and environmental effects on coastal resources. 

Using information provided in response to the Call and from scoping comments, BOEM then 

developed an Area ID recommendation memorandum. The Area ID is an administrative prelease 

step that describes the geographic area for environmental analysis and consideration for leasing. 

On November 20, 2015, the Area ID decision was made. One Area ID was prepared for all 

proposed lease sales. The Area ID memorandum recommended keeping the entire regionwide area 

of the GOM included in the Draft Proposed Program for consideration in this Multisale EIS. The area 

identified for lease includes all of the available unleased blocks in the GOM not subject to 

Congressional moratorium pursuant to the Gulf of Mexico Energy Security Act of 2006.

A Notice of Availablity (NOA) of the Draft Multisale EIS was published in the Federal Register

on April 22, 2016, initiating a solicitation of public comments on the Draft Multisale EIS (Federal 

Register, 2016a). The 45-day comment period ended on June 7, 2016. In accordance with 
x Gulf of Mexico Multisale EIS

30 CFR § 556.26, BOEM scheduled public meetings soliciting comments on the Draft Multisale EIS. 

Ninety-three individuals attended five public meetings, which were held in Beaumont, Texas; New 

Orleans, Louisiana; Panama City, Florida; Mobile, Alabama; and Gulfport, Mississippi. BOEM 

received over 1,300 comments in response to the Draft Multisale EIS via letter, email, written and 

verbal comments at public meetings, and the regulations.gov website. A large majority of the 

comments was a form letter from the “No New Leases” organization. As requested by the Director 

of the Mississippi Coalition for Vietnamese-American Fisher Folks and Families (MSCVAFF) during 

the comment period, BOEM had select portions of the Multisale EIS (the summary, fish and 

invertebrates, and commercial fishing sections, as well as meeting handouts) translated into the 

Vietnamese language. Once completed, these documents were made available to the MSCVAFF

for review and comment through August 31, 2016. BOEM did not receive any additional comments.

ALTERNATIVES

BOEM has identified four action alternatives, and the no action alternative, to be analyzed in 

this Multisale EIS. These alternatives are briefly described below. The mitigating measures

(pre- and postlease), including the proposed stipulations, are fully described in Chapter 2 and

Appendices B and D, as are the deferred alternatives not analyzed in detail.

Alternative A—Regionwide OCS Lease Sale (The Preferred Alternative)

Alternative A would allow for a proposed regionwide lease sale encompassing all three 

planning areas within the U.S. portion of the Gulf of Mexico OCS for any given lease sale in the 

Five-Year Program. This is BOEM’s preferred alternative. This alternative would offer for lease all 

available unleased blocks within the WPA, CPA, and EPA portions of the proposed lease sale area 

for oil and gas operations (Figure 2), with the following exceptions:

(1) whole and portions of blocks deferred by the Gulf of Mexico Energy Security Act 

of 2006 (discussed in the OCS Regulatory Framework white paper [Cameron 

and Matthews, 2016]); 

(2) blocks that are adjacent to or beyond the United States’ Exclusive Economic 

Zone in the area known as the northern portion of the Eastern Gap; and

(3) whole and partial blocks within the current boundary of the Flower Garden 

Banks National Marine Sanctuary. 
Executive Summary xi

Figure 2. Proposed Regionwide Lease Sale Area, Encompassing the Available Unleased Blocks within 

All Three Planning Areas (approximately 91.93 million acres with approximately 75.4 million 

acres available for lease as of January 2017).

Alternative B—Regionwide OCS Lease Sale Excluding Available Unleased Blocks in the WPA

Portion of the Proposed Lease Sale Area

Alternative B would allow for a proposed lease sale encompassing the CPA and EPA within 

the U.S. portion of the Gulf of Mexico OCS (Figure 3). Available blocks within the WPA would not

be considered under this alternative. This alternative would offer for lease all available unleased 

blocks within the CPA and EPA portions of the proposed lease sale area as those planning area 

portions described in Alternative A for oil and gas operations, with the following exceptions:

(1) whole and portions of blocks deferred by the Gulf of Mexico Energy Security Act 

of 2006 (discussed in the OCS Regulatory Framework white paper [Cameron 

and Matthews, 2016]); and

(2) blocks that are adjacent to or beyond the United States’ Exclusive Economic 

Zone in the area known as the northern portion of the Eastern Gap. 
xii Gulf of Mexico Multisale EIS

Figure 3. Proposed Lease Sale Area for Alternative B, Excluding the Available Unleased Blocks in the 

WPA (approximately 63.35 million acres with approximately 49.6 million acres available for 

lease as of January 2017).

Alternative C—Regionwide OCS Lease Sale Excluding Available Unleased Blocks in the 

CPA/EPA Portions of the Proposed Lease Sale Area

Alternative C would allow for a proposed lease sale encompassing the WPA within the U.S. 

portion of the Gulf of Mexico OCS (Figure 4). Available blocks within the CPA and EPA would not

be considered under this alternative. This alternative would offer for lease all available unleased 

blocks within the WPA portion of the proposed lease sale area for oil and gas operations, with the 

following exception:

(1) whole and partial blocks within the current boundary of the Flower Garden Banks

National Marine Sanctuary. 
Executive Summary xiii

Figure 4. Proposed Lease Sale Area for Alternative C, Excluding the Available Unleased Blocks in the 

CPA and EPA (approximately 28.58 million acres with approximately 25.8 million acres

available for lease as of January 2017).

Alternative D—Alternative A, B, or C, with the Option to Exclude Available Unleased Blocks 

Subject to the Topographic Features, Live Bottom (Pinnacle Trend), and/or Blocks South of 

Baldwin County, Alabama, Stipulations

Alternative D could be combined with any of the action alternatives above (A, B, or C) and 

would allow the flexibility to offer leases under any alternative with additional exclusions. Under 

Alternative D, the decisionmaker could exclude from leasing any available unleased blocks subject 

to any one and/or combination of the following stipulations: 

• Topographic Features Stipulation; 

• Live Bottom (Pinnacle Trend) Stipulation; and

• Blocks South of Baldwin County, Alabama, Stipulation (not applicable to 

Alternative C). 

This alternative considered blocks subject to these stipulations because these areas have 

been emphasized in scoping, can be geographically defined, and adequate information exists 

regarding their ecological importance and sensitivity to OCS oil- and gas-related activities, as shown 
xiv Gulf of Mexico Multisale EIS

in Figure 5. All of the assumptions (including the other potential mitigating measures) and estimates 

would remain the same as described for any given alternative.

Figure 5. Identified Topographic Features, Pinnacle Trend, and Baldwin County Stipulation Blocks in 

the Gulf of Mexico.

Alternative E—No Action

Alternative E is the cancellation of a single proposed lease sale. The opportunity for 

development of the estimated oil and gas that could have resulted from a proposed action (i.e., a 

single proposed lease sale) or alternative to a proposed action, as described above, would be 

precluded or postponed to a future lease sale. Any potential environmental impacts resulting from a 

proposed lease sale would not occur. Activities related to previously issued leases and permits (as 

well as those that may be issued in the future under a separate decision) related to the OCS oil and 

gas program would continue. If a lease sale were to be cancelled, the resulting development of oil 

and gas would most likely be postponed to a future lease sale; therefore, the overall level of OCS 

oil- and gas-related activity would only be reduced by a small percentage, if any.
Executive Summary xv 

MITIGATING MEASURES

Proposed lease stipulations and other mitigating measures designed to reduce or eliminate 

environmental risks and/or potential multiple-use conflicts between OCS operations and U.S. 

Department of Defense activities may be applied to the chosen alternative. Mitigating measures in 

the form of lease stipulations are added to the lease terms and are therefore enforceable as part of 

the lease. The 10 lease stipulations being considered are the Topographic Features Stipulation; 

Live Bottom (Pinnacle Trend) Stipulation; Military Areas Stipulation; Evacuation Stipulation; 

Coordination Stipulation; Blocks South of Baldwin County, Alabama, Stipulation; Protected Species 

Stipulation; United Nations Convention on the Law of the Sea Royalty Payment Stipulation; Below 

Seabed Operations Stipulation; and the Stipulation on the Agreement between the United States of 

America and the United Mexican States Concerning Transboundary Hydrocarbon Reservoirs in the 

Gulf of Mexico (Transboundary Stipulation). The United Nations Convention on the Law of the Sea 

Royalty Payment Stipulation is applicable to a proposed lease sale even though it is not an 

environmental or military stipulation. The Topographic Features and Live Bottom (Pinnacle Trend) 

Stipulations have been applied as programmatic mitigation in the Five-Year Program EIS (USDOI, 

BOEM, 2016b) and, therefore, would apply to all leases issued under the Five-Year Program in the 

designated lease blocks. Chapter 2.2.4 provides a brief description of each stipulation and the 

potential benefits associated with its use. Appendix D provides a more detailed analysis of the 

10 lease stipulations and their effectiveness.

Application of lease stipulations will be considered by the Assistant Secretary of the Interior 

for Land and Minerals Management (ASLM). The inclusion of the stipulations as part of the analysis 

of the proposed actions does not ensure that the ASLM will make a decision to apply the stipulations 

to leases that may result from a proposed lease sale, nor does it preclude minor modifications in 

wording during subsequent steps in the prelease process if comments indicate changes are 

necessary or if conditions warrant. Any lease stipulations or mitigating measures to be included in a 

lease sale will be described in the Final Notice of Sale. In addition, mitigations may be added to plan 

and/or permits for OCS oil- and gas-related activities (Chapter 2.2.4.3). For more information on 

mitigating measures that are added at the postlease stage, refer to Appendix B (“Commonly 

Applied Mitigating Measures”).

DIRECT AND INDIRECT ACTIONS ASSOCIATED WITH A PROPOSED LEASE SALE

BOEM describes the potentially occurring actions associated with a single proposed lease 

sale and the cumulative activities that provide a framework for a detailed analysis of the potential 

environmental impacts. Exploration and development scenarios describe the infrastructure and 

activities that could potentially affect the biological, physical, and socioeconomic resources in the 

GOM. They also include a set of ranges for resource estimates, projected exploration and 

development activities, and impact-producing factors.

Offshore activities are described in the context of scenarios for a proposed action 

(Chapter 3.1) and for the OCS Program (Chapter 3.3). BOEM’s Gulf of Mexico OCS Region 

developed these scenarios to provide a framework for detailed analyses of potential impacts of a 
xvi Gulf of Mexico Multisale EIS

proposed lease sale. The scenarios are presented as ranges of the amounts of undiscovered, 

unleased hydrocarbon resources estimated to be leased and discovered as a result of a proposed 

action. The analyses are based on a traditionally employed range of activities (e.g., the installation 

of platforms, wells, and pipelines, and the number of helicopter operations and service-vessel trips) 

that would be needed to develop and produce the amount of resources estimated to be leased.

Within each resource section in Chapter 4, the cumulative analysis considers environmental 

and socioeconomic impacts that may result from the incremental impact of a proposed action when 

added to all past, present, and reasonably foreseeable future activities, including non-OCS oil- and 

gas-related activities such as import tankering and commercial fishing, as well as all OCS oil- and 

gas-related activities (OCS Program). This includes projected activity from lease sales that have 

been held but for which exploration or development has not yet begun or is continuing. In addition, 

impacts from natural occurrences, such as hurricanes, are analyzed.

ENVIRONMENTAL IMPACTS

The affected environment and the potential impacts of a single proposed lease sale and 

each alternative have been described and analyzed by resource. Analysis of the alternatives include 

routine activities, accidental events, cumulative impact analysis, incomplete or unavailable 

information, and conclusions for each resource. This Multisale EIS also considers baseline data in 

the assessment of impacts from a proposed action on the resources and the environment 

(Chapter 4). 

The major issues that frame the environmental analyses in this Multisale EIS are the result of 

concerns raised during years of scoping for the Gulf of Mexico OCS Program. Issues related to 

OCS oil and gas exploration, development, production, and transportation activities include the 

potential for oil spills, wetlands loss, air emissions, wastewater discharges and water quality

degradation, marine trash and debris, structure and pipeline emplacement activities, platform 

removal, vessel and helicopter traffic, multiple-use conflicts, support services, population 

fluctuations, land-use planning, impacts to recreation and beaches, aesthetic interference, 

environmental justice, and conflicts with State coastal zone management programs. Environmental 

resources and activities identified during the scoping process that warrant an environmental analysis 

include air quality, water quality, coastal habitats (including wetlands and seagrasses), barrier 

beaches and associated dunes, live bottom habitats (including topographic features and pinnacle 

trends), Sargassum and associated communities, deepwater benthic communities, marine 

mammals, sea turtles, birds, fishes and invertebrate resources, commercial fisheries, recreational 

fishing, recreational resources, archaeological resources, and socioeconomic factors (including 

environmental justice), and within the CPA only, beach mice. 

Other relevant issues include impacts from the Deepwater Horizon explosion, oil spill, and 

response; impacts from past and future hurricanes on environmental and socioeconomic resources; 

and impacts on coastal and offshore infrastructure. During the past several years, the Gulf Coast 

States and Gulf of Mexico oil and gas activities have been impacted by major hurricanes. The 
Executive Summary xvii

description of the affected environment includes impacts from these relevant issues on the physical 

environment, biological environment, and socioeconomic activities, and on OCS oil- and gas-related 

infrastructure.

Impact Conclusions

The full analyses of the potential impacts of routine activities and accidental events 

associated with a proposed action and a proposed action’s incremental contribution to the 

cumulative impacts are described in the individual resource discussions in Chapter 4. A summary 

of the potential impacts from a proposed action on each environmental and socioeconomic resource 

and the conclusions of the analyses can be found in the following discussions. Table 1 provides a 

comparison of the expected impact levels by alternative and is derived from the analysis of each 

resource in Chapter 4. The impact level ratings have been specifically tailored and defined for each 

resource within the Chapter 4 impact analysis. Cumulative impacts of current and past activities 

would continue to occur under Alternative E.

Table 1. Alternative Comparison Matrix. 

Impact Level Key1

Beneficial2 Negligible Minor Moderate Major

Alternative

Resource A B C D E

Air Quality Minor Minor Minor Minor None

Water Quality Negligible Negligible Negligible Negligible None

Coastal Habitats

Estuarine 

Systems Moderate Moderate Minor Moderate Negligible

Coastal Barrier 

Beaches and 

Associated 

Dunes

Minor Minor

Negligible to Negligible to

Negligible

Minor Minor

Deepwater Benthic 

Communities Negligible Negligible Negligible Negligible None

Sargassum and 

Associated 

Communities

Negligible Negligible Negligible Negligible None

Live Bottoms

Topographic 

Features Negligible Negligible Negligible Negligible None

Pinnacles and 

Low-Relief

Features

Negligible to Negligible to Negligible Negligible None

Minor Minor

Fishes and 

Invertebrate 

Resources

Minor Minor Minor Minor None

Birds Moderate Moderate Moderate Moderate None
xviii Gulf of Mexico Multisale EIS

Impact Level Key1

Beneficial2 Negligible Minor Moderate Major

Alternative

Resource A B C D E

Protected Species

Marine Mammals Negligible Negligible Negligible Negligible None

Sea Turtles Negligible Negligible Negligible Negligible None

Beach Mice Negligible Negligible Negligible Negligible None

Protected Birds Negligible Negligible Negligible Negligible None

Protected Corals Negligible Negligible Negligible Negligible None

Commercial 

Fisheries

Beneficial to Beneficial to Beneficial to Beneficial to Negligible Minor Minor Minor Minor

Recreational 

Fishing

Beneficial to Beneficial to Beneficial to Beneficial to Negligible Minor Minor Minor Minor

Recreational 

Resources

Beneficial to Beneficial to Beneficial to Beneficial to Negligible Minor Minor Minor Minor

Archaeological 

Resources Negligible3 Negligible3 Negligible3 Negligible3 None

Human Resources

and Land Use

Land Use and 

Coastal 

Infrastructure

Economic 

Factors

Minor Minor Minor Minor None

Beneficial to Beneficial to Beneficial to Beneficial to Negligible to

Minor Minor Minor Minor Minor

Social Factors 

(including 

Environmental 

Justice)

Minor Minor Minor Minor None

Note: Some resources have a range for the impact levels to account for certain variables such as the 

uncertainty of non-OCS oil- or gas-related activities, the level and magnitude of potential 

accidental events, and the minimization of the OCS oil- or gas-related impacts through lease 

stipulations, mitigations, and/or regulations. The impact level ratings have been specifically 

tailored and defined for each resource within the Chapter 4 impact analysis.

1 The findings for Alternatives A-D would be the incremental contribution of a proposed action to what 

would be expected to occur under the No Action Alternative (i.e., no lease sale). Therefore, each 

impact determination under Alternatives A-D assumes that the conditions and impacts (i.e., past, 

present, and future activities) under the No Action Alternative would be present.

2 The level of beneficial impacts is specified in the analysis, which could range from low, medium, or 

high.

3 The level of impacts for archaeological resources ranges between negligible to major and is dependent 

upon whether survey is performed, mitigation is imposed, mitigation is followed, or a site is identified 

prior to the activity.

Air Quality

Air quality is the degree at which the ambient air is free of pollution; it is assessed by 

measuring the pollutants in the air. To protect public health and welfare, the Clean Air Act 
Executive Summary xix

established National Ambient Air Quality Standards (NAAQS) for certain common and widespread 

pollutants. The six common "criteria pollutants" are particle pollution (also known as particulate 

matter, PM2.5 and PM10), carbon monoxide (CO); nitrogen dioxide (NO2); sulfur dioxide (SO2); lead 

(Pb); and ozone (O3). Air emissions from OCS oil and gas development in the Gulf of Mexico would 

arise from emission sources related to drilling and production with associated vessel support, flaring

and venting, decommissioning, fugitive emissions, and oil spills. Associated activities that take place 

as a result of a proposed action support and maintain the OCS oil and gas platform sources. Air 

emissions from non-OCS oil- and gas-related emissions in the Gulf of Mexico would arise from 

emission sources related to State oil and gas programs, onshore industrial and transportation 

sources, and natural events. Since the primary National Ambient Air Quality Standards are 

designed to protect human health, BOEM focuses on the impact of these activities on the States, 

where there are permanent human populations.

In the “Air Quality Modeling in the Gulf of Mexico Region” study (Appendices F-H), 

photochemical grid modeling was conducted to assess the impacts to nearby states of existing and 

proposed future OCS oil and gas exploration, development, and production. This draft interim 

assessment is being used to disclose potential cumulative and incremental air quality impacts of the 

proposed lease sales; the final results are expected in fall 2017. The air quality modeling study 

examines the potential impacts of the proposed lease sales with respect to the NAAQS for the 

criteria pollutants O3, NO2, SO2, CO, PM2.5, PM10; the air quality-related values (AQRVs), including 

visibility and acid deposition (sulfur and nitrogen) in nearby Class I and sensitive Class II areas; and 

the incremental impacts of Prevention of Significant Deterioration (PSD) pollutants (NO2, PM10, 

PM2.5) with respect to PSD Class I and Class II increments. (Note: This analysis does not constitute 

a regulatory PSD increment consumption analysis as would be required for major sources subject to 

the New Source Review program requirements of the Clean Air Act). An assessment of the final 

study results will be discussed in future NEPA documents.

A regionwide lease sale has not previously been analyzed and historic trend data are limited. 

In the scenario in Chapter 3.1, the projected activities of a single regionwide lease sale is based on 

a range of historic observations and provides a reasonable expectation of oil and gas production 

anticipated from a single proposed lease sale. The projected activities of 10 proposed regionwide 

lease sales’ mid-case scenario, which was used in the model, falls within the range of a single 

proposed lease sale. To understand how these results would apply to a single proposed lease sale, 

the level of projected activity was compared between the modeled highest year of the 10 proposed 

lease sales to a single proposed lease sale. This is conservative because the current price of oil 

equals the low range of the scenario. Using these assumptions, the potential impacts of a single 

proposed lease sale would be minor. More specifically, the potential impacts of a single proposed 

lease sale to the Breton Wilderness Area would be moderate, whereas the overall potential impacts 

of a single proposed lease sale would be minor for all other areas. However, since these potential 

impacts are conservative given the current prices of oil and gas, BOEM anticipates future modeling. 

A full analysis of air quality can be found in Chapter 4.1. 
xx Gulf of Mexico Multisale EIS

The incremental contribution of a proposed lease sale to the cumulative impacts would most 

likely have a minor effect on coastal nonattainment areas because most impacts on the affected 

resource could be avoided with proper mitigation. Portions of the Gulf Coast onshore areas have 

ozone levels that exceed the Federal air quality standard, but the incremental contribution from a 

proposed lease sale would be very small and would not on their own cause an exceedance.

As previously stated, BOEM contracted an air quality modeling study in the GOM region to 

assess the impacts of OCS oil- and gas-related development to nearby States, as required under the 

OCSLA. The data from forecasted emissions resulting from the 10 proposed lease sales was 

annualized using BOEM’s Resource Evaluation’s mid-case scenario. These results are presented in 

Appendices F-H. The cumulative impacts from all 10 proposed lease sales would be minor to 

moderate. More specifically, the cumulative impacts of 10 proposed lease sales to the Breton 

Wilderness Area and Gulf Islands National Seashore would be moderate, whereas the overall 

cumulative impacts of 10 proposed lease sales would be minor to moderate. 

The cumulative impacts, in addition to the past, present, and future activities, of 10 proposed 

lease sales would most likely have a moderate effect on coastal nonattainment areas for certain 

pollutants. Portions of the Gulf Coast onshore areas have ozone levels that exceed the Federal air 

quality standard, but the cumulative impacts from 10 proposed lease sales do not on their own 

cause an exceedance. A full analysis of air quality can be found in Chapter 4.1. 

Water Quality

Water quality is a term used to describe the condition or environmental health of a waterbody 

or resource, reflecting its particular biological, chemical, and physical characteristics and the ability 

of the waterbody to maintain the ecosystems it supports and influences. It is an important measure 

for both ecological and human health. The impacts of OCS Program-related drilling operational 

discharges (Chapter 3.1.5.1) on water quality are short term and localized. The potential impact 

from the discharge of produced water is considered negligible (beyond 1,000 m [3,281 ft]) to 

moderate (within 1,000 m [3,281 ft]). The potential impacts from OCS Program-related oil spills on 

water quality after mitigation are also short term and are considered moderate, even with the 

implementation of mitigating measures. This is because, after removal of most free product, the 

residual oil dissipates quickly through dispersion and weathering; however, secondary impacts to 

water quality may occur, such as the introduction of additional hydrocarbon into the dissolved phase 

through the use of dispersants and the sinking of hydrocarbon residuals from burning. The impacts 

from a proposed action are a small addition to the cumulative impacts on water quality when 

compared with inputs from hypoxia, potentially leaking shipwrecks, chemical weapon and industrial 

waste dumpsites, natural oil seeps, and natural turbidity. The incremental contribution of the routine 

activities and accidental events associated with a proposed action to the cumulative impacts on 

water quality is not expected to be significant. For Alternative E, the cancellation of a proposed 

lease sale would result in no new activities associated with a proposed lease sale; therefore, the 

incremental impacts would be none. A full analysis of water quality can be found in Chapter 4.2. 
Executive Summary xxi

Coastal Habitats

Estuarine Systems (Wetlands and Seagrasses/Submerged Vegetation) 

The estuarine system is the transition zone between freshwater and marine environments. It 

can consist of many habitats, including wetlands and submerged vegetation. The impacts to these 

habitats from routine activities associated with a proposed action are expected to be minor to 

moderate. Minor impacts would be due to the projected low probability for any new pipeline

landfalls (0-1 projected), the minimal contribution to the need for maintenance dredging, and the 

mitigating measures expected to be used to further reduce or avoid these impacts (e.g., use of 

modern techniques such as directional drilling). However, impacts caused by vessel operation 

related to the proposed action over a 50-year period would be moderate considering the permanent 

loss of hundreds of acres of wetlands. Overall, impacts to estuarine habitats from oil spills

associated with activities related to a proposed action would be expected to be minor because of 

the distance of most postlease activities from the coast, the expected weathering of spilled oil, the 

projected low probability of large spills near the coast, the resiliency of wetland vegetation, and the 

available cleanup techniques.

Cumulative impacts to estuarine habitats are caused by a variety of factors, including the 

OCS oil- and gas-related and non-OCS oil- and gas-related activities outlined in Chapter 4.3.1 and 

the human and natural impacts. Development pressures in the coastal regions of the GOM have 

been largely the result of tourism and residential beach-side development, and this trend is expected 

to continue. Storms would continue to impact the coastal habitats and have differing impacts. The 

incremental contribution of a proposed action to the cumulative impacts on estuarine habitats is 

expected to be minor to moderate depending on the selected alternative. For Alternative E, the 

cancellation of a proposed lease sale would result in no new activities associated with a proposed 

lease sale. There could, however, be some incremental increase in impacts caused by a 

compensatory increase in imported oil and gas to offset reduced OCS production, but it would likely 

be negligible. A full analysis of estuarine habitats can be found in Chapter 4.3.1. 

Coastal Barrier Beaches and Associated Dunes

The coastal barrier beaches and associated dunes are those beaches and dunes that line 

the coast of the northern GOM, including both barrier islands and beaches on the mainland. The 

impacts to coastal barrier beaches and dunes from routine activities associated with a proposed 

action are expected to be minor due to the minimal number of projected onshore pipelines, the 

minimal contribution to vessel traffic and the need for maintenance dredging, and the mitigating 

measures that would be used to further reduce or avoid these impacts. The greater threat from an 

oil spill to coastal beaches is from a coastal spill as a result of a nearshore vessel accident or 

pipeline rupture and from cleanup activities. Overall, impacts to coastal barrier beaches and dunes 

from oil spills associated with OCS oil- and gas-related activities related to a proposed action would 

be expected to be minor because of the distance of most of the resulting activities from the coast, 

expected weathering of spilled oil, projected low probability of large spills near the coast, and 

available cleanup techniques. Cumulative impacts to coastal barrier beaches and dunes are caused 
xxii Gulf of Mexico Multisale EIS

by a variety of factors, including the OCS oil- and gas-related and non-OCS oil- and gas-related 

activities outlined in Chapter 4.3.2 and the other human and natural impacts. Development 

pressures in the coastal regions of the GOM have been largely the result of tourism and residential 

beach-side development, and this trend is expected to continue. Efforts to stabilize the GOM 

shoreline can deprive natural restoration of the barrier beaches through sediment nourishment and 

sediment transport, which has adversely impacted coastal beach landscapes. Storms will continue 

to impact the coastal habitats and have differing impacts. The incremental contribution of a 

proposed action to the cumulative impacts on coastal barrier beaches and dunes is expected to be 

minor. Under Alternative E, the cancellation of a proposed lease sale, the resulting additional 

impacts to coastal barrier beaches and dunes would be negligible; however, cumulative impacts 

from all sources, including OCS and non-OCS sources, would be the same as Alternative A. A full 

analysis of coastal barrier beaches and associated dunes can be found in Chapter 4.3.2. 

Deepwater Benthic Communities

BOEM defines “deepwater benthic communities” as including both chemosynthetic 

communities (chemosynthetic organisms plus seep-associated fauna) and deepwater coral

communities (deepwater coral plus associated fauna). These communities are typically found in 

water depths of 984 feet (ft) (300 meters [m]) or deeper throughout the GOM, although deepwater 

benthic habitats are relatively rare compared with ubiquitous soft bottom habitats. 

The OCS oil- and gas-related impact-producing factors for deepwater benthic communities 

can be grouped into three main categories: (1) bottom-disturbing activities; (2) drilling-related 

sediment and waste discharges; and (3) noncatastrophic oil spills. These impact-producing factors 

have the potential to damage individual deepwater habitats and disrupt associated benthic 

communities if insufficiently distanced or otherwise mitigated. However, impacts from individual 

routine activities and accidental events are usually temporary, highly localized, and expected to 

impact only small numbers of organisms and substrates at a time. Moreover, use of the expected 

site-specific plan reviews/mitigations will distance activities from deepwater benthic communities, 

greatly diminishing the potential effects. Therefore, at the regional, population-level scope of this 

analysis and assuming adherence to all expected regulations and mitigations, the incremental 

contribution would be expected to be negligible to minor. Proposed OCS oil- and gas-related 

activities would also contribute incrementally to the overall OCS and non-OCS cumulative effects 

experienced by deepwater benthic communities and habitats. The OCS oil- and gas-related 

cumulative impacts to deepwater benthic communities are estimated to be negligible to minor. 

Under Alternative E, the potential for impacts would be none because new impacts to deepwater 

benthic communities related to a cancelled lease sale would be avoided entirely. A full analysis of 

deepwater benthic communities can be found in Chapter 4.4. 

Sargassum and Associated Communities

Sargassum in the GOM is comprised of S. natans and S. fluitans, and is characterized by a 

brushy, highly branched thallus with numerous leaf-like blades and berrylike pneumatocysts. The 

Sargassum cycle is truly expansive, encompassing most of the western Atlantic Ocean and the Gulf 
Executive Summary xxiii

of Mexico with the growth, death, and decay of these plant and epiphytic communities, which may 

play a substantial role in the global carbon cycle. Several impacting factors can affect Sargassum, 

including vessel-related operations, oil and gas drilling discharges, operational discharges, 

accidental spills, non-OCS oil- and gas-related vessel activity, and coastal water quality. Routine 

vessel operations and accidental events that occur during drilling operations or vessel operations, 

and oiling due to an oil spill were the impact-producing factors that could be reasonably expected to 

impact Sargassum populations in the GOM. All of these impact-producing factors would result in the 

death or injury to the Sargassum plants or to the organisms that live within or around the plant 

matrix. However, the unique and transient characteristics of the life history of Sargassum and the 

globally widespread nature of the plants and animals that use the plant matrix buffer against impacts

that could be at any given location. Impacts to the overall population of the Sargassum community 

are therefore expected to be negligible from either routine activities or reasonably foreseeable 

accidental events. The incremental impact of a proposed action on the population of Sargassum 

would be negligible when considered in the context of cumulative impacts to the population. Under 

Alternative E, a proposed lease sale would be cancelled and the potential for impacts from routine 

activities and accidental events would be none. Impacts from changing water quality would be 

much more influential on Sargassum than OCS development and would still occur without the 

presence of OCS oil- and gas-related activities. A full analysis of Sargassum and associated 

communities can be found in Chapter 4.5. 

Live Bottoms

Topographic Features

Defined topographic features (Chapter 4.6.1) are a subset of GOM live bottom habitats that 

are large enough to have an especially important ecological role, with specific protections defined in 

the proposed Topographic Features Stipulation. Within the Gulf of Mexico, BOEM has identified 

37 topographic features where some degree of protection from oil and gas development may be 

warranted based on geography and ecology. Of all the possible impact-producing factors, it was 

determined that bottom-disturbing activities associated with drilling, exploration, and vessel 

operations were the only impact-producing factors from routine activities that could be reasonably 

expected to substantially impact topographic features. The impact-producing factors resulting from 

accidental events include bottom-disturbing activities from drilling, exploration, and vessel 

operations, as well as the release of sediments and toxins during drilling operations. Oil-spill

response activities were also considered to be a source of potential impacts to topographic features.

Adherence to the Topographic Features Stipulation, which is analyzed in each action 

alternative (detailed in Appendix D), would assist in preventing most of the potential impacts on 

topographic feature communities by increasing the distance of OCS oil- and gas-related activities. 

Should this stipulation be applied to any future lease sale, as it has been historically, impacts of a 

proposed action to topographic features from routine activities and accidental events or the 

cumulative impact of a proposed action in the GOM are expected to be negligible. The incremental 

contribution of a proposed action to the cumulative impacts on topographic features is also expected 

to be negligible assuming adherence to the proposed Topographic Features Stipulation. Under 
xxiv Gulf of Mexico Multisale EIS

Alternative E, the potential for new incremental impacts to topographic features from a cancelled 

lease sale would be none because they would be avoided entirely. Impacts ranging from negligible

to moderate may still be expected from non-OCS oil- and gas-related activities depending on factors 

such as fishing and pollution; however, the incremental impact of the proposed activities should not 

result in an augmentation of the expected impacts. A full analysis of topographic features can be 

found in Chapter 4.6.1. 

Pinnacles and Low-Relief Features

The Pinnacle Trend is an approximately 64 x 16 mile (103 x 26 kilometer) high-relief area in 

water depths ranging from approximately 200-650 ft (60-200 m). It is in the northeastern portion of 

the CPA at the outer edge of the Mississippi-Alabama shelf between the Mississippi River and 

De Soto Canyon (Figures 2-4 and 4-16). Outside of the Pinnacle Trend area, low-relief live bottom

epibenthic communities occur in isolated locations in shallow waters (<984 ft; 300 m) throughout the 

GOM, wherever there exists suitable hard substrate and other physical conditions (e.g., depth, 

turbidity, etc.) allowing for community development. Hard bottom habitats occur throughout the 

GOM but are relatively rare compared with ubiquitous soft bottoms. 

The impact-producing factors for pinnacles and low-relief live bottom features can be 

grouped into three main categories: (1) bottom-disturbing activities; (2) drilling-related sediment and 

waste discharges; and (3) oil spills. These impact-producing factors have the potential to damage 

individual live bottom habitats and disrupt associated benthic communities if insufficiently distanced 

or otherwise mitigated. At the broad geographic and temporal scope of this analysis, and assuming 

adherence to all expected lease stipulations and typically applied regulations and mitigations, routine 

activities are expected to have largely localized and temporary effects. Although accidental events 

have the potential to cause severe damage to specific live bottom communities, the number of such 

events is expected to be very small. Therefore, at the regional, population-level scope of this 

analysis, the incremental contribution of impacts from reasonably foreseeable routine activities and 

accidental events to the overall cumulative impacts is expected to be negligible to minor. 

Proposed OCS oil- and gas-related activities would also contribute incrementally to the overall OCS 

and non-OCS cumulative impacts experienced by live bottom habitats. Under Alternative E, the 

potential for impacts to pinnacle and low-relief feature communities related to a cancelled lease sale 

would be none because new impacts would be avoided entirely. The OCS oil- and gas-related 

cumulative impacts to live bottom communities are estimated to be negligible. A full analysis of 

pinnacles and low-relief features can be found in Chapter 4.6.2. 

Fish and Invertebrate Resources

The distribution of fishes and invertebrates varies widely, and species may be associated 

with different habitats at various life stages, which is discussed further in Chapter 4.7. The impactproducing factors affecting these resources are anthropogenic sound, bottom-disturbing activities, 

habitat modification, and accidental oil spills. The impacts from routine activities, excluding 

infrastructure emplacement, would be expected to be negligible or minor due to short-term 

localized effects. The installation of OCS oil- and gas-related infrastructure constitutes a long-term 
Executive Summary xxv 

modification of the local habitat and is hypothesized to have resulted over the life of the program in 

moderate changes in the distribution of some species. Although this effect is not necessarily 

adverse and infrastructure is expected to be decommissioned and sites restored to natural habitat, 

the cumulative impact over the life of the OCS Program extensively pertains to time and space. 

Accidental spills have been historically low-probability events and are typically small in size. The 

expected impact to fishes and invertebrate resources from accidental oil spills is negligible. 

Commercial and recreational fishing are expected to have the greatest direct effect on fishes and 

invertebrate resources, resulting in impact levels ranging from negligible for most species to 

potentially moderate for some targeted species (e.g., hogfish spp., gray triggerfish [Balistes 

capriscus], and greater amber jack [Seriola dumerili]). The analysis of routine activities and 

accidental events indicates that the incremental contribution to the overall cumulative impacts on 

fishes and invertebrate resources as a result of a single proposed lease sale would be minor. 

Under Alternative E, the expected impacts on fish and invertebrate resources would be none. A full 

analysis of fish and invertebrate resources can be found in Chapter 4.7. 

Birds

The affected birds include both terrestrial songbirds and many groups of waterbirds. Routine 

impacts to coastal, marine, and migratory birds that were considered include routine discharges and 

wastes, noise, platform severance with explosives (barotrauma), geophysical surveys with airguns

(barotrauma), platform presence and lighting, and pipeline landfalls. The impacts to birds from OCS 

oil-and gas-related routine activities are similar wherever they may occur in the GOM, and all are 

considered negligible to minor. Negligible to minor impacts would not affect a substantial number 

of birds. Any impacts would be acute and reversible. As used here, acute means short-term, as it 

does in the context of short-term toxicity exposure and tests. Further, no injury to or mortality of a 

small number of individuals or a small flock would occur. Accidental impacts to birds are caused by 

oil spills, spill cleanup activities, and emergency air emissions. Seabirds may not always experience 

the greatest impacts from a spill but it may take longer for populations to recover because of their 

unique population ecology (demography). Some species, such as gulls, have larger clutches 

(laughing gulls usually have three eggs per clutch except in the tropics) and may recover quite 

quickly. However, many species of seabirds can have a clutch size of just one egg, and they have 

relatively long life spans and often have delayed age at first breeding. Because of the latter case, 

impacts for overall accidental events would be expected to be moderate. Impacts from overall 

accidental events on other waterbirds farther inshore would also be expected to be moderate 

because of the extensive overlap of their distributions with oiled inshore areas and shorelines 

expected from a large oil spill (≥1,000 bbl). Moderate impacts would affect a substantial abundance 

of birds.

The incremental contribution of a proposed action to the overall cumulative impacts is 

considered moderate, but only because of the potential impacts that could result from a large oil 

spill (≥1,000 bbl). This conclusion is based on the incremental contribution of a proposed action to 

the cumulative OCS oil- and gas-related and non-OCS oil- and gas-related impacts. Alternative E 

would offer no new lease blocks for exploration and development; therefore, incremental impacts to 
xxvi Gulf of Mexico Multisale EIS

birds would be none. However, there would be continuing impacts associated with the existing oil 

and gas activities from previously permitted activities and previous lease sales. A full analysis of 

birds can be found in Chapter 4.8. 

Protected Species

Marine Mammals

The Gulf of Mexico marine mammal community is diverse and distributed throughout the 

GOM, with the greatest abundances and diversity of species inhabiting oceanic and OCS waters. 

The major potential impact-producing factors affecting marine mammals in the GOM as a result of 

cumulative past, present, and reasonably foreseeable OCS energy-related activities are 

decommissioning activities, operational discharges, G&G activities, noise, transportation, marine 

debris, and accidental oil spill and spill-response activities. Accidental events that involve large 

spills, particularly those continuing to flow fresh hydrocarbons into oceanic and/or outer shelf waters 

for extended periods (i.e., days, weeks, or months), pose an increased likelihood of impacting 

marine mammal populations inhabiting GOM waters. While accidental events have the potential to 

impact marine mammal species, the number of such events is expected to be very small.

Proposed OCS oil- and gas-related activities would also contribute incrementally to the 

overall OCS and non-OCS cumulative effects experienced by marine mammal populations. At the 

regional, population-level scope of this analysis, impacts from reasonably foreseeable routine 

activities and accidental events could be negligible to moderate for any of the action alternatives. 

However, the incremental contribution of a proposed action to cumulative impacts to marine 

mammal populations, depending upon the affected species and their respective population estimate, 

even when taking into consideration the potential impacts of the Deepwater Horizon explosion, oil 

spill, and response; non-OCS oil- or gas-related factors; and the minimization of the OCS oil- or gasrelated impacts through lease stipulations and regulations, would be expected to be negligible. 

Under Alternative E, the cancellation of a proposed lease sale, impacts on marine mammals within 

the Gulf of Mexico would be none. However, cumulative impacts would be unchanged from the 

conclusions reached for the other alternatives. A full analysis of marine mammals can be found in 

Chapter 4.9.1. 

Sea Turtles

Five sea turtle species have been ESA-listed and are present throughout the northern GOM; 

however, only Kemp’s ridley and loggerhead sea turtles commonly nest on beaches in the GOM. 

Because of expected mitigations (e.g., BOEM and the Bureau of Safety and Environmental 

Enforcement [BSEE] proposed compliance with Notices to Lessees and Operators [NTLs] under the 

proposed Protected Species Stipulation and conditions of approval on postlease activities), the 

routine activities (e.g., noise or transportation) and accidental events (e.g., oil spills) related to a 

proposed action are not expected to have long-term adverse effects on the size and productivity of 

any sea turtle species or populations in the northern GOM. Lethal effects could occur from chance 

collisions with OCS oil- and gas-related service vessels or ingestion of accidentally released plastic 
Executive Summary xxvii

materials from OCS oil- and gas-related vessels and facilities. However, there have been no reports 

to date on such incidences. Most routine activities and accidental events are therefore expected to 

have negligible to moderate impacts. For example, a minor impact might be a behavioral change 

in response to noise while a moderate impact might be a spill contacting an individual and causing 

injury or mortality.

Historically, intense harvesting of eggs, loss of suitable nesting beaches, and fishery-related 

mortality have led to the rapid decline of sea turtle populations. Anthropogenic actions continue to 

pose the greatest threat to sea turtles since their listing under the Endangered Species Act (ESA), 

as well as different natural threats including climate change and natural disasters. The incremental 

contribution of a proposed action to the cumulative impacts to sea turtles would be expected to be 

negligible as a result of a proposed action. Population-level impacts are not anticipated. Under 

Alternative E, the cancellation of a proposed lease sale, impacts on sea turtles within the Gulf of 

Mexico would be none. However, cumulative impacts would be unchanged from the conclusions 

reached for the other alternatives. A full analysis of sea turtles can be found in Chapter 4.9.2. 

Beach Mice

The four subspecies of beach mouse (Peromyscus polionotus ssp.) are small coastal 

rodents that are only found along beaches in parts of Alabama and northwest Florida and are 

federally listed as endangered. Beach mice rely on dune systems as favorable habitat for foraging 

and maintaining burrows. Due to the distance between beach mouse habitat and OCS oil- and 

gas-related activities, routine impacts are not likely to affect beach mouse habitat except under very 

limited situations. Pipeline emplacement or construction, for example, could cause temporary 

degradation of beach mouse habitat; however, these activities are not expected to occur in areas of 

designated critical habitat. Accidental oil spills and associated spill-response efforts are not likely to 

impact beach mice or their critical habitat because the species live above the intertidal zone where 

contact is less likely. Habitat loss from non-OCS oil- and gas-related activities (e.g., beachfront 

development) and predation have the greatest impacts to beach mice. Overall, the incremental 

contribution of impacts from reasonably foreseeable routine activities and accidental events to the 

overall cumulative impacts on beach mice is expected to be negligible. Under Alternative E, the 

cancellation of a proposed lease sale, impacts on beach mice would be none. However, cumulative 

impacts would be unchanged from the conclusions reached for the other alternatives. A full analysis 

of beach mice can be found in Chapter 4.9.3. 

Protected Birds

Protected birds are those species or subspecies listed under the ESA by the U.S. Fish and 

Wildlife Service (FWS) as threatened or endangered due to the decrease in their population sizes or 

loss of habitat; therefore, a proposed action could have a greater impact. BOEM is undergoing 

consultation with FWS to minimize the potential impacts to ESA-listed species. Impacts from routine 

activities, which include discharges and wastes affecting air and water quality, noise, and possibly 

artificial lighting, would be negligible to protected birds. The listed bird species considered are 

typically coastal birds and would not be exposed to much of the oil- and gas-related activities. 
xxviii Gulf of Mexico Multisale EIS

Waste discharges to air or water produced as a result of routine activities are regulated by the U.S. 

Environmental Protection Agency and BOEM, and these discharges are subject to limits to reduce

potential impacts; therefore, due to precautionary requirements and monitoring, the impacts to 

protected birds would be negligible. The major impact-producing factors resulting from accidental 

events associated with a proposed action that may affect protected birds include accidental oil spills

and response efforts and marine debris. In the case of an accidental oil spill, impacts would be 

negligible to moderate depending on the magnitude and time and place of such an event. Major 

impacts could occur if a large oil spill occurred with direct contact to a protected bird species or if the 

habitat became contaminated resulting in mortality of a listed species. Marine debris produced by 

OCS oil- and gas-related activities as a result of accidental disposal into the water may affect 

protected birds by entanglement or ingestion. Due to the regulations prohibiting the intentional 

disposal of items, impacts would be expected to be negligible; however, impacts may scale up to 

moderate if the accidental release of marine debris caused mortality of a listed bird. 

Overall, BOEM would expect negligible to moderate impacts to protected birds considering 

routine activities, accidental events, and cumulative impacts. Due to the precautionary requirements 

and monitoring discussed above, the incremental impacts to protected birds would be negligible for 

any of the action alternatives (i.e., Alternatives A-D). Under Alternative E, the additional incremental

impacts to ESA-protected birds or their habitats would be none. A full analysis of protected birds 

can be found in Chapter 4.9.4. 

Protected Corals

Elkhorn, staghorn, boulder star, lobed star, and mountainous star corals are listed by the 

National Marine Fisheries Service as threatened due to the decrease in their population sizes; 

therefore, the relative impacts from a proposed action could be disproportionate to those 

experienced by other coral species. BOEM understands this and is undergoing consultation for 

these species to minimize the potential impacts. Though the listed species are given ESA status, 

they could be affected by the same types of impact-producing factors from a proposed action as 

other coral species that are not ESA-listed. Assuming adherence to all expected lease stipulations

and other postlease, protective restrictions and mitigations, the routine activities related to a 

proposed action are expected to have mostly localized and temporary effects because the sitespecific survey information and distancing requirements described in NTL 2009-G39 will allow 

BOEM to identify and protect live bottom features (where protected corals may be found) from harm 

by proposed OCS oil- and gas-related activities during postlease reviews. While accidental events 

have the potential to cause severe damage to specific coral communities, the number of such events 

is expected to be small. Further, many of the protected corals occur in the Flower Garden Banks

National Marine Sanctuary, which under the current boundaries is not proposed for future leasing 

under any of the alternatives in this Multisale EIS. Therefore, the incremental contribution of 

activities resulting from a proposed action to the overall cumulative impacts on protected corals is 

expected to be negligible. Proposed OCS oil- and gas-related activities would contribute 

incrementally to the overall OCS and non-OCS cumulative impacts experienced by corals. Under 

Alternative E, the cancellation of the proposed action, impacts to protected corals would be none. 
Executive Summary xxix

However, cumulative impacts would be unchanged from the conclusions reached for the other 

alternatives. A full analysis of protected corals can be found in Chapter 4.9.5. 

Commercial Fisheries

A proposed action could affect commercial fisheries by affecting fish populations or by 

affecting the socioeconomic aspects of commercial fishing. The impacts of a proposed action on 

fish populations are presented in Chapter 4.7. Routine activities such as seismic surveys, drilling 

activities, and service-vessel traffic can cause space-use conflicts with fishermen. Structure 

emplacement could have positive or negative impacts depending on the location and species. For 

example, structure emplacement prevents trawling in the associated area and, thus, could impact 

the shrimp fishery. On the other hand, production platforms can facilitate fishing for reef fish such as 

red snapper and groupers. Accidental events, such as oil spills, could cause fishing closures and 

have other impacts on the supply and demand for seafood. However, accidental events that could 

arise from a proposed action would likely be small and localized. A proposed action would be 

relatively small when compared with the overall OCS Program, State oil and gas activities, overall 

vessel traffic, hurricanes, economic factors, Federal and State fisheries management strategies, and 

other non-OCS oil- and gas-related factors. Therefore, the incremental contribution of a proposed 

action to the cumulative impacts to commercial fisheries would range from minor beneficial to 

minor adverse effects. The exact impacts would depend on the locations of activities, the species 

affected, the intensity of commercial fishing activity in the affected area, and the substitutability of 

any lost fishing access. Alternative E would prevent these impacts from occurring, although 

commercial fisheries would still be subject to the impacts from the OCS Program, as well as the 

impacts from non-OCS sources. A full analysis of commercial fisheries can be found in Chapter 

4.10. 

Recreational Fishing

The Gulf of Mexico’s extensive estuarine habitats (Chapter 4.3.1), live bottom habitats 

(Chapter 4.6), and artificial substrates (including artificial reefs, shipwrecks, and oil and gas 

platforms) support several valuable recreational fisheries. Alternatives A-D can affect recreational 

fishing by affecting fish populations or by affecting the socioeconomic aspects of recreational fishing. 

The impacts of Alternatives A-D on fish populations are presented in Chapter 4.7. Vessel traffic can 

cause space-use conflicts with anglers. Structure emplacement generally enhances recreational 

fishing, although this positive effect will be offset during decommissioning unless a structure were 

maintained as an artificial reef. Accidental events, such as oil spills, can cause fishing closures and 

can affect the aesthetics of fishing in an area. However, accidental events that could arise would 

likely be small and localized. Alternatives A-D should also be viewed in light of overall trends in 

OCS platform decommissioning, State oil and gas activities, overall vessel traffic, hurricanes, 

economic factors, and Federal and State fisheries management strategies. The incremental impacts 

of Alternatives A-D on recreational fisheries are expected to be beneficial (low) to minor. 

Alternative E would cause some economic adjustments (refer to Chapter 4.14.2.), which could 

cause negligible impacts to recreational fishing activities. A full analysis of recreational fishing can 

be found in Chapter 4.11. 
xxx Gulf of Mexico Multisale EIS

Recreational Resources

Alternatives A-D would contribute to the negligible to minor aesthetic impacts and space-use 

conflicts that arise due to the broader OCS Program. These conflicts arise due to marine debris, the 

visibility of platforms, and vessel traffic. Structure emplacements can have positive impacts on 

recreational fishing and diving because platforms often act as artificial reefs. Oil spills can negatively 

affect beaches and other coastal recreational resources. Alternatives A-D should also be viewed in 

light of economic trends, as well as various non-OCS oil- and gas-related factors that can cause 

space-use conflicts and aesthetic impacts, such as commercial and military activities. Because of 

the relatively small contribution of any given lease sale under any of the proposed action alternatives 

to the overall OCS Program, in addition to other non-OCS oil- and gas-related activities, the 

incremental impacts are expected to be minor beneficial (low) to minor adverse effects. There 

could be negligible impacts to recreational resources due to the small economic adjustments that 

would occur in light of Alternative E. A full analysis of recreational resources can be found in 

Chapter 4.12. 

Archaeological Resources

Archaeological resources are any material remains of human life or activities that are at least 

50 years of age and that are capable of providing scientific or humanistic understanding of past 

human behavior, cultural adaptation, and related topics through the application of scientific or 

scholarly techniques, such as controlled observation, contextual measurement, controlled collection, 

analysis, interpretation, and explanation (30 CFR § 250.105). Archaeological resources are 

primarily impacted by any activity that directly disturbs or has the potential to disturb the seafloor. 

For the OCS Program, this includes the placement of drilling rigs and production systems on the 

seafloor; pile driving associated with platform emplacement; pipeline placement and installation; the 

use of seismic receiver nodes and cables; the dredging of new channels, as well as maintenance 

dredging of existing channels; anchoring activities; post-decommissioning activities, including 

trawling clearance; and the masking of archaeological resources from industry-related infrastructure

and debris.

Regardless of which planning area a proposed lease sale is held, the greatest potential 

impact to an archaeological resource as a result of a proposed action under any of the action 

alternatives is site-specific and would result from direct contact between an offshore activity or 

accidental event and a site. Archaeological surveys, where required prior to an operator beginning 

OCS oil- and gas-related activities on a lease, are expected to be effective at identifying possible 

archaeological sites. Major impacts could potentially occur if the mitigations (e.g., archaeological 

surveys) were not applied to postlease activities. With identification, evaluation, and avoidance or 

mitigation of archaeological resources, the incremental contribution of a proposed action is expected 

to result in negligible, long-term cumulative impacts to archaeological resources; however, if an 

archaeological site were to be impacted, impacts to that specific site may range from negligible to 

major. Under Alternative E, the impact-producing factors described in Chapter 4.13 would not take 

place for that proposed lease sale; therefore, the impacts would be none. A full analysis of 

archaeological resources can be found in Chapter 4.13. 
Executive Summary xxxi 

Human Resources and Land Use (Including Environmental Justice) 

Land Use and Coastal Infrastructure

Oil and gas exploration, production, and development activities on the OCS are supported by 

an expansive onshore network of coastal infrastructure that includes hundreds of large and small 

companies. Because OCS oil- and gas-related activities are supported by this long-lived, expansive 

onshore network, the potential impacts of a proposed lease sale are not expected to produce any 

major impacts to land use and coastal infrastructure. The impact of routine operations would range 

from beneficial to moderate. The impacts of reasonably foreseeable accidental events such as oil 

spills, chemical and drilling fluid spills, and vessel collisions are not likely to last long enough to 

adversely affect overall land use or coastal infrastructure in the analysis area and would therefore be 

negligible to moderate. In the cumulative analysis, activities relating to all past, present, and future 

OCS oil- and gas-related activities and State oil and gas production are expected to minimally affect 

the current land use of the analysis area because most subareas have strong industrial bases and 

designated industrial parks. Non-OCS oil- and gas-related factors contribute substantially to the 

cumulative impacts on land use and coastal infrastructure, while there is only a minor incremental 

contribution of a proposed lease sale. 

For any of the action alternatives, the cumulative impacts on land use and coastal 

infrastructure could range from beneficial to moderate for OCS oil- and gas-related activities and 

beneficial to major for non-OCS oil- and gas-related activities, depending on the specifics of each 

situation, whether the impacts are measurable, how long the impacts would last, and the size of the 

affected geographic area as defined in Chapter 4.14.1. Alternative E would result in no lease sale 

and, thus, the direct impacts as a result of a proposed lease sale would be none, and would result in 

no incremental contribution of impacts to land use and coastal infrastructure beyond a temporary 

negative economic impact for the oil and gas industry and coastal states (such as Louisiana) that are 

more dependent on oil and gas revenues. A full analysis of land use and coastal infrastructure can 

be found in Chapter 4.14.1. 

Economic Factors

A proposed lease sale would lead to beneficial (low) impacts arising from industry 

expenditures, government revenues, corporate profits, and other market impacts. Some of these 

impacts would be concentrated along the Gulf Coast, while others would be widely distributed. A 

proposed lease sale would also lead to negative economic impacts arising from accidental events 

and other sources. There would be some differences in economic impacts among Alternatives A-D, 

corresponding to the differences in the scales and distributions of likely activities. Alternatives A-D 

should be viewed in light of the OCS Program, as well the numerous forces that can affect energy 

markets and the overall economy. Most of the incremental economic impacts of a proposed action 

are forecast to be beneficial, although there would be some minor adverse impacts due to oil spills

and to the effects on industries that compete with the offshore oil and gas industry for resources. 

Alternative E, the cancellation of a proposed lease sale, would negatively impact firms and 

employees that depend on recurring leases; therefore, the impacts of Alternative E would be 
xxxii Gulf of Mexico Multisale EIS

negligible to minor, with some partially offsetting beneficial impacts. A full analysis of economic 

factors can be found in Chapter 4.14.2. 

Social Factors (Including Environmental Justice) 

Potential social impacts resulting from a proposed action would occur within the larger 

socioeconomic context of the GOM region. The affected environment of the analysis area is quite 

large geographically and in terms of population (133 counties and parishes with over 22.7 million 

residents). The impacts from routine activities related to a proposed action are expected to be 

negligible to moderate, widely distributed, and to have little impact because of the existing 

extensive and widespread support system for the petroleum industry and its associated labor force. 

Outside of a low-probability catastrophic oil spill, which is not reasonably foreseeable and not part of 

a proposed action, any potential accidental events are not likely to be of sufficient scale or duration 

to have adverse and disproportionate long-term impacts for people and communities in the analysis 

area and would therefore range from negligible to moderate. In the cumulative analysis, impacts 

from OCS oil- and gas-related activities would range from beneficial to moderate. Non-OCS 

oil- and gas-related factors, which include all human activities, natural events, and processes, 

actually contribute more to cumulative impacts than do factors related to OCS oil- and gas-related 

activities alone, and result in beneficial to major adverse impacts. The incremental contribution to 

cumulative impacts of a proposed action would be minor. Alternative E would result in no lease sale 

and, thus, overall incremental impacts as a result of alternative E would be none. A full analysis of 

social factors can be found in Chapter 4.14.3. 

Environmental Justice Determination: The oil and gas industry in the GOM region is 

expansive and long-lived over several decades with substantial infrastructure in place to support 

both onshore and offshore activities. BOEM’s scenario estimates call for 0-1 new gas processing 

plant and 0-1 new pipeline landfall over the 50-year life of a single proposed action. Impacts to 

GOM populations from a proposed action would be immeasurable for environmental justice since 

these low-income and minority communities are located onshore, distant from Federal OCS oil- and 

gas-related activities. Also, since these vulnerable populations are located within the larger context 

of onshore and State-regulated nearshore oil and gas activities that are connected to downstream 

infrastructure over which BOEM has no regulatory authority, BOEM has determined that a proposed 

action would not produce environmental justice impacts in the GOM region. A full analysis of social 

factors and an environmental justice determination can be found in Chapter 4.14.3. 

APPENDICES

To improve the readability of this Multisale EIS, more detailed supporting information has 

been placed in the appendices, which include postlease processes, commonly applied mitigating 

measures, a Memorandum of Agreement between BOEM and the U.S. Environmental Protection 

Agency, prelease stipulations, OSRA figures, species not considered further, and State Coastal 

Management Programs. 
Executive Summary xxxiii

Appendix A describes postlease approval activities, including the following: geological and 

geophysical surveys; exploration and development plans; permits and applications; inspection and 

enforcement; pollution prevention, oil-spill response plans, and financial responsibility; air emissions; 

flaring and venting; hydrogen sulfide contingency plans; archaeological resources regulation; coastal 

zone management consistency review and appeals for postlease activities; best available and safest 

technologies, including at production facilities; personnel training and education; structure removal

and site clearance; marine protected species NTLs; and the Rigs-to-Reefs program.

Appendix B describes commonly applied mitigations that were developed as a result the 

continuing OCS Program in the Gulf of Mexico. These are mitigations that BOEM and BSEE could 

apply to permits and approvals. These mitigating measures address concerns such as endangered 

and threatened species, geologic and manmade hazards, military warning and ordnance disposal 

areas, archaeological sites, air quality, oil-spill response planning, chemosynthetic communities, 

artificial reefs, operations in hydrogen sulfide-prone areas, and shunting of drill effluents in the 

vicinity of biologically sensitive features. Operational compliance of the mitigating measures is 

enforced through BSEE’s onsite inspection program.

Appendix C is the Memorandum of Agreement between BOEM and the USEPA; it outlines 

the roles and responsibilities for both agencies during the preparation of this Multisale EIS.

Appendix D describes the potential lease stipulations that were developed as a result of 

numerous scoping efforts for the continuing OCS Program in the Gulf of Mexico. The lease 

stipulations being considered are the Topographic Features Stipulation; Live Bottom (Pinnacle 

Trend) Stipulation; Military Areas Stipulation; Evacuation Stipulation; Coordination Stipulation; 

Blocks South of Baldwin County, Alabama, Stipulation; Protected Species Stipulation; United 

Nations Convention on the Law of the Sea Royalty Payment Stipulation; Below Seabed Operations 

Stipulation; and the Stipulation on the Agreement between the United States of America and the 

United Mexican States Concerning Transboundary Hydrocarbon Reservoirs in the Gulf of Mexico 

(Transboundary Stipulation). The United Nations Convention on the Law of the Sea Royalty 

Payment Stipulation is applicable to a proposed lease sale even though it is not an environmental or 

military stipulation. 

Appendix E provides the combined probabilities for an offshore oil spill ≥1,000 barrels

occurring and contacting coastal and offshore areas for each of the proposed actions.

Appendix F details the meteorological information used for the air quality modeling 

described in Chapter 4.1. Parameters such as wind speed, wind direction, air temperature, and 

humidity are required by models to determine the rate that pollutants disperse and react in the 

atmosphere. This appendix details the modeling performance evaluation of a Weather and 

Research Forecast model for 2012 used in conducting the air quality modeling summarized in 

Chapter 4.1. 
xxxiv Gulf of Mexico Multisale EIS

Appendix G describes how the emissions were generated for the Cumulative and Visibility 

Impact Analysis Emissions Inventory used in conducting the air quality modeling summarized in 

Chapter 4.1. 

Appendix H provides the photochemical modeling, the evaluation of the modeling, and the 

results of the the air quality modeling summarized in Chapter 4.1. 

Appendix I is a listing of species not considered further in this Multisale EIS because these 

species are not generally found in the area of activity and/or impact. Therefore, it is not reasonably 

foreseeable that these species would have population effects from a proposed action.

Appendix J describes State Coastal Management Programs (CMPs). Each State’s CMP is 

a comprehensive statement setting forth objectives, enforceable policies or guidelines, and 

standards for public and private use of land and water resources and uses in that State’s coastal 

zone. The programs provide for direct State land and water use planning and regulations. The 

programs also include a definition of what constitutes permissible land uses and water uses. To 

ensure conformance with State CMP policies or guidelines and local land use plans, BOEM 

prepares a Federal consistency determination for each proposed OCS lease sale. Federal 

consistency is the Coastal Zone Management Act requirement where Federal agency activities that 

have reasonably foreseeable effects on any land or water use or natural resource of the coastal 

zone must be consistent to the maximum extent practicable with the enforceable policies or 

guidelines of a coastal State’s federally approved CMP. 

Appendix K provides consultation correspondence with Federal and State agencies.

Appendix L provides detailed responses to comments received on the Draft Multisale EIS. 

The comments and responses are presented in a matrix organized by the topics of the comments. 

All substantive comment letters, emails, and public meeting transcripts, along with their respective 

unique identifiers, are reproduced in their entirety following the matrix and references.
Table of Contents xxxv 

TABLE OF CONTENTS

Volume I

Page

EXECUTIVE SUMMARY ..................................................................................................................... vii

LIST OF FIGURES................................................................................................................................liii

LIST OF TABLES................................................................................................................................lxiii

ABBREVIATIONS AND ACRONYMS ...............................................................................................lxvii

CONVERSION CHART ....................................................................................................................lxxiii

1 PURPOSE OF AND NEED FOR THE PROPOSED ACTIONS..................................................... 1-3

1.0 Introduction............................................................................................................................. 1-3

1.1 Purpose of the Proposed Actions........................................................................................... 1-5

1.2 Need for the Proposed Actions .............................................................................................. 1-5

1.3 OCS Oil and Gas Program Planning and Decision Process ................................................. 1-7

1.3.1 Prelease Process....................................................................................................... 1-7

1.3.1.1 Five-Year Program of Proposed OCS Lease Sales .................................. 1-8

1.3.1.2 Individual Lease Sale Consultation and Decision Process...................... 1-10

1.3.2 Gulf of Mexico Postlease Activities.......................................................................... 1-12

1.4 The Decision To Be Made.................................................................................................... 1-13

1.5 Regulatory Framework ......................................................................................................... 1-13

1.6 Other OCS Oil- and Gas-Related Activities ......................................................................... 1-15

1.7 Other Pertinent Environmental Reviews or Documentation ................................................ 1-18

1.8 Format and Organization of the Multisale EIS ..................................................................... 1-22

2 ALTERNATIVES INCLUDING THE PROPOSED ACTIONS......................................................... 2-3

2.0 Introduction............................................................................................................................. 2-3

2.1 Multisale NEPA Analysis ........................................................................................................ 2-4

2.2 Alternatives, Mitigating Measures, and Issues....................................................................... 2-5

2.2.1 What is the 2017-2022 Proposed Lease Sale Schedule?......................................... 2-5

2.2.2 What are the Alternatives that BOEM is Considering for Each Proposed 

Lease Sale? ............................................................................................................... 2-6

2.2.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) ................................................................................................. 2-6

2.2.2.2 Alternative B—Regionwide OCS Lease Sale Excluding Available 

Unleased Blocks in the WPA Portion of the Proposed Lease Sale 

Area ............................................................................................................ 2-8

2.2.2.3 Alternative C—Regionwide OCS Lease Sale Excluding Available 

Unleased Blocks in the CPA/EPA Portions of the Proposed Lease 

Sale Area.................................................................................................... 2-9

2.2.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations............................................................................... 2-10

2.2.2.5 Alternative E—No Action.......................................................................... 2-13
xxxvi Gulf of Mexico Multisale EIS

2.2.3 What Other Alternatives and Deferrals have BOEM Considered but 

Not Analyzed in Detail?............................................................................................ 2-14

2.2.4 What Types of Mitigating Measures Does BOEM Apply? ....................................... 2-23

2.2.4.1 Proposed Lease Mitigating Measures (Stipulations) ............................... 2-24

2.2.4.2 Prelease Mitigating Measures (Stipulations) by Alternative .................... 2-28

2.2.4.3 Postlease Mitigating Measures ................................................................ 2-29

2.2.5 What are the Primary Topics and Resources Being Evaluated? ............................ 2-31

2.2.5.1 Issues to be Analyzed .............................................................................. 2-31

2.2.5.2 Issues Considered but Not Analyzed....................................................... 2-34

2.3 Comparison of Impacts by Alternative ................................................................................. 2-35

2.4 Summary of Impacts............................................................................................................. 2-37

2.4.1 Air Quality................................................................................................................. 2-37

2.4.2 Water Quality ........................................................................................................... 2-39

2.4.3 Coastal Habitats....................................................................................................... 2-39

2.4.3.1 Estuarine Systems (Wetlands and Seagrasses/Submerged 

Vegetation) ............................................................................................... 2-39

2.4.3.2 Coastal Barrier Beaches and Associated Dunes..................................... 2-40

2.4.4 Deepwater Benthic Communities ............................................................................ 2-41

2.4.5 Sargassum and Associated Communities............................................................... 2-41

2.4.6 Live Bottoms ............................................................................................................ 2-42

2.4.6.1 Topographic Features .............................................................................. 2-42

2.4.6.2 Pinnacles and Low-Relief Features ......................................................... 2-42

2.4.7 Fish and Invertebrate Resources............................................................................. 2-43

2.4.8 Birds ......................................................................................................................... 2-44

2.4.9 Protected Species.................................................................................................... 2-44

2.4.9.1 Marine Mammals...................................................................................... 2-44

2.4.9.2 Sea Turtles ............................................................................................... 2-45

2.4.9.3 Beach Mice............................................................................................... 2-46

2.4.9.4 Protected Birds......................................................................................... 2-46

2.4.9.5 Protected Corals....................................................................................... 2-47

2.4.10 Commercial Fisheries .............................................................................................. 2-47

2.4.11 Recreational Fishing ................................................................................................ 2-48

2.4.12 Recreational Resources........................................................................................... 2-48

2.4.13 Archaeological Resources ....................................................................................... 2-49

2.4.14 Human Resources and Land Use (Including Environmental Justice)..................... 2-50

2.4.14.1 Land Use and Coastal Infrastructure ....................................................... 2-50

2.4.14.2 Economic Factors..................................................................................... 2-50

2.4.14.3 Social Factors (Including Environmental Justice).................................... 2-51

3 IMPACT-PRODUCING FACTORS AND SCENARIO.................................................................... 3-3

3.0 Introduction............................................................................................................................. 3-3

3.1 Impact -Producing Factors and Scenario—Routine Operations............................................ 3-6

3.1.1 Resource Estimates and Timetables......................................................................... 3-6

3.1.2 Exploration and Delineation..................................................................................... 3-11

3.1.2.1 Geological and Geophysical Surveys ...................................................... 3-11

3.1.2.2 Exploration and Delineation Plans and Drilling........................................ 3-17

3.1.3 Offshore Development and Production.................................................................... 3-22

3.1.3.1 Development and Production Drilling....................................................... 3-22

3.1.3.2 Offshore Production Systems .................................................................. 3-29
Table of Contents xxxvii 

3.1.3.3 Infrastructure Emplacement/Structure Installation and Commissioning 

Activities ................................................................................................... 3-33

3.1.3.3.1 Pipelines ................................................................................ 3-37

3.1.3.3.2 Bottom-Area Disturbance ...................................................... 3-42

3.1.3.3.3 Sediment Displacement......................................................... 3-44

3.1.3.3.4 Navigation Channels ............................................................. 3-45

3.1.3.4 Infrastructure Presence............................................................................ 3-50

3.1.3.4.1 Anchoring............................................................................... 3-50

3.1.3.4.2 Space-Use Requirements ..................................................... 3-50

3.1.3.4.3 Structure Lighting .................................................................. 3-51

3.1.3.5 Workovers and Abandonments................................................................ 3-52

3.1.4 Transport.................................................................................................................. 3-53

3.1.4.1 Barges ...................................................................................................... 3-53

3.1.4.2 Oil Tankers ............................................................................................... 3-53

3.1.4.3 Service Vessels........................................................................................ 3-55

3.1.4.4 Helicopters................................................................................................ 3-56

3.1.5 Discharges and and Wastes.................................................................................... 3-58

3.1.5.1 Operational Wastes and Discharges Generated by OCS Oil- and 

Gas-Related Facilities .............................................................................. 3-58

3.1.5.1.1 Drilling Muds and Cuttings..................................................... 3-62

3.1.5.1.2 Produced Waters................................................................... 3-66

3.1.5.1.3 Well-Treatment, Workover, and Completion Fluids .............. 3-69

3.1.5.1.4 Production Solids and Equipment ......................................... 3-70

3.1.5.1.5 Bilge, Ballast, and Fire Water................................................ 3-71

3.1.5.1.6 Cooling Water........................................................................ 3-71

3.1.5.1.7 Deck Drainage....................................................................... 3-72

3.1.5.1.8 Treated Domestic and Sanitary Wastes................................ 3-72

3.1.5.1.9 Minor/Miscellaneous Discharges........................................... 3-73

3.1.5.2 Operational Wastes and Discharges Generated by Service Vessels ..... 3-73

3.1.5.3 Onshore Disposal of Waste and Discharge Generated Offshore or 

Onshore.................................................................................................... 3-74

3.1.5.3.1 Onshore Disposal of Wastes Generated from OCS Oiland Gas-Related Facilities .................................................... 3-74

3.1.5.3.2 Onshore Disposal and Storage Facilities Supporting 

OCS-Generated Operational Wastes.................................... 3-75

3.1.5.3.3 Discharges from Onshore Support Facilities......................... 3-76

3.1.6 Decommissioning and Removal Operations ........................................................... 3-76

3.1.6.1 Structure Age and Idle Iron ...................................................................... 3-79

3.1.6.2 Artificial Reefs........................................................................................... 3-81

3.1.7 Coastal Infrastructure............................................................................................... 3-81

3.1.7.1 Construction Facilities .............................................................................. 3-84

3.1.7.1.1 Platform Fabrication Yards.................................................... 3-84

3.1.7.1.2 Shipbuilding and Shipyards................................................... 3-84

3.1.7.1.3 Pipe-Coating Facilities and Yards ......................................... 3-85

3.1.7.2 Support Facilities and Transportation ...................................................... 3-86

3.1.7.2.1 Service Bases and Ports ....................................................... 3-86

3.1.7.2.2 Helicopter Hubs ..................................................................... 3-88

3.1.7.2.3 Tanker Port Areas ................................................................. 3-88

3.1.7.2.4 Barge Terminals .................................................................... 3-89

3.1.7.2.5 Pipeline Shore Facilities ........................................................ 3-89

3.1.7.2.6 Waste Disposal Facilities....................................................... 3-89

3.1.7.2.7 Natural Gas Storage Facilities............................................... 3-90
xxxviii Gulf of Mexico Multisale EIS

3.1.7.3 Processing Facilities................................................................................. 3-90

3.1.7.3.1 Gas Processing Plants .......................................................... 3-90

3.1.7.3.2 Refineries............................................................................... 3-91

3.1.7.3.3 Onshore Liquefied Natural Gas Facilities.............................. 3-91

3.1.7.3.4 Petrochemical Plants............................................................. 3-92

3.1.8 Air Emissions ........................................................................................................... 3-92

3.1.8.1 Drilling....................................................................................................... 3-94

3.1.8.2 Production ................................................................................................ 3-94

3.1.8.3 Vessel Support Operations and Activities during Offshore Oil and 

Gas Activities............................................................................................ 3-94

3.1.8.4 Flaring and Venting .................................................................................. 3-95

3.1.8.5 Fugitive Emissions ................................................................................... 3-96

3.1.8.6 Greenhouse Gases .................................................................................. 3-96

3.1.8.7 Decommissioning..................................................................................... 3-96

3.1.9 Noise ........................................................................................................................ 3-96

3.1.10 New and Unusual Technology................................................................................. 3-99

3.2 Impact-Producing Factors and Scenario—Accidental Events ...........................................3-101

3.2.1 Oil Spills .................................................................................................................3-101

3.2.1.1 Past OCS Spills......................................................................................3-101

3.2.1.1.1. Trends in Reported Spill Volumes and Numbers................3-101

3.2.1.1.2 Coastal Spills.......................................................................3-106

3.2.1.1.3 Offshore Spills .....................................................................3-110

3.2.1.2 Characteristics of OCS Oil .....................................................................3-116

3.2.1.3 Transport and Fate of Offshore Spills....................................................3-117

3.2.1.4 Analysis of Offshore Spills ≥1,000 bbl ...................................................3-120

3.2.1.4.1 Overview of Spill Risk Analysis ...........................................3-120

3.2.1.4.2 Trajectory Modeling for Offshore Spills ≥1,000 bbl .............3-121

3.2.1.4.3 Estimated Number of Offshore Spills ≥1,000 bbl and 

Probability of Occurrence....................................................3-123

3.2.1.4.4 Most Likely Source of Offshore Spills ≥1,000 bbl ...............3-125

3.2.1.4.5 Most Likely Size of an Offshore Spill ≥1,000 bbl.................3-125

3.2.1.4.6 Length of Coastline Affected by Offshore Spills 

≥1,000 bbl ............................................................................3-125

3.2.1.4.7 Risk Analysis by Resource..................................................3-126

3.2.1.4.8 Likelihood of an Offshore Spill ≥1,000 bbl Occurring and 

Contacting Coastal and Offshore Areas..............................3-126

3.2.1.5 Analysis of Offshore Spills <1,000 bbl ...................................................3-127

3.2.1.5.1 Estimated Number of Offshore Spills <1,000 bbl and 

Total Volume of Oil Spilled..................................................3-127

3.2.1.5.2 Most Likely Source and Type of Offshore Spills 

<1,000 bbl............................................................................3-127

3.2.1.5.3 Most Likely Size of Offshore Spills <1,000 bbl....................3-127

3.2.1.5.4 Likelihood of an Offshore Spill <1,000 bbl Occurring and 

Contacting Coastal and Offshore Areas..............................3-127

3.2.1.6 Analysis of Coastal Spills.......................................................................3-128

3.2.1.6.1 Estimated Number and Most Likely Sizes of Coastal 

Spills ....................................................................................3-128

3.2.1.6.2 Likelihood of Coastal Spill Contact......................................3-128

3.2.2 Losses of Well Control...........................................................................................3-129

3.2.3 Accidental Air Emissions........................................................................................3-132

3.2.3.1 Hydrogen Sulfide and Sulfurous Petroleum...........................................3-132

3.2.4 Pipeline Failures.....................................................................................................3-134

3.2.5 Vessel and Helicopter Collisions ...........................................................................3-135
Table of Contents xxxix 

3.2.6 Chemical and Drilling-Fluid Spills ..........................................................................3-137

3.2.7 Trash and Debris....................................................................................................3-138

3.2.8 Spill Response .......................................................................................................3-139

3.2.8.1 BSEE Spill-Response Requirements and Initiatives..............................3-139

3.2.8.1.1 Spill-Response Requirements.............................................3-139

3.2.8.1.2 Spill-Response Initiatives ....................................................3-141

3.2.8.2 Offshore Response, Containment, and Cleanup Technology ...............3-141

3.2.8.2.1 Mechanical Cleanup............................................................3-144

3.2.8.2.2 Spill Treating Agents ...........................................................3-147

3.2.8.2.3 In-situ Burning......................................................................3-150

3.2.8.2.4 Natural Dispersion...............................................................3-150

3.2.8.3 Onshore Response and Cleanup...........................................................3-151

3.3 Cumulative Impacts ............................................................................................................3-157

3.3.1 Cumulative OCS Oil and Gas Program Scenario..................................................3-157

3.3.1.1 Cumulative OCS Oil and Gas Program Projected Production...............3-159

3.3.1.2 Cumulative Geological and Geophysical Surveys .................................3-160

3.3.1.3 Cumulative Exploration and Delineation Plans and Drilling...................3-161

3.3.1.4 Cumulative Development and Production Drilling .................................3-161

3.3.1.5 Infrastructure Emplacement/Structure Installation and 

Decommissioning Activities....................................................................3-162

3.3.1.6 Infrastructure Presence..........................................................................3-163

3.3.1.7 Transport................................................................................................3-164

3.3.1.8 Discharges and Wastes .........................................................................3-165

3.3.1.9 Decommissioning and Removal Operations..........................................3-165

3.3.1.10 Coastal Infrastructure.............................................................................3-165

3.3.1.11 Air Emissions..........................................................................................3-165

3.3.2 Non-OCS Oil- and Gas-Related Impact-Producing Factors..................................3-166

3.3.2.1 State Oil and Gas Activity ......................................................................3-166

3.3.2.1.1 State Pipeline Infrastructure ................................................3-168

3.3.2.1.2 Artificial Reefs......................................................................3-168

3.3.2.2 Marine Vessel Activity ............................................................................3-169

3.3.2.3 Non-OCS Oil- and Gas-Related Wastes and Discharges .....................3-171

3.3.2.3.1 Potentially Polluting Shipwrecks..........................................3-171

3.3.2.3.2 Discharges Associated with Military Activities.....................3-172

3.3.2.3.3 Historical Chemical Weapon Disposal Areas......................3-173

3.3.2.3.4 Historical Industrial Waste Dumping Areas.........................3-174

3.3.2.3.5 Dredged Material Disposal..................................................3-174

3.3.2.3.6 Land-Based Discharges ......................................................3-177

3.3.2.3.7 Trash and Debris .................................................................3-177

3.3.2.4 Non-OCS Oil- and Gas-Related Spills...................................................3-178

3.3.2.5 Non-OCS Oil- and Gas- Related Air Emissions.....................................3-181

3.3.2.6 Other Non-OCS Oil- and Gas-Related Activities ...................................3-181

3.3.2.6.1 Military Warning and Water Test Areas ..............................3-181

3.3.2.6.2 Offshore Deepwater Ports and Nearshore Liquefied 

Natural Gas Terminals.........................................................3-182

3.3.2.6.3 Development of Gas Hydrates ............................................3-184

3.3.2.6.4 Renewable Energy and Alternative Use .............................3-185

3.3.2.6.5 Aquaculture..........................................................................3-187

3.3.2.6.6 OCS Sand Borrowing ..........................................................3-188

3.3.2.7 Noise from Non-OCS Oil- and Gas-Related Sources............................3-191
xl Gulf of Mexico Multisale EIS

3.3.2.8 Coastal Environments ............................................................................3-193

3.3.2.8.1 Sea-Level Rise and Subsidence .........................................3-193

3.3.2.8.2 Erosion.................................................................................3-196

3.3.2.8.3 Coastal Restoration Programs ............................................3-196

3.3.2.8.4 Saltwater Intrusion...............................................................3-203

3.3.2.8.5 Maintenance Dredging and Federal Channels....................3-204

3.3.2.9 Natural Events and Processes...............................................................3-206

3.3.2.9.1 Physical Oceanography.......................................................3-206

3.3.2.9.2 Natural Seeps ......................................................................3-207

3.3.2.9.3 Hurricanes ...........................................................................3-207

3.3.2.9.4 Climate Change...................................................................3-209

3.3.2.10 Mississippi River Hydromodification ......................................................3-209

3.3.2.11 Mississippi River Eutrophication ............................................................3-210

3.3.2.12 Hypoxia...................................................................................................3-211

3.3.2.13 Sedimentation.........................................................................................3-212
Table of Contents xli

Volume II 

Page

LIST OF FIGURES.............................................................................................................................. xxi

LIST OF TABLES...............................................................................................................................xxxi

4 DESCRIPTION OF THE AFFECTED ENVIRONMENT AND IMPACT ANALYSIS....................... 4-3

4.0 Overview................................................................................................................................. 4-3

4.0.1 What Encompasses the Affected Environment for a Gulf of Mexico Lease Sale? ... 4-5

4.0.2 How are the Potential Environmental Consequences Determined? ......................... 4-6

4.0.2.1 Routine Activities........................................................................................ 4-9

4.0.2.2 Accidental Events....................................................................................... 4-9

4.0.2.3 Cumulative Impacts.................................................................................... 4-9

4.0.2.4 Incomplete or Unavailable Information .................................................... 4-10

4.0.2.5 Alternative A ............................................................................................. 4-11

4.0.2.6 Alternative B ............................................................................................. 4-11

4.0.2.7 Alternative C............................................................................................. 4-12

4.0.2.8 Alternative D............................................................................................. 4-12

4.0.2.9 Alternative E ............................................................................................. 4-12

4.1 Air Quality ............................................................................................................................. 4-13

4.1.1 Description of the Affected Environment ................................................................. 4-16

4.1.2 Environmental Consequences................................................................................. 4-24

4.1.2.1 Routine Activities...................................................................................... 4-27

4.1.2.2 Accidental Events..................................................................................... 4-30

4.1.2.3 Cumulative Impacts.................................................................................. 4-33

4.1.2.3.1 Impacts Assessment ............................................................. 4-38

4.1.2.4 Incomplete or Unavailable Information .................................................... 4-51

4.1.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) ............................................................................................... 4-52

4.1.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area....................................................................................... 4-52

4.1.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area....................................................................................... 4-53

4.1.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ................................................................. 4-53

4.1.2.9 Alternative E—No Action.......................................................................... 4-53

4.2 Water Quality........................................................................................................................ 4-53

4.2.1 Description of the Affected Environment ................................................................. 4-56

4.2.2 Environmental Consequences................................................................................. 4-58

4.2.2.1 Routine Activities...................................................................................... 4-58

4.2.2.2 Accidental Events..................................................................................... 4-63

4.2.2.3 Cumulative Impacts.................................................................................. 4-64

4.2.2.4 Incomplete or Unavailable Information .................................................... 4-67

4.2.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) ............................................................................................... 4-67
xlii Gulf of Mexico Multisale EIS

4.2.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area....................................................................................... 4-68

4.2.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area....................................................................................... 4-68

4.2.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ................................................................. 4-69

4.2.2.9 Alternative E—No Action.......................................................................... 4-69

4.3 Coastal Habitats ................................................................................................................... 4-69

4.3.1 Estuarine Systems (Wetlands and Seagrass/Submerged Vegetation)................... 4-69

4.3.1.1 Description of the Affected Environment.................................................. 4-71

4.3.1.1.1 Wetlands................................................................................ 4-71

4.3.1.1.2 Submerged Aquatic Vegetation............................................. 4-74

4.3.1.2 Environmental Consequences ................................................................. 4-76

4.3.1.2.1 Routine Activities ................................................................... 4-76

4.3.1.2.2 Accidental Events .................................................................. 4-79

4.3.1.2.3 Cumulative Impacts ............................................................... 4-84

4.3.1.2.4 Incomplete or Unavailable Information.................................. 4-93

4.3.1.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ............................................................ 4-94

4.3.1.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ......................................... 4-95

4.3.1.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area........................... 4-95

4.3.1.2.8 Alternative D—Alternative D—Alternative A, B, or C, 

with the Option to Exclude Available Unleased Blocks 

Subject to the Topographic Features, Live Bottom 

(Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations............................................................ 4-96

4.3.1.2.9 Alternative E—No Action....................................................... 4-96

4.3.2 Coastal Barrier Beaches and Associated Dunes..................................................... 4-96

4.3.2.1 Description of the Affected Environment.................................................. 4-98

4.3.2.2 Environmental Consequences ...............................................................4-102

4.3.2.2.1 Routine Activities .................................................................4-102

4.3.2.2.2 Accidental Events ................................................................4-104

4.3.2.2.3 Cumulative Impacts .............................................................4-106

4.3.2.2.4 Incomplete or Unavailable Information................................4-112

4.3.2.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..........................................................4-113

4.3.2.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-114

4.3.2.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-114
Table of Contents xliii

4.3.2.2.8 Alternative D—Alternative D—Alternative A, B, or C, 

with the Option to Exclude Available Unleased Blocks 

Subject to the Topographic Features, Live Bottom 

(Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations..........................................................4-114

4.3.2.2.9 Alternative E—No Action.....................................................4-115

4.4 Deepwater Benthic Communities.......................................................................................4-115

4.4.1 Description of the Affected Environment ...............................................................4-121

4.4.1.1 Chemosynthetic Communities ...............................................................4-123

4.4.1.2 Deepwater Coral Communities ..............................................................4-127

4.4.2 Environmental Consequences...............................................................................4-129

4.4.2.1 Routine Activities....................................................................................4-129

4.4.2.2 Accidental Events...................................................................................4-133

4.4.2.3 Cumulative Impacts................................................................................4-137

4.4.2.4 Incomplete or Unavailable Information ..................................................4-140

4.4.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) .............................................................................................4-141

4.4.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.....................................................................................4-142

4.4.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.....................................................................................4-143

4.4.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ...............................................................4-144

4.4.2.9 Alternative E—No Action........................................................................4-144

4.5 Sargassum and Associated Communities .........................................................................4-145

4.5.1 Description of the Affected Environment ...............................................................4-149

4.5.2 Environmental Consequences...............................................................................4-152

4.5.2.1 Routine Activities....................................................................................4-153

4.5.2.2 Accidental Events...................................................................................4-154

4.5.2.3 Cumulative Impacts................................................................................4-156

4.5.2.4 Incomplete or Unavailable Information ..................................................4-159

4.5.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) .............................................................................................4-160

4.5.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.....................................................................................4-160

4.5.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.....................................................................................4-161

4.5.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ...............................................................4-161

4.5.2.9 Alternative E—No Action........................................................................4-161
xliv Gulf of Mexico Multisale EIS

4.6 Live Bottom Habitats ..........................................................................................................4-161

4.6.1 Topographic Features and Associated Communities............................................4-163

4.6.1.1 Description of the Affected Environment................................................4-167

4.6.1.2 Environmental Consequences ...............................................................4-172

4.6.1.2.1 Routine Activities .................................................................4-172

4.6.1.2.2 Accidental Events ................................................................4-174

4.6.1.2.3 Cumulative Impacts .............................................................4-178

4.6.1.2.4 Incomplete or Unavailable Information................................4-180

4.6.1.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..........................................................4-182

4.6.1.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-183

4.6.1.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-183

4.6.1.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-184

4.6.1.2.9 Alternative E—No Action.....................................................4-184

4.6.2 Pinnacles and Low-Relief Features and Associated Communities.......................4-185

4.6.2.1 Description of the Affected Environment................................................4-190

4.6.2.2 Environmental Consequences ...............................................................4-196

4.6.2.2.1 Routine Activities .................................................................4-196

4.6.2.2.2 Accidental Events ................................................................4-199

4.6.2.2.3 Cumulative Impacts .............................................................4-203

4.6.2.2.4 Incomplete or Unavailable Information................................4-207

4.6.2.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..........................................................4-208

4.6.2.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-209

4.6.2.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-210

4.6.2.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-211

4.6.2.2.9 Alternative E—No Action.....................................................4-212

4.7 Fishes and Invertebrate Resources ...................................................................................4-213

4.7.1 Description of the Affected Environment ...............................................................4-216

4.7.2 Environmental Consequences...............................................................................4-221

4.7.2.1 Routine Activities....................................................................................4-221

4.7.2.2 Accidental Events...................................................................................4-226

4.7.2.3 Cumulative Impacts................................................................................4-227

4.7.2.4 Incomplete or Unavailable Information ..................................................4-231

4.7.2.5 Alternatives A, B, C, and D ....................................................................4-231

4.7.2.6 Alternative E—No Action........................................................................4-232
Table of Contents xlv

4.8 Birds....................................................................................................................................4-232

4.8.1 Description of the Affected Environment ...............................................................4-235

4.8.2 Environmental Consequences...............................................................................4-245

4.8.2.1 Routine Activities....................................................................................4-245

4.8.2.2 Accidental Events...................................................................................4-247

4.8.2.3 Cumulative Impacts................................................................................4-249

4.8.2.4 Incomplete or Unavailable Information ..................................................4-254

4.8.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) .............................................................................................4-254

4.8.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.....................................................................................4-256

4.8.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.....................................................................................4-257

4.8.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ...............................................................4-258

4.8.2.9 Alternative E—No Action........................................................................4-259

4.9 Protected Species ..............................................................................................................4-259

4.9.1 Marine Mammals....................................................................................................4-265

4.9.1.1 Description of the Affected Environment................................................4-266

4.9.1.2 Environmental Consequences ...............................................................4-278

4.9.1.2.1 Routine Activities .................................................................4-279

4.9.1.2.2 Accidental Events ................................................................4-289

4.9.1.2.3 Cumulative Impacts .............................................................4-297

4.9.1.2.4 Incomplete or Unavailable Information................................4-303

4.9.1.2.5 Alternatives A, B, C, and D..................................................4-306

4.9.1.2.6 Alternative E—No Action.....................................................4-308

4.9.2 Sea Turtles.............................................................................................................4-308

4.9.2.1 Description of the Affected Environment................................................4-308

4.9.2.2 Environmental Consequences ...............................................................4-318

4.9.2.2.1 Routine Activities .................................................................4-319

4.9.2.2.2 Accidental Events ................................................................4-324

4.9.2.2.3 Cumulative Impacts .............................................................4-329

4.9.2.2.4 Incomplete or Unavailable Information................................4-334

4.9.2.2.5 Alternatives A, B, C, and D..................................................4-335

4.9.2.2.6 Alternative E—No Action.....................................................4-336

4.9.3 Beach Mice (Alabama, Choctawhatchee, Perdido Key, and St. Andrew).............4-336

4.9.3.1 Description of the Affected Environment................................................4-337

4.9.3.2 Environmental Consequences ...............................................................4-337

4.9.3.2.1 Routine Activities .................................................................4-338

4.9.3.2.2 Accidental Events ................................................................4-338

4.9.3.2.3 Cumulative Impacts .............................................................4-339

4.9.3.2.4 Incomplete or Unavailable Information................................4-340

4.9.3.2.5 Alternative A—Regionwide OCS Proposed Lease Sale 

(The Preferred Alternative)..................................................4-340

4.9.3.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-341
xlvi Gulf of Mexico Multisale EIS

4.9.3.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-341

4.9.3.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-342

4.9.3.2.9 Alternative E—No Action.....................................................4-342

4.9.4 Protected Birds.......................................................................................................4-342

4.9.4.1 Description of the Affected Environment................................................4-342

4.9.4.2 Environmental Consequences ...............................................................4-347

4.9.4.2.1 Routine Activities .................................................................4-348

4.9.4.2.2 Accidental Events ................................................................4-349

4.9.4.2.3 Cumulative Impacts .............................................................4-349

4.9.4.2.4 Incomplete or Unavailable Information................................4-350

4.9.4.2.5 Alternative A—Regionwide OCS Proposed Lease Sale 

(The Preferred Alternative)..................................................4-350

4.9.4.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-350

4.9.4.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-351

4.9.4.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-351

4.9.4.2.9 Alternative E—No Action.....................................................4-351

4.9.5 Protected Corals ....................................................................................................4-351

4.9.5.1 Description of the Affected Environment................................................4-351

4.9.5.2 Environmental Consequences ...............................................................4-353

4.9.5.2.1 Routine Activities .................................................................4-354

4.9.5.2.2 Accidental Events ................................................................4-354

4.9.5.2.3 Cumulative Impacts .............................................................4-354

4.9.5.2.4 Alternatives A, B, and C ......................................................4-355

4.9.5.2.5 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-356

4.9.5.2.6 Alternative E—No Action.....................................................4-356

4.10 Commercial Fisheries.........................................................................................................4-356

4.10.1 Description of the Affected Environment ...............................................................4-358

4.10.2 Environmental Consequences...............................................................................4-360

4.10.2.1 Routine Activities....................................................................................4-360

4.10.2.2 Accidental Events...................................................................................4-361

4.10.2.3 Cumulative Impacts................................................................................4-362

4.10.2.4 Incomplete or Unavailable Information ..................................................4-365

4.10.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) .............................................................................................4-365
Table of Contents xlvii

4.10.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.....................................................................................4-365

4.10.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.....................................................................................4-366

4.10.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ...............................................................4-366

4.10.2.9 Alternative E—No Action........................................................................4-366

4.11 Recreational Fishing...........................................................................................................4-367

4.11.1 Description of the Affected Environment ...............................................................4-368

4.11.2 Environmental Consequences...............................................................................4-375

4.11.2.1 Routine Activities....................................................................................4-376

4.11.2.2 Accidental Events...................................................................................4-377

4.11.2.3 Cumulative Impacts................................................................................4-377

4.11.2.4 Incomplete or Unavailable Information ..................................................4-379

4.11.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) .............................................................................................4-379

4.11.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.....................................................................................4-380

4.11.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.....................................................................................4-380

4.11.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ...............................................................4-381

4.11.2.9 Alternative E—No Action........................................................................4-381

4.12 Recreational Resources .....................................................................................................4-381

4.12.1 Description of the Affected Environment ...............................................................4-383

4.12.2 Environmental Consequences...............................................................................4-387

4.12.2.1 Routine Activities....................................................................................4-387

4.12.2.2 Accidental Events...................................................................................4-391

4.12.2.3 Cumulative Impacts................................................................................4-393

4.12.2.4 Incomplete or Unavailable Information ..................................................4-397

4.12.2.5 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative) .............................................................................................4-397

4.12.2.6 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.....................................................................................4-398

4.12.2.7 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.....................................................................................4-398

4.12.2.8 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin 

County, Alabama, Stipulations ...............................................................4-399

4.12.2.9 Alternative E—No Action........................................................................4-399
xlviii Gulf of Mexico Multisale EIS

4.13 Archaeological Resources..................................................................................................4-399

4.13.1 Description of the Affected Environment ...............................................................4-401

4.13.1.1 Prehistoric...............................................................................................4-401

4.13.1.2 Historic....................................................................................................4-403

4.13.2 Environmental Consequences...............................................................................4-406

4.13.2.1 Routine Activities....................................................................................4-406

4.13.2.2 Accidental Events...................................................................................4-408

4.13.2.3 Cumulative Impacts................................................................................4-410

4.13.2.4 Incomplete or Unavailable Information ..................................................4-413

4.13.2.5 Alternatives A, B, C, and D ....................................................................4-414

4.13.2.6 Alternative E—No Action........................................................................4-415

4.14 Human Resources and Land Use ......................................................................................4-415

4.14.1 Land Use and Coastal Infrastructure.....................................................................4-415

4.14.1.1 Description of the Affected Environment................................................4-418

4.14.1.1.1 Land Use .............................................................................4-418

4.14.1.1.2 Coastal Infrastructure ..........................................................4-422

4.14.1.2 Environmental Consequences ...............................................................4-424

4.14.1.2.1 Routine Activities .................................................................4-424

4.14.1.2.2 Accidental Events ................................................................4-426

4.14.1.2.3 Cumulative Impacts .............................................................4-429

4.14.1.2.4 Incomplete or Unavailable Information................................4-436

4.14.1.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..........................................................4-437

4.14.1.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-438

4.14.1.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-438

4.14.1.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-439

4.14.1.2.9 Alternative E—No Action.....................................................4-439

4.14.2 Economic Factors ..................................................................................................4-439

4.14.2.1 Description of the Affected Environment................................................4-440

4.14.2.2 Environmental Consequences ...............................................................4-443

4.14.2.2.1 Routine Activities .................................................................4-444

4.14.2.2.2 Accidental Events ................................................................4-446

4.14.2.2.3 Cumulative Impacts .............................................................4-447

4.14.2.2.4 Incomplete or Unavailable Information................................4-453

4.14.2.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..........................................................4-454

4.14.2.2.6 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area .......................................4-457

4.14.2.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-461
Table of Contents xlix

4.14.2.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-464

4.14.2.2.9 Alternative E—No Action.....................................................4-464

4.14.3 Social Factors (Including Environmental Justice)..................................................4-465

4.14.3.1 Description of the Affected Environment................................................4-466

4.14.3.2 Environmental Consequences ...............................................................4-471

4.14.3.2.1 Routine Activities .................................................................4-472

4.14.3.2.2 Accidental Events ................................................................4-473

4.14.3.2.3 Cumulative Impacts .............................................................4-474

4.14.3.2.4 Incomplete or Unavailable Information................................4-482

4.14.3.2.5 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..........................................................4-483

4.14.3.2.6 Alternative B—Regionwide OCS Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the 

Proposed Lease Sale Area .................................................4-484

4.14.3.2.7 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.........................4-484

4.14.3.2.8 Alternative D—Alternative A, B, or C, with the Option 

to Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..........................................................................4-484

4.14.3.2.9 Alternative E—No Action.....................................................4-484

4.14.3.3 Environmental Justice Determination ....................................................4-485

4.15 Unavoidable Adverse Impacts of a Proposed Action.........................................................4-486

4.16 Irreversible and Irretrievable Commitment of Resources...................................................4-489

4.16.1 Coastal Habitats.....................................................................................................4-490

4.16.2 Biological Resources..............................................................................................4-490

4.16.2.1 Threatened and Endangered Species ...................................................4-490

4.16.2.2 Fish and Invertebrate Resources, Deepwater Benthic Communities, 

Commercial Fisheries, and Recreational Fishing ..................................4-490

4.16.3 Archaeological Resources .....................................................................................4-491

4.16.4 Oil and Gas Development......................................................................................4-491

4.16.5 Loss of Human and Animal Life.............................................................................4-491

4.17 Relationship Between the Short-term Use of Man’s Environment and the Maintenance 

and Enhancement of Long-term Productivity.....................................................................4-491

4.17.1 Short-Term Use......................................................................................................4-491

4.17.2 Relationship to Long-Term Productivity.................................................................4-493

5 CONSULTATION AND COORDINATION...................................................................................... 5-3

5.0 Introduction............................................................................................................................. 5-3

5.1 Coastal Zone Management Act.............................................................................................. 5-3

5.2 Endangered Species Act........................................................................................................ 5-4

5.3 Magnuson-Stevens Fishery Conservation and Management Act.......................................... 5-5

5.4 National Historic Preservation Act.......................................................................................... 5-5

5.5 Government-to-Government Tribal Consultation................................................................... 5-7
l Gulf of Mexico Multisale EIS

5.6 National Environmental Policy Act ......................................................................................... 5-8

5.6.1 Development of the Proposed Actions ...................................................................... 5-8

5.6.1.1 Notice of Intent to Prepare an EIS and Call for Information ...................... 5-8

5.6.1.2 Summary of Comments Received in Response to the Call 

for Information ............................................................................................ 5-9

5.6.1.3 Area ID Memorandum................................................................................ 5-9

5.6.2 Development of the Draft Multisale EIS................................................................... 5-10

5.6.2.1 Scoping..................................................................................................... 5-10

5.6.2.2 Summary of Scoping Comments ............................................................. 5-12

5.6.2.3 Additional Public Input Opportunities ....................................................... 5-15

5.6.2.4 Cooperating Agencies.............................................................................. 5-15

5.6.2.5 Distribution of the Draft Multisale EIS for Review and Comment ............ 5-16

5.6.3 Development of the Final Multisale EIS................................................................... 5-20

5.6.3.1 Major Differences Between the Draft and Final Multisale EISs ............... 5-20

5.6.3.2 Public Meetings ........................................................................................ 5-20

5.6.3.3 Comments Received on the Draft Multisale EIS and BOEM’s 

Responses................................................................................................ 5-21

6 REFERENCES CITED.................................................................................................................... 6-3

7 PREPARERS.................................................................................................................................. 7-3

8 GLOSSARY .................................................................................................................................... 8-3
Table of Contents li 

Volume III 

Page 

LIST OF FIGURES ............................................................................................................................ xxi

LIST OF TABLES ............................................................................................................................ xxxi

APPENDICES 

Appendix A Postlease Permitting and Approval Processes ...................................................... A-3

Appendix B Commonly Applied Mitigating Measures ............................................................... B-3

Appendix C Cooperating Agency Memorandum of Agreement ................................................ C-3

Appendix D Proposed lease Mitigating Measures (Stipulations) .............................................. D-3

Appendix E Oil Spill Risk Analysis Figures ............................................................................... E-3

Appendix F Air Quality: WRF Model Performance ................................................................... F-1

Appendix G Air Quality: Emissions for the Cumulative and Visibility Impacts .......................... G-1 

Appendix H Air Quality: Cumulative and Visibility Impacts ...................................................... H-1

Appendix I Species Not Considered Further ............................................................................. I-3

Appendix J State Coastal Management Programs ................................................................... J-3

Appendix K Consultation Correspondence ............................................................................... K-3

Appendix L Responses to Public Comments on the Draft Multisale EIS ................................... L-3

KEYWORD INDEX ............................................................................................................. Keywords-3

List of Figures liii

LIST OF FIGURES

Page

Figure 1-1. Proposed Regionwide Lease Sale Area Combining the Western, Central, and 

Eastern Planning Areas. ............................................................................................... 1-4 

Figure 1-2. Energy Use in the United States................................................................................... 1-6 

Figure 1-3. OCS Oil and Gas Program Development Process....................................................... 1-7 

Figure 1-4. Planning for the Five-Year Program. ............................................................................ 1-9 

Figure 1-5. Typical Planning Timeline for Regional OCS Oil and Gas Lease Sales. ................... 1-10

Figure 1-6. Supplemental Approach Showing the Tiering Relationships for Proposed Gulf 

of Mexico Lease Sales................................................................................................ 1-12 

Figure 1-7. BOEM’s Consultation Partners for Specific Federal Statutes and Regulations. ........ 1-14 

Figure 1-8. BOEM’s Integrated Approach for Incorporating Applied Science into 

Decisionmaking........................................................................................................... 1-16 

Figure 2-1. Proposed Regionwide Lease Sale Area, Encompassing the Available Unleased 

Blocks within All Three Planning Areas (a total of approximately 91.93 million ac 

with approximately 75.4 million ac available for lease as of January 2017)................. 2-7 

Figure 2-2. Proposed Lease Sale Area for Alternative B, Excluding the Available Unleased 

Blocks in the WPA (approximately 63.35 million ac with approximately 

49.6 million ac available for lease as of January 2017)................................................ 2-9 

Figure 2-3. Proposed Lease Sale Area for Alternative C, Excluding the Available Unleased 

Blocks in the CPA and EPA (approximately 28.58 million ac with approximately 

25.8 million ac available for lease as of January 2017).............................................. 2-10

Figure 2-4. Identified Topographic Features, Pinnacle Trend, and Blocks South of Baldwin 

County, Alabama, Stipulation Blocks in the Gulf of Mexico........................................ 2-11 

Figure 2-5. Example of Excluded Blocks under Alternative D. ..................................................... 2-12 

Figure 2-6. Federal OCS Blocks Subject to the Gulf Islands National Seashore’s Information 

to Lessees and Operators........................................................................................... 2-17 

Figure 2-7. Historical Structure Locations near Horn and Petit Bois Islands................................ 2-18 

Figure 2-8. Military Warning Areas and Eglin Water Test Areas in the Gulf of Mexico. ............... 2-26 

Figure 3-1. Total Oil and Gas Production (BOE) in the Gulf of Mexico in the Low and High 

Production Scenario by Water Depth for a Single Proposed Lease Sale 

(2017-2066)................................................................................................................... 3-7 

Figure 3-2. Offshore Subareas in the Gulf of Mexico...................................................................... 3-8 

Figure 3-3. Typical Timeline for Offshore Oil and Gas Drilling...................................................... 3-11

Figure 3-4. General Well Schematic.............................................................................................. 3-19

Figure 3-5. (A) Number of Exploration and Delineation Wells Drilled over the Course 

of a Proposed Action under Alternative A for 50 Years. (B, C) Location 

of Exploration Wells Drilled during the Entire 50-Year Period.................................... 3-21

Figure 3-6. (A) Number of Production Wells Drilled over the Course of a Proposed Action 

under Alternative A for 50 Years. (B, C) Total Number of Development and 

Production Wells Drilled in the Low and High Production Scenario by Water 

Depth for Alternative A................................................................................................ 3-27

Figure 3-7. Offshore Production Systems. .................................................................................... 3-29

Figure 3-8. Number of Production Structures and Service Vessels Operating over the 

Course of a Proposed Action under Alternative A for 50 Years. (B, C) Total 

Number of Platforms Installed in the Low and High Production Scenario by 

Water Depth. ............................................................................................................... 3-36

Figure 3-9. Gulfwide OCS Oil- and Gas-Related Service Bases and Major Waterways.............. 3-49

Figure 3-10. Boundaries for USEPA Regions 4 and 6. ................................................................... 3-59

Figure 3-11. Onshore Infrastructure. ............................................................................................... 3-83

Figure 3-12. OCS-Related Ports and Waterways in the Gulf of Mexico. ........................................ 3-87
liv Gulf of Mexico Multisale EIS

Figure 3-13. Number of Oil Spills ≥1 bbl That Have Occurred in the Gulf of Mexico for the 

Period 2001 through 2015.........................................................................................3-102

Figure 3-14. Total Volume (bbl) of Oil Spilled in Gulf of Mexico Waters for Spills ≥1 bbl 

for the Period 2001 through 2015 .............................................................................3-103

Figure 3-15. Number of Platform and Pipeline-Related Oil Spills ≥1 bbl That Have Occurred 

in the Gulf of Mexico for the Period 2001 through 2015...........................................3-104

Figure 3-16. Total Volume of Spilled Oil for Platform and Pipeline-Related Oil Spills ≥1 bbl 

That Have Occurred in the Gulf of Mexico for the Period 2001 through 2015. ........3-105

Figure 3-17. The Oil Spill Risk Analysis Model Process. ..............................................................3-121

Figure 3-18. OCS Oil and Gas Production Between 2004 and 2015............................................3-160

Figure 3-19. Number of Production Structures Installed and Decommissioned in Past 

Programs and the Range of Future Projections that May Occur as a Result 

of All Past, Present, and Future Actions ...................................................................3-162

Figure 3-20. 2015 Gulf of Mexico Hypoxic Zone...........................................................................3-212

Figure 4-1. Gulf of Mexico Region with the Planning Areas, Nonattainment Areas, Air 

Quality Jurisdiction, and Class I and Sensitive Class II Areas. .................................. 4-15

Figure 4-2. Year 2011 Gulfwide Emission Inventory Results for Total Platform and 

Non-Platform Criteria Pollutant Emissions (TPY)....................................................... 4-22

Figure 4-3. Year 2011 Gulfwide Emission Inventory Results for Total Platform and 

Non-Platform Greenhouse Gas Emissions (TPY). ..................................................... 4-22

Figure 4-4. 2011 Criteria Pollutant Emissions (TPY) from Platform Sources............................... 4-23

Figure 4-5. 2011 Greenhouse Gases (TPY) from Platform Sources............................................ 4-23

Figure 4-6. Overview of the Gulf of Mexico Region’s Cumulative and Visibility Impacts 

Assessment................................................................................................................. 4-35

Figure 4-7. Geographic Domain of the “Air Quality Modeling in the Gulf of Mexico” Region 

Study. .......................................................................................................................... 4-36

Figure 4-8. Coastal Watersheds of the Upper Gulf of Mexico Showing the Magnitude 

of Saltwater (intertidal) Wetland Loss to Open Water, 2004 to 2009 ......................... 4-72

Figure 4-9. Seagrass Locations of the Northern Gulf of Mexico. .................................................. 4-75

Figure 4-10. Deepwater Coral Records from NOAA’s National Deep-Sea Coral and Sponge 

Database ...................................................................................................................4-116

Figure 4-11. Estimated Distribution of Known Deepwater Benthic Communities in the 

Gulf of Mexico as of 2015. ........................................................................................4-124

Figure 4-12. BOEM’s Water Bottom Seismic Anomaly Database Showing Grouped Anomaly 

Categories Thought Likely to Support Deepwater Benthic Communities and 

Those That Generally Do Not ...................................................................................4-125

Figure 4-13. Example of a Predictive Habitat Suitability Model for Selected Deepwater, 

Framework-Forming Scleractinian Corals ................................................................4-129

Figure 4-14. Sargassum Loop System..........................................................................................4-148

Figure 4-15. Pelagic Brown Algae in the Genus Sargassum........................................................4-149

Figure 4-16. Small Fishes in Sargassum.......................................................................................4-150

Figure 4-17. Lease Blocks Subject to the Topographic Features and Live Bottom (Pinnacle 

Trend) Stipulations....................................................................................................4-162

Figure 4-18. Ecological Representation of Common Features on Topographic Features 

in the Gulf of Mexico. ................................................................................................4-168

Figure 4-19. General Location of the Pinnacle Trend (A), Multibeam Bathymetry and Named 

Reef Areas (B), and an Exaggerated Vertical Relief Profile of Rough Tongue 

Reef (C). ..................................................................................................................4-193

Figure 4-20. Migration Routes for Trans-Gulf Migratory Birds in the Presence of an Eastern 

Continental High........................................................................................................4-239

Figure 4-21. Migration Routes for Trans-Gulf Migratory Birds in the Presence of a Bermuda 

High ...........................................................................................................................4-240

Figure 4-22. Spring Wood Thrush Partial Migratory Corridor in North America ...........................4-241
List of Figures lv

Figure 4-23. Fall Wood Thrush Partial Migratory Corridor in North America................................4-242

Figure 4-24. Platform Density and Spring Migration Routes for Trans-Gulf Migratory Birds........4-243

Figure 4-25. Gulf of Mexico Protected Species’ Critical Habitats. ................................................4-261

Figure 4-26. Gulf Islands National Seashore. ...............................................................................4-387

Figure 4-27. Photograph of Remaining OCS Structures taken from Petit Bois Island Looking 

South (Petit Bois Island is within the Gulf Islands National Seashore 

and is a National Park Service-designated wilderness area.)..................................4-389

Figure 4-28. Economic Land Use Patterns. ..................................................................................4-419

Figure 4-29. Historical Land Loss in Louisiana, 1932-2010..........................................................4-435

Figure 4-30. Moderate Scenario: Projected Land Loss in Louisiana. ..........................................4-435

Figure 4-31. Less Optimistic Scenario: Projected Land Loss in Louisiana..................................4-436

Figure 4-32. Population of BOEM’s Economic Impact Areas in the Gulf of Mexico. ....................4-467

Figure 4-33. Percentage of Poverty in Texas and Louisiana. .......................................................4-469

Figure 4-34. Percentage of Poverty in Mississippi, Alabama, and Florida. ..................................4-469

Figure 4-35. Percentage of Minority Populations in Texas and Louisiana....................................4-470

Figure 4-36. Percentage of Minority Populations in Mississippi, Alabama, and Florida...............4-471

Figure 5-1. Timeline for the Development of the Multisale EIS....................................................... 5-8 

Figure E-1. The Oil Spill Risk Analysis Domain.............................................................................. E-4 

Figure E-2. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

the Shoreline (counties and parishes) as a Result of Alternative A. ........................... E-4 

Figure E-3. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

the Shoreline (counties and parishes) as a Result of Alternative A. ........................... E-5 

Figure E-4. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

the Shoreline (counties and parishes) as a Result of Alternative B. ........................... E-5 

Figure E-5. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

the Shoreline (counties and parishes) as a Result of Alternative B. ........................... E-6 

Figure E-6. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

the Shoreline (counties and parishes) as a Result of Alternative C. ........................... E-6 

Figure E-7. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

the Shoreline (counties and parishes) as a Result of Alternative C. ........................... E-7 

Figure E-8. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative A............................................................................................................ E-7 

Figure E-9. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative A............................................................................................................ E-8 

Figure E-10. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative A............................................................................................................ E-8 

Figure E-11. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative A............................................................................................................ E-9 

Figure E-12. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative B............................................................................................................ E-9 
lvi Gulf of Mexico Multisale EIS

Figure E-13. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative B.......................................................................................................... E-10

Figure E-14. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative B.......................................................................................................... E-10

Figure E-15. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative B.......................................................................................................... E-11

Figure E-16. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative C.......................................................................................................... E-11

Figure E-17. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative C.......................................................................................................... E-12

Figure E-18. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative C.......................................................................................................... E-12

Figure E-19. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative C.......................................................................................................... E-13

Figure E-20. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

and 30 Days State Offshore Waters as a Result of Alternative A, B, or C................ E-13

Figure F-1. Location of the “Air Quality Modeling in the Gulf of Mexico Region” Study 

with Class I Areas and Platform Locations .................................................................. F-3 

Figure F-2. Ozone Nonattainment Areas in the Southeastern U.S................................................ F-4 

Figure F-3. Overview of the “Air Quality Modeling in the Gulf of Mexico Region” Study Tasks .... F-6 

Figure F-4. WRF 36-km CONUS (d01), 12-km SE Regional (d02), and 4-km Gulf of Mexico 

Region (d03) Domains. ................................................................................................ F-9 

Figure F-5. BOEM Gulf of Mexico OCS Region WRF 36-km METSTAT Wind Direction 

Performance for 2012. ............................................................................................... F-18

Figure F-6. BOEM Gulf of Mexico OCS Region WRF 36-km METSTAT Wind Speed 

Performance for 2012. ............................................................................................... F-18

Figure F-7. BOEM Gulfof Mexico OCS Region WRF 36-km METSTAT Temperature 

Performance for 2012. ............................................................................................... F-19

Figure F-8. BOEM Gulf of Mexico OCS Region WRF 36-km METSTAT Humidity 

Performance for 2012. ............................................................................................... F-19

Figure F-9. BOEM Gulf of Mexico OCS Region WRF 12-km METSTAT Wind Direction 

Performance for 2012. ............................................................................................... F-20

Figure F-10. BOEM Gulf of Mexico OCS Region WRF 12-km METSTAT Wind Speed 

Performance for 2012. ............................................................................................... F-20

Figure F-11. BOEM Gulf of Mexico OCS Region WRF 12-km METSTAT Temperature 

Performance for 2012. ............................................................................................... F-21

Figure F-12. BOEM Gulf of Mexico OCS Region WRF 12-km METSTAT Humidity 

Performance for 2012. ............................................................................................... F-21
List of Figures lvii

Figure F-13. BOEM Gulf of Mexico OCS Region WRF 4-km METSTAT Wind Direction 

Performance for 2012. ............................................................................................... F-22

Figure F-14. BOEM Gulf of Mexico OCS Region WRF 4-km METSTAT Wind Speed 

Performance for 2012. ............................................................................................... F-22

Figure F-15. BOEM Gulf of Mexico OCS Region WRF 4-km METSTAT Temperature 

Performance for 2012. ............................................................................................... F-23

Figure F-16. BOEM Gulf of Mexico OCS Region WRF 4-km METSTAT Humidity 

Performance for 2012. ............................................................................................... F-23

Figure F-17. Wind Rose Locations for Port Isabel, TX (PTIT), Calcasieu, LA (CAPL), 

Gulfport, MS (KGPT), and Naples, FL (NPSF).......................................................... F-24

Figure F-18. 2012 WRF Wind Rose (left) Compared to 2012 Observation Wind Rose 

from Gulfport, MS (right) in 4-km Domain.................................................................. F-25

Figure F-19. 2012 WRF Wind Rose (left) Compared to 2012 Observation Wind Rose 

from Naples, FL (right) in 4-km Domain..................................................................... F-26

Figure F-20. 2012 WRF Wind Rose (left) Compared to 2012 Observation Wind Rose 

from Port Isabel, TX (right) in 4-km Domain.............................................................. F-27

Figure F-21. 2012 WRF Wind Rose (left) Compared to 2012 Observation Wind Rose 

from Calcasieu, LA (right) in 4-km Domain................................................................ F-28

Figure F-22. Vertical Profile Soundings Comparing the 4-km WRF (blue lines) to Upper-Air 

Observations Data (red lines) for Brownsville, TX on August 3, 2012, and 

Key West, FL on January 4, 2012, at 00 UTC........................................................... F-30

Figure F-23. January 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain............... F-33

Figure F-24. February 2012 PRISM Precipitation and WRF Precipitation 4-km Domain.............. F-34

Figure F-25. March 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain.................. F-35

Figure F-26. April 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain. ................... F-36

Figure F-27. May 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain..................... F-37

Figure F-28. June 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain.................... F-38

Figure F-29. July 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain. ................... F-39

Figure F-30. August 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain. ............... F-40

Figure F-31. September 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain......... F-41

Figure F-32. October 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain............... F-42

Figure F-33. November 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain........... F-43

Figure F-34. December 2012 PRISM Precipitation and WRF Precipitation, 4-km Domain........... F-44

Figure F-35. January 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-46

Figure F-36. February 2012 TRMM Precipitation Average and Corresponding WRF 

Precipitation Average in the 12-km Domain. ............................................................. F-47

Figure F-37. March 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-48

Figure F-38. April 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-49

Figure F-39. May 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-50

Figure F-40. June 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-51

Figure F-41. July 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-52

Figure F-42. August 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-53

Figure F-43. September 2012 TRMM Precipitation Average and Corresponding WRF 

Precipitation Average in the 12-km Domain. ............................................................. F-54

Figure F-44. October 2012 TRMM Precipitation Average and Corresponding WRF Precipitation 

Average in the 12-km Domain. .................................................................................. F-55
lviii Gulf of Mexico Multisale EIS

Figure F-45. November 2012 TRMM Precipitation Average and Corresponding WRF 

Precipitation Average in the 12-km Domain. ............................................................. F-56

Figure F-46. December 2012 TRMM Precipitation Average and Corresponding WRF 

Precipitation Average in the 12-km Domain. ............................................................. F-57

Figure F-47. Daily Precipitation Plots from WRF, PRISM, and TRMM on August 30, 2012.......... F-59

Figure F-48. Daily Precipitation Plots from WRF, PRISM, and TRMM Databases 

on June 25, 2012........................................................................................................ F-60

Figure G-1. Location of the “Air Quality Modeling in the Gulf of Mexico Region” Study, 

with Class I Areas and Platform Locations .................................................................. G-1 

Figure G-2. Ozone Nonattainment Areas in the Southeastern U.S................................................ G-2 

Figure G-3. Overview of the “Air Quality Modeling in the Gulf of Mexico Region” Study Tasks .... G-4 

Figure G-4. WRF 36-km CONUS (d01), 12-km SE Regional (d02), and 4-km Gulf of Mexico 

Region (d03) Domains Along With the PGM Grids. .................................................... G-6 

Figure G-5. 2012 Platform NOx Emissions Aggregated by Lease Block ...................................... G-11

Figure G-6. 2012 Platform VOC Emissions Aggregated by Lease Block..................................... G-12

Figure G-7. 2012 Platform PM2.5 Emissions Aggregated by Lease Block.................................... G-13

Figure G-8. 2012 Non-platform NOx Emissions ............................................................................ G-15

Figure G-9. 2012 Non-platform VOC Emissions........................................................................... G-16

Figure G-10. 2012 Non-platform PM2.5 Emissions.......................................................................... G-17

Figure G-11. Emission Estimates for all Planning Areas and Future Activities. ............................. G-27

Figure G-12. Combined Annual NOx Emissions. ............................................................................ G-27

Figure G-13. Combined Annual VOC Emissions............................................................................ G-28

Figure G-14. Combined Annual PM2.5 Emissions........................................................................... G-28

Figure G-15. BOEM OCS Planning Areas and Water Depths........................................................ G-29

Figure H-1. Location of the “Air Quality Modeling in the Gulf of Mexico Region” Study, 

with Class I Areas......................................................................................................... H-1 

Figure H-2. Ozone Nonattainment Areas in the Southeastern U.S................................................ H-3 

Figure H-3. Class I and Sensitive Class II Areas in the Study Region. .......................................... H-5 

Figure H-4. Overview of the “Air Quality Modeling in the Gulf of Mexico Region” Study Tasks .... H-6 

Figure H-5. Meteorological (WRF model) and PGM Modeling Domains Including the 36-km 

Horizontal Grid Resolution CONUS WRF Domain, 12-km Resolution Southeast 

Regional WRF and PGM Domains (d02), and 4-km Resolution Gulf of Mexico 

OCS Region WRF and PGM Domains (d03)............................................................... H-7 

Figure H-6. BOEM’s 12-km 2012 Base Case NOx Emissions Summary in Tons per Year 

by Source Category and State (Alabama, Florida, Louisiana, Mississippi, 

and Texas). ................................................................................................................ H-19

Figure H-7. BOEM 12-km 2012 Base Case VOC Emissions Summary in Tons per Year 

by Source Category and State (Alabama, Florida, Louisiana, Mississippi, 

and Texas). ................................................................................................................ H-20

Figure H-8. BOEM 12-km 2012 Base Case PM2.5 Emissions Summary in Tons per Year 

by Source Category and State (Alabama, Florida, Louisiana, Mississippi, 

and Texas). ................................................................................................................ H-21

Figure H-9. BOEM 12-km 2012 Base Case SO2 Emissions Summary in Tons per Year 

by Source Category and State (Alabama, Florida, Louisiana, Mississippi, 

and Texas). ................................................................................................................ H-22

Figure H-10. BOEM 12-km Future Year NOx Emissions Summary in Tons per Year by Source 

Category and State (Alabama, Florida, Louisiana, Mississippi, and Texas)............. H-23

Figure H-11. BOEM 12-km Future Year VOC Emissions Summary in Tons per Year by Source 

Category and State (Alabama, Florida, Louisiana, Mississippi, and Texas)............. H-24

Figure H-12. BOEM 12-km Future Year PM2.5 Emissions Summary in Tons per Year by Source 

Category and State (Alabama, Florida, Louisiana, Mississippi, and Texas)............. H-25

Figure H-13. BOEM 12-km Future Year SO2 Emissions Summary in Tons per Year by Source 

Category and State (Alabama, Florida, Louisiana, Mississippi, and Texas)............. H-26
List of Figures lix

Figure H-14. Spatial Distribution of NOx, VOC, SO2, and PM2.5 Emissions (tons per year) 

from New OCS Oil and Gas Production Platforms under the Proposed Action........ H-29

Figure H-15. Spatial Distribution of Emissions (tons per year) of NOx, VOC, SO2, and PM2.5 

from BOEM’s OCS Additional Oil and Gas Support Vessels and Helicopters 

under the Proposed Action Scenario. ........................................................................ H-30

Figure H-16. Spatial Distribution of NOx, VOC, SO2, and PM2.5 Emissions (tons per year) 

from BOEM’s OCS Oil and Gas Platforms, Support Vessels, and Helicopters 

under the No Action Alternative in BOEM’s 4-km Domain. ....................................... H-31

Figure H-17. Spatial Distribution of NOx, VOC, SO2, and PM2.5 Emissions (tons per year) 

from All Other Marine Vessel Activity in the Gulf of Mexico under the Future Year 

Scenario in BOEM’s 4-km Domain. ........................................................................... H-32

Figure H-18. Spatial Distribution of NOx, VOC, SO2, and PM2.5 Emissions (tons per year) 

from Other Anthropogenic U.S. Sources for the Future Year Scenario within 

BOEM’s 4-km Domain................................................................................................ H-33

Figure H-19. Ozone Monitoring Sites Used in the Model Performance Evaluation: CASTNet 

Sites in the Southeastern U.S. and AQS Sites within the 4-km Modeling Domain .. H-42

Figure H-20. Speciated PM Monitoring Sites Used in the Model Performance Evaluation: 

CSN Network, IMPROVE Network, and SEARCH Network ..................................... H-44

Figure H-21. Monthly Normalized Mean Bias and Normalized Mean Error for Daily Maximum 

8-hour Average Ozone at AQS and CASTNet Monitoring Sites Located within 

the 4-km Modeling Domain and the 12-km Domain .................................................. H-50

Figure H-22. Fraction of Site-days during Each Month of 2012 with Observed Daily Maximum 

8-hour Ozone Exceeding 60, 65, or 70 ppb Over All Monitoring Sites in the 

4-km Domain.............................................................................................................. H-51

Figure H-23. Observed (blue) and Predicted Monthly Mean Daily Maximum 8-hour Average 

Ozone Over All Sites in the 4-km Modeling Domain. ................................................ H-52

Figure H-24. Scatter and Scatter Density Plots for Observed vs. Predicted Daily Maximum 

8-hour Ozone in Q2 and Q3 for All AQS Monitoring Sites in the 4-km Modeling 

Domain....................................................................................................................... H-53

Figure H-25. Normalized Mean Bias (NMB) for Daily Maximum 8-hour Ozone for Q2 (top) 

and Q3........................................................................................................................ H-54

Figure H-26. Time Series of Daily Maximum 8-hour Ozone at Monitoring Sites with Highest 

Design Values in Harris, Brazoria, and Galveston Counties, Texas, for Q2 

and Q3........................................................................................................................ H-56

Figure H-27. Time Series of Daily Maximum 8-hour Ozone at Monitoring Sites in the 

Baton Rouge Nonattainment Area: LSU and Carville for Q2 and Q3 ...................... H-56

Figure H-28. Time Series of Daily Maximum 8-hour Ozone at the ALC188 (AlabamaCoushatta, Texas) CASTNet Monitoring Site for Q2 and Q3 .................................... H-57

Figure H-29. PM Monitoring Sites in the Southeastern U.S. Domain............................................. H-59

Figure H-30. Soccer Plots of Total PM2.5 Mass Model Performance Across the IMPROVE, 

CSN SEARCH, and FRM Daily Monitoring Networks for Sites in the Southeastern 

U.S. Domain............................................................................................................... H-60

Figure H-31. Comparisons of Predicted with Observed Daily Average PM at CSN Network 

Sites in the Southeastern U.S. for Q2 and Q4 for Total PM2.5, Other PM2.5, 

and Sodium ................................................................................................................ H-61

Figure H-32. Comparisons of Observed vs. Predicted OC and EC (bottom) at SEARCH and 

CSN Network Sites in the Southeastern U.S............................................................. H-62

Figure H-33. Monthly Normalized Mean Bias and Normalized Mean Error for Hourly NO2 and 

Daily NOy at SEARCH Network Sites and AQS Sites in the 4-km Domain............... H-63

Figure H-34. Monthly Normalized Mean Bias and Normalized Mean Error for NO3 at SEARCH 

Network Monitoring Sites and AQS Sites and NO3 Deposition at NADP Sites 

in the Southeastern U.S............................................................................................. H-64
lx Gulf of Mexico Multisale EIS

Figure H-35. Monthly Normalized Mean Bias and Normalized Mean Error at Monitoring Sites 

in the 4-km Domain for SO2, SO4, and SO4 Deposition Measured at NADP Sites... H-66

Figure H-36. Annual Normalized Mean Bias for Hourly SO2 (based on 12-km resolution 

CAMx results)............................................................................................................. H-67

Figure H-37. Monthly Normalized Mean Bias and Normalized Mean Error for Daily Average 

NH4 at CSN and SEARCHNetwork Sites in the 4-km Modeling Domain. ................ H-68

Figure H-38. Monthly Normalized Mean Bias and Normalized Mean Error for Hourly CO 

at SEARCH Network Sites and AQS Sites ................................................................ H-69

Figure H-39. Class I and Sensitive Class II Areas for Which Incremental AQ/AQRV Impacts 

Were Calculated......................................................................................................... H-73

Figure H-40. Base Scenario Ozone Design Values (DVC), Future Year Ozone Design Values 

(DVF) and Their Differences (DVF – DVC) Calculated Using the MATS UAA 

Tool............................................................................................................................. H-87

Figure H-41. MATS UAA Future Year Ozone Design Values (DFV) Calculated After First 

Removing the Hourly Contributions from a Source Group and the Corresponding 

Contributions of the Source Group to DVF Calculated by Subtracting the DVFs 

Shown in the Left-hand Column from the “All Sources” DVF Shown in the Top 

Right-hand Corner of Figure H-40 ............................................................................. H-88

Figure H-42. Modeled 4th Highest MDA8 Ozone for the Base Year and Future Year Scenarios 

and Their Differences................................................................................................. H-89

Figure H-43. Contributions of Source Groups A, B, C, D, and E to Future Year All-sources 

4th Highest MDA8 ...................................................................................................... H-91

Figure H-44. Contributions from Source Group F (natural and non-US emission sources 

including boundary conditions) and Boundary Conditions Only, to Future Year 

All-sources 4th Highest MDA8. .................................................................................. H-92

Figure H-45. Current Year (DVC) and Future Year (DVF) Annual Average PM2.5 Design 

Values from the MATS Unmonitored Area Analysis and the Difference, 

DVF – DVC................................................................................................................. H-98

Figure H-46. Contributions of Source Groups A, B, C, D, and E to the Future Year All-sources 

Annual Average PM2.5 Concentration Based on the MATS Unmonitored Area 

Analysis ...................................................................................................................... H-99

Figure H-47. Modeled 8th Highest Daily Average PM2.5 Concentrations for the Base Year, 

Future Year, and the Future – Base Difference....................................................... H-101

Figure H-48. Contributions of Source Groups A, B, C, D, and E to the Future Year All-sources 

8th Highest Daily Average PM2.5 Concentration...................................................... H-102

Figure H-49. Contributions from Source Group F (natural and non-U.S. emission sources 

including boundary conditions) and Boundary Conditions Only to Future Year 

All-sources 8th Highest 24-hour PM2.5..................................................................... H-103

Figure H-50. Modeled Annual Average PM2.5 Concentrations for the Base Year, Future Year, 

and the Future – Base Difference............................................................................ H-104

Figure H-51. Contributions of Source Group A, B, C, D, and E to the Future Year All-sources 

Annual Average PM2.5 Concentration ...................................................................... H-105

Figure H-52. Contributions from Source Group F (natural and non-U.S. emission sources 

including boundary conditions) and Boundary Conditions Only to Future Year 

All-sources Annual Average PM2.5 ........................................................................... H-106

Figure H-53. Modeled 2nd Highest 24-hour Average PM10 Concentrations for the Base Year, 

Future Year, and the Future – Base Difference....................................................... H-107

Figure H-54. Contributions of Source Groups A, B, C, D, and E to the Future Year All-sources 

2nd Highest Daily Average PM10 Concentration...................................................... H-108

Figure H-55. Contributions from Source Group F (natural and non-U.S. emission sources 

including boundary conditions) and Boundary Conditions Only to Future Year 

All-sources 2nd Highest Daily Average PM10 Concentration.................................... H-109
List of Figures lxi

Figure H-56. Modeled 8th Highest 1-hour NO2 Concentrations for the Base Year, Future 

Year, and the Future – Base Difference .................................................................. H-110

Figure H-57. Contributions of Source Group A, B, C, D, and E to the Future Year All-sources 

8th Highest Daily Average NO2 Concentrations ...................................................... H-111

Figure H-58. Modeled Annual Average NO2 Concentrations for the Base Year, Future Year, 

and the Future – Base Difference............................................................................ H-112

Figure H-59. Contributions of Source Groups A, B, C, D, and E to the Future Year All-sources 

Annual Average NO2 Concentrations. ..................................................................... H-113

Figure H-60. Modeled 4th Highest Daily Maximum 1-hour SO2 Concentrations for the Base 

Year, Future Year, and the Future – Base Difference............................................. H-115

Figure H-61. Contributions of Source Group A, B, C, D, and E to the Future Year All-sources 

4th Highest Daily Maximum 1-hour SO2 Concentration .......................................... H-116

Figure H-62. Modeled Annual 2nd Highest Block 3-hour SO2 Concentrations for the Base 

Year, Future Year, and the Future – Base Difference............................................. H-117

Figure H-63. Contributions of Source Group A, B, C, D, and E to the Future Year All-sources 

2nd Highest 3-hour Block Average SO2 Concentration........................................... H-118

Figure H-64. Modeled Annual 2nd Highest Non-overlapping Running 8-hour Average CO 

Concentrations for the Base Year, Future Year, and the Future – Base Difference..... H119

Figure H-65. Modeled Annual 2nd Highest 1-hour Average CO Concentrations for the Base 

Year, Future Year, and the Future – Base Difference............................................. H-120

List of Tables lxiii

LIST OF TABLES

Page

Table 2-1. Applicable Stipulations by Alternative .......................................................................... 2-29

Table 2-2. Alternative Comparison Matrix. .................................................................................... 2-36 

Table 3-1. Projected Oil and Gas in the Gulf of Mexico OCS. ........................................................ 3-7 

Table 3-2. Offshore Scenario Activities and Impact-Producing Factors Related to a Single 

Proposed Lease Sale for Alternative A, B, or C from 2017 through 2066. .................... 3-9 

Table 3-3. Estimated Exploration and Seismic Survey Activity Leading Up To and Following 

a Proposed Lease Sale in the Gulf of Mexico. ............................................................. 3-16

Table 3-4. Oil Transportation Scenario under Alternatives A, B, and C........................................ 3-37

Table 3-5. Existing Coastal Infrastructure Related to OCS Oil- and Gas-Related Activities 

in the Gulf of Mexico..................................................................................................... 3-38

Table 3-6. OCS Pipeline Landfalls Installed from 1996 to 2014. .................................................. 3-42

Table 3-7. Waterway Length, Depth, Traffic, and Number of Trips for 2012. ............................... 3-45

Table 3-8. Pollution-Related Incidents of Noncompliance (INCs) Issued Since 1986. ................. 3-61

Table 3-9. National Pollutant Discharge Elimination System Inspections from 1999 

through 2016................................................................................................................. 3-62

Table 3-10. Annual Volume of Produced Water Discharged by Depth (millions of bbl). ................ 3-68

Table 3-11. OCS Oil- and Gas-Related Service Bases................................................................... 3-86

Table 3-12. Spill Rates for Petroleum Spills ≥1,000 Barrels from OCS Platforms and Pipelines, 

1964 through 2010......................................................................................................3-106

Table 3-13. Historic Spill Source, Location, and Characteristics of a Maximum Spill for 

Coastal Waters (data extracted from USDHS, CG records, 2002-July 2015). ..........3-108

Table 3-14. Petroleum Spills ≥1,000 Barrels from United States OCS Platforms, 

1964-July 2016. ..........................................................................................................3-111

Table 3-15. Petroleum Spills ≥1,000 Barrels from United States OCS Pipelines, 

1964-July 2016. ..........................................................................................................3-113

Table 3-16. Properties and Persistence by Oil Component Group. ..............................................3-117

Table 3-17. Probability (percent chance) of a Particular Number of Offshore Spills 

≥1,000 Barrels Occurring as a Result of Either Facility or Pipeline Operations 

Related to Alternative A, B, or C.................................................................................3-122

Table 3-18. Mean Number and Sizes of Spills Estimated to Occur in OCS Offshore Waters 

from an Accident Related to Rig/Platform and Pipeline Activities Supporting Each 

Alternative Over a 50-Year Time Period. ...................................................................3-123

Table 3-19. Oil-Spill Occurrence Probability Estimates for Offshore Spills ≥1,000 Barrels 

Resulting from Each Alternative (2017-2066) and the Cumulative OCS Oil and 

Gas Program (2017-2086)..........................................................................................3-124

Table 3-20. Oil-Spill Occurrence Probability Estimates for Offshore Spills ≥10,000 Barrels 

Resulting from Each Alternative (2017-2066) and the Cumulative OCS Oil and 

Gas Program (2017-2086)..........................................................................................3-124

Table 3-21. Number and Volume of Chemical and Synthetic-Based Fluid Spills for 

10-49 Barrels and >50 Barrels in the Gulf of Mexico from 2007 through 2014. ........3-137

Table 3-22. Primary Cleanup Options Used during the Deepwater Horizon Response. ..............3-142

Table 3-23. Future Activity Projections Associated with the Cumulative OCS Oil and Gas 

Program (2017-2086), Including All Future Activities that are Projected to Occur 

from Past, Proposed, and Future Lease Sales. .........................................................3-158

Table 3-24. Cumulative G&G Surveying Activities Expected in the Gulf of Mexico 

(2017-2086). ...............................................................................................................3-161

Table 3-25. Future Oil Transportation Projections Associated with the Cumulative OCS Oil 

and Gas Program (2017-2086), Including All Future Transportation that is 

Projected to Occur from Past, Proposed, and Future Lease Sales...........................3-164
lxiv Gulf of Mexico Multisale EIS

Table 3-26. Number of Vessel Calls at U.S. Gulf Ports Between 2002 and 20111. .....................3-170

Table 3-27. Quantities of Dredged Materials Disposed of in Ocean Dredged-Material Disposal 

Sites Between 2004 and 2013....................................................................................3-176

Table 3-28. Average Annual Inputs of Petroleum Hydrocarbons to Coastal Waters of the 

Gulf of Mexico, 1990-1999. ........................................................................................3-179

Table 3-29. Average Annual Inputs of Petroleum Hydrocarbons to Offshore Waters of the 

Gulf of Mexico, 1990-1999. ........................................................................................3-180

Table 3-30. Projected OCS Sand Resource Needs for Planned Restoration Projects.................3-189

Table 3-31. Hurricane Landfalls in the Northern Gulf of Mexico from 1995 through 2016. ..........3-208

Table 3-32. Oil Spilled from Pipelines on the Federal OCS, 2002-2009.......................................3-209

Table 4-1. Air Quality Impact-Producing Factors That Are Reasonably Foreseeable. ................. 4-14

Table 4-2. National Ambient Air Quality Standards....................................................................... 4-17

Table 4-3. Nonattainment and Maintenance Areas in the Gulf of Mexico Region. ....................... 4-19

Table 4-4. Source Categories for Source Apportionment Calculations......................................... 4-37

Table 4-5. NAAQS and PSD Increments....................................................................................... 4-38

Table 4-6. Class I and Sensitive Class II Areas in Gulf Coast and Nearby States. ...................... 4-43

Table 4-7. Source Group for Incremental Impacts Analysis.......................................................... 4-45

Table 4-8. Water Quality Impact-Producing Factors That Are Reasonably Foreseeable............. 4-54

Table 4-9. Estuarine Systems Impact-Producing Factors That Are Reasonably Foreseeable..... 4-70

Table 4-10. Coastal Barrier Beaches and Associated Dunes Impact-Producing Factors That 

Are Reasonably Foreseeable....................................................................................... 4-97

Table 4-11. Deepwater Benthic Communities Impact-Producing Factors That are Reasonably 

Foreseeable................................................................................................................4-116

Table 4-12. Sargassum and Associated Communities Impact-Producing Factors That Are 

Reasonably Foreseeable............................................................................................4-145 

Table 4-13. Topographic Features Impact-Producing Factors That Are Reasonably 

Foreseeable................................................................................................................4-164

Table 4-14. Pinnacles and Low-Relief Features Impact-Producing Factors That Are 

Reasonably Foreseeable............................................................................................4-185

Table 4-15. Fish and Invertebrate Resources Impact-Producing Factors That Are Reasonably 

Foreseeable................................................................................................................4-215

Table 4-16. Birds Impact-Producing Factors That Are Reasonably Foreseeable.........................4-233

Table 4-17. Species within the Gulf of Mexico That Are Protected Under the Endangered 

Species Act and/or the Marine Mammal Protection Act.............................................4-260

Table 4-18. Protected Species Impact-Producing Factors That Are Reasonably Foreseeable. ..4-263

Table 4-19. Best Available Population Estimates for Marine Mammal Species in the Northern 

Gulf of Mexico.............................................................................................................4-267

Table 4-20. Commercial Fisheries Impact-Producing Factors That Are Reasonably 

Foreseeable................................................................................................................4-357

Table 4-21. Landings Revenues: Landings Revenue by Species and State. ..............................4-359

Table 4-22. Recreational Fishing Impact Producing Factors That Are Reasonably 

Foreseeable................................................................................................................4-367

Table 4-23. CPA and EPA Effort Data: Angler Trips in the Gulf of Mexico..................................4-369

Table 4-24. CPA and EPA Catch Data: Number of Fish Species Caught by Recreational 

Anglers from 2008 through 2013 in Louisiana, Mississippi, and Alabama 

Combined....................................................................................................................4-371

Table 4-25. CPA and EPA Catch Data: Fish Species Caught by Recreational Anglers 

from 2008 through 2013 in West Florida....................................................................4-372

Table 4-26. Texas Effort Data: Number of Angler Trips from 2011 through 2015. ......................4-373

Table 4-27. Texas Catch Data: Top Species Landed by Recreational Fishermen......................4-374

Table 4-28. Recreational Resources Impact-Producing Factors That Are Reasonably 

Foreseeable. ...............................................................................................................4-382
List of Tables lxv

Table 4-29. Recreational and Tourism Employment and Value-Added in BOEM's Economic 

Impact Areas in 2013. .................................................................................................4-383

Table 4-30. Archaeological Surveys and Resources Identified, 2009-2014. ................................4-404

Table 4-31. Land Use and Coastal Infrastructure Impact-Producing Factors That Are 

Reasonably Foreseeable............................................................................................4-417

Table 4-32. Comparison of the 1954 and 2015 Populations by State...........................................4-429

Table 4-33. Economic and Demographic Information for BOEM's Economic Impact Areas 

in 2015. .......................................................................................................................4-441

Table 4-34. Sales Volumes, Sales Values, and Revenues...........................................................4-443

Table 4-35. Cumulative Low: MAG-PLAN Industry Expenditure Impacts....................................4-449

Table 4-36. Cumulative High: MAG-PLAN Industry Expenditure Impacts. ..................................4-450

Table 4-37. Economic and Demographic Information for BOEM's Economic Impact Areas 

in 2050. .......................................................................................................................4-452

Table 4-38. Gulf of Mexico Single Low: MAG-PLAN Industry Expenditure Impacts....................4-454

Table 4-39. Gulf of Mexico Single High: MAG-PLAN Industry Expenditure Impacts...................4-456

Table 4-40. CPA/EPA Single Low: MAG-PLAN Industry Expenditure Impacts. ..........................4-458

Table 4-41. CPA/EPA Single High: MAG-PLAN Industry Expenditure Impacts. .........................4-460

Table 4-42. WPA Single Low: MAG-PLAN Industry Expenditure Impacts...................................4-462

Table 4-43. WPA Single High: MAG-PLAN Industry Expenditure Impacts..................................4-463

Table B-1. Commonly Applied or “Standard” Mitigating Measures. ............................................... B-5 

Table F-1. Nonattainment and Maintenance Areas in the Southeastern U.S. ............................... F-5 

Table F-2. BOEM’s Gulf of Mexico OCS Region WRF Domain Configuration. ............................. F-8 

Table F-3. BOEM Gulf of Mexico OCS Region WRF Dataset Model Levels. .............................. F-10

Table F-4. BOEM Gulf of Mexico OCS Region WRF Physics Options........................................ F-13

Table F-5. Meteorological Model Performance Benchmarks for Simple and Complex 

Conditions.................................................................................................................... F-14

Table G-1. Nonattainment and Maintenance Areas in the Southeastern U.S. ............................... G-3 

Table G-2. Gulf of Mexico Air Quality Modeling Study Source Categories..................................... G-7 

Table G-3. Base Case Offshore Oil and Gas Production Source Emissions Estimates 

for the GOM Western and Central/Eastern Planning Areas. ...................................... G-10

Table G-4. Future Year Production Platform Emission Factors.................................................... G-21

Table G-5. Summary of Vessel Characteristics. ........................................................................... G-23

Table G-6. Load Factors to be Used in the Future Year Projections............................................ G-24

Table G-7. Marine Vessel Emission Factors (g/kW-hr)................................................................. G-24

Table G-8. Emission Estimates for the Western, Central, and Eastern Planning Areas, 

All Depths, By Year and Pollutant. .............................................................................. G-25

Table H-1. Nonattainment and Maintenance Areas in the Southeastern U.S. ............................... H-4 

Table H-2. Gulf of Mexico OCS Region Air Quality Modeling Study Source Categories ............... H-9 

Table H-3. 2012 Fire Criteria Air Pollutant Emissions Summary by Fire Type for BOEM’s 

36-, 12-, and 4-km Domains........................................................................................ H-14

Table H-4. 2012 Base Case and Future Year Emissions Summary by State for BOEM’S 

12-km Domain (only Gulf Coast States: Alabama, Florida, Louisiana, Mississippi, 

and Texas)................................................................................................................... H-18

Table H-5. 2012 Base Case and Future Year Emissions Summary by Source Category 

for BOEM’s 4-km Domain............................................................................................ H-26

Table H-6. Changes in Emissions between the 2012 Base Case and Future Year Emissions 

(short tons per year) by Source Category for BOEM’s 4-km Domain......................... H-27

Table H-7. Source Categories for Source Apportionment Calculations........................................ H-34

Table H-8. Domain Grid Definitions for the WRF and CAMx/CMAQ Modeling. ........................... H-35

Table H-9. Vertical Layer Interface Definition for WRF Simulations and the Layer-collapsing 

Scheme for the CAMx/CMAQ Layers.......................................................................... H-36

Table H-10. CAMx Model Configuration.......................................................................................... H-39

Table H-11. Definitions of Model Performance Evaluation Statistical Metrics................................ H-45
lxvi Gulf of Mexico Multisale EIS

Table H-12. Ozone and PM Model Performance Goals and Criteria.............................................. H-46

Table H-13. Model Performance Statistics at Different Observed Ozone Concentration 

Screening Thresholds Based on All Monitoring Sites in the 4-km Domain ................ H-55

Table H-14. NAAQS and PSD Increments...................................................................................... H-71

Table H-15. Source Group for Incremental Impacts Analysis......................................................... H-72

Table H-16. Class I and Sensitive Class II Areas in Gulf Coast and Nearby States. ..................... H-74

Table H-17. Current Year (DVC) and Future Year (DVF) Ozone Design Values at Ambient Air 

Monitoring Sites within the 4-km Modeling Domain from MATS................................. H-82

Table H-18. Ozone Current (DVC) and Future Year (DVF) Design Values and Reduction 

in DVF with Contributions from Individual Source Groups Removed. ........................ H-84

Table H-19. MATS Ozone Design Value Results for All Monitoring Sites Where Exclusion 

of Contributions from Source Group A or B is Sufficient to Reduce the Predicted 

Future Design Value (DVF) from Above the NAAQS to Below the NAAQS 

(all values in ppb)......................................................................................................... H-86

Table H-20. Current Year (DVC) and Future Year (DVF) 24-Hour PM2.5 Design Values 

for Monitoring Sites in the 4-km Modeling Domain from MATS.................................. H-93

Table H-21. 24-Hour PM2.5 Current (DVC) and Future Year (DVF) Design Values and 

Reduction in DVF with Contributions from Individual Source Groups Removed........ H-94

Table H-22. Current (DVC) and Projected Future (DVF) Annual Average PM2.5 Design Values 

for Monitoring Sites in the 4-km Modeling Domain ..................................................... H-95

Table H-23. Annual Average PM2.5 Future Year Design Values (DVF) and Change in DVF 

with Contributions from Individual Source Groups Removed ..................................... H-96

Table H-24. Maximum Source Group Contributions for PSD Pollutants at Class I and 

Sensitive Class II Areas in the 4-km Modeling Domain. ........................................... H-121

Table H-25. Source Group Contributions for PSD Pollutants at All Class I and Sensitive 

Class II Areas in the 4-km Modeling Domain............................................................ H-123

Table H-26. Incremental Visibility Impacts Relative to Natural Background Conditions 

from Source Group A................................................................................................. H-124

Table H-27. Incremental Visibility Impacts Relative to Natural Background Conditions 

from Source Group B................................................................................................. H-125

Table H-28. Cumulative Visibility Results for 20% Worst Visibility Days (W20%) at Class I 

Areas for Base (2012) Year (BY) and Future Year (FY) Scenarios with All 

Sources Included and with Contributions from Each Source Group Removed........ H-128

Table H-29. Differences in Cumulative Visibility Results for 20% Worst Visibility Days (W20%) 

at Class I Areas Between the Future Year (FY) and Base Year (BY) Scenarios 

and Contributions of Each Source Group to the Future Year Scenario Visibility...... H-130

Table H-30. Cumulative Visibility Results for 20% Best Visibility Days (B20%) at Class I 

Areas for Base (2012) Year (BY) and Future Year (FY) Scenarios with All 

Sources Included and with Contributions from Each Source Group Removed........ H-132

Table H-31. Differences in Cumulative Visibility Results for 20% Best Visibility Days (B20%) 

at Class I Areas Between the Future Year (FY) and Base Year (BY) Scenarios 

and Contributions of Each Source Group to the Future Year Scenario Visibility...... H-133

Table H-32. Deposition Analysis Threshold Values (kg/ha/yr) as Defined in the Federal Land 

Manager Guidance .................................................................................................... H-135

Table H-33. Incremental Deposition Impacts from Source Groups A and B at Class I and 

Sensitive Class II Areas in the 4-km Domain............................................................ H-135

Table H-34. Cumulative Nitrogen (N) and Sulfur (S) Deposition Impacts (kg/ha/yr) under 

the Base and Future Year Scenarios (shading indicates values exceeding 

the Critical Load threshold)........................................................................................ H-136

Table L-1. Public Comments and BOEM’s Response Matrix........................................................ L-14
Abbreviations and Acronyms lxvii

ABBREVIATIONS AND ACRONYMS

°C degree Celsius

°F degree Fahrenheit

μg microgram

μg/g micrograms/gram

μm micrometer

2012-2017 Five-Year 

Program

Proposed Final Outer Continental Shelf Oil & Gas Leasing Program: 

2012-2017

2D two dimensional

3D three dimensional

4D four dimensional

ac acre

Agreement Agreement between the United States of America and the United

Mexican States Concerning Transboundary Hydrocarbon Reservoirs 

in the Gulf of Mexico

AL Alabama

API American Petroleum Institute

Area ID Area Identification

AQRV air quality-related value

ASLM Assistant Secretary of the Interior for Land and Minerals

bbl barrel

Bbbl billion barrels

Bcf billion cubic feet

BBO billion barrels of oil

BOEM Bureau of Ocean Energy Management

BOEMRE Bureau of Ocean Energy Management, Regulation and Enforcement

BOP blowout preventer

BP Before Present

BSEE Bureau of Safety and Environmental Enforcement

BTEX benzene, toluene, ethylbenzene, and xylene

Call Call for Information

CAMx Comprehensive Air-quality Model with extensions

Cd cadmium

CD Consistency Determination

CEI Coastal Environments, Inc.

CEQ Council on Environmental Quality

CEWAF chemically enhanced (dispersed) water-accommodated fractions

CFR Code of Federal Regulations

CG Coast Guard (also: USCG)

CH4 methane

CIAP Coastal Impact Assistance Program

CMP Coastal Management Program

CO carbon monoxide
lxviii Gulf of Mexico Multisale EIS

CO2 carbon dioxide

CO2-e CO2-equivalent

COE Corps of Engineers (U.S. Army)

CPA Central Planning Area

CPRA Coastal Protection and Restoration Authority

Cu copper

CSA Continental Shelf Associates

CYP1A cytochrome P-4501A

CWPPRA Coastal Wetlands Planning, Protection and Restoration Act

CZMA Coastal Zone Management Act

dB decibel

dB re: 1μPa decibels referenced 1 microPascal

DOI Department of the Interior (U.S.) (also: USDOI)

DOT Department of Transportation (U.S.) (also: USDOT)

DMR discharge monitoring report

DPP development and production plan

Draft Proposed Program 2017-2022 OCS Oil and Gas Leasing: Draft Proposed Program

EFH essential fish habitat

e.g. for example

EIA Economic Impact Area

EIS environmental impact statement

EPA Eastern Planning Area

EPAct Energy Policy Act of 2005

ERMA Environmental Response Management Application

ESA Endangered Species Act of 1973

ESI Environmental Sensitivity Index

et al. and others

et seq. and the following

FERC Federal Energy Regulatory Commission

Five-Year Program 2017-2022 Outer Continental Shelf Oil and Gas Leasing: 

Proposed Final Program (also: 2017-2022 Five-Year Program)

Five-Year Program EIS Outer Continental Shelf Oil and Gas Leasing Program: 2017-2022, 

Final Programmatic Environmental Impact Statement

FL Florida

FGBNMS Flower Garden Banks National Marine Sanctuary

FPSO floating production, storage, and offloading system

FR Federal Register

ft feet

FWS Fish and Wildlife Service

G&G geological and geophysical

g gram

GAP General Activities Plan

GIS Geographic Information System

GIWW Gulf Intracoastal Waterway
Abbreviations and Acronyms lxix

GMFMC Gulf of Mexico Fishery Management Council

GOM Gulf of Mexico

GPS global positioning system

GUIS Gulf Islands National Seashore

GWEI Gulfwide Emissions Inventory

H2S hydrogen sulfide

ha hectare

HAPC habitat area of particular concern

Hg mercury

HRG high-resolution geophysical

Hz Hertz

i.e. that is

km kilometer

IPCC Intergovernmental Panel on Climate Change

ITL Information to Lessees and Operators

LA Louisiana

lb pound

LCA Louisiana Coastal Area

LNG liquefied natural gas

LOOP Louisiana Offshore Oil Port

m meter

MAG-PLAN MMS Alaska-GOM Model Using IMPLAN

MARAD Maritime Administration (U.S. Department of Transportation)

MATS Modeled Attainment Test Software

Mcf thousand cubic feet

MCV modular capture vessel

mg/L milligrams/liter

mi mile

mm millimeter

MMbbl million barrels

MMcf million cubic feet

MMPA Marine Mammal Protection Act

MMS Minerals Management Service

MODU mobile offshore drilling unit

MOU Memorandum of Understanding

MS Mississippi

MSCVAFF Mississippi Coalition for Vietnamese-American Fisher Folks and 

Families

MWCC Marine Well Containment Company

N2O nitrous oxide

NAAQS National Ambient Air Quality Standards

NASA National Aeronautics and Space Administration

NAZ narrow azimuth

NCP National Oil and Hazardous Substances Pollution Contingency Plan 
lxx Gulf of Mexico Multisale EIS

NEPA National Environmental Policy Act

NGL natural gas liquids

NHPA National Historic Preservation Act

NMFS National Marine Fisheries Service

nmi nautical-mile

NO2 nitrogen dioxide

NOx nitrogen oxides

NOA Notice of Availability

NOAA National Oceanic and Atmospheric Administration

NOI Notice of Intent to Prepare an EIS

NOS National Ocean Service

NPDES National Pollutant Discharge Elimination System

NPS National Park Service

NRC National Research Council

NRDA Natural Resource Damage Assessment

NTL Notice to Lessees and Operators

O3 ozone

OBF oil-based fluid

OCD Offshore and Coastal Dispersion

OCS Outer Continental Shelf

OCSLA Outer Continental Shelf Lands Act

ODMDS ocean dredged-material disposal site

ONRR Office of Natural Resources Revenue

OSAT Operational Science Advisory Team

OSHA Occupational Safety and Health Administration

OSRA Oil Spill Risk Analysis

OSRP oil-spill response plan

OSV offshore supply/service vessel

P.L. Public Law

PAH polycyclic aromatic hydrocarbons

Pb lead

PBR Potential Biological Removal

PDARP/PEIS Programmatic Damage Assessment and Restoration Plan 

and Final Programmatic Environmental Impact Statement

pH potential of hydrogen

PM particulate matter

PM2.5 particulate matter less than or equal to 2.5 μm

PM10 particulate matter less than or equal to 10 μm

ppb parts per billion

ppm parts per million

PSD Prevention of Significant Deterioration

psi pounds per square inch

RESTORE Act Resources and Ecosystems Sustainability, Tourist Opportunities, and 

Revived Economies of the Gulf Coast States Act
Abbreviations and Acronyms lxxi

ROD Record of Decision

RSDFO Regional Supervisor for District Field Operations

SAP Site Assessment Plan

SBF synthetic-based fluid

SBM synthetic-based mud

Secretary Secretary of the Interior

SEL sound exposure level

SMART Special Monitoring of Applied Response Technologies

SO2 sulphur dioxide

SOx sulphur oxides

Stat. Statute

SURF subsea umbilical, risers, and flowlines

sVGP Small Vessel General Permit

Tcf trillion cubic feet

TLP tension-leg platform

Trustee Council Natural Resource Damage Assessment Trustee Council

TX Texas

U.S. United States

U.S.C. United States Code

UME unusual mortality event

UNCLOS United Nations Convention on the Law of the Sea

USCG U.S. Coast Guard (also: CG)

USDHS U.S. Department of Homeland Security

USDOC U.S. Department of Commerce

USDOE U.S. Department of Energy

USDOI U.S. Department of the Interior (also: DOI)

USDOT U.S. Department of Transportation (also: DOT)

USEPA U.S. Environmental Protection Agency

USGS U.S. Geological Survey

VGP Vessel General Permit

VOC volatile organic compound

VSP vertical seismic profiling

W. west

WAF water-accommodated fraction

WAZ wide azimuth

WBF water-based fluid

WRF Weather and Research Forecasting

WPA Western Planning Area

WTCW well treatment fluids, completion fluids, and workover

yd yard

Zn zinc

Conversion Chart lxxiii

CONVERSION CHART

To convert from To Multiply by

centimeter (cm) inch (in) 0.3937

millimeter (mm) inch (in) 0.03937

meter (m) foot (ft) 3.281

meter2 (m2) foot2 (ft2) 10.76

meter2 (m2) yard2 (yd2) 1.196

meter2 (m2) acre (ac) 0.0002471

meter3 (m3) foot3 (ft3) 35.31

meter3 (m3) yard3 (yd3) 1.308

kilometer (km) mile (mi) 0.6214

kilometer2 (km2) mile2 (mi2) 0.3861

hectare (ha) acre (ac) 2.47

liter (L) gallons (gal) 0.2642

degree Celsius (°C) degree Fahrenheit (°F) °F = (1.8 x °C) + 32

1 barrel (bbl) = 42 gal = 158.9 L = approximately 0.1428 metric tons

1 nautical mile (nmi) = 1.15 mi (1.85 km) or 6,076 ft (1,852 m)

tonnes = 1 long ton or 2,240 pounds (lb)

CHAPTER 1 

THE PROPOSED ACTIONS

The Proposed Actions 1-3

What’s in This Chapter?

• The Bureau of Ocean Energy Management (BOEM) has issued the 2017-2022 Outer 

Continental Shelf Oil and Gas Leasing: Proposed Final Program (Five-Year Program). It 

sets forth a schedule for 10 proposed regionwide Gulf of Mexico (GOM) lease sales

spaced evenly throughout the 5-year period.

• The purpose of a proposed action (i.e., a proposed lease sale) in this 2017-2022 Gulf of 

Mexico Multisale Environmental Impact Statement (Multisale EIS) is to offer for lease those 

areas in the GOM that may contain economically recoverable oil and gas resources in 

accordance with the Outer Continental Shelf Lands Act of 1953 (OCSLA), subject to 

environmental safeguards. 

• The need for a proposed action is to manage the development of Outer Continental Shelf 

(OCS) energy resources in an environmentally and economically responsible manner. Oil 

from the Gulf of Mexico OCS would contribute to meeting domestic demand and enhance 

national economic security.

• Pursuant to the OCSLA’s staged leasing process, for each lease sale proposed in the 

Five-Year Program, individual decisions are made on whether and how to proceed with 

each proposed lease sale. Therefore, this Multisale EIS is a programmatic EIS that will 

provide the environmental review foundation for all 10 proposed GOM lease sales in the 

Five-Year Program schedule.

• Following an established, robust decisionmaking process that invites input from numerous 

interested parties and the general public, BOEM produced this Multisale EIS to inform 

decisionmaking for the first proposed lease sale (i.e., Lease Sale 249) and for 

supplemental National Environmental Policy Act (NEPA) reviews for the subsequent

proposed GOM lease sales in the Five-Year Program.

• This Multisale EIS explains the environmental considerations used to assess the potential 

environmental consequences of the proposed actions and alternatives, as well as the

potential mitigations that could minimize or avoid those consequences. 

1 PURPOSE OF AND NEED FOR 

THE PROPOSED ACTIONS 

1.0 INTRODUCTION

The Bureau of Ocean Energy Management 

(BOEM) has issued the 2017-2022 Outer Continental 

Shelf Oil and Gas Leasing: Proposed Final Program

(Five-Year Program; USDOI, BOEM, 2016a). The 

Five-Year Program schedules 10 regionwide Gulf of 

Mexico (GOM) oil and gas lease sales. Five regionwide lease sales are tentatively scheduled in 

August of each year from 2017 through 2021 and five regionwide lease sales are tentatively 

scheduled in March of each year from 2018 through 2022. The lease sales proposed in the GOM in 

the Five-Year Program are regionwide lease sales comprised of the Western, Central, and a small 

portion of the Eastern Planning Areas (WPA, CPA, and EPA, respectively) not subject to 

Congressional moratorium. These planning areas are located off the States of Texas, Louisiana, 

Mississippi, Alabama, and Florida (Figure 1-1).

2017-2022 Schedule of Proposed

Gulf of Mexico OCS Region 

Lease Sales

Lease Sale Number Year

249 2017

250 and 251 2018

252 and 253 2019

254 and 256 2020

257 and 259 2021

261 2022
1-4 Gulf of Mexico Multisale EIS

The proposed action is to hold a lease sale in the 

GOM according to the schedule of proposed 

lease sales set forth by the Five-Year Program. 

Since each of the 10 proposed lease sales in the 

GOM are very similar and occur in close 

timeframes, BOEM has decided to prepare this 

programmatic EIS to support the individual 

decisions for each proposed lease sale. 

Pursuant to the OCSLA’s staged leasing process, 

BOEM must make an individual decision on 

whether and how to proceed with each proposed 

lease sale. Therefore, in order to make an 

informed decision on a single proposed lease 

sale, the analyses contained in this Multisale EIS 

examine the impacts from a single proposed 

lease sale. This analysis will be used to support 

each of the 10 proposed lease sale decisions.

Figure 1-1. Proposed Regionwide Lease Sale Area Combining the Western, Central, and Eastern 

Planning Areas.

The development of the Five-Year 

Program triggers region-specific NEPA

reviews for each of the proposed lease sales. 

Region-specific reviews are conducted by 

Program Area (i.e., the Gulf of Mexico and

Alaska OCS Regions) prior to individual

lease sale decisions for those areas that are 

included in the Five-Year Program. Even 

though the Five-Year Program includes 

regionwide lease sales, any individual lease 

sale could still be scaled back during the 

prelease sale process, including, for 

example, to employ the separate planning 

area model used in the Proposed Final Outer 

Continental Shelf Oil & Gas Leasing 

Program: 2012-2017 (2012-2017 Five-Year 

Program; USDOI, BOEM, 2012a), should 

circumstances warrant.

The Secretary of the Interior (Secretary) has designated BOEM as the administrative agency 

responsible for the leasing of submerged Outer Continental Shelf (OCS) lands for oil and gas 

production and for the supervision of certain offshore operations after lease issuance. BOEM is 

responsible for managing development of the Nation’s offshore resources in an environmentally and 

economically responsible way. The functions of BOEM include the following: OCS oil and gas
The Proposed Actions 1-5

“It is hereby declared to be the policy 

of the United States that ... the Outer 

Continental Shelf is a vital national 

resource held by the Federal 

Government for the public, which 

should be made available for 

expeditious and orderly development, 

subject to environmental safeguards, 

in a manner which is consistent with 

the maintenance of competition and 

other national needs."

OCSLA, 43 U.S.C. §§ 1331 et seq.

leasing; oversight of exploration and development; plan administration; environmental studies; 

resource evaluation and economic analyses; the use of OCS sand, gravel, and shell resources; and 

the OCS renewable energy program. The Bureau of Safety and Environmental Enforcement (BSEE) 

is responsible for enforcing safety and environmental regulations related to energy activities on the 

OCS. The functions of BSEE include oversight of all field operations, such as permitting for drilling 

and decommissioning, research, inspections, offshore regulatory programs, oil-spill response, and 

training and environmental compliance functions.

1.1 PURPOSE OF THE PROPOSED ACTIONS

The Outer Continental Shelf Lands Act of 1953, 

as amended (43 U.S.C. §§ 1331 et seq.), hereafter 

referred to as OCSLA, establishes the Nation’s policy for 

managing the vital energy and mineral resources of the 

OCS. Section 18 of OCSLA requires the Secretary to 

prepare and maintain a schedule of proposed OCS oil 

and gas lease sales determined to “best meet national 

energy needs for the 5-year period following its approval 

or reapproval” (43 U.S.C. § 1344). The Five-Year

Program establishes a schedule that the U.S. Department 

of the Interior (USDOI or DOI) will use as a basis for 

considering where and when leasing might be appropriate 

over a 5-year period.

The purpose of the proposed Federal actions in this Multisale EIS (i.e., each of the 

10 proposed lease sales) is to offer for lease those areas that may contain economically recoverable 

oil and gas resources in accordance with OCSLA, which specifically states that these areas “should 

be made available for expeditious and orderly development, subject to environmental safeguards” 

(OCSLA, 43 U.S.C. §§ 1331 et seq.). Each individual proposed lease sale would provide qualified 

bidders the opportunity to bid upon and lease acreage in the Gulf of Mexico OCS in order to explore, 

develop, and produce oil and natural gas.

1.2 NEED FOR THE PROPOSED ACTIONS

The need for the proposed actions (i.e., each of the 10 proposed lease sales) is to manage 

the development of the OCS energy resources in an environmentally and economically responsible 

manner. Oil serves as the feedstock for liquid hydrocarbon products, including gasoline, aviation 

and diesel fuel, and various petrochemicals. Oil from the Gulf of Mexico OCS contributes to meeting 

domestic demand and enhances national economic security. 

In 2015, the United States (U.S.) consumed 7.08 billion barrels of petroleum products, an 

average of about 19.4 million barrels per day (USDOE, Energy Information Administration, 2016a) 

and 27.47 trillion cubic feet (Tcf) of natural gas per day (USDOE, Energy Information Administration, 

2016b). Over the next 20 years, the Energy Information Administration expects the U.S. to rely on 
1-6 Gulf of Mexico Multisale EIS

more oil and natural gas to meet its energy demands, even as alternative sources of energy provide 

an increasing share of U.S. energy needs. The Energy Information Administration projects that 

consumption of liquid fuels will decrease slightly through 2040, but consumption of natural gas would 

increase by a greater amount over the same period (Figure 1-2). For the purposes of this Multisale 

EIS, it is assumed that both future energy demand and supply would mirror historical trends and, at 

this time, it does not consider any possible climate change policy interventions, which could 

potentially implicate demand or supply, price, or modes of domestic or global energy substitution.

Figure 1-2. Energy Use in the United States (Sources: USDOE, Energy Information Administration, 

2016c and 2016d).

Since the U.S. is expected to continue to rely on oil and natural gas to meet its energy 

needs, the proposed actions would contribute to meeting domestic demand and reduce the need for 

imports of these resources (USDOI, BOEM, 2016a). The Gulf of Mexico OCS region has the 

greatest resource potential for being a major long-term supplier of crude oil and natural gas of the 

four OCS regions in the United States. In 2015, the Gulf of Mexico OCS as a whole was responsible 

for 16 percent of domestic oil production and 5 percent of domestic natural gas production. Crude 

oil recovered from the OCS is of high importance to U.S refineries, especially along the Gulf Coast. 

The GOM production is expected to account for 18 percent and 21 percent of total forecast U.S. 

crude oil production in 2016 and 2017, respectively. For more details on national energy markets, 

refer to Chapter 1.2 of the Five Year Program) (USDOI, BOEM, 2016a).
The Proposed Actions 1-7

1.3 OCS OIL AND GAS PROGRAM PLANNING AND DECISION PROCESS

BOEM produces NEPA documents for each of the major stages of energy development 

planning. From the overarching Outer Continental Shelf Oil and Gas Leasing Program: 2017-2022; 

Final Programmatic Environmental Impact Statement (Five-Year Program EIS) (USDOI, BOEM, 

2016b), through each of the NEPA documents for the individual decisions on oil and gas lease sales, 

and followed by more site-specific reviews for the approval of exploration, development and 

production, and decommissioning plans (Figure 1-3). 

Figure 1-3. OCS Oil and Gas Program Development Process. 

1.3.1 Prelease Process

BOEM has a two-stage Federal offshore prelease sale planning process: 

(1) develop a Five-Year Program of proposed offshore lease sales for the OCS 

Program; and

(2) conduct an individual lease sale consultation and decision process for each 

lease sale scheduled in the approved Five-Year Program.
1-8 Gulf of Mexico Multisale EIS

Due to the staged decisionmaking process in OCSLA, BOEM does a staged or tiered 

process in which NEPA documents are prepared that cover potential impacts associated with the 

various stages of the OCSLA process. This includes analyses at the Five-Year Program stage, 

proposed lease sale stage, exploration or development and production plan stage, and various 

permitting stages, including, but not limited to, drilling and decommissioning. At the lease sale 

stage, this is typically done through an EIS, which analyzes the potential impacts of postlease 

activities. However, at the lease issuance stage, no activities beyond certain ancillary activities are 

actually authorized by the lease; therefore, there are few environmental impacts reasonably 

expected from the lease sale itself. The U.S. Court of Appeals for the District of Columbia has ruled 

that the obligation to fully comply with NEPA does not mature until leases are issued (Center for 

Biological Diversity v. U.S. Department of the Interior, 2009; Center for Sustainable Economy v. 

Sally Jewell, 2015). BOEM has chosen at its discretion to prepare an EIS at this stage to analyze 

the potential environmental impacts that could result if exploration, development, production, and 

decommissioning activities eventually occur, in order to provide the context and setting of future 

proposed actions and to better understand the potential impacts associated with these types of 

activities as well as the cumulative impacts on GOM resources. This allows more time to include 

public involvement and to evaluate the potential impacts, and it provides for a more informed lease 

sale decision, which in turn allows for future site-specific reviews to tier to and be more streamlined.

1.3.1.1 Five-Year Program of Proposed OCS Lease Sales

As required by the OCSLA, a new oil and gas leasing program—to cover the years 

2017-2022—has been developed. There are multiple stages to developing the Five-Year Program. 

Following issuing a request for information, the 2017-2022 Outer Continental Shelf Oil and Gas 

Leasing: Draft Proposed Program (Draft Proposed Program) (USDOI, BOEM, 2015a) was the first 

proposal in the staged preparation process of the new Five-Year Program, which is a nationwide

schedule of proposed lease sales. The Draft Proposed Program proposed a schedule of 

14 potential lease sales in eight OCS planning areas: 10 lease sales in the three GOM planning 

areas; 1 lease sale each in the Chukchi Sea, Beaufort Sea, and Cook Inlet Planning Areas, offshore 

Alaska; and 1 lease sale in a portion of the combined Mid-Atlantic and South Atlantic Planning 

Areas. BOEM received hundreds of thousands of comments in response to the publication of the 

Draft Proposed Program and analyzed the comments as appropriate for the second proposal in the 

staged preparation process—the Proposed Program.

The Proposed Program, which was released for public comment in March 2016 (USDOI, 

BOEM, 2016c), removed the proposed Atlantic planning areas from further consideration for the 

5-year period and proposed a schedule of 13 lease sales in seven OCS Planning areas: 10 lease 

sales in the three GOM planning areas; and 1 lease sale each in the Chukchi Sea, Beaufort Sea, 

and Cook Inlet Planning Areas, offshore Alaska.

On November 18, 2016, the final proposal, the Proposed Final Program (also known as the

Five-Year Program), was published, which removed the proposed lease sales in the Chukchi Sea 

and Beaufort Sea from further consideration for the 5-year period (USDOI, BOEM, 2016a). The 
The Proposed Actions 1-9

Proposed Final Program schedules 11 proposed lease sales in two program areas in all or parts of 

four OCS planning areas: 10 proposed lease sales in the regionwide Gulf of Mexico (GOM) 

Program Area; and 1 proposed lease sale in the Cook Inlet Program Area offshore Alaska. No lease 

sales are scheduled for the Pacific or Atlantic OCS.

In accordance with Section 18(c)(2) of the OCSLA, the Secretary will not approve the 

Proposed Final Program until at least 60 days after sending it to the President and Congress. On 

January 17, 2017, the Secretary’s decision was described in the Record of Decision and a signed 

program decision memorandum was made publicly available (USDOI, 2017). 

The Five-Year Program EIS (USDOI, BOEM, 2016b) analyzed as its proposed action in the 

Draft Five-Year Program EIS the schedule of leases put forward in the Draft Proposed Program. 

The Final Five-Year Program EIS includes an analysis of the potential environmental impacts of the 

lease sale schedule put forward in the Proposed Program, including the 10 proposed GOM lease 

sales. It also analyzes reasonable alternatives to the proposed lease sale schedule and the 

mitigating measures that may reduce or eliminate any potential impacts. On January, 29, 2015, 

BOEM released a Notice of Intent (NOI) to prepare the Five-Year Program EIS in conjunction with 

the release of the Draft Proposed Program (Federal Register, 2015b). As a part of the NOI, BOEM 

solicited public input on the scope of the environmental analysis and on the alternatives and 

mitigating measures to be analyzed. BOEM received thousands of comments and analyzed and 

incorporated these as appropriate into the Five-Year Program EIS. The Draft Five-Year Program

EIS was released for public comment in March 2016 (Figure 1-4). The Final Five-Year Program EIS 

was made available on November 18, 2016, and the Record of Decision was made available on 

January 18, 2017.

Figure 1-4. Planning for the Five-Year Program. 
1-10 Gulf of Mexico Multisale EIS

This Multisale EIS tiers from the

Five-Year Program EIS. In January 

2017, the Secretary selected 

Alternative A, which includes a 

schedule for 10 proposed 

regionwide lease sales in the GOM.

The analyses contained in this 

Multisale EIS examines the 

impacts of a single proposed lease 

sale, which would apply to any of 

the 10 proposed GOM lease sales.

1.3.1.2 Individual Lease Sale Consultation and Decision Process

As noted earlier, the development of the Five-Year 

Program also triggers region-specific NEPA reviews for 

the individual proposed lease sales (refer to Figure 1-5). 

Region-specific reviews are conducted by Program Area

(i.e., the Gulf of Mexico and Alaska OCS Regions) prior to 

lease sale decisions for those areas that are included in

the Program. No lease sales have been scheduled for the 

Pacific or Atlantic OCS Regions in the Five-Year Program. 

Figure 1-5. Typical Planning Timeline for Regional OCS Oil and Gas Lease Sales. 

Pursuant to the OCSLA staged leasing process, for each lease sale proposed in the 

Five-Year Program, BOEM makes individual decisions on whether and how to proceed with a 

proposed lease sale. Federal regulations allow for several related or similar proposals to be 

analyzed in one EIS (40 CFR § 1502.4). Since each proposed lease sale and the projected 

activities related to such a lease sale are very similar and would occur in close timeframes, BOEM 

has decided to prepare a single programmatic EIS to support the 10 proposed GOM lease sales 

scheduled in the Five-Year Program. However, as previously noted, OCSLA requires individual 

decisions to be made for each lease sale. Therefore, in order to make an informed decision on a 

single proposed lease sale, the analyses contained in this 

Multisale EIS examine impacts from a single proposed 

lease sale. A lease sale scenario, described in Chapter 3, 

includes all of the activities that could occur over a 50-year 

analysis period. The findings of these analyses can be 

applied individually to each of the subsequent proposed 

lease sales.
The Proposed Actions 1-11

BOEM plans to supplement this Multisale EIS on a regular basis to provide for more 

consistency and for planning purposes. Unless circumstances or information warrants an earlier 

Supplemental EIS, BOEM expects to issue a Supplemental EIS once a calendar year. An additional 

NEPA review (e.g., a Determination of NEPA Adequacy, an environmental assessment [EA] or, if 

determined necessary, a Supplemental EIS) will be conducted prior to the decision on an individual

proposed GOM lease sale to address any relevant new information. Each subsequent supplemental 

review tiers from the previous NEPA documents in this series of reviews as illustrated in Figure 1-6. 

Informal and formal consultation with other Federal agencies, federally recognized Indian Tribes, the 

affected States, and stakeholders would also be carried out as appropriate. This Multisale EIS 

would also assist decisionmakers in making informed, future decisions regarding the approval of 

operations, as well as the individual proposed lease sale decisions. 

Also, as described in the Five-Year Program, any individual lease sale could be scaled back 

during the prelease sale process to offer a smaller area should circumstances warrant. For 

example, an individual lease sale could offer an area that conforms more closely to the separate 

planning area model used in the 2012-2017 Five-Year Program. Therefore, the analyses in this 

Multisale EIS also include alternatives similar to past WPA, CPA, and EPA lease sale environmental 

reviews.

This Multisale EIS is the NEPA document prepared for proposed Lease Sale 249. 

Subsequently, BOEM plans to prepare supplemental EISs on a calendar year basis as illustrated in 

Figure 1-6. Respective NEPA documents will be completed before decisions are made on the 

subsequent lease sales. This Multisale EIS approach allows for subsequent NEPA analyses to 

focus on the potential changes in each of the proposed lease sales and on any new issues and 

information that may have become available since the publication of the previous NEPA document.
1-12 Gulf of Mexico Multisale EIS

Figure 1-6. Supplemental Approach Showing the Tiering Relationships for Proposed Gulf of 

Mexico Lease Sales.

1.3.2 Gulf of Mexico Postlease Activities

BOEM and BSEE are responsible for managing, regulating, and monitoring oil and natural 

gas exploration, development, and production operations on the Federal OCS to promote the orderly 

development of mineral resources in a safe and environmentally sound manner. BOEM’s 

regulations for oil, gas, and sulphur lease operations are specified in 30 CFR parts 550, 551, 554, 

and 556. The BSEE regulations for oil, gas, and sulphur operations are specified in 30 CFR parts 

250 and 254. Refer to Appendix A for descriptions of postlease activities, including the following: 

geological and geophysical (G&G) surveys; exploration and development plans; permits and 

applications; inspection and enforcement; pollution prevention, oil-spill response plans, and financial 

responsibility; air emissions; flaring and venting; hydrogen sulfide contingency plans; archaeological 

resources regulation; coastal zone management consistency review and appeals for postlease 

activities; best available and safest technologies, including at production facilities; personnel training 

and education; structure removal and site clearance; marine protected species Notices to Lessees 

and Operators (NTLs); and the Rigs-to-Reefs program.

All plans for OCS oil- and gas-related activities (e.g., exploration and development plans) go 

through rigorous BOEM review and approval to ensure compliance with established laws and 

regulations before any project-specific activities can begin on a lease. Mitigating measures are

incorporated and documented in plans submitted to BOEM. These measures may be implemented 

through, among other things, lease stipulations and project-specific requirements or conditions of 
The Proposed Actions 1-13

approval. Conditions of approval are based on BOEM’s and BSEE’s technical and environmental 

evaluations of the proposed operations. Conditions may be applied to any OCS plan, permit, 

right-of-use and easement, or pipeline right-of-way grant.

Mitigating measures address concerns such as endangered and threatened species, 

geologic and manmade hazards, military warning and ordnance disposal areas, archaeological sites, 

air quality, oil-spill response planning, chemosynthetic communities, artificial reefs, operations in 

hydrogen sulfide (H2S)-prone areas, and shunting of drill effluents in the vicinity of biologically 

sensitive features. Refer to Appendix B (“Commonly Applied Mitigating Measures”) for more 

information on the mitigations that BOEM and BSEE often apply to permits and approvals. 

Operational compliance of the mitigating measures is enforced through BSEE’s onsite inspection 

program.

BOEM and BSEE issue NTLs to provide clarification, description, or interpretation of a 

regulation; guidelines on the implementation of a special lease stipulation or regional requirement; or 

administrative information. A detailed listing of the current Gulf of Mexico OCS Region’s NTLs is 

available through BOEM’s Gulf of Mexico OCS Region’s website at http://boem.gov/Regulations/

Notices-Letters-and-Information-to-Lessees-and-Operators.aspx or through the Region’s Public 

Information Office at 504-736-2519 or 1-800-200-GULF. A detailed listing of BSEE’s Gulf of Mexico 

OCS Region’s current NTLs is available through BSEE’s Gulf of Mexico OCS Region’s website at 

https://www.bsee.gov/guidance-and-regulations/guidance/notice-to-lessees. 

1.4 THE DECISION TO BE MADE

A decision will be made on whether and how to proceed with each proposed lease sale in 

the Five-Year Program. After completion of this Multisale EIS, a decision will be made on proposed 

Lease Sale 249 (i.e., prepare a Record of Decision for Lease Sale 249 only). As discussed in 

Chapter 1.3.1, individual decisions will be made on each subsequent lease sale after completion of 

the appropriate NEPA documents.

1.5 REGULATORY FRAMEWORK

Federal laws mandate the OCS leasing program (i.e., OCSLA) and the environmental review 

process (e.g., NEPA). These regulations are intended to encourage orderly, safe, and 

environmentally responsible development of oil, natural gas, alternative energy sources, and other 

mineral resources on the OCS. BOEM consults with numerous federally recognized Indian Tribes 

and Federal and State departments and agencies that have authority to govern and maintain ocean 

resources pursuant to other Federal laws. As illustrated in Figure 1-7, BOEM’s consultation 

partners for specific Federal regulations, several Federal regulations establish specific consultation 

and coordination processes with federally recognized Indian Tribes and Federal, State, and local 

agencies. 
1-14 Gulf of Mexico Multisale EIS

e

Figure 1-7. BOEM’s Consultation Partners for Specific Federal Statutes and Regulations.

Among these Federal entities are the U.S. Environmental Protection Agency (USEPA), U.S. 

Fish and Wildlife Service (FWS), and the National Oceanic and Atmospheric Administration (NOAA) 

through the National Marine Fisheries Service (NMFS). In addition to coordinating with Federal 

Government entities, BOEM coordinates and consults with any State governor or local government 

executives that may be affected by a particular lease, easement, or right-of-way. Each state, with 

the exception of Alaska, has developed and implemented a federally approved coastal management 

program pursuant to the Coastal Zone Management Act (16 U.S.C. §§ 1451 et seq.). The 

boundaries of each State’s coastal zone are available at https://coast.noaa.gov/czm/media/

StateCZBoundaries.pdf. A detailed description of major Federal laws and Executive Orders that are 

relevant to the OCS leasing process is provided in the OCS Regulatory Framework white paper, 

which can be found on BOEM’s website (Cameron and Matthews, 2016). Chapter 3 of BOEM’s 

OCS Regulatory Framework white paper identifies 43 major Federal laws and Executive Orders that 

are relevant to the OCS leasing process (Cameron and Matthews, 2016). During the planning 

process, federally recognized Indian Tribes are informed of the potential activities on the OCS and 

are asked if they are interested in entering into a meaningful consultation with BOEM’s leadership to 

discuss the activities. 
The Proposed Actions 1-15

1.6 OTHER OCS OIL- AND GAS-RELATED ACTIVITIES

BOEM and BSEE have programs and activities that are OCS-related but not specific to the 

oil and gas leasing process or to the management of exploration, development, and production 

activities. These programs include environmental and technical studies, cooperative agreements 

with other Federal and State agencies for NEPA work, joint jurisdiction over cooperative efforts, 

inspection activities, and regulatory enforcement. BOEM also participates in industry research 

efforts and forums. The information collected through these efforts is used in support of the BOEM

NEPA documents that inform Agency decisions.

Environmental Studies Program

BOEM promotes energy independence, environmental protection, and economic 

development through responsible management of OCS resources based on the best available 

science. To support this work and inform bureau policy decisions, BOEM’s Environmental Studies 

Program develops, conducts, and oversees world-class scientific research specifically to inform 

policy decisions regarding development of OCS energy and mineral resources.

Through the Environmental Studies Program, BOEM is a leading contributor to the growing 

body of scientific knowledge about the marine and coastal environment. The Environmental Studies 

Program obtains information needed for NEPA assessment and the management of environmental 

and socioeconomic impacts on the human, marine, and coastal environments that may be affected 

by OCS oil and gas development. Research covers a broad range of disciplines, including physical 

oceanography, atmospheric sciences, biology, protected species, social sciences, economics, 

submerged cultural resources, and the environmental impacts of energy development. BOEM (and 

its predecessors) has funded more than $1 billion in research since the studies program was 

established in 1973 in accordance with Section 20 of the OCSLA. Technical summaries of more 

than 1,200 BOEM-sponsored environmental research projects and more than 3,400 research reports 

are publicly available online through the Environmental Studies Program Information System 

(ESPIS). For the latest information on BOEM’s ongoing environmental studies work, go to

http://www.boem.gov/studies. In the Gulf of Mexico OCS Region, over 350 studies for approximately 

$250 million have been completed and more than 900 reports and scientific papers have been 

produced. A complete list of all ongoing Gulf of Mexico OCS Region studies is available on the 

BOEM website. Each listing not only describes the research being conducted but also shows the 

institution performing the work, the cost of the effort, timeframe, and any associated publications, 

presentations, or affiliated websites.

BOEM incorporates findings from the studies program into its environmental reviews and 

NEPA documents, which are used to avoid, mitigate, or monitor the impact of energy and mineral 

resource development on the OCS. The BOEM’s Gulf of Mexico OCS Region analysts use the ESP 

studies to prepare this document. While not all of the Gulf of Mexico OCS Region’s studies are 

specifically referenced in this Multisale EIS, analysts used those that are relevant. Decisionmakers 

also use the information in ESP studies in managing and regulating exploration, development, and 
1-16 Gulf of Mexico Multisale EIS

production activities on the OCS. This integrated approach of incorporating applied science to 

inform decisionmakers is illustrated in Figure 1-8. 

Figure 1-8. BOEM’s Integrated Approach for Incorporating Applied 

Science into Decisionmaking.

Technology Assessment Program

The BSEE’s Technology Assessment Program supports research associated with 

operational safety and pollution prevention. The Technology Assessment Program is comprised of 

two functional research activities: (1) operational safety and engineering research (topics such as 

air quality, decommissioning, and mooring and anchoring); and (2) other research (topics such as 

renewable energy and alternate use; Hurricanes Andrew, Ivan, Katrina, Rita, and Lili; and 

international activities). The Technology Assessment Program has four primary objectives:

• Technical Support—Providing engineering support in evaluating industry 

operational proposals and related technical issues and in ensuring that these 

proposals comply with applicable regulations, rules, and operational guidelines 

and standards.
The Proposed Actions 1-17

• Technology Assessment—Investigating and assessing industry applications of 

technological innovations and promoting the use of the best available and safest 

technologies in Bureau regulations, rules, and operational guidelines. 

• Research Catalyst—Promoting leadership in the fields of operational safety and 

pollution prevention in offshore energy extraction activities. 

• International Regulations—Providing international cooperation for research and 

development initiatives to enhance the safety of offshore energy extraction 

activities and the development of appropriate regulatory program elements 

worldwide. 

Oil-Spill Response Research

For more than 25 years, BSEE (and its predecessors) have aggressively maintained a 

comprehensive, long-term research program dedicated to improving oil-spill response options. The 

major focus of the program is to improve the methods and technologies used for oil-spill detection, 

containment, treatment, recovery, and cleanup. The Oil-Spill Response Research Program is a 

cooperative effort bringing together funding and expertise from research partners in government 

agencies, industry, and the international community.

The Program also manages Ohmsett, the National Oil Spill Response Research Test 

Facility, located in Leonardo, New Jersey. Ohmsett is the largest outdoor saltwater wave/tow tank 

facility in North America. Ohmsett allows full-scale, oil-spill response testing, training, and research 

with oil in a realistic marine environment.

Interagency Agreements

Memoranda of Understanding under NEPA

The Council on Environmental Quality’s (CEQ) implementing regulations (40 CFR § 

1500.5(b)) encourages agency cooperation early in the NEPA process. A Federal agency can be a 

lead, joint lead, or cooperating agency. A lead agency manages the NEPA process and is 

responsible for the preparation of an EIS; a joint lead agency shares these responsibilities; and a 

cooperating agency that has jurisdiction by law and has special expertise with respect to any 

environmental issue shall participate in the NEPA process upon the request of the lead agency.

When an agency becomes a cooperating agency, the cooperating and lead agencies usually 

enter into a Memorandum of Understanding (MOU), previously called a Cooperating Agency 

Agreement. The MOU details the responsibilities of each participating agency. BOEM, as lead 

agency, has previously requested other Federal agencies to become cooperating agencies while 

other agencies have requested BOEM to become a cooperating agency (e.g., the Ocean Express 

Pipeline project). Some projects, such as major gas pipelines across Federal waters and projects 

under the Deepwater Port Act of 1974, can require cooperative efforts by multiple Federal and State 

agencies.
1-18 Gulf of Mexico Multisale EIS

The NOI for this Multisale EIS included an invitation to other Federal agencies and State, 

Tribal, and local governments to consider becoming cooperating agencies in the preparation of this 

EIS. Consultation and coordination activities for this Multisale EIS are described in Chapter 5. In a 

letter dated September 8, 2015, the U.S. Environmental Protection Agency’s (USEPA) Regions 4 

and 6 requested cooperating agency status for the 2017-2022 Multisale EIS. On December 16, 

2015, a Memorandum of Agreement between BOEM’s Gulf of Mexico OCS Region and USEPA 

Regions 4 and 6 was initiated; this Memorandum of Agreement defines the roles and responsibilities 

for each agency (Appendix C).

Memorandum of Understanding and Memoranda of Agreement between BSEE and USCG

Since BSEE and USCG have closely related jurisdiction over different aspects of safety and 

operations on the OCS, the agencies have established a formal MOU that delineates lead 

responsibilities for managing OCS activities in accordance with the OCSLA, as amended, and the 

Oil Pollution Act of 1990. The latest MOU, dated November 27, 2012, supersedes the September 

2004, December 1998, and August 1989 versions of the interagency agreement. The MOU is 

designed to minimize duplication and promote consistent regulation of facilities under the jurisdiction 

of both agencies.

Generally, the MOU identifies BSEE as the lead agency for matters concerning the 

equipment and operations directly involved in the production of oil and gas. These include, among 

others, design and operation of risers, permanent mooring foundations of the facility, drilling and well 

production and services, inspection and testing of all drilling-related equipment, and platform 

decommissioning. Issues regarding certain aspects of safe operation of the facility, its systems, and 

equipment generally fall under the jurisdiction of USCG. These include, among others, design of 

vessels, their sea-keeping characteristics, propulsion and dynamic positioning systems, supply and 

lightering procedures and equipment, utility systems, safety equipment and procedures, and 

pollution prevention and response procedures.

Memorandum of Agreement between BOEM and BSEE – Environmental and NEPA

The BOEM/BSEE Memorandum of Agreement establishes the working relationship between 

BOEM and BSEE for environmental review and enforcement for activities on the OCS. It is intended 

to minimize duplication of efforts, promote consistency in procedures and regulations, and resolve 

disputes. Under this Memorandum of Agreement, BSEE will serve as a cooperating agency on 

BOEM’s NEPA documents and may adopt NEPA analyses prepared by BOEM.

1.7 OTHER PERTINENT ENVIRONMENTAL REVIEWS OR DOCUMENTATION

BOEM is aware of other environmental reviews and studies relevant to the resources under 

consideration in this Multisale EIS. Notices of Intent were published in the Federal Register for the 

following reviews:
The Proposed Actions 1-19

• BOEM’s Gulf of Mexico Geological and Geophysical Activities Programmatic

Draft EIS. BOEM, with the National Oceanic and Atmospheric Administration’s 

NMFS and BSEE as cooperating agencies, prepared a Programmatic EIS to 

evaluate the potential environmental impacts of multiple G&G activities within 

Federal waters of the Gulf of Mexico’s OCS and adjacent State waters. BOEM 

and NMFS intend for that Programmatic EIS to provide the necessary 

documentation and analyses to support informed decisions regarding future 

OCSLA permit and Marine Mammal Protection Act (MMPA) authorization actions 

related to G&G activities on the OCS. In addition, the preparation of this 

Programmatic EIS will help to ensure compliance with other applicable laws and 

statutes such as the Endangered Species Act (ESA), Magnuson-Stevens Fishery 

Conservation and Management Act, Coastal Zone Management Act (CZMA), 

and the National Historic Preservation Act (NHPA). The G&G Programmatic EIS 

establishes a framework for subsequent NEPA analyses for site-specific actions 

while identifying and analyzing appropriate mitigating measures to be used 

during future G&G activities on the OCS in support of the oil and gas, renewable 

energy, and marine mineral resource programs. The impacts of future 

site-specific actions will be addressed in subsequent NEPA evaluations, per the 

Council on Environmental Quality’s regulations (40 CFR § 1502.20), by tiering 

from this programmatic evaluation. Public scoping for the G&G Programmatic 

EIS was held from May 10-July 9, 2013, and the Draft G&G Programmatic EIS 

was available for public review and comment from September 29, 2016 until 

November 28, 2106. BOEM anticipates the release of the Final G&G 

Programmatic EIS in August 2017.

• NOAA’s Flower Garden Banks National Marine Sanctuary Expansion EIS. In 

February 2015, NOAA's Office of National Marine Sanctuaries announced its 

intent to prepare a Draft EIS to consider possible expansion of the Flower 

Garden Banks National Marine Sanctuary. When the Flower Garden Banks 

National Marine Sanctuary was designated in 1992, the boundaries were 

established based on best available information regarding biologically sensitive 

habitats. Subsequent exploration in the northwestern Gulf of Mexico has 

identified other reefs, banks, and associated features that may be ecologically 

linked to the Flower Garden Banks National Marine Sanctuary. Although many 

of these areas have some level of protection through other designations, 

inclusion in the sanctuary would provide a comprehensive management 

framework to fill in the existing regulatory gaps and provide necessary protection 

to these critical habitats. In June 2016, NOAA issued a Draft EIS that considers 

five alternatives. BOEM, among other agencies, is a Cooperating Agency in the 

preparation of this EIS. Refer to Chapter 2.2.3 for more information as this 

relates to the alternatives considered in this Multisale EIS.

• Deepwater Horizon Natural Resource Trustees’ Natural Resource Damage 

Assessment Final Programmatic EIS (Deepwater Horizon Natural Resource 
1-20 Gulf of Mexico Multisale EIS

Damage Assessment Trustees, 2016). In February 2016, the Federal and State 

natural resource trustee agencies (Trustees) issued the Deepwater Horizon Oil 

Spill: Final Programmatic Damage Assessment and Restoration Plan and Final 

Programmatic Environmental Impact Statement (PDARP/PEIS) for public review. 

The PDARP/PEIS considers programmatic alternatives to restore natural 

resources, ecological services, and recreational use services injured or lost as a 

result of the Deepwater Horizon oil spill. The Deepwater Horizon oil spill’s

natural resource Trustees have developed restoration alternatives, comprised of 

various restoration types, to address injuries to natural resources and resource 

services resulting from the Deepwater Horizon oil spill. Criteria and evaluation 

standards under the Oil Pollution Act of 1990’s natural resource damage 

assessment regulations guided the Trustees’ consideration of programmatic 

restoration alternatives. The PDARP/PEIS also evaluates the environmental 

consequences of the restoration alternatives under NEPA. 

Supporting technical information in previous NEPA reviews have been developed as 

standalone technical reports and are summarized and incorporated by reference as appropriate. 

These include the OCS regulatory framework and improvements since the Deepwater Horizon

explosion, oil spill, and response; the catastrophic spill event analysis; and the essential fish habitat

assessment. Subsequent updates to this information have been minimal and, therefore, BOEM has 

prepared separate technical reports, which will be updated as needed. This approach would be 

conducive to reducing the size of this Multisale EIS and future NEPA documents. 

• OCS Regulatory Framework White Paper. Federal laws mandate the OCS 

leasing program (i.e., the OCSLA) and the environmental review process (i.e., 

the NEPA). In implementing its responsibilities under the OCSLA, BOEM and 

BSEE must consult with numerous Federal departments and agencies that have 

authority to govern and maintain ocean resources pursuant to other Federal 

laws. Among these Federal entities are the USCG, USEPA, COE, FWS, and 

NOAA through NMFS. Several Federal regulations establish specific 

consultation and coordination processes with Federal, State, and local agencies 

(i.e., the Coastal Zone Management Act of 1972 [CZMA], the Endangered 

Species Act of 1973 [ESA], the Magnuson-Stevens Fishery Conservation and 

Management Act, and the Marine Mammal Protection Act [MMPA]). These

regulations have been discussed in past NEPA documents for oil and natural gas 

lease sales, such as the Gulf of Mexico OCS Oil and Gas Lease Sales: 

2012-2017; Western Planning Area Lease Sales 229, 233, 238, 246, and 248; 

Central Planning Area Lease Sales 227, 231, 235, 241, and 247, Final 

Environmental Impact Statement (2012-2017 WPA/CPA Multisale EIS) (USDOI, 

BOEM, 2012b). This report is available on BOEM’s website (Cameron and 

Matthews, 2016).
The Proposed Actions 1-21

• Catastrophic Spill Event Analysis White Paper. The August 16, 2010, CEQ 

report, prepared following the Deepwater Horizon explosion, oil spill, and 

response in the GOM, recommended that BOEM, formerly the Minerals 

Management Service (MMS) and Bureau of Ocean Energy Management, 

Regulation and Enforcement (BOEMRE), should “[e]nsure that NEPA [National 

Environmental Policy Act] documents provide decisionmakers with a robust 

analysis of reasonably foreseeable impacts, including an analysis of reasonably 

foreseeable impacts associated with low probability catastrophic spills for oil and 

gas activities on the Outer Continental Shelf” (CEQ, 2010). BOEM prepared a 

“Catastrophic Spill Event Analysis,” which was included as Appendix B in the 

2012-2017 WPA/CPA Multisale EIS. This analysis has been reviewed and 

updated, as appropriate, during each Supplemental EIS for the remaining 

proposed GOM lease sales through 2017. These subsequent updates have 

been minimal and, therefore, BOEM has prepared a separate technical report, 

which will be updated as needed. This evaluation is a robust analysis of the 

impacts from low-probability catastrophic spills and will be made available to all 

applicable decisionmakers including, but not limited to, the Secretary of the 

Department of the Interior for the Five-Year Program, the Assistant Secretary of 

Land and Minerals Management for an oil and gas lease sale, and the Regional 

Supervisors of the Gulf of Mexico OCS Region’s Office of Environment and 

Office of Leasing and Plans. This report is also available on BOEM’s website 

(USDOI, BOEM, 2017).

• Essential Fish Habitat Assessment White Paper. The 2017-2022 Programmatic 

EFH Assessment for the Gulf of Mexico (“EFH Assessment”) is a stand-alone 

analysis that addresses BOEM’s obligation under Section 305(b) of the 

Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. § 

1855(b)) to consult with the U.S. Department of Commerce regarding actions that 

may adversely affect essential fish habitat. The EFH Assessment also informs 

many of the analyses documented in this Multisale EIS. The Federal actions 

addressed in the EFH Assessment are the individual proposed Gulf of Mexico 

Lease Sales 249-254, 256, 257, 259, and 261 and related activities, such as 

G&G activities and decommissioning operations. Individual lease sales would 

offer for lease some or all unleased blocks in the WPA, CPA, and EPA proposed 

lease sale areas for oil and gas exploration and recovery operations. A proposed 

action would provide for the issuance of permits to conduct G&G survey activities 

between the coastline and the seaward extent of the Exclusive Economic Zone of 

the GOM. Decommissioning operations encompass many component activities: 

(1) equipment and vessel mobilization and target preparation; (2) underwater 

structural-member severance (nonexplosive and explosive methods); 

(3) post-severance salvage; and (4) final site-clearance verification. These types 

of activities all have the potential to impact fish and EFH. The EFH Assessment 

serves as the initiation of a Programmatic Consultation by BOEM’s Gulf of 
1-22 Gulf of Mexico Multisale EIS

Mexico OCS Region with the U.S. Department of Commerce on OCS oil- and 

gas-related activities for 2017-2022. Based on the most recent and best 

available information, BOEM will also continue to evaluate and assess risks to 

managed species and identified EFH in upcoming environmental compliance 

documentation under NEPA and other statutes. Information relevant to EFHs is

incorporated and analyzed in this Multisale EIS in Chapter 4.2 (Water Quality), 

Chapter 4.3 (Coastal Habitats), Chapter 4.4 (Deepwater Benthic Communities),

Chapter 4.5 (Sargassum and Associated Communities), and Chapter 4.6 (Live 

Bottom Habitats). This report is also available on BOEM’s website (USDOI, 

BOEM, 2016d).

1.8 FORMAT AND ORGANIZATION OF THE MULTISALE EIS

In an effort to thoroughly explain all the environmental considerations and mitigations that 

are involved in BOEM’s assessment of the potential environmental consequences of OCS oil- and 

gas-related activities, BOEM recognizes that past NEPA reviews have become encyclopedic in 

nature. To more closely align with CEQ’s guidance regarding EIS format, a major goal in preparing 

this Multisale EIS includes increasing the readability of the document for decisionmakers and the 

public, and shortening the document by providing relevant and appropriate information needed to 

assess the effects of the proposed actions and alternatives. A major focus for preparing this 

Multisale EIS has been on clear and concise writing, using graphics to emphasize major concepts

where appropriate, and placing more detailed and technical supporting information in the appendices 

and incorporating it by reference. The remaining chapters in this Multisale EIS are described below.

• Chapter 2 describes the potential lease sale options and the alternatives, 

including the proposed action, being analyzed in this Multisale EIS; discusses the 

potential mitigating measures (pre- and postlease), including the proposed 

stipulations, and the issues considered and not considered in the analysis; and 

discusses the deferred alternatives and provides a broad comparison of impacts 

by alternative.

• Chapter 3 describes all the potentially occurring actions associated with a single 

lease for the Five-Year Program and the cumulative activities that provide a 

framework for detailed analyses of the potential impacts analyzed in Chapter 4. 

Exploration and development scenarios describe the infrastructure and activities 

that could potentially affect the biological, physical, and socioeconomic resources 

in the GOM. It is a hypothetical framework of assumptions based on estimated 

amounts, timing, and general locations of OCS exploration, development, and 

production activities and facilities, both offshore and onshore. It also includes a 

set of ranges for resource estimates, projected exploration and development 

activities, and impact-producing factors.

• Chapter 4 describes the affected environment and the potential impacts of a 

single proposed lease sale and each alternative by resource. Analysis of the 
The Proposed Actions 1-23

alternatives includes routine activities, accidental events, cumulative impact 

analysis, incomplete or unavailable information, and conclusions for each 

resource.

• Chapter 5 describes the consultation and coordination efforts used in preparing 

this Multisale EIS. This includes a description of the scoping process, activities, 

and results; cooperating agencies; distribution of the EIS; consultations with 

Federal and State agencies under the Coastal Zone Management Act, 

Endangered Species Act, the Magnuson-Stevens Fishery Conservation and 

Management Act, and the National Historic Preservation Act; and government-togovernment consultation and coordination. Chapter 5 also includes comments 

received on the Draft Multisale EIS and BOEM’s responses.

• Chapter 6 includes all of the citations referenced throughout this Multisale EIS.

• Chapter 7 is a list of all the preparers of this Multisale EIS.

• Chapter 8 is a glossary of terms used in this Multisale EIS. 

• Finally, to improve the readability of this Multisale EIS, more detailed supporting 

information has been placed in the Appendices. 

CHAPTER 2 

ALTERNATIVES INCLUDING THE PROPOSED ACTIONS

Alternatives Including the Proposed Actions 2-3 

What’s In This Chapter?

• This Multisale EIS is the NEPA document used to support a decision on proposed Lease 

Sale 249.

• The analyses in this Multisale EIS are also relevant to proposed Lease Sales 250-254, 

256, 257, 259, and 261.

• Alternative A: A single proposed lease sale offering all available unleased blocks within 

the WPA, CPA, and EPA portions of the proposed lease sale area with exceptions as 

outlined in Chapter 2.2.2.

• Alternative B: A single proposed lease sale offering all available unleased blocks within 

the CPA and EPA but not within the WPA portion of the proposed lease sale area with 

exceptions.

• Alternative C: A single proposed lease sale offering all available unleased blocks within 

the WPA but not within the CPA/EPA portions of the proposed lease sale area with one 

exception.

• Alternative D: Alternative A, B, or C with the option to exclude any available unleased 

blocks subject to the Topographic Features Stipulation, Live Bottom (Pinnacle Trend)

Stipulation, and/or Blocks South of Baldwin County, Alabama, Stipulation.

• Alternative E: Cancellation of a single proposed lease sale.

• Alternatives not analyzed include the following:

− follow the 2012-2017 Five-Year Program leasing schedule, including separate 

lease sales for the EPA;

− exclude blocks that would be subject to any future expansion of the Flower 

Garden Banks National Marine Sanctuary;

− add additional buffer zones to further protect sensitive environments, species, 

or the view from shores;

− exclude the WPA and CPA;

− add more measures to reduce the potential impacts to sperm whale high-use 

areas;

− exclude blocks within the De Soto Canyon area;

− exclude areas that have been designated as loggerhead sea turtle critical 

habitat by NOAA; and

− delay the proposed lease sales until the state of recovery of the GOM following 

the Deepwater Horizon explosion, oil spill, and response is known.

• The issues that most impact the decision to lease are reviewed in this Multisale EIS, 

including impacts to air and water quality, biological resources, recreation, land use, 

economics, and environmental justice. 

• A comparison of alternatives and impact summaries is presented.

2 ALTERNATIVES INCLUDING THE PROPOSED ACTIONS

2.0 INTRODUCTION

As stated in Chapter 1.0, the proposed action is to hold a lease sale in the GOM according 

to the schedule of proposed lease sales set forth in the 2017-2022 Five-Year Program. Since each 

of the 10 proposed lease sales in the GOM region are very similar and occur in close timeframes, 

BOEM has decided to prepare this multisale analysis as described in Chapter 2.1. Four action 

alternatives and a No Action Alternative (Alternative E) are described, including a comparison of 

impacts by alternative.
2-4 Gulf of Mexico Multisale EIS

Agencies are encouraged to tier 

their environmental impact 

statements to eliminate repetitive 

discussions of the same issues 

and to focus on the actual issues 

ripe for decision at each level of 

environmental review.

Agencies are encouraged to tier 

their environmental impact 

statements to eliminate repetitive 

discussions of the same issues 

and to focus on the actual issues 

ripe for decision at each level of 

environmental review.

2.1 MULTISALE NEPA ANALYSIS

As authorized under 40 CFR § 1502.4, one EIS is allowed to analyze related or similar 

proposals. This Multisale EIS addresses 10 proposed regionwide oil and gas lease sales 

encompassing all three planning areas in the U.S. portion of the Gulf of Mexico OCS (Figure 1-1), 

as scheduled in the Five-Year Program (USDOI, BOEM, 2016a). However, as previously noted in 

Chapter 1.3.1.2, the OCSLA requires individual decisions to be made for each lease sale. 

Therefore, in order to make an informed decision on a single proposed lease sale, the analyses 

contained in this Multisale EIS examine impacts from a single proposed regionwide lease sale (i.e., 

proposed Lease Sale 249).

For analysis purposes, a proposed action is presented as a set of ranges of resource

extraction estimates, projected exploration and development activities, and impact-producing factors 

for the proposed lease sale area. Each of the proposed lease sales is expected to have oil and gas 

production within the scenario ranges for the proposed lease sale area analyzed in this Multisale 

EIS; therefore, a proposed action is also representative of proposed Lease Sales 249-254, 256, 257, 

259, and 261. Each proposed action includes existing regulations and lease stipulations. This EIS 

will be the only NEPA document prepared for proposed Lease Sale 249. An additional NEPA review 

(a Determination of NEPA Adequacy, an EA or, if determined necessary, a Supplemental EIS) will 

be conducted prior to each of the remaining proposed lease sales to address any relevant new 

information available since this Final Multisale EIS Informal and formal consultations with other 

Federal agencies, the affected States, federally recognized Indian Tribes, and the public will be 

carried out to assist in the determination of whether or not the information and analyses in this 

Multisale EIS are still valid. Specifically, information requests such as NOIs and request for public 

comment will be issued soliciting input on subsequent proposed lease sales as appropriate (refer to 

Chapter 1.3.1.2).

The supplemental approach for regional lease sales 

is intended to focus the NEPA/EIS process on updating 

subsequent lease sale NEPA reviews to address any 

relevant significant new information and/or issues since 

publication of the previous lease sale NEPA document from 

which it tiers (Figure 1-6) This tiering approach also 

lessens duplication and saves resources. The scoping 

process for this document is described in Chapter 5. As 

mandated by NEPA, this Multisale EIS analyzes the 

potential impacts of the proposed actions on the marine, 

coastal, and human environment.

Any subsequent NEPA reviews will tier from this Multisale EIS and will summarize and 

incorporate the material by reference. Because any subsequent reviews will be prepared for a 

proposed action that “is, or is closely similar to, one which normally requires the preparation of an 

EIS” (40 CFR § 1501.4(e)(2)), the review documents will be made publicly available.
Alternatives Including the Proposed Actions 2-5 

If a Supplemental EIS is necessary (40 CFR § 1502.9), it will tier from this Multisale EIS, 

summarize and incorporate the material by reference, and focus on addressing any new information, 

issue(s) and/or concern(s). The Supplemental EIS will include a discussion of the purpose of the 

Supplemental EIS, a description of the proposed action(s) and alternatives, a comparison of the 

proposed alternatives, a description of the affected environment, potentially affected resources, an 

analysis of new impacts, and new information not addressed in this Multisale EIS. The 

Supplemental EIS will also include an updated discussion of associated BOEM coordination and 

consultations. As discussed further in Chapter 1.7, an analysis of the impacts of low-probability 

catastrophic spills has been prepared as a BOEM white paper and is incorporated by reference 

(Catastrophic Spill Event Analysis white paper; USDOI, BOEM, 2017).

2.2 ALTERNATIVES, MITIGATING MEASURES, AND ISSUES

Below is a description of the 2017-2022 proposed Gulf of Mexico OCS Region’s lease sale 

schedule per the Five-Year Program followed by a reasonable range of alternatives to the proposed 

action that can be considered for selection to avoid or minimize impacts throughout the 2017-2022 

Five-Year Program.

2.2.1 What is the 2017-2022 Proposed Lease Sale Schedule?

A total of 10 proposed regionwide lease sales 

has been identified in BOEM’s 2017-2022 Five-Year 

Program, with 1 lease sale in 2017; 2 lease sales each 

year in 2018, 2019, 2020, and 2021; and 1 lease sale 

in 2022 offering all available unleased blocks not 

subject to Congressional moratorium in the combined 

WPA, CPA, and EPA in each proposed lease sale. 

The alternatives below are being considered in order to 

ensure that BOEM has considered a reasonable range 

of alternatives to the proposed actions within the 

framework of the Five-Year Program.

The regionwide lease sale approach provides greater flexibility, including responding to 

changing conditions (including Mexico’s new plan offering offshore licenses every September); a 

better workload balance within BOEM; and allowing for more frequent opportunities to bid on 

rejected, relinquished, or expired blocks. Also, any individual lease sale could still be scaled back to 

offer a smaller area, if conditions warrant. In addition, regionwide leasing could facilitate better 

planning to explore pools that may straddle the U.S.-Mexico boundary. More frequent lease sales in 

the planning areas (through regionwide leasing) may expedite and increase the present value of 

leasing and tax revenues. More frequent lease sales for the available unleased blocks, however, 

could reduce the time available for companies to update their information and develop improved

value estimates for the remaining available unleased blocks.

2017-2022 Schedule of Proposed

Gulf of Mexico OCS Region

Lease Sales 

Lease Sale Number Year

249 2017

250 and 251 2018

252 and 253 2019

254 and 256 2020

257 and 259 2021

261 2022
2-6 Gulf of Mexico Multisale EIS

2.2.2 What are the Alternatives that BOEM is Considering for Each Proposed 

Lease Sale?

The discussions below outline the alternatives that are considered for this environmental 

analysis. To make an informed decision on a single proposed lease sale, the alternatives and 

analyses contained in this Multisale EIS examine impacts from a single proposed lease sale and can 

be applied individually to each of the subsequent proposed lease sales. Additional alternatives 

could also be considered in subsequent NEPA reviews should new information or circumstances 

warrant.

The analyses of impacts summarized below in Chapter 2.3 and described in detail in 

Chapter 4 for each resource are based on the development scenario, which is a set of assumptions 

and estimates on the amounts, locations, and timing for OCS exploration, development, and 

production operations and facilities, both offshore and onshore, related to a single proposed lease 

sale. A detailed discussion of the development scenario and major related impact-producing factors 

is included in Chapter 3. A proposed lease sale includes proposed lease stipulations designed to 

reduce environmental risks; these stipulations are discussed in Chapter 2.2.4.1. 

2.2.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred Alternative)

Alternative A would allow for a proposed regionwide lease sale encompassing all three 

planning areas within the U.S. portion of the Gulf of Mexico OCS for any given lease sale in the 

Five-Year Program. This is BOEM’s preferred alternative. This alternative would offer for lease all 

available unleased blocks within the WPA, CPA, and EPA portions of the proposed lease sale area 

for oil and gas operations (Figure 2-1), with the following exceptions:

(1) whole and portions of blocks deferred by the Gulf of Mexico Energy Security Act 

of 2006 (discussed in the OCS Regulatory Framework white paper [Cameron 

and Matthews, 2016]); 

(2) blocks that are adjacent to or beyond the United States’ Exclusive Economic 

Zone in the area known as the northern portion of the Eastern Gap; and

(3) whole and partial blocks within the current boundary of the Flower Garden 

Banks National Marine Sanctuary.
Alternatives Including the Proposed Actions 2-7 

Figure 2-1. Proposed Regionwide Lease Sale Area, Encompassing the Available Unleased Blocks 

within All Three Planning Areas (a total of approximately 91.93 million acres with 

approximately 75.4 million acres available for lease as of January 2017).

The WPA begins 3 marine leagues (9 nautical miles [nmi]; 10.36 miles [mi]; 16.67 kilometers 

[km]) offshore Texas and extends seaward to the limits of the United States’ jurisdiction over the 

continental shelf (often referred to as the Exclusive Economic Zone) in water depths up to 

approximately 3,346 m (m) (10,978 feet [ft]). The proposed WPA portion of the lease sale area 

encompasses about 28.58 million ac. As of January 2017, approximately 25.8 million ac of the 

proposed WPA lease sale area are currently unleased.

The CPA begins 3 nmi (3.5 mi; 5.6 km) offshore Louisiana, Mississippi, and Alabama, and 

extends seaward to the limits of the United States’ jurisdiction over the continental shelf (often 

referred to as the Exclusive Economic Zone) in water depths up to approximately 3,346 m 

(10,978 ft). The proposed CPA portion of the lease sale area encompasses about 63 million ac of 

the total CPA area of 66.45 million ac. As of January 2017, approximately 49.0 million ac of the 

proposed CPA lease sale area are currently unleased.

The proposed EPA portion of the lease sale area covers approximately 657,905 ac and 

includes those blocks previously included in the EPA Lease Sales 225 and 226 areas, which is 
2-8 Gulf of Mexico Multisale EIS

bordered by the CPA boundary on the west and the Military Mission Line (86o41' W. longitude) on 

the east. The portion of the EPA available for leasing is south of eastern Alabama and western 

Florida; the nearest point of land is 125 mi (201 km) northwest in Louisiana. As of January 2017, 

approximately 606,995 ac of the proposed EPA lease sale area are currently unleased.

In general, a regionwide lease sale, which would include all available unleased blocks in all 

three planning areas, would represent 1.2-4.2 percent of the total OCS Program production in the 

GOM based on barrels of oil equivalent resource estimates. The estimated amounts of resources 

projected to be leased, discovered, developed, and produced as a result of a typical proposed 

regionwide lease sale are 0.211-1.118 billion barrels of oil (BBO) and 0.547-4.424 trillion cubic feet 

(Tcf) of gas (refer to Table 3-1). A regionwide lease sale would offer approximately 91.93 million ac, 

with approximately 75.4 million ac available for lease as of January 2017. Leasing information 

related to all three planning areas is updated monthly and can be found on BOEM’s website at 

http://www.boem.gov/Gulf-of-Mexico-Region-Lease-Map/. 

2.2.2.2 Alternative B—Regionwide OCS Lease Sale Excluding Available Unleased Blocks in 

the WPA Portion of the Proposed Lease Sale Area

Alternative B would allow for a proposed lease sale encompassing the CPA and EPA within 

the U.S. portion of the Gulf of Mexico OCS (Figure 2-2). Available blocks within the WPA would not

be considered under this alternative. This alternative would offer for lease all available unleased 

blocks within the CPA and EPA portions of the proposed lease sale area as those planning area 

portions are described in Alternative A for oil and gas operations, with the following exceptions:

(1) whole and portions of blocks deferred by the Gulf of Mexico Energy Security Act 

of 2006 (discussed in the OCS Regulatory Framework white paper [Cameron 

and Matthews, 2016]); and

(2) blocks that are adjacent to or beyond the United States’ Exclusive Economic 

Zone in the area known as the northern portion of the Eastern Gap. 
Alternatives Including the Proposed Actions 2-9 

Figure 2-2. Proposed Lease Sale Area for Alternative B, Excluding the Available Unleased Blocks in 

the WPA (approximately 63.35 million acres with approximately 49.6 million acres available 

for lease as of January 2017).

In general, a lease sale that would include all available unleased blocks in the CPA and EPA 

would represent approximately 1.0-3.6 percent of the total OCS Program production in the GOM 

based on barrels of oil equivalent resource estimates. The estimated amounts of resources 

projected to be leased, discovered, developed, and produced as a result of a proposed lease sale 

under Alternative B are 0.185-0.970 BBO and 0.44-3.672 Tcf of gas (refer to Table 3-1).

2.2.2.3 Alternative C—Regionwide OCS Lease Sale Excluding Available Unleased Blocks in 

the CPA/EPA Portions of the Proposed Lease Sale Area

Alternative C would allow for a proposed lease sale encompassing the WPA within the U.S. 

portion of the Gulf of Mexico OCS (Figure 2-3). Available blocks within the CPA and EPA would not

be considered under this alternative. This alternative would offer for lease all available unleased 

blocks within the WPA portion of the proposed lease sale area for oil and gas operations, with the 

following exception:

(1) whole and partial blocks within the current boundary of the Flower Garden Banks

National Marine Sanctuary. 
2-10 Gulf of Mexico Multisale EIS

The proposed Alternative C lease sale area encompasses virtually all of the WPA’s 

approximately 28.58 million ac as that planning area is described as a subset of Alternative A. In 

general, a lease sale that would include all available unleased blocks in the WPA would represent 

approximately 0.2-0.6 percent of the total OCS Program production in the GOM based on barrels of 

oil equivalent resource estimates. The estimated amounts of resources projected to be leased, 

discovered, developed, and produced as a result of a proposed lease sale offering only WPA 

available unleased blocks are 0.026-0.148 BBO and 0.106-0.752 Tcf of gas (refer to Table 3-1).

Figure 2-3. Proposed Lease Sale Area for Alternative C, Excluding the Available Unleased 

Blocks in the CPA and EPA (approximately 28.58 million acres with approximately 

25.8 million acres available for lease as of January 2017).

2.2.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude Available Unleased 

Blocks Subject to the Topographic Features, Live Bottom (Pinnacle Trend), and/or 

Blocks South of Baldwin County, Alabama, Stipulations

Alternative D could be combined with any of the Action alternatives above (i.e., Alternatives 

A, B, or C) and would allow the flexibility to offer leases under any alternative with additional 

exclusions. Under Alternative D, the decisionmaker could exclude from leasing any available 

unleased blocks subject to any one and/or a combination of the following stipulations: 

− Topographic Features Stipulation; 

− Live Bottom (Pinnacle Trend) Stipulation; and 
Alternatives Including the Proposed Actions 2-11

− Blocks South of Baldwin County, Alabama, Stipulation (not applicable to 

Alternative C).

This alternative considered blocks subject to these stipulations because these areas have 

been emphasized in scoping, can be geographically defined, and adequate information exists 

regarding their ecological importance and sensitivity to OCS oil- and gas-related activities.

A total of 207 blocks within the CPA and 160 blocks in the WPA are affected by the 

Topographic Features Stipulation (Figure 2-4). There are currently no identified topographic 

features protected under this stipulation in the EPA. The Live Bottom Stipulation covers the pinnacle 

trend area of the CPA, affecting a total of 74 blocks (Figure 2-4). More details on the blocks 

affected by the Topographic Features Stipulation and the Pinnacle Trend blocks subject to the Live 

Bottom Stipulation can be found at http://www.boem.gov/Biologically-Sensitive-Areas-List/. Maps 

indicating the areas affected by the Topographic Features Stipulation can be found at 

http://www.boem.gov/Topographic-Features-Stipulation-Map-Package/. 

Figure 2-4. Identified Topographic Features, Pinnacle Trend, and Blocks South of Baldwin County, 

Alabama, Stipulation Blocks in the Gulf of Mexico.
2-12 Gulf of Mexico Multisale EIS

Figure 2-5 illustrates one example of the blocks that would be excluded under this 

alternative (shaded in blue). For this example, under Alternative D, there would be 15 blocks 

eliminated from the proposed lease sale area. Any production that could potentially result from

these blocks would not be realized. Should the decisionmaker decide instead to adopt Alternatives 

A, B, or C, which apply the Topographic Features Stipulation, the 15 blocks (that would have been 

eliminated from potential exploration and development under Alternative D) would still be made 

available but with mitigations applied to avoid or minimize impacts to the features.

Figure 2-5. Example of Excluded Blocks under Alternative D.

As of the publication of this Multisale EIS, the Blocks South of Baldwin County, Alabama, 

Stipulation (herein referred to as the Baldwin County Stipulation Blocks) applies to a total of 

32 blocks (Mobile 826-830, 869-874, 913-918, 957-962, 1001-1006, and Viosca Knoll 33-35) within 

15-mi (24 km) of Baldwin County, Alabama (representing less than 1% of the total number of blocks 

to be offered under Alternative A or B). The intent of a proposal excluding these blocks would be to 
Alternatives Including the Proposed Actions 2-13

mitigate the visual impacts of concern raised by the Governor of Alabama on previous EISs, as well 

as on the 2017-2022 Five-Year Program from which this Multisale EIS tiers. The stipulation, 

however, has been continually adopted in annual CPA lease sales since 1999 and has effectively 

mitigated visual impacts. The stipulation specifies requirements for consultation that lessees must 

follow when developing plans for fixed structures (refer to Appendix D) while still allowing leasing 

and OCS oil- and gas-related operations in the area, which could not occur with the no-leasing 

buffer. If any of the action alternatives are selected, BOEM expects this stipulation to be analyzed 

and decided on during each individual lease sale stage in the Five-Year Program; therefore, no 

visual impacts would be expected to occur should the stipulation be applied.

Alternative D, if adopted, would prevent any OCS oil- and gas-related activity whatsoever in 

the affected blocks; thus, it would eliminate any potential direct impacts to the biota of those blocks 

from OCS oil- and gas-related activities, which otherwise could be conducted within the blocks. 

Under Alternative D, the number of blocks that would become unavailable for lease represents only 

a small percentage of the total number of blocks to be offered under Alternative A, B, or C (<4%, 

even if blocks subject to all three stipulations were excluded). Therefore, Alternative D could reduce 

offshore infrastructure and activities, but Alternative D may (and BOEM believes more reasonable to 

expect) only shift the location of offshore infrastructure and activities farther from these sensitive 

zones and not lead to a reduction in overall offshore infrastructure and activities. The regional 

impact levels for all resources, except for the topographic features and live bottoms, would be similar 

to those described under Alternative A, B, or C. All of the assumptions (including the other potential 

mitigating measures) and estimates would remain the same as described for Alternatives A, B, C. 

The exclusion of this small subset of available unleased blocks could reduce exploration, 

development, and production flexibility and, therefore, could result in adverse economic effects (e.g., 

reduced royalties). A detailed discussion of the development scenario and major related 

impact-producing factors is included in Chapter 3. A proposed lease sale includes proposed lease 

stipulations designed to reduce environmental risks; these stipulations are discussed in Chapter 

2.2.4.1. 

2.2.2.5 Alternative E—No Action

Alternative E is the cancellation of a single proposed lease sale. The opportunity for 

development of the estimated oil and gas that could have resulted from a proposed action (i.e., a 

single proposed lease sale) or alternative to the proposed action, as described above, would be 

precluded or postponed to a future lease sale. Any potential environmental impacts resulting from a 

proposed lease sale would not occur. Activities related to previously issued leases and permits (as 

well as those that may be issued in the future under a separate decision) related to the OCS oil and 

gas program would continue. If a lease sale were to be cancelled, the resulting development of oil 

and gas would most likely be postponed to a future lease sale; therefore, the overall level of OCS 

oil- and gas-related activity would only be reduced by a small percentage, if any. Therefore, the 

cancellation of a proposed lease sale would not significantly change the environmental impacts of 

overall OCS oil- and gas-related activity. However, the cancellation of a proposed lease sale may 

result in direct economic impacts to the individual companies, and the revenues collected by the 
2-14 Gulf of Mexico Multisale EIS

Federal Government (and thus revenue disbursements to the States) could also be adversely

affected. If future lease sales were to occur, the impacts from the cancellation of a single lease sale 

to individual companies and Federal revenues would likely be minor. The Five-Year Program

discusses the impacts of cancelling all proposed GOM lease sales included in the Five-Year 

Program. 

2.2.3 What Other Alternatives and Deferrals have BOEM Considered but Not 

Analyzed in Detail?

BOEM evaluated a range of alternatives to ensure that a reasonable range of alternatives 

have been considered in this Multisale EIS. Below are the alternatives that have been considered 

but eliminated from detailed study with a brief discussion of the reasons for eliminating them.

Previous Multisale Schedule

This alternative would maintain the approach taken in the 2012-2017 Five-Year Program, 

which consisted of 12 lease sales in total, including 5 annual lease sales beginning in 2017 in the 

WPA offering all available unleased blocks, 5 annual lease sales beginning in 2018 in the CPA 

offering all available unleased blocks, and 2 lease sales in the EPA in 2014 and 2016 offering all 

available unleased blocks. No CPA or EPA blocks that are subject to Congressional moratorium 

pursuant to GOMESA would be included for leasing consideration.

While lease sales in the GOM have historically been separate annual lease sales in the CPA 

and WPA and periodic lease sales in the EPA as appropriate, significant recent energy reforms in 

Mexico have the potential to meaningfully change how exploration and development decisions are 

made in the GOM. The Transboundary Agreement reached with Mexico (refer to Chapter 2.2.4.1) 

allows leaseholders on the U.S. side of the boundary and Pemex to explore and exploit a 

transboundary reservoir as a “unit,” just as leaseholders are permitted to do on reservoirs on the 

U.S. side of the boundary. By scheduling lease sales offering all available unleased blocks in the 

GOM, BOEM is providing more frequent opportunities to bid on rejected, relinquished, or expired 

OCS lease blocks, as well as facilitating better planning to explore resources that may straddle the 

U.S.-Mexico boundary. Furthermore, any individual lease sale could be scaled back to conform 

more closely to the traditional separate planning area model should circumstances warrant.

This Multisale EIS considers Alternatives B and C, which were similar to the previous lease 

sale approach of having lease sales for each planning area. Alternative B is fundamentally 

equivalent to a CPA lease sale in the 2012-2017 Five-Year Program, differing in that the EPA would 

be combined with the CPA into a single proposed lease sale (similar to how the two EPA lease sales 

in the 2012-2017 Five-Year Program were held concurrently with CPA lease sales). Alternative C is 

fundamentally equivalent to a WPA lease sale in the 2012-2017 Five-Year Program. Because this 

alternative (i.e., the 2012-2017 Five-Year Program lease sale schedule) is a decision made at the 

programmatic level under the Five-Year Program, this alternative was not considered for further 

analysis.
Alternatives Including the Proposed Actions 2-15

Exclude Blocks Subject to the Flower Garden Banks National Marine Sanctuary Expansion

BOEM is aware of NOAA’s proposal to expand the boundaries of the Flower Garden Banks

National Marine Sanctuary (FGBNMS) and has considered analyzing a separate alternative that 

would exclude all blocks subject to that expansion from oil and gas leasing. The NOAA published a 

Draft EIS for the proposed expansion on June 7, 2016, and BOEM is a cooperating agency on that 

EIS. The NOAA’s Draft EIS has five alternatives for expansion. In their preferred alternative 

(Alternative C), the sanctuary would expand to 383 square miles (mi2

) (992 square kilometers [km2]) 

and would include 15 additional reefs and banks. This alternative includes a total of 18 nationally 

significant natural features within 11 discrete proposed boundary areas. Refer to Chapter 1.7 for 

further discussion on NOAA’s Flower Garden Banks National Marine Sanctuary Expansion EIS.

BOEM has existing protective measures in the Topographic Features Stipulation that 

currently protect topographic features from oil and gas activities, including some features outside of 

the current FGBNMS boundaries, which are proposed for inclusion in NOAA’s new proposed 

expansion. In addition, BOEM protects topographic features and other surrounding habitats by 

conducting site-specific, case-by-case reviews of plans and permit applications in order to distance 

bottom-disturbing activities from sensitive habitat. Should NOAA decide in the future to expand the 

boundaries of the FGBNMS, the potential environmental effects from OCS oil- and gas-related 

activities would likely be further reduced from those impacts already considered. However, there 

could be adverse economic impacts by the removal of potential blocks of interest. Because of the 

protective measures already in place, as well as the flexibility to adjust the current set of alternatives 

to encompass any future FGBNMS expansion, BOEM believes that the effects of a potential 

expansion are appropriately accounted for within the existing alternatives in this Multisale EIS.

Additional Buffers

BOEM has considered a suite of alternatives that would implement additional buffer zones 

around potential areas of concern. Each of these is briefly discussed below, including the reasons 

why these additional buffer area alternatives have not been carried forward for full analysis.

• During scoping, the Save the Manatee Club requested an alternative that would 

impose a buffer around those blocks in the EPA that are subject to 

Congressional moratorium pursuant to GOMESA. The Save the Manatee Club 

noted that, even though leasing is not allowed in these areas of the EPA, 

previous experiences such as the Deepwater Horizon explosion, oil spill, and 

response demonstrate that these areas are still at risk to potential impacts. The 

GOMESA includes a moratorium on oil and gas leasing within 125 mi (201 km) of 

the Florida coastline in the EPA and in a portion of the CPA until 2022. For an 

analysis of a low-probability catastrophic spill, such as the Deepwater Horizon

explosion and oil spill, refer to the Catastrophic Spill Event Analysis white paper 

(USDOI, BOEM, 2017). Such an event, however, is not considered reasonably 

foreseeable as a result of a proposed action. Additionally, the comments did not 

offer any well-defined buffer areas and/or reasoning to support such a buffer.
2-16 Gulf of Mexico Multisale EIS

A key component to managing risk is to implement a rigorous regulatory regime 

to ensure that postlease drilling activities are conducted in a safe manner. It is at 

this stage that detailed information regarding a specific proposed action is 

available for review, including reservoir characteristics, infrastructure designs, 

and features to ensure safety and reduce environmental risk. BOEM has 

implemented a suite of regulatory changes following the Deepwater Horizon

explosion, oil spill, and response. These are discussed in detail in Chapter 3.2 

and Appendix A. For these reasons, BOEM concluded that an alternative 

including an additional buffer around the EPA was not warranted for detailed 

analysis.

• The National Park Service (NPS) requested an alternative that considered a noleasing buffer within 15 mi (24 km) of the Gulf Islands National Seashore (GUIS). 

As noted in Chapter 1.1, the purpose of the proposed Federal actions is to offer 

for lease those areas that may contain economically recoverable oil and gas 

resources in accordance with the OCSLA (67 Stat. 462), as amended (43 U.S.C. 

§§ 1331 et seq.). Over time, using adaptive management practices, BOEM and 

its predecessors have proactively developed a suite of mitigating measures that 

are applied at the prelease or postlease phases of the oil and gas program to 

avoid and protect fixed biologically and culturally sensitive features, which 

includes the GUIS (Gulf Islands National Seashore Information to Lessees and 

Operators [ITL]). This ITL ensures that postlease plans submitted by lessees of 

whole and partial lease blocks within the first 12 mi (19 km) of Federal waters 

near the GUIS are reviewed by BOEM in order to minimize visual impacts from 

development operations on these blocks. The lease blocks that would be subject 

to the Gulf Islands National Seashore ITL are illustrated in Figure 2-6. This is 

consistent with NPS’ proposed management strategy for maintaining optimal 

night sky viewing conditions, which include cooperating with partners to minimize 

intrusion of artificial light into the night scene in the national seashore and 

evaluating the impacts on the night sky caused by national seashore facilities 

(USDOI, NPS, 2011).

Based on historical leasing patterns, the proposed actions would likely only 

minimally contribute to the existing disturbances from OCS and non-OCS 

sources. Numerous OCS structures and wells have existed within 15 mi (24 km) 

of the GUIS over the years, many of which have been removed. Some OCS 

platforms are visible on the horizon (Figure 2-7).

Section 8(g) of the OCSLA, as amended, requires a “fair and equitable” 

distribution of revenues between the Federal Government and a coastal state for 

Federal lease blocks within 3 mi (5 km) of the seaward boundary of the State that 

may contain oil and gas reservoirs underlying both OCS and submerged State 

tidelands. Due to the location of the GUIS, the proposed buffer area includes 

blocks off the coasts of Louisiana, Mississippi, and Alabama, and could result in 
Alternatives Including the Proposed Actions 2-17

reduced revenue sharing for those States as a result of the alternative being 

chosen. Consultation with the Governor of each State is required at the time of 

soliciting nominations for the leasing of OCS lands wholly or partially within the 

3 mi (5 km) mentioned above. The GOMESA enhances the revenue sharing 

provisions for the four Gulf oil- and gas-producing States of Alabama, Louisiana, 

Mississippi, and Texas, and their coastal political subdivisions, which are to be 

used for coastal conservation, restoration, and hurricane protection.

Figure 2-6. Federal OCS Blocks Subject to the Gulf Islands National Seashore’s

Information to Lessees and Operators.
2-18 Gulf of Mexico Multisale EIS

Figure 2-7. Historical Structure Locations near Horn and Petit Bois Islands.

Even without the presence of oil and gas activities in State waters and on the 

Federal OCS, there is substantial vessel traffic in this area due to the presence of 

federally designated shipping safety fairways and anchorage areas to provide 

unobstructed approaches for vessels using U.S. ports (33 CFR part 166). These 

visual impacts would remain ongoing and unaffected by the proposed actions; 

therefore, altering a proposed action would not alleviate visual impacts to the 

GUIS. Because of the environmental protection measures already implemented 

by BOEM and BSEE through the established ITL for the subject area, this 

alternative was not analyzed in detail in this Multisale EIS.

To exclude the additional buffer areas proposed above from potential oil and gas exploration 

and development would not achieve the desired goal of reducing risk from OCS oil- and gas-related 

activities. The Gulf of Mexico OCS has a mature oil and gas program. Over time, using adaptive 

management practices, BOEM has proactively developed a suite of mitigating measures that are 

applied at the prelease or postlease phases of the oil and gas program. These measures serve to 

avoid and protect potential areas of concern, such as topographic features, pinnacles, live bottoms, 

chemosynthetic communities, deepwater corals, and historic shipwrecks (e.g., Topographic Features 

Stipulation, Live Bottom (Pinnacle Trend) Stipulation, NTL 2009-G39, NTL 2009-G40, and 
Alternatives Including the Proposed Actions 2-19

NTL 2005-G07). Protective measures are also in place to mitigate potential impacts from seismic 

activities, marine debris, vessel traffic, structure-removal activities, and vessel traffic to mobile 

resources such as marine mammals and sea turtles (e.g., NTL 2016-G02, NTL 2012-G01, and 

NTL 2010-G05).

Lease Sale Offering Only EPA Available Unleased Blocks

This alternative would allow for a proposed lease sale encompassing the EPA within the U.S. 

portion of the Gulf of Mexico OCS. Available unleased blocks within the CPA and WPA would not

be considered under this alternative. This alternative would offer for lease all available unleased 

blocks within the EPA portion of the proposed lease sale area for oil and gas operations with the 

exception of whole and portions of blocks deferred by the Gulf of Mexico Energy Security Act of 

2006. During scoping, the Save the Manatee Club requested NEPA analysis of the EPA in a 

separate process. The Save the Manatee Club noted that the EPA has unique environmental and 

cultural resources, and has heretofore only been minimally impacted by drilling operations in the Gulf 

of Mexico. Any potential impacts to resources exclusive or more prevalent to the EPA (e.g., 

manatees and Gulf sturgeon) have been considered in the alternatives analyses.

The proposed EPA portion of the lease sale area covers approximately 657,905 ac and 

includes those blocks previously included in the EPA Lease Sales 225 and 226 areas, which is 

bordered by the CPA boundary on the west and the Military Mission Line (86o41′ W. longitude) on 

the east. The area is south of eastern Alabama and western Florida; the nearest point of land is 

125 mi (201 km) northwest in Louisiana. As of March 2016 January 2017, approximately 606,995 ac 

(70%) and 175 lease blocks of the proposed EPA lease sale area are currently unleased.

Although the majority of the EPA is unavailable for leasing through June 30, 2022, under 

GOMESA, there are existing leases in the planning area. Thirteen lease sales have been held in 

this planning area as it has been configured over the years, and 105 wells have been drilled, with 

significant discoveries of natural gas. However, there has been no production from the wells in the 

planning area currently available for leasing. Lease Sale 224 in March 2008 resulted in leases being 

awarded on 36 OCS blocks with bonuses totaling $64.7 million in the small area available for leasing 

consideration. For the most recent lease sales held in the same small area (i.e., Lease Sales 225 

and 226), no bids were received.

From a leasing perspective, it is less practical to conduct separate lease sales for the EPA 

due to its size (i.e., the number of blocks available for lease) and considering the leasing history in 

this area. Although recent leasing in the EPA has been minimal, providing these blocks more 

frequently through a regionwide approach would more effectively balance Bureau workload and 

provide greater flexibility to industry, including the ability to respond to the significant recent energy 

reforms in Mexico that have the potential to meaningfully change how exploration and development 

decisions are made in the GOM.
2-20 Gulf of Mexico Multisale EIS

Regionwide OCS Lease Sale with Additional Mitigating Measures for Sperm Whale High-Use 

Areas

Sperm whales, protected under the ESA, often concentrate in the deepwater area offshore 

the Mississippi River delta, especially in the vicinity of the Mississippi Canyon area and adjacent 

continental slope (Davis and Fargion, 1996). Some commenters have requested special 

consideration of the Mississippi Canyon area to protect potentially important sperm whale habitat 

and have suggested that a ban on new leasing in the Mississippi Canyon area would help protect 

sperm whales from further disruption caused by new offshore oil- and gas-related activities. They

also provided literature (Wise et al., 2014) regarding potential water quality effects to the Mississippi 

Canyon area following the Deepwater Horizon oil spill and how the persistence of oil and 

contaminants following the Deepwater Horizon oil spill might be affecting marine species in the 

Mississippi Canyon area. 

Wise et al. (2014) found nickel and chromium in skin cells from sampled animals in the 

Mississippi Canyon and in adjacent areas; however, it is important to note that sperm whales in the 

GOM are using the entire GOM, not just the Mississippi Canyon area. There are substantially less 

OCS oil and gas structures in the Mississippi Canyon and De Soto Canyon areas compared with the 

entire Gulf of Mexico. Limiting leasing in such a relatively small area would not limit the exposure of 

sperm whales and Bryde’s whales to chemicals because chemicals may still enter these areas via 

the Mississippi River. Various chemicals and heavy metals, including nickel and chromium, 

accumulate in soils near urban, industrial, and agricultural areas and are washed into the Mississippi 

River during heavy rainfall events (Mielke et al., 2000). Furthermore, high concentrations of trace 

metals (including nickel and chromium) have been observed in some core sediment samples that 

were taken in the central Gulf of Mexico at various depths across the shelf, slope, and abyssal plain 

and at least 3,000 m (9,843 ft) away from offshore platforms more than 7 years before the 

Deepwater Horizon oil spill (Wade et al., 2008). Wade et al. (2008) stated that the concentrations of 

trace metals from these particular samples were likely due to complex natural transport and 

biogeochemical processes and not to anthropogenic resources.

Although Wise et al. (2014) detected the presence of nickel and chromium in oil sampled 

during the Deepwater Horizon oil spill, it was stated that their data could not directly show that the 

nickel and chromium found in the whales they sampled were from the Deepwater Horizon oil spill 

and that other sources could be industry-related waste or boat paint from various marine vessels 

containing chromium as an antifouling agent. Some data suggest that sperm whale skin cells are 

more resistant to the cytotoxic and genotoxic effects of chromium than human skin cells and that 

sperm whale skin cells have evolved cellular mechanisms to protect them against the genotoxicity of 

environmental agents such as chromium (Chen et al., 2012).

Although it can be speculated that excluding the Mississippi Canyon area could result in less 

projected OCS oil- and gas-related activity, thus decreasing the likelihood of OCS oil- and gasrelated activities impacting sperm whales, there are not enough conclusive data on their density and 

distribution in the GOM throughout the year to conclude that speculation. Therefore, because of 
Alternatives Including the Proposed Actions 2-21

sperm whale diversity and wide distribution throughout the GOM, the overall level of impacts would 

not be expected to change by excluding the Mississippi Canyon area from a proposed lease sale. 

BOEM believes that current long-term biological data do not support additional mitigating measures

or exclusion of this area beyond the long-standing mitigation practices already in place to minimize 

impacts on this species. A full analysis of marine mammals, including sperm whales, can be found 

in Chapter 4.9.1. 

Regionwide OCS Lease Sale Excluding Blocks within the De Soto Canyon Area

Some commenters have requested special consideration of the De Soto Canyon area to 

protect potentially important Bryde’s whale habitat. Bryde's whales in the De Soto Canyon area are 

of particular concern considering that the available information suggests a very small and genetically 

distinct population within a limited range, making the population vulnerable to anthropogenic 

impacts. Large baleen whales are particularly vulnerable to vessel strikes because most are slow 

moving and may not be able to evade an oncoming vessel (Laist et al., 2001).

However, there is currently very limited oil- and gas-related activity in the De Soto Canyon 

area. Furthermore, BOEM and BSEE provide guidance on vessel strike avoidance measures and 

protected species reporting, marine trash and debris awareness and elimination, and seismic survey 

mitigating measures and Protected Species Observer Reports to all operators via NTLs. Adherence 

to these NTLs is expected to effectively reduce potential impacts to protected species without having 

to exclude these areas all together. Limiting leasing even further in the De Soto Canyon area would 

not limit other anthropogenic impacts, such as vessel strikes from marine transportation, to Bryde's 

whales. Additionally, biologically important areas for marine mammals in the GOM were identified 

based on both scientific information and expert elicitation and developed to inform regulatory and 

management decisions (Ferguson et al., 2015). The biologically important area identified in the 

GOM for Bryde’s whale includes slope waters off the coast of Florida, primarily between 100 and 

300 m (328 and 984 ft) deep (LaBrecque et al., 2016). For these reasons, this alternative was not 

carried through for detailed analysis. A full analysis of marine mammals can be found in Chapter 

4.9.1. 

Regionwide OCS Lease Sale Excluding Blocks within Loggerhead Sea Turtle Critical Habitat

Some commenters have requested special consideration of loggerhead sea turtle critical 

habitat (as designated by NMFS) to protect potentially important habitat for the Northwest Atlantic 

loggerhead sea turtle distinct population segment. Chapter 4.9.2 analyzed loggerhead sea turtles, 

including a discussion of loggerhead sea turtles’ critical habitat and threats. According to Chapter 

4.9.2.2.1, the incremental contribution to cumulative impacts on sea turtles would be expected to be 

negligible as a result of a proposed action, and population-level impacts to sea turtles are not 

anticipated. The NMFS designated marine critical habitats in its Final Rule in July 2014. Within the 

GOM, the only NMFS-designated offshore marine critical habitat for Northwest Atlantic loggerhead 

sea turtle is Sargassum. A full analysis of Sargassum can be found in Chapter 4.5, where BOEM 

concluded negligible impacts to this habitat as a result of a proposed action. 
2-22 Gulf of Mexico Multisale EIS

As noted in NMFS’ Final Rule, it is challenging to identify specific areas where these 

Sargassum concentrations are likely to form consistently, given its dynamic nature. Estimates 

suggest that between 0.6 and 6 million metric tons of Sargassum are present annually in the GOM, 

with an additional 100 million metric tons exported to the Atlantic basin (Gower and King, 2008 and 

2011; Gower et al., 2013). Due to the expansive areal extent of loggerhead sea turtle critical habitat 

(i.e., Sargassum) in the GOM, excluding all such areas is effectively considered under the No Action 

Alternative. Furthermore, Sargassum has a yearly cycle that promotes quick recovery from impacts. 

Routine activities and accidental events would only impact a small portion of this habitat and be 

limited in size and scope as new plants rapidly replace the impacted plants, therefore, BOEM does 

not believe it is necessary to include an alternative excluding these areas.

Delay Leasing Until the State of the Gulf of Mexico Environmental Baseline is Known

This suggested alternative would address comments raised that the state of recovery of the 

Gulf of Mexico environmental baseline following the Deepwater Horizon explosion, oil spill, and 

response has not yet been fully determined and that BOEM should delay leasing until missing 

information is known, or at least for several years. The basis for this alternative is the concern that 

additional leasing could contribute to an incremental increase in the chance of another 

low-probability catastrophic oil spill or that cumulative impacts could have devastating environmental 

effects on an ecosystem that is still recovering from a previous event. It should be noted that, 

because of the dynamic nature of the Gulf of Mexico, the environmental baseline is not static and is 

constantly changing due to a variety of natural and anthropogenic factors. This would be true even if 

the Deepwater Horizon explosion, oil spill, and response had not occurred. This Multisale EIS has 

taken into account that there remains incomplete information and that an Agency will likely never 

have complete and perfect information available to it at the time of a decision. Throughout this 

Multisale EIS, BOEM has complied with the analytical requirements of 40 CFR § 1502.22 of the 

CEQ regulations, which allow an agency to evaluate the information that is available, disclose what 

information is incomplete or unavailable, and evaluate its relevance and importance to the 

underlying analysis. Thereafter, a Federal agency may proceed with a decision in light of the 

information that is available and applied using accepted methodologies. It should also be noted that 

this option of delaying leasing is already incorporated into the No Action Alternative that is analyzed 

in this Multisale EIS. At the time of the lease-sale decision, the Assistant Secretary for Land and 

Minerals Management can choose the No Action Alternative for any of the lease sales covered in 

this Multisale EIS. This would result in a delay of leasing, potentially until the next scheduled lease 

sale in the current Five-Year Program or beyond, where again the Assistant Secretary for Land and 

Minerals Management can choose the No Action Alternative.

In addition, credible scientific data regarding the potential short-term and long-term impacts 

of the Deepwater Horizon explosion, oil spill, and response on Gulf of Mexico resources has become

available through issuance of the PDARP/PEIS, but there remains information being developed 

through the Natural Resource Damage Assessment (NRDA) process and other sources. New 

information would include evaluation of restoration techniques to see if adjustments would be 

needed and BOEM’s Environmental Studies Program, as well as numerous studies by other Federal 
Alternatives Including the Proposed Actions 2-23

Mitigating measures 

considered in this NEPA 

document rely primarily on 

avoiding an impact altogether 

by not allowing certain actions 

or parts of an action.

and State agencies and academia. Nonetheless, the subject-matter experts that prepared this 

Multisale EIS acquired and used new scientifically credible information that was publicly available, 

determined that additional information was not available absent exorbitant expenditures or could not 

be obtained regardless of cost in a timely manner, and where gaps remained, exercised their best 

professional judgment to extrapolate baseline conditions and impact analyses using accepted 

methodologies based on credible information. This approach complies with the requirements of 

40 CFR § 1502.22 of the CEQ regulations regarding how agencies should address incomplete or 

unavailable information.

The references for Chapters 1-5 are dominated by scientific research. In the vast majority of 

these references, the methods used to conduct the research are spelled out. These references are 

publicly available and the “scientific methodologies of research and modeling” would be too 

extensive to detail in an EIS. However, in numerous places in this Multisale EIS, where it was 

considered important, specific methodologies were summarized. For example, the use of in-situ

fluorescence and oxygen measurements as proxies for oil concentration and biodegradation to track 

the subsurface plume of oil from the Deepwater Horizon explosion and oil spill was included in this 

Multisale EIS where appropriate.

In addition, BOEM’s catastrophic analysis, the Catastrophic Spill Event Analysis white paper, 

provides more information about general impacts of a low-probability catastrophic oil spill (USDOI, 

BOEM, 2017). A low-probability catastrophic oil spill is not reasonably foreseeable and not part of a 

proposed action; however, it should be noted that the catastrophic analysis is intended to be a 

general overview of the potential effects of a catastrophic spill and to complement the substantive 

analyses of reasonably foreseeable smaller accidental events (noncatastrophic) presented in the 

main body of the EIS. As such, the Catastrophic Spill Event Analysis white paper should be read 

with the understanding that further detail about oil impacts from more reasonably foreseeable 

accidents on a particular resource can be found in the main body of this Multisale EIS or previous 

relevant NEPA documents. Given the above, BOEM has determined that this suggested alternative 

does not require additional analysis in this Multisale EIS, distinct and apart from the No Action 

Alternative already considered.

2.2.4 What Types of Mitigating Measures Does BOEM Apply?

The NEPA process is intended to help public officials 

make decisions that are based on an understanding of 

environmental consequences and to take actions that protect, 

restore, and enhance the environment. Agencies are required to 

identify and include in an EIS those appropriate mitigating 

measures not already included in the proposed action or 

alternatives. The CEQ regulations (40 CFR § 1508.20) define 

mitigation as follows:
2-24 Gulf of Mexico Multisale EIS

• Avoidance—Avoiding an impact altogether by not taking a certain action or part 

of an action.

• Minimization—Minimizing impacts by limiting the intensity or magnitude of the 

action and its implementation.

• Restoration—Rectifying the impact by repairing, rehabilitating, or restoring the 

affected environment.

• Maintenance—Reducing or eliminating the impact over time by preservation and 

maintenance operations during the life of the action.

• Compensation—Compensating for the impact by replacing or providing substitute 

resources or environments.

BOEM considers the use of mitigation at all phases of energy development and planning, 

from the overarching Five-Year Program EIS, through each of the NEPA documents for the lease 

sales, and followed by more site-specific reviews for exploration, development and production, and 

platform removal plans (Figure 1-2). Mitigations can be applied at the prelease stage, typically 

through applying lease stipulations or at the postlease stage by applying site-specific mitigating 

measures to plans, permits, and/or authorizations (refer to Chapter 2.2.4.3). Through this approach, 

BOEM is able to analyze impacts and mitigations that are appropriate for consideration at the 

appropriate time.

2.2.4.1 Proposed Lease Mitigating Measures (Stipulations) 

The potential lease stipulations and mitigating measures included for analysis in this 

Multisale EIS were developed as a result of numerous scoping efforts for the continuing OCS 

Program in the Gulf of Mexico. The 10 lease stipulations described below would be considered at 

the prelease stage, as applicable, to any proposed lease sale. These measures will be considered 

for adoption by the ASLM under authority delegated by the Secretary of the Interior. The 

Topographic Features and Live Bottom (Pinnacle Trend) Stipulations have been adopted as 

programmatic mitigation in the 2017-2022 Five-Year Program EIS (USDOI, BOEM, 2016b) and, 

therefore, would apply to all leases issued under the 2017-2022 Five-Year Program in designated 

lease blocks. The analysis of the other eight stipulations for any particular alternative does not 

ensure that the ASLM will make a decision to apply the stipulations to leases that may result from 

any proposed lease sale nor does it preclude minor modifications in wording during subsequent 

steps in the prelease process if comments indicate changes are necessary or if conditions change. 

Any stipulations or mitigation requirements to be included in a proposed lease sale will be described 

in the Record of Decision for that proposed lease sale. Appendix D provides a more detailed 

analysis of the 10 lease stipulations and their effectiveness.
Alternatives Including the Proposed Actions 2-25

This stipulation has been 

adopted as programmatic 

mitigation in the 2017-2022 

Five-Year Program EIS and 

would apply to all leases 

issued under the 2017-2022 

Five-Year Program

This stipulation has been 

adopted as programmatic 

mitigation in the 2017-2022 

Five-Year Program EIS and 

would apply to all leases 

issued under the 2017-2022 

Five-Year Program

Topographic Features Stipulation

The topographic features located in the WPA and CPA 

provide habitat for coral-reef-community organisms (Chapter 

4.1.1.6). There are currently no identified topographic features 

protected under this stipulation in the EPA. The OCS oil- and 

gas-related activities resulting from a proposed action could 

have potentially major impacts on or near these communities if 

the Topographic Features Stipulation is not adopted and such 

activities are not otherwise mitigated. The blocks affected by the 

Topographic Features Stipulation are shown in Figure 2-4. 

The stipulation establishes No Activity Zones at the topographic features. Outside the No 

Activity Zones, additional restrictive zones are established where oil and gas operations could occur, 

but where drilling discharges would be shunted. Monitoring studies have demonstrated that the 

shunting requirements of the stipulations are effective in preventing the muds and cuttings from 

impacting the biota of the banks. The stipulation would prevent or minimize damage to the biota of 

the banks from routine OCS oil- and gas-related activities resulting from a proposed action, while 

allowing the development of nearby oil and gas resources, specifically as discussed in Appendix D. 

Live Bottom (Pinnacle Trend) Stipulation

For the purpose of this stipulation, “live bottom areas” 

are defined as seagrass communities or those areas that 

contain biological assemblages consisting of sessile 

invertebrates such as sea fans, sea whips, hydroids, anemones, 

ascidians, sponges, bryozoans, or corals living upon and 

attached to naturally occurring hard or rocky formations with 

rough, broken, or smooth topography; or areas whose lithotope 

favors the accumulation of turtles, fishes, and other fauna. Live 

bottom features may include pinnacle trend features, low-relief

features, or potentially sensitive biological features. This stipulation would be applied to protect 

pinnacle trend features (i.e., Live Bottom [Pinnacle Trend] Stipulation). The Live Bottom (Pinnacle 

Trend) Stipulation protects pinnacle trend features from routine OCS oil- and gas-related activity by 

distancing bottom-disturbing activity (e.g., anchors, chains, cables, and wire ropes) 30 m (100 ft) 

from hard bottoms/pinnacles. The Live Bottom (Pinnacle Trend) Stipulation is intended to protect 

live bottom features (Pinnacle Trend features) from damage and, at the same time, provide for the 

recovery of potential oil and gas resources. It is noted that blocks potentially subject to the Live 

Bottom (Low Relief) Stipulation are not included as part of the proposed action for this Multisale EIS; 

however, should any such blocks become available, the Live Bottom (Low Relief) Stipulation could 

be applied to protect these features.
2-26 Gulf of Mexico Multisale EIS

BOEM has effectively 

managed and avoided 

space-use conflicts with 

military activities in the Gulf of 

Mexico since the early 1970s. 

Military Areas Stipulation

The Military Areas Stipulation has been applied to all 

blocks leased in military areas since 1977 and reduces potential 

impacts, particularly in regards to safety, but it does not reduce 

or eliminate the actual physical presence of OCS oil- and 

gas-related operations in areas where military operations are 

conducted. The stipulation contains a “hold harmless” clause 

(holding the U.S. Government harmless in case of an accident 

involving military operations) and requires lessees to coordinate their activities with appropriate local 

military contacts. Figure 2-8 shows the military warning areas in the Gulf of Mexico.

Figure 2-8. Military Warning Areas and Eglin Water Test Areas in the Gulf of Mexico.

Evacuation Stipulation

This stipulation would be a part of any lease in the easternmost portion of the CPA and all 

blocks leased in the EPA portion of the proposed lease sale area resulting from a proposed action. 

An evacuation stipulation has been applied to all blocks leased in these areas since 2001. The 

Evacuation Stipulation is designed to protect the lives and welfare of offshore oil and gas personnel. 

The OCS oil- and gas-related activities have the potential to occasionally interfere with specific 

requirements and operating parameters for the lessee’s activities in accordance with the military 

stipulation clauses contained herein. If it is determined that the operations will result in interference 

with scheduled military missions in such a manner as to possibly jeopardize the national defense or 

to pose unacceptable risks to life and property, then a temporary suspension of operations and the 

evacuation of personnel may be necessary.
Alternatives Including the Proposed Actions 2-27

Coordination Stipulation

This stipulation would be a part of any lease in the easternmost portion of the CPA and all 

blocks leased in the EPA portion of the proposed lease sale area resulting from a proposed action. 

A coordination stipulation has been applied to all blocks leased in these areas since 2001. The 

Coordination Stipulation is designed to increase communication and cooperation between military 

authorities and offshore oil and gas operators. Specific requirements and operating parameters are 

established for the lessee’s activities in accordance with the military stipulation clauses. For 

instance, if it is determined that the operations will result in interference with scheduled military 

missions in such a manner as to possibly jeopardize the national defense or to pose unacceptable 

risks to life and property, then certain measures become activated and the OCS oil- and gas-related 

operations may be curtailed in the interest of national defense.

Blocks South of Baldwin County, Alabama, Stipulation

This stipulation would be included only on leases on blocks south of and within 15 mi (24 km) 

of Baldwin County, Alabama. The stipulation specifies requirements for consultation that lessees 

must follow when developing plans for fixed structures, with the goal of reducing potential visual 

impacts The stipulation has been continually adopted in annual CPA lease sales since 1999 and

has effectively mitigated visual impacts. 

Protected Species Stipulation

The Protected Species Stipulation has been applied to all blocks leased in the GOM since 

December 2001. This stipulation was developed in consultation with the U.S. Department of 

Commerce, National Oceanic and Atmospheric Administration, NMFS and the U.S. Department of

the Interior, FWS in accordance with Section 7 of the Endangered Species Act, and it is designed to 

minimize or avoid potential adverse impacts to federally protected species.

United Nations Convention on the Law of the Sea Royalty Payment Stipulation

Consistent with Article 82 of the 1982 United Nations Convention on the Law of the Sea 

(UNCLOS), there are 12 royalty payment lease provisions that would apply to applicable leases

should the United States becomes a party to the UNCLOS. These provisions would apply prior to or 

during the life of any lease issued by the United States on a block or portion of a block located 

beyond its Exclusive Economic Zone as defined in UNCLOS and subject to such conditions that the 

Senate may impose through its constitutional role of advice and consent.

Below Seabed Operations Stipulation

The Below Seabed Operations Stipulation language is intended to be lease sale-specific 

language and would incorporate maps of the potentially affected blocks containing rights-of-use and 

easements. This stipulation is designed to minimize or avoid potential space-use conflicts with 

moored and/or floating production facilities that have already been granted rights-of-use and 

easements in particular OCS blocks.
2-28 Gulf of Mexico Multisale EIS

Stipulation on the Agreement Between the United States of America and the United Mexican 

States Concerning Transboundary Hydrocarbon Reservoirs in the Gulf of Mexico 

(Transboundary Stipulation)

The “Agreement between the United States of America and the United Mexican States 

Concerning Transboundary Hydrocarbon Reservoirs in the Gulf of Mexico” (Agreement) was signed 

on February 20, 2012, and entered into force on July 18, 2014. The stipulation has been applied to 

blocks or portions of blocks located wholly or partially within the 3 statute miles (4.8 km) of the 

maritime or continental shelf boundary with Mexico. The stipulation incorporates by reference the 

Agreement and notifies lessees that, among other things, activities in this boundary area will be 

subject to the Agreement and that approval of plans, permits, and unitization agreements will be 

conditioned upon compliance with the terms of the Agreement. A copy of the Agreement can be 

found on BOEM’s website at http://www.boem.gov/BOEM-Newsroom/Library/BoundariesMexico.aspx.

Summary

These measures would be considered for adoption by the ASLM at the prelease stage, as 

applicable, under authority delegated by the Secretary of the Interior. The analysis of any 

stipulations for any particular alternative does not ensure that the ASLM will make a decision to 

apply the stipulations to leases that may result from any proposed lease sale nor does it preclude 

minor modifications in wording during subsequent steps in the prelease process if comments 

indicate changes are necessary or if conditions change.

Any stipulations or mitigation requirements to be included in a lease sale will be described in 

the Record of Decision for that lease sale. Mitigating measures in the form of lease stipulations are 

added to the lease terms and are therefore enforceable as part of the lease. In addition, each 

exploration and development plan, as well as any permits and pipeline applications related to leases 

issued as a result of a lease sale, will undergo a NEPA review, and additional project-specific 

mitigations applied as conditions of plan or permit approval at the postlease stage. The BSEE has 

the authority to monitor and enforce these conditions under 30 CFR part 250 subpart N and may 

seek remedies and penalties from any operator that fails to comply with those conditions, 

stipulations, and mitigating measures.

2.2.4.2 Prelease Mitigating Measures (Stipulations) by Alternative

Table 2-1 indicates what stipulations could be applied for each alternative. Alternative D 

would consider the same stipulations as Alternative A, B, or C, as applicable, with the exception of 

removing the Topographic Features and Live Bottoms (Pinnacle Trend) Stipulations since all blocks 

subject to these stipulations would not be made available. Since Alternative E is the cancellation of 

a proposed lease sale, no stipulations would apply.
Alternatives Including the Proposed Actions 2-29

Mitigating measures are a 

standard part of BOEM’s program 

to ensure that operations are 

always conducted in an 

environmentally sound manner.

Table 2-1. Applicable Stipulations by Alternative. (Stipulations that would apply to specific lease blocks 

under any given alternative are marked with an X. Stipulations that would not apply are 

marked “–”. Because Alternative E would cancel a proposed lease sale, no leasing activities 

would occur and, therefore, no stipulations would apply.)

Stipulation Alternative A Alternative B Alternative C Alternative D Alternative E

Topographic 

Features X X X – – 

Live Bottoms X X – – –

Military Areas X X X X – 

Evacuation X X – See A, B, or C –

Coordination X X – See A, B, or C – 

Blocks South of 

Baldwin County, 

Alabama

X X – See A, B, or C – 

Protected Species X X X X –

United Nations 

Convention on the 

Law of the Sea 

Royalty Payment

X X X X – 

Below Seabed 

Operations X X – See A, B, or C – 

Transboundary X X X X – 

2.2.4.3 Postlease Mitigating Measures

Postlease mitigating measures have been 

implemented for over 40 years in the Gulf of Mexico region, 

as they relate to OCS plans and pipeline applications. 

Following a lease sale, an applicant seeks approvals to 

develop their lease by preparing and submitting OCS 

plans. The OCS plans are reviewed by BOEM and, 

depending on what is proposed to take place in a specific 

place, BOEM may assign conditions of approval on the plan. The conditions of approval become 

part of the approved postlease authorization and include environmental protections, requirements 

that maintain conformance with law, requirements of other agencies having jurisdiction, or safety 

precautions. Mitigating measures are an integral part of BOEM’s program to ensure that postlease 

operations are conducted in an environmentally sound manner (with an emphasis on minimizing any 

adverse impact of routine operations on the environment). For example, certain measures ensure 

site clearance, and survey procedures are carried out to determine potential snags to commercial 

fishing and avoidance of archaeological sites and biologically sensitive areas such as pinnacles, 

topographic features, and chemosynthetic communities. 

BOEM analyzes impacts on a finer geographic scale and mitigations that are appropriate for 

consideration through site-specific environmental reviews. This chapter discusses mitigating 
2-30 Gulf of Mexico Multisale EIS

measures that could be applied by BOEM during site-specific plan and/or permit reviews. 

Appendix A discusses BOEM’s rigorous postlease processes and Appendix B describes over 

120 standard mitigations that may be required by BOEM or BSEE as a result of plan and permit 

review processes for the Gulf of Mexico OCS Region.

Mitigating measures have been proposed, identified, evaluated, or developed through 

previous BOEM lease sale and site-specific NEPA reviews and analyses. Many of these mitigating 

measures have been adopted and incorporated into regulations and/or as guidelines governing OCS 

exploration, development, and production activities. All plans for OCS oil- and gas-related activities 

(e.g., exploration and development plans, pipeline applications, and structure-removal applications) 

go through rigorous BOEM review and approval to ensure compliance with established laws and 

regulations. Existing mitigating measures must be incorporated and documented in plans submitted 

to BOEM. Operational compliance of the mitigating measures is enforced through BSEE’s onsite 

inspection program.

Some BOEM-identified mitigating measures are incorporated into OCS oil- and gas-related 

operations through cooperative agreements or efforts with industry and State and Federal agencies. 

These mitigating measures include NMFS’ Observer Program to protect marine mammals and sea 

turtles during explosive removals, labeling operational supplies to track possible sources of debris or 

equipment loss, development of methods of pipeline landfall to eliminate impacts to beaches or 

wetlands, and beach cleanup events.

Site-specific mitigating measures are also applied by BOEM during plan and permit reviews. 

BOEM realized that many of these site-specific mitigations were recurring and developed a list of 

commonly applied “standard” mitigations. There are currently over 120 standard mitigations. The 

wording of a standard mitigation is developed by BOEM in advance and may be applied whenever 

conditions warrant. Standard mitigation text is revised as often as is necessary (e.g., to reflect 

changes in regulatory citations, agency/personnel contact numbers, and internal policy). Categories 

of site-specific mitigations include the following: air quality; archaeological resources; artificial reef

material; chemosynthetic communities; Flower Garden Banks; topographic features; hard 

bottoms/pinnacles/potentially sensitive biological features; military warning areas and Eglin Water 

Test Areas; hydrogen sulfide; drilling hazards; remotely operated vehicle surveys; geophysical 

survey reviews; and general safety concerns. Site-specific mitigation “types” include the following: 

advisories; conditions of approval; hazard survey reviews; inspection requirements; notifications; 

post-approval submittals; and safety precautions. In addition to standard mitigations, BOEM may 

also apply nonrecurring mitigating measures that are developed on a case-by-case basis. Refer to 

Appendix B (“Commonly Applied Mitigating Measures”) for more information on the mitigations that 

BOEM and BSEE typically apply to plans and/or permits.

BOEM is continually revising applicable mitigations to allow the Gulf of Mexico OCS Region 

to more easily and routinely track mitigation compliance and effectiveness. A primary focus of this 

effort is requiring post-approval submittal of information within a specified timeframe or after a 
Alternatives Including the Proposed Actions 2-31

triggering event (e.g., end of operations reports for plans, construction reports for pipelines, and 

removal reports for structure removals).

2.2.5 What are the Primary Topics and Resources Being Evaluated?

Issues are defined by CEQ to represent those principal “effects” that an EIS should evaluate 

in-depth. Scoping identifies specific environmental resources and/or activities rather than “causes” 

as significant issues (CEQ, 1981). The analysis in the EIS can then show the degree of change 

from the present conditions for each issue to the actions related to a proposed action.

Selection of environmental and socioeconomic issues to be analyzed was based on the 

following criteria:

• issue is identified in CEQ regulations as subject to evaluation;

• the relevant resource/activity was identified through agency expertise, through 

the scoping process, or from comments on past EISs;

• the resource/activity may be vulnerable to one or more of the impact-producing 

factors associated with the OCS Program;

• a reasonable probability of an interaction between the resource/activity and 

impact-producing factor should exist; or

• information that indicates a need to evaluate the potential impacts to a 

resource/activity has become available.

2.2.5.1 Issues to be Analyzed

The following issues relate to potential impact-producing factors and the resources and 

activities that could be affected by OCS exploration, development, production, and transportation 

activities.

Accidental Events: Concerns were raised related to the potential impact of oil spills, 

including the Deepwater Horizon explosion, oil spill, and response, on the marine and coastal 

environments, specifically regarding the potential effects of oil spills on tourism, emergency 

response capabilities, spill prevention, effect of winds and currents on the transport of oil spills, 

accidental discharges from both deepwater losses of well control and pipeline ruptures, and oil spills 

resulting from past and future hurricanes. Other concerns raised over the years of scoping were the 

fate and behavior of oil spills, availability and adequacy of oil-spill containment and cleanup 

technologies, oil-spill cleanup strategies, impacts of various oil-spill cleanup methods, effects of 

weathering on oil spills, toxicological effects of fresh and weathered oil, air pollution associated with 

spilled oil, and short-term and long-term impacts of oil on wetlands. 

After the Deepwater Horizon explosion, oil spill, and response, BOEM prepared a 

“Catastrophic Spill Event Analysis,” which was previously included as an appendix to the 2012-2017 
2-32 Gulf of Mexico Multisale EIS

WPA/CPA Multisale EIS and the subsequent Supplemental EISs. This analysis has since been 

published as an independent white paper and can be found on BOEM’s website (USDOI, BOEM, 

2017). The purpose of this technical analysis is to assist BOEM in the preparation of robust 

environmental analyses of the proposed actions. The CEQ guidance addresses impacts with 

catastrophic consequences in the context of evaluating reasonably foreseeable significant adverse 

effects in an EIS when they address the issue of incomplete or unavailable information (40 CFR § 

1502.22). “‘Reasonably foreseeable’ impacts include impacts which have catastrophic 

consequences even if their probability of occurrence is low, provided that the analysis of the impacts 

is supported by credible scientific evidence, is not based on pure conjecture, and is within the rule of 

reason” (40 CFR § 1502.22(b)(4)). Therefore, this analysis, which is based on credible scientific 

evidence, identifies the most likely and most significant impacts from a high-volume blowout and oil 

spill that continues for an extended period of time. Such a catastrophic event is not reasonably 

foreseeable and not part of a proposed action; but, in line with CEQ guidance (CEQ, 2010), the 

reasonably foreseeable impacts that could result in the exceedingly unlikely event that such a spill 

were to occur are analyzed in the Catastrophic Spill Event Analysis white paper (USDOI, BOEM, 

2017). The scenario and impacts discussed in this analysis should not be confused with the 

scenario and impacts anticipated to result from routine activities or more reasonably foreseeable 

smaller accidental events of a proposed action.

Drilling Fluids and Cuttings: Specific concerns related to drilling fluids include impacts on 

water quality from the presence of mercury, synthetic-based drilling fluids (SBFs) and large volumes 

of industrial chemicals necessary for deepwater drilling operations, and potential for persistence of 

drilling muds and cuttings. Other concerns raised over the years of scoping were potential 

smothering of benthic communities by offshore disposal of drilling fluids and cuttings, the use and 

disposal of drilling fluids including potential spills of oil-based drilling fluids (OBFs), onshore disposal 

of OBFs, the fate and effects of SBFs in the marine environment, and the potential toxic effects or 

bioaccumulation of trace metals in drilling fluids discharged into the marine environment.

Visual and Aesthetic Interference: Lighting was raised as a specific concern. Concerns 

raised over the years of scoping were the potential effects of the presence of drilling rigs and 

platforms, service vessels, helicopters, trash and debris, and flaring on visual aesthetics.

Air Emissions: The potential effects of emissions of combustion gases from platforms, drill 

rigs, service vessels, and helicopters have been raised as an issue over the years of scoping. Also 

under consideration are the flaring of produced gases during extended well testing and the potential 

impacts of the transport of production with associated hydrogen sulfide (H2S).

Water Quality Degradation: Issues related to water quality degradation raised over the years 

of scoping most often were associated with operational discharges of drilling muds and cuttings, 

produced waters, and domestic wastes. Water quality issues also included concerns related to 

impacts from sediment disturbance, petroleum spills and blowouts, and discharges from service 

vessels.
Alternatives Including the Proposed Actions 2-33

Other Wastes: Other concerns raised over the years of scoping include storage and 

disposal of trash and debris, and trash and debris on recreational beaches.

Structure and Pipeline Emplacement: Some of the issues raised over the years of scoping 

related to structure and pipeline emplacement are bottom area disturbances from bottom-founded 

structures or anchoring, sediment displacement related to pipeline burial, space-use conflicts, and 

the vulnerability of offshore pipelines to damage that could result in hydrocarbon spills or H2S leaks.

Platform Removals: Concerns were raised over the years of scoping about the 

abandonment of operations include how a platform is removed, the potential impacts of explosive 

severance and removals on marine organisms, the remaining operational debris snagging fishing 

nets, and site-clearance procedures.

OCS Oil- and Gas-Related Support Services, Activities, and Infrastructure: Specific issues 

were damage to coastal infrastructure by past hurricane activity and the vulnerability of coastal 

infrastructure to damage from future hurricanes. Concerns raised over the years of scoping include 

activities related to the shore-based support of the development and production plan include vessel 

and helicopter traffic and emissions, construction or expansion of navigation channels or onshore 

infrastructure, maintenance and use of navigation channels and ports, and deepening of ports.

Sociocultural and Socioeconomic: Many concerns have focused on the potential impacts to 

coastal communities, including demands on public services and tourism. Issues raised from years of 

scoping include impacts on employment, population fluctuations, effects on land-use impacts to 

low-income or minority populations, and cultural impacts.

Geological and Geophysical Activities: Specific issues were noise impacts related to seismic 

airgun surveys on marine mammals, sea turtles, fisheries, and other resources. Other concerns 

include vessel strikes with marine mammals and sea turtles, as well as concerns regarding potential 

space-use conflicts.

Other Issues: Many other issues have been identified. Several of these issues are subsets 

or variations of the issues listed above. All are taken under advisement and are considered in the 

analyses, if appropriate. Additional issues raised during scoping are consideration of the extensive 

safety improvements implemented since the Deepwater Horizon explosion, oil spill, and response; 

noise from platforms, vessels, and helicopters; turbidity as a result of seafloor disturbance or 

discharges; and damage to biota and habitats.

Resource Topics Analyzed in This Multisale EIS: The analyses in Chapters 4.1-4.5 address 

the issues and concerns identified above under the following resource topics:
2-34 Gulf of Mexico Multisale EIS

− Air Quality

− Water Quality (Coastal and Offshore)

− Coastal Habitats (Estuarine Systems and 

Coastal Barrier Beaches and Associated 

Dunes) 

− Deepwater Benthic Communities 

(Chemosynthetic and Deepwater Coral) 

− Sargassum and Associated Communities

− Live Bottoms (Topographic Features, 

Pinnacles, and Low-Relief Features)

− Fishes and Invertebrate Resources

− Birds

− Protected Species (ESA Listed Marine 

Mammals, Sea Turtles, Beach Mice, 

Protected Birds, and Protected Corals) 

− Commercial Fisheries

− Recreational Fishing

− Recreational Resources

− Archaeological Resources (Historic and 

Prehistoric)

− Human Resources and Land Use 

(Land Use and Coastal Infrastructure,

Economic Factors, and Social Factors, 

Including Environmental Justice)

2.2.5.2 Issues Considered but Not Analyzed

As previously noted, the CEQ regulations for implementing NEPA instruct agencies to adopt 

an early process (termed “scoping”) for determining the scope of issues to be addressed and for 

identifying significant issues related to a proposed action. As part of this scoping process, agencies 

shall identify and eliminate from detailed study the issues that are not significant to the proposed 

action or have been covered by prior environmental review.

Through our scoping efforts, numerous issues and topics were identified for consideration in 

this Multisale EIS. The following categories were considered not to be significant issues related to a 

proposed action or have been covered by prior environmental review.

Program and Policy Issues

Comments and concerns that relate to program and policy are issues under the direction of 

the U.S. Department of the Interior and/or BOEM’s guiding regulations, statutes, and laws. The 

comments and concerns related to program and policy issues are not considered to be specifically 

related to the proposed actions. For example, the Louisiana Department of Natural Resources, 

Office of Coastal Management requested that this Multisale EIS make provisions for compensatory 

mitigation for all lease sale impacts. Such comments are forwarded to the appropriate program 

offices for their consideration. Programmatic issues including expansion of the proposed lease sale 

area, administrative boundaries, and royalty relief have been considered in the preparation of the 

Five-Year Program EIS (USDOI, BOEM, 2016b).

Revenue Sharing

A number of comments were received on previous EISs from State and local governments, 

interest groups, and the general public stating that locally affected communities should receive an 

increased share of revenues generated by the OCS oil and gas leasing program. In particular to the 

GOM, Louisiana reiterated continued concerns that Louisiana’s coastal wetlands are 

disproportionately bearing the impacts from OCS oil- and gas-related activities and that BOEM 

should make provisions for appropriate compensatory mitigation related to OCS lease sale activities. 
Alternatives Including the Proposed Actions 2-35

Comments and concerns that relate to the use and distribution of revenues are issues under the 

direction of the U.S. Congress or the Department of the Interior and their guiding regulations, 

statutes, and laws.

On October 1, 2010, the revenue collection function of the Minerals Management Service 

(BOEM’s predecessor) became the independent Office of Natural Resource Revenue. The Office of 

Natural Resource Revenue distributes revenues collected from Federal mineral leases to 

special-purpose funds administered by Federal agencies, to States, and to the General Fund of the 

U.S. Department of the Treasury. Legislation and regulations provide formulas for the disbursement 

of these revenues. With the enactment of GOMESA, the Gulf producing States (i.e., Texas, 

Louisiana, Mississippi, and Alabama) and their coastal political subdivisions (CPSs) were granted an 

increased share of offshore oil and gas revenue. Beginning in FY 2007, and thereafter, Gulf 

producing States and their CPSs received 37.5 percent of the qualified OCS revenue from new 

leases, including bonus bids, rentals, and production royalty, issued in the 181 Area in the EPA and 

in the 181 South Area, which is located from 100 mi (161 km) offshore from the Alabama-Florida 

State line and over 285 mi (459 km) from Tampa, Florida. Beginning in FY 2017 and through 2055, 

GOM producing States and their CPSs will receive 37.5 percent and the Land and Water 

Conservation Fund will receive 12.5 percent of qualified OCS revenue from new leases in the 

existing areas available for leasing, subject to a $500 million cap. The remaining 50 percent of 

qualified OCS revenues and revenues exceeding the $500 million cap will be distributed to the U.S. 

Treasury.

The socioeconomic benefits and impacts to local communities are analyzed in 

Chapter 4.1.1.23.3.

2.3 COMPARISON OF IMPACTS BY ALTERNATIVE

The full analyses of the potential impacts of routine activities and accidental events 

associated with a proposed action and a proposed action’s incremental contribution to the 

cumulative impacts are described in the individual resource discussions in Chapter 4. Table 2-2

provides a comparison of expected impact levels by alternative and is derived from the analysis of 

each resource in Chapter 4. The impact level ratings have been specifically tailored and defined for 

each resource within the Chapter 4 impact analysis. Cumulative impacts of current and past 

activities, however, would continue to occur under Alternative E. 
2-36 Gulf of Mexico Multisale EIS

Table 2-2. Alternative Comparison Matrix.

Impact Level Key1

Beneficial2 Negligible Minor Moderate Major

Alternative

Resource A B C D E

Air Quality Minor Minor Minor Minor None

Water Quality Negligible Negligible Negligible Negligible None

Coastal Habitats

Estuarine 

Systems Moderate Moderate Minor Moderate Negligible

Coastal Barrier 

Beaches and 

Associated 

Dunes

Minor Minor

Negligible to Negligible to

Negligible

Minor Minor

Deepwater Benthic 

Communities Negligible Negligible Negligible Negligible None

Sargassum and 

Associated 

Communities

Negligible Negligible Negligible Negligible None

Live Bottoms

Topographic 

Features Negligible Negligible Negligible Negligible None

Pinnacles and 

Low-Relief

Features

Negligible to Negligible to Negligible Negligible None

Minor Minor

Fishes and 

Invertebrate 

Resources

Minor Minor Minor Minor None

Birds Moderate Moderate Moderate Moderate None

Protected Species

Marine Mammals Negligible Negligible Negligible Negligible None

Sea Turtles Negligible Negligible Negligible Negligible None

Beach Mice Negligible Negligible Negligible Negligible None

Protected Birds Negligible Negligible Negligible Negligible None

Protected Corals Negligible Negligible Negligible Negligible None

Commercial 

Fisheries

Beneficial to Beneficial to Beneficial to Beneficial to Negligible Minor Minor Minor Minor

Recreational 

Fishing

Beneficial to Beneficial to Beneficial to Beneficial to Negligible Minor Minor Minor Minor

Recreational 

Resources

Beneficial to Beneficial to Beneficial to Beneficial to Negligible Minor Minor Minor Minor

Archaeological 

Resources Negligible3 Negligible3 Negligible3 Negligible3 None
Alternatives Including the Proposed Actions 2-37

Impact Level Key1

Beneficial2 Negligible Minor Moderate Major

Alternative

Resource A B C D E

Human Resources

and Land Use

Land Use and 

Coastal 

Infrastructure

Economic 

Factors

Minor Minor Minor Minor None

Beneficial to Beneficial to Beneficial to Beneficial to Negligible to

Minor Minor Minor Minor Minor

Social Factors 

(including 

Environmental 

Justice)

Minor Minor Minor Minor None

Note: Some resources have a range for the impact levels to account for certain variables such as the 

uncertainty of non-OCS oil- or gas-related activities, the level and magnitude of potential 

accidental events, and the minimization of the OCS oil- or gas-related impacts through lease 

stipulations, mitigations, and/or regulations. The impact level ratings have been specifically 

tailored and defined for each resource within the Chapter 4 impact analysis.

1 The findings for Alternatives A-D would be the incremental contribution of a proposed action to what 

would be expected to occur under the No Action Alternative (i.e., no lease sale). Therefore, each 

impact determination under Alternatives A-D assumes that the conditions and impacts (i.e., past, 

present, and future activities) under the No Action Alternative would be present.

2 The level of beneficial impacts is specified in the analysis, which could range from low, medium, or 

high.

3 The level of impacts for archaeological resources ranges between negligible to major and is dependent 

upon whether survey is performed, mitigation is imposed, mitigation is followed, or a site is identified 

prior to the activity.

2.4 SUMMARY OF IMPACTS

Presented here is an overall summary of impacts for each resource. A more detailed 

analysis of impacts for each resource from a proposed action is presented in Chapter 4. 

2.4.1 Air Quality

Air quality is the degree at which the ambient air is free of pollution; it is assessed by 

measuring the pollutants in the air. To protect public health and welfare, the Clean Air Act 

established National Ambient Air Quality Standards (NAAQS) for certain common and widespread 

pollutants. The six common "criteria pollutants" are particle pollution (also known as particulate 

matter, PM2.5 and PM10), carbon monoxide (CO); nitrogen dioxide (NO2); sulfur dioxide (SO2); lead 

(Pb); and ozone (O3). Air emissions from OCS oil and gas development in the Gulf of Mexico would 

arise from emission sources related to drilling and production with associated vessel support, flaring

and venting, decommissioning, fugitive emissions, and oil spills. Associated activities that take place 

as a result of a proposed action support and maintain the OCS oil and gas platform sources. Air 

emissions from non-OCS oil- and gas-related emissions in the Gulf of Mexico would arise from 

emission sources related to State oil and gas programs, onshore industrial and transportation 
2-38 Gulf of Mexico Multisale EIS

sources, and natural events. Since the primary National Ambient Air Quality Standards are 

designed to protect human health, BOEM focuses on the impact of these activities on the States, 

where there are permanent human populations.

In the “Air Quality Modeling in the Gulf of Mexico Region” study (Appendices F-H), 

photochemical grid modeling was conducted to assess the impacts to nearby states of existing and 

proposed future OCS oil and gas exploration, development, and production. This draft interim 

assessment is being used to disclose potential cumulative and incremental air quality impacts of the 

proposed lease sales; the final results are expected in fall 2017. The air quality modeling study 

examines the potential impacts of the proposed lease sales with respect to the NAAQS for the 

criteria pollutants O3, NO2, SO2, CO, PM2.5, PM10; the air quality-related values (AQRVs), including 

visibility and acid deposition (sulfur and nitrogen) in nearby Class I and sensitive Class II areas; and 

the incremental impacts of Prevention of Significant Deterioration (PSD) pollutants (NO2, PM10, 

PM2.5) with respect to PSD Class I and Class II increments. (Note: This analysis does not constitute 

a regulatory PSD increment consumption analysis as would be required for major sources subject to 

the New Source Review program requirements of the Clean Air Act). An assessment of the final 

study results will be discussed in future NEPA documents.

A regionwide lease sale has not previously been analyzed and historic trend data are limited. 

In the scenario in Chapter 3.1, the projected activities of a single regionwide lease sale is based on 

a range of historic observations and provides a reasonable expectation of oil and gas production 

anticipated from a single proposed lease sale. The projected activities of 10 proposed regionwide 

lease sales’ mid-case scenario, which was used in the model, falls within the range of a single 

proposed lease sale. To understand how these results would apply to a single proposed lease sale, 

the level of projected activity was compared between the modeled highest year of the 10 proposed 

lease sales to a single proposed lease sale. This is conservative because the current price of oil 

equals the low range of the scenario. Using these assumptions, the potential impacts of a single 

proposed lease sale would be minor. More specifically, the potential impacts of a single proposed 

lease sale to the Breton Wilderness Area would be moderate, whereas the overall potential impacts 

of a single proposed lease sale would be minor for all other areas. However, since these potential 

impacts are conservative given the current prices of oil and gas, BOEM anticipates future modeling. 

A full analysis of air quality can be found in Chapter 4.1. 

The incremental contribution of a proposed lease sale to the cumulative impacts would most 

likely have a minor effect on coastal nonattainment areas because most impacts on the affected 

resource could be avoided with proper mitigation. Portions of the Gulf Coast onshore areas have 

ozone levels that exceed the Federal air quality standard, but the incremental contribution from a 

proposed lease sale would be very small and would not on their own cause an exceedance.

As previously stated, BOEM contracted an air quality modeling study in the GOM region to 

assess the impacts of OCS oil- and gas-related development to nearby States, as required under the 

OCSLA. The data from forecasted emissions resulting from the 10 proposed lease sales was 

annualized using BOEM’s Resource Evaluation’s mid-case scenario. These results are presented in 
Alternatives Including the Proposed Actions 2-39

Appendices F-H. The cumulative impacts from all 10 proposed lease sales would be minor to 

moderate. More specifically, the cumulative impacts of 10 proposed lease sales to the Breton 

Wilderness Area and Gulf Islands National Seashore would be moderate, whereas the overall 

cumulative impacts of 10 proposed lease sales would be minor to moderate. 

The cumulative impacts, in addition to the past, present, and future activities, of 10 proposed 

lease sales would most likely have a moderate effect on coastal nonattainment areas for certain 

pollutants. Portions of the Gulf Coast onshore areas have ozone levels that exceed the Federal air 

quality standard, but the cumulative impacts from 10 proposed lease sales do not on their own 

cause an exceedance. A full analysis of air quality can be found in Chapter 4.1. 

2.4.2 Water Quality

Water quality is a term used to describe the condition or environmental health of a waterbody 

or resource, reflecting its particular biological, chemical, and physical characteristics and the ability 

of the waterbody to maintain the ecosystems it supports and influences. It is an important measure 

for both ecological and human health. The impacts of OCS Program-related routine operational 

discharges (Chapter 3.1.5.1) on water quality are considered negligible (beyond 1,000 m [3,281 ft]) 

to moderate (within 1,000 m [3,281 ft]) of the source. The potential impacts from OCS Programrelated oil spills on water quality are considered moderate, even with the implementation of

mitigating measures. This is because activities to address oil spills may cause secondary impacts to 

water quality, such as the introduction of additional hydrocarbons into the dissolved phase through 

the use of dispersants and the sinking of hydrocarbon residuals from burning. The impacts from a 

proposed action are a small addition to the cumulative impacts on water quality when compared with 

inputs from hypoxia, potentially leaking shipwrecks, chemical weapon dumpsites, natural oil seeps, 

and natural turbidity. The incremental contribution of the routine activities and accidental events 

associated with a proposed action to the cumulative impacts on water quality is expected to be 

negligible for any of the action alternatives. For Alternative E, the cancellation of a proposed lease 

sale would result in no new activities associated with a proposed lease sale; therefore, the 

incremental impacts would be none. A full analysis of water quality can be found in Chapter 4.2. 

2.4.3 Coastal Habitats

2.4.3.1 Estuarine Systems (Wetlands and Seagrasses/Submerged Vegetation) 

The estuarine system is the transition zone between freshwater and marine environments. It

can consist of many habitats, including wetlands and submerged vegetation. The impacts to these 

habitats from routine activities associated with a proposed action are expected to be minor to 

moderate. Minor impacts would be due to the projected low probability for any new pipeline

landfalls (0-1 projected), the minimal contribution to the need for maintenance dredging, and the 

mitigating measures expected to be used to further reduce or avoid these impacts (e.g., the use of 

modern techniques such as directional drilling). However, impacts caused by vessel operations 

related to a proposed action over 50 years would be moderate considering the permanent loss of 

hundreds of acres of wetlands. Overall, impacts to estuarine habitats from oil spills associated with 
2-40 Gulf of Mexico Multisale EIS

activities related to a proposed action would be expected to be minor because of the distance of 

most postlease activities from the coast, the expected weathering of spilled oil over that distance, the 

projected low probability of large spills near the coast, the resiliency of wetland vegetation, and the 

available cleanup techniques.

Cumulative impacts to estuarine habitats are caused by a variety of factors, including the 

OCS oil- and gas-related and non-OCS oil- and gas-related activities outlined in Chapter 4.3.1 and 

human and natural impacts. Development pressures in the coastal regions of the GOM have been 

largely the result of tourism and residential beach-side development, and this trend is expected to 

continue. Storms will continue to impact the coastal habitats and have differing impacts. The 

incremental contribution of a proposed action to the cumulative impacts on estuarine habitats is 

expected to be minor to moderate depending on the selected alternative. For Alternative E, the 

cancellation of a proposed lease sale would result in no new activities associated with a proposed 

lease sale. There could, however, be some incremental increase in impacts caused by a 

compensatory increase in imported oil and gas to offset reduced OCS production, but it would likely 

be negligible. A full analysis of estuarine habitats can be found in Chapter 4.3.1. 

2.4.3.2 Coastal Barrier Beaches and Associated Dunes

The coastal barrier beaches and associated dunes are those beaches and dunes that line 

the coast of the northern GOM, including both barrier islands and beaches on the mainland. The 

impacts to coastal barrier beaches and dunes from routine activities associated with a proposed 

action are expected to be minor due to the minimal number of projected onshore pipelines, the 

minimal contribution to vessel traffic and to the need for maintenance dredging, and the mitigating 

measures that would be used to further reduce or avoid these impacts. The greater threat from an 

oil spill to coastal beaches is from a coastal spill as a result of a nearshore vessel accident or 

pipeline rupture, and cleanup activities. Overall, impacts to coastal barrier beaches and dunes from 

oil spills associated with OCS oil- and gas-related activities related to a proposed action would be 

expected to be minor because of the distance of most of the resulting activities from the coast, 

expected weathering of spilled oil, projected low probability of large spills near the coast, and 

available cleanup techniques. Cumulative impacts to coastal barrier beaches and dunes are caused 

by a variety of factors, including the OCS oil- and gas-related and non-OCS oil- and gas-related 

activities outlined in Chapter 4.3.2 and other human and natural impacts. Development pressures in 

the coastal regions of the GOM have been largely the result of tourism and residential beach-side 

development, and this trend is expected to continue. Efforts to stabilize the GOM shoreline can 

deprive natural restoration of the barrier beaches through sediment nourishment and sediment 

transport, which have adversely impacted coastal beach landscapes. Storms will continue to impact 

the coastal habitats and have differing impacts. The incremental contribution of a proposed action to 

the cumulative impacts on coastal barrier beaches and dunes is expected to be minor. Under 

Alternative E, the cancellation of a proposed lease sale, the resulting additional impacts to coastal 

barrier beaches and dunes would be negligible; however, cumulative impacts from all sources, 

including OCS and non-OCS sources, would be the same as Alternative A. A full analysis of coastal

barrier beaches and associated dunes can be found in Chapter 4.3.2. 
Alternatives Including the Proposed Actions 2-41

2.4.4 Deepwater Benthic Communities

BOEM defines “deepwater benthic communities” as including both chemosynthetic 

communities (chemosynthetic organisms plus seep-associated fauna) and deepwater coral

communities (deepwater coral plus associated fauna). These communities are typically found in 

water depths of 984 ft (300 m) or deeper throughout the GOM. Deepwater benthic habitats are 

relatively rare compared with ubiquitous soft bottom habitats. 

The OCS oil- and gas-related, impact-producing factors for deepwater benthic communities 

can be grouped into three main categories: (1) bottom-disturbing activities; (2) drilling-related 

sediment and waste discharges; and (3) noncatastrophic oil spills. These impact-producing factors 

have the potential to damage individual deepwater habitats and disrupt associated benthic 

communities if insufficiently distanced or otherwise mitigated. However, impacts from individual 

routine activities and accidental events are usually temporary, highly localized, and expected to 

impact only small numbers of organisms and substrates at a time. Moreover, use of the expected 

site-specific plan reviews/mitigations will distance activities from deepwater benthic communities, 

greatly diminishing the potential effects. Therefore, at the regional, population-level scope of this 

analysis and assuming adherence to all expected regulations and mitigations, the incremental 

contribution would be expected to be negligible for any of the action alternatives. Proposed OCS 

oil- and gas-related activities would also contribute incrementally to the overall OCS and non-OCS 

cumulative effects experienced by deepwater benthic communities and habitats. The OCS oil- and 

gas-related cumulative impacts to deepwater benthic communities are estimated to be negligible to 

minor. Under Alternative E, the potential for impacts would be none because new impacts to 

deepwater benthic communities related to a cancelled lease sale would be avoided entirely. A full 

analysis of deepwater benthic communities can be found in Chapter 4.4. 

2.4.5 Sargassum and Associated Communities

Sargassum in the GOM is comprised of S. natans and S. fluitans (Lee and Moser, 1998; 

Stoner, 1983; Littler and Littler, 2000) and is characterized by a brushy, highly branched thallus with 

numerous leaf-like blades and berrylike pneumatocysts (Coston-Clements et al., 1991; Lee and 

Moser, 1998; Littler and Littler, 2000). The Sargassum cycle is expansive, encompassing most of 

the western Atlantic Ocean and the Gulf of Mexico with the growth, death, and decay of these plant 

and epiphytic communities, which may play a substantial role in the global carbon cycle (Gower and 

King, 2008). Several impacting factors can affect Sargassum, including vessel-related operations, 

oil and gas drilling discharges, operational discharges, accidental spills, non-OCS oil- and 

gas-related vessel activity, and coastal water quality. Routine vessel operations and accidental 

events that occur during drilling operations or vessel operations, and oiling due to an oil spill were 

the impact-producing factors that could be reasonably expected to impact Sargassum populations in 

the GOM. All of these impact-producing factors would result in the death or injury to the Sargassum 

plants or to the organisms that live within or around the plant matrix. However, the unique and 

transient characteristics of the life history of Sargassum and the globally widespread nature of the 

plants and animals that use the plant matrix buffer against impacts that could occur at any given 

location. Impacts to the overall population of the Sargassum community are therefore expected to 
2-42 Gulf of Mexico Multisale EIS

be negligible from either routine activities or reasonably foreseeable accidental events for any of the 

action alternatives. The incremental impact of the proposed action on the population of Sargassum 

would be negligible when considered in the context of cumulative impacts to the population. Under 

Alternative E, a proposed lease sale would be cancelled and the potential for impacts from routine 

activities and accidental events would be none. Impacts from changing water quality would be 

much more influential on Sargassum than OCS development and would still occur without the 

presence of OCS oil- and gas-related activities. A full analysis of Sargassum and associated 

communities can be found in Chapter 4.5. 

2.4.6 Live Bottoms

2.4.6.1 Topographic Features

Defined topographic features (Chapter 4.6.1) are a subset of GOM live bottom habitats that 

are large enough to have an especially important ecological role, with specific protections defined in 

the proposed Topographic Features Stipulation. Within the Gulf of Mexico, BOEM has identified 

37 topographic features where some degree of protection from oil and gas development may be 

warranted based on geography and ecology. Of all the possible impact-producing factors, it was 

determined that bottom-disturbing activities associated with drilling, exploration, and vessel 

operations were the only impact-producing factors from routine activities that could be reasonably 

expected to substantially impact topographic features. The impact-producing factors resulting from 

accidental events include bottom-disturbing activities from drilling, exploration, and vessel operations 

as well as the release of sediments and toxins during drilling operations. Oil-spill response-related 

activities were also considered to be a source of potential impacts to topographic features.

Adherence to the Topographic Features Stipulation, which is analyzed in each action 

alternative and which is detailed in Appendix D, would assist in preventing most of the potential 

impacts on topographic feature communities by increasing the distance of OCS oil- and gas-related 

activities. Should this stipulation be applied to any future lease sale, as it has been historically, the 

impacts of a proposed action to topographic features from routine activities and accidental events 

would be negligible. The incremental contribution of a proposed action to the cumulative impacts

on topographic features is also expected to be negligible, assuming adherence to the proposed 

Topographic Features Stipulation. Under Alternative E, the potential for new incremental impacts to 

topographic features from a cancelled lease sale would be none because they would be avoided 

entirely. Impacts ranging from negligible to moderate may still be expected from non-OCS oil- and 

gas-related activities depending on factors such as fishing and pollution; however, the incremental 

impact of the proposed activities should not result in an augmentation of the expected impacts. A 

full analysis of topographic features can be found in Chapter 4.6.1. 

2.4.6.2 Pinnacles and Low-Relief Features

The Pinnacle Trend is an approximately 64 x 16 mi (103 x 26 km) high-relief area in water 

depths ranging from approximately 200 to 650 ft (60 to 200 m). It is in the northeastern portion of 

the CPA at the outer edge of the Mississippi-Alabama shelf between the Mississippi River and 
Alternatives Including the Proposed Actions 2-43

De Soto Canyon (Figures 2-4 and 4-18). Outside of the Pinnacle Trend area, low-relief, live bottom

epibenthic communities occur in isolated locations in shallow waters (<984 ft; 300 m) throughout the 

GOM wherever there exists suitable hard substrate and other physical conditions (e.g., depth, 

turbidity, etc.) allowing for community development. Hard bottom habitats occur throughout the 

GOM, but are relatively rare compared with ubiquitous soft bottoms. 

The impact-producing factors for pinnacles and low-relief live bottom features can be 

grouped into three main categories: (1) bottom-disturbing activities; (2) drilling-related sediment and 

waste discharges; and (3) oil spills. These impact-producing factors have the potential to damage 

individual live bottom habitats and disrupt associated benthic communities if insufficiently distanced 

or otherwise mitigated. At the broad geographic and temporal scope of this analysis, and assuming 

adherence to all expected lease stipulations and typically applied regulations and mitigations, routine 

activities are expected to have largely localized and temporary effects. Although accidental events 

have the potential to cause severe damage to specific live bottom communities, the number of such 

events is expected to be very small. Therefore, at the regional, population-level scope of this 

analysis, the incremental contribution of impacts from reasonably foreseeable routine activities and 

accidental activities to the overall cumulative impacts is expected to be negligible to minor. 

Proposed OCS oil- and gas-related activities would also contribute incrementally to the overall OCS 

and non-OCS cumulative effects experienced by live bottom habitats. Under Alternative E, the 

potential for impacts to pinnacle and low-relief feature communities related to the cancelled lease 

sale would be none because new impacts would be avoided entirely. The OCS oil- and gas-related 

cumulative impacts to live bottom communities are estimated to be negligible. A full analysis of 

pinnacles and low-relief features can be found in Chapter 4.6.2. 

2.4.7 Fish and Invertebrate Resources

The distribution of fishes and invertebrates varies widely and species may be associated with 

different habitats at various life stages, as discussed further in Chapter 4.7. The impact-producing 

factors affecting these resources are anthropogenic sound, bottom-disturbing activities, habitat 

modification, and accidental oil spills. The impacts from routine activities, excluding infrastructure

emplacement, would be expected to be negligible or minor due to short-term localized effects. The 

installation of OCS oil- and gas-related infrastructure constitutes a long-term modification of the local 

habitat and is hypothesized to have resulted over the life of the program in moderate changes in the 

distribution of some species. Although this effect is not necessarily adverse and infrastructure is 

expected to be decommissioned and sites restored to natural habitat, the cumulative impact over the 

life of the OCS Program is spatiotemporally extensive. Accidental spills have been historically lowprobability events and are typically small in size. The expected impact to fishes and invertebrate 

resources from accidental oil spills is negligible. Commercial and recreational fishing are expected 

to have the greatest direct effect on fishes and invertebrate resources, resulting in impact levels 

ranging from negligible for most species to potentially moderate for some targeted species (e.g., 

hogfish spp., gray triggerfish [Balistes capriscus], and greater amber jack [Seriola dumerili]). The 

analysis of routine activities and accidental events indicates that the incremental contribution to the 

overall cumulative impacts on fishes and invertebrate resources as a result of a single proposed 
2-44 Gulf of Mexico Multisale EIS

lease sale would be minor. Under Alternative E, the expected impacts on fish and invertebrate 

resources would be none. A full analysis of fish and invertebrate resources can be found in 

Chapter 4.7. 

2.4.8 Birds

The affected birds include both terrestrial songbirds and many groups of waterbirds. Routine 

impacts to coastal, marine, and migratory birds that were considered include routine discharges and 

wastes, noise, platform severance with explosives (barotrauma), geophysical surveys with airguns 

(barotrauma), platform presence and lighting, and pipeline landfalls. The impacts to birds from OCS 

oil-and gas-related routine activities are similar wherever they may occur in the GOM, and all are 

considered negligible to minor. Negligible to minor impacts would not affect a substantial number of 

birds. Any impacts would be acute and reversible. As used here, acute means short-term, as it 

does in the context of short-term toxicity exposure and tests. Further, no injury to or mortality of a 

small number of individuals or a small flock would occur. Accidental impacts to birds are caused by 

oil spills, spill cleanup activities, and emergency air emissions. Seabirds may not always experience 

the greatest impacts from a spill but may take longer for populations to recover because of their 

unique population ecology (demography). Some species of seabirds, such as gulls, have larger 

clutches (laughing gulls usually have 3 eggs per clutch except in the tropics) and may recover quite 

quickly. However, many species of seabirds can have a clutch size of just one egg, and they have 

relatively long life spans and often have delayed age at first breeding. Because of the latter case, 

impacts on seabirds from overall accidental events would be expected to be moderate. Impacts 

from overall accidental events on other waterbirds farther inshore would also be expected to be 

moderate because of the extensive overlap of their distributions with oiled inshore areas and 

shorelines expected from a large oil spill (≥1,000 bbl). Moderate impacts would affect a substantial 

abundance of birds.

The incremental contribution of a proposed action to the overall cumulative impacts is 

considered moderate, but only because of the potential impacts that could result from a large oil 

spill (≥1,000 bbl). This conclusion is based on the incremental contribution of a proposed action to 

the cumulative OCS oil- and gas-related and non-OCS oil- and gas-related impacts. Alternative E 

would offer no new lease blocks for exploration and development; therefore, incremental impacts to 

birds would be none. However, there would be continuing impacts associated with the existing oil 

and gas activities from previously permitted activities and previous lease sales. A full analysis of 

coastal and migratory birds can be found in Chapter 4.8. 

2.4.9 Protected Species

2.4.9.1 Marine Mammals

The Gulf of Mexico marine mammal community is diverse and distributed throughout the 

GOM, with the greatest abundances and diversity of species inhabiting oceanic and OCS waters. 

The major potential impact-producing factors affecting marine mammals in the GOM as a result of 

cumulative past, present, and reasonably foreseeable OCS energy-related activities are 
Alternatives Including the Proposed Actions 2-45

decommissioning activities, operational discharges, G&G activities, noise, transportation, marine 

debris, and accidental oil-spill and spill-response activities. Accidental events involving large spills, 

particularly those continuing to flow fresh hydrocarbons into oceanic and/or outer shelf waters for 

extended periods (i.e., days, weeks, or months), pose an increased likelihood of impacting marine 

mammal populations inhabiting GOM waters. While accidental events have the potential to impact 

marine mammal species, the number of such events is expected to be very small.

Proposed OCS oil- and gas-related activities would also contribute incrementally to the 

overall OCS and non-OCS cumulative effects experienced by marine mammal populations. At the 

regional, population-level scope of this analysis, impacts from reasonably foreseeable routine 

activities and accidental events could be negligible to moderate for any of the action alternatives. 

However, the incremental contribution of a proposed action to the cumulative impacts to marine 

mammal populations, depending upon the affected species and their respective population estimate, 

even when taking into consideration the potential impacts of the Deepwater Horizon explosion, oil 

spill, and response; non-OCS oil- or gas-related factors; and the minimization of the OCS oil- or gasrelated impacts through lease stipulations and regulations, would be expected to be negligible. 

Under Alternative E, the cancellation of a proposed lease sale, impacts on marine mammals within 

the Gulf of Mexico would be none. However, cumulative impacts would be unchanged from the 

conclusions reached for the other alternatives. A full analysis of marine mammals can be found in 

Chapter 4.9.1. 

2.4.9.2 Sea Turtles

Five sea turtle species have been ESA-listed and are present throughout the northern GOM; 

however, only Kemp’s ridley and loggerhead sea turtles commonly nest on beaches in the GOM. 

Because of expected mitigations (e.g., BOEM and BSEE proposed compliance with NTLs under the 

proposed Protected Species Stipulation and conditions of approval on postlease activities), routine

activities (e.g., noise or transportation) and accidental events (e.g., oil spills) related to a proposed 

action are not expected to have long- term adverse effects on the size and productivity of any sea 

turtle species or populations in the northern GOM. Lethal effects could occur from chance collisions

with OCS oil- and gas-related service vessels or ingestion of accidentally released plastic materials 

from OCS oil- and gas-related vessels and facilities. However, there have been no reports to date 

on such incidences. Most routine activities and accidental events as a result of a proposed action 

are therefore expected to have negligible to moderate impacts. For example, a minor impact might 

be a behavioral change in response to noise while a moderate impact might be a spill contacting an 

individual and causing injury or mortality.

Historically, intense harvesting of eggs, loss of suitable nesting beaches, and fishery-related 

mortality have led to the rapid decline of sea turtle populations. Anthropogenic actions continue to 

pose the greatest threat to sea turtles since their listing under the ESA, as well as different natural 

threats including climate change and natural disasters. The incremental contribution of a proposed 

action to the cumulative impacts to sea turtles would be expected to be negligible as a result of a 

proposed action. Population-level impacts are not anticipated. Under Alternative E, the cancellation 
2-46 Gulf of Mexico Multisale EIS

of a proposed lease sale, impacts on sea turtles within the Gulf of Mexico would be none. However, 

cumulative impacts would be unchanged from the conclusions reached for the other alternatives. A 

full analysis of sea turtles can be found in Chapter 4.9.2. 

2.4.9.3 Beach Mice

The four subspecies of beach mouse (Peromyscus polionotus ssp.) are small coastal 

rodents that are only found along beaches in parts of Alabama and northwest Florida, and they are 

federally listed as endangered. Beach mice rely on dune systems as favorable habitat for foraging 

and maintaining burrows. Due to the distance between beach mouse habitat and OCS oil- and 

gas-related activities, routine impacts are not likely to affect beach mouse habitat except under very 

limited situations. Pipeline emplacement or construction, for example, could cause temporary 

degradation of beach mouse habitat; however, these activities are not expected to occur in areas of 

designated critical habitat. Accidental oil spills and associated spill-response efforts are not likely to 

impact beach mice or their critical habitat because the species live above the intertidal zone where 

contact is less likely. Habitat loss from non-OCS oil- and gas-related activities (e.g., beachfront 

development) and predation have the greatest impacts to beach mice. Overall, the incremental 

contribution of impacts from reasonably foreseeable routine activities and accidental activities to the 

overall cumulative impacts on beach mice is expected to be negligible. Under Alternative E, the 

cancellation of a proposed lease sale, impacts on beach mice would be none. However, cumulative 

impacts would be unchanged from the conclusions reached for the other alternatives. A full analysis 

of beach mice can be found in Chapter 4.9.3. 

2.4.9.4 Protected Birds

Protected birds are species or subspecies ESA-listed by FWS as threatened or endangered 

due to the decrease in their population sizes or loss of habitat; therefore, a proposed action could 

have a greater impact. BOEM is undergoing consultation with FWS to minimize the potential 

impacts to ESA-listed species. Impacts from routine activities, which include discharges and wastes

affecting air and water quality, noise, and possibly artificial lighting, would be negligible to protected 

birds. The listed bird species considered are typically coastal birds and would not be exposed to 

much of the oil and gas activities. Waste discharges to air or water produced as a result of routine 

activities are regulated by the USEPA and BOEM and are subject to limits to reduce potential 

impacts; therefore, due to precautionary requirements and monitoring, the impacts to protected birds 

would be negligible for any of the action alternatives. The major impact-producing factors resulting 

from accidental events associated with a proposed action that may affect protected birds include 

accidental oil spills and response efforts and marine debris. In the case of an accidental oil spill, 

impacts would be negligible to moderate depending on the magnitude and spatiotemporal 

proximity of such an event. Major impacts could occur if a large oil spill occurred with direct contact 

to a protected bird species or if the habitat became contaminated resulting in mortality of a listed 

species. Marine debris produced by OCS oil- and gas-related activities as a result of accidental 

disposal into the water may affect protected birds by entanglement or ingestion. Due to the 

regulations prohibiting the intentional disposal of items, impacts would be expected to be negligible; 
Alternatives Including the Proposed Actions 2-47

however, impacts may scale up to moderate if the accidental release of marine debris caused 

mortality of a listed bird.

Overall, BOEM would expect negligible to moderate impacts to protected birds considering 

routine activities, accidental events, and cumulative impacts. Due to the precautionary requirements 

and monitoring discussed above, the incremental impacts to protected birds would be negligible for 

any of the action alternatives (i.e., Alternatives A-D). Under Alternative E, the additional incremental 

impacts to ESA-protected birds or their habitats would be none. A full analysis of protected birds 

can be found in Chapter 4.9.4. 

2.4.9.5 Protected Corals

Elkhorn, staghorn, boulder star, lobed star, and mountainous star corals are listed by NMFS 

as threatened due to the decrease in their population sizes; therefore, the relative impacts from a 

proposed action could be disproportionate to those experienced by other coral species. BOEM

understands this and is undergoing consultation for these species to minimize the potential impacts. 

Though the listed species are given ESA status, they could be affected by the same types of 

impact-producing factors from a proposed action as other coral species that are not ESA listed. 

Assuming adherence to all expected lease stipulations and other postlease, protective restrictions 

and mitigations, the routine activities related to a proposed action are expected to have mostly 

localized and temporary effects because the site-specific survey information and distancing 

requirements described in NTL 2009-G39 will allow BOEM to identify and protect live bottom 

features (where protected corals may be found) from harm by proposed OCS oil- and gas-related 

activities during postlease reviews. While accidental events have the potential to cause severe 

damage to specific coral communities, the number of such events is expected to be small. Further, 

many of the protected corals occur in the Flower Garden Banks National Marine Sanctuary, which, 

under the current boundaries, is not proposed for future leasing under any of the alternatives in this 

Multisale EIS. Therefore, the incremental contribution of activities resulting from a proposed action 

to the overall cumulative impacts to protected corals is expected to be negligible for any of the 

action alternatives. Proposed OCS oil- and gas-related activities would contribute incrementally to 

the overall OCS and non-OCS cumulative impacts experienced by corals. Under Alternative E, the 

cancellation of a proposed lease sale, impacts on protected corals would be none. However, 

cumulative impacts would be unchanged from the conclusions reached for the other alternatives. A 

full analysis of protected corals can be found in Chapter 4.9.5. 

2.4.10 Commercial Fisheries

A proposed action could affect commercial fisheries by affecting fish populations or by 

affecting the socioeconomic aspects of commercial fishing. The impacts of a proposed action on 

fish populations are presented in Chapter 4.7. Routine activities such as seismic surveys, drilling 

activities, and service-vessel traffic can cause space-use conflicts with fishermen. Structure 

emplacement could have positive or negative impacts, depending on the location and species. For 

example, structure emplacement prevents trawling in the associated area and, thus, could impact 

the shrimp fishery. On the other hand, production platforms can facilitate fishing for reef fish such as 
2-48 Gulf of Mexico Multisale EIS

red snapper and groupers. Accidental events, such as oil spills, could cause fishing closures and 

have other impacts on the supply and demand for seafood. However, accidental events that could 

arise from a proposed action would likely be small and localized. A proposed action would be 

relatively small when compared with the overall OCS Program, State oil and gas activities, overall 

vessel traffic, hurricanes, economic factors, Federal and State fisheries management strategies, and 

other non-OCS oil- and gas-related factors. Therefore, the incremental contribution of a proposed 

action to the cumulative impacts to commercial fisheries would range from minor beneficial to 

minor adverse effects for any of the action alternatives. The exact impacts would depend on the 

locations of activities, the species affected, the intensity of commercial fishing activity in the affected 

area, and the substitutability of any lost fishing access. Alternative E would prevent these impacts 

from occurring, although commercial fisheries would still be subject to the impacts from the OCS 

Program, as well as the impacts from non-OCS sources. A full analysis of commercial fisheries can 

be found in Chapter 4.10. 

2.4.11 Recreational Fishing

The Gulf of Mexico’s extensive estuarine habitats (Chapter 4.3.1), live bottom habitats 

(Chapter 4.6), and artificial substrates (including artificial reefs, shipwrecks, and oil and gas 

platforms) support several valuable recreational fisheries. Alternatives A-D can affect recreational 

fishing by affecting fish populations or by affecting the socioeconomic aspects of recreational fishing. 

The impacts of Alternatives A-D on fish populations are presented in Chapter 4.7. Vessel traffic can 

cause space-use conflicts with anglers. Structure emplacement generally enhances recreational 

fishing, although this positive effect will be offset during decommissioning unless a structure were 

maintained as an artificial reef. Accidental events, such as oil spills, can cause fishing closures and 

can affect the aesthetics of fishing in an area. However, accidental events that could arise would 

likely be small and localized. Alternatives A-D should also be viewed in light of overall trends in 

OCS platform decommissioning, State oil and gas activities, overall vessel traffic, hurricanes, 

economic factors, and Federal and State fisheries management strategies. The incremental impacts 

of Alternatives A-D on recreational fisheries are expected to be beneficial (low) to minor. 

Alternative E would cause some economic adjustments (refer to Chapter 4.14.2), which could cause 

negligible impacts to recreational fishing activities. A full analysis of recreational fishing can be 

found in Chapter 4.11. 

2.4.12 Recreational Resources

Alternatives A-D would contribute to the negligible to minor aesthetic impacts and space-use 

conflicts that arise due to the broader OCS Program. These conflicts arise due to marine debris, the 

visibility of platforms, and vessel traffic. Structure emplacements can have positive impacts on 

recreational fishing and diving because platforms often act as artificial reefs. Oil spills can negatively 

affect beaches and other coastal recreational resources. Alternatives A-D should also be viewed in 

light of economic trends, as well as various non-OCS oil- and gas-related factors that can cause 

space-use conflicts and aesthetic impacts, such as commercial and military activities. Because of 

the relatively small contribution of any given lease sale under any of the proposed action alternatives 

to the overall OCS Program, in addition to other non-OCS oil- and gas-related activities, the 
Alternatives Including the Proposed Actions 2-49

incremental impacts are expected to be beneficial (low) to minor adverse effects. There could be 

negligible impacts to recreational resources due to the small economic adjustments that would 

occur as a result of Alternative E. A full analysis of recreational resources can be found in 

Chapter 4.12. 

2.4.13 Archaeological Resources

Archaeological resources are any material remains of human life or activities that are at least 

50 years of age and that are capable of providing scientific or humanistic understanding of past 

human behavior, cultural adaptation, and related topics through the application of scientific or 

scholarly techniques, such as controlled observation, contextual measurement, controlled collection, 

analysis, interpretation, and explanation (30 CFR § 250.105). Archaeological resources are 

primarily impacted by any activity that directly disturbs or has the potential to disturb the seafloor. 

For the OCS Program, this includes the placement of drilling rigs and production systems on the 

seafloor; pile driving associated with platform emplacement; pipeline placement and installation; the 

use of seismic receiver nodes and cables; the dredging of new channels, as well as maintenance 

dredging of existing channels; anchoring activities; post-decommissioning activities including 

trawling clearance; and the masking of archaeological resources from industry-related infrastructure

and debris.

Regardless of which planning area a proposed lease sale is held, the greatest potential 

impact to an archaeological resource as a result of a proposed action under any of the action 

alternatives is site-specific and would result from direct contact between an offshore activity or 

accidental event and a site. Archaeological surveys, where required prior to an operator beginning 

OCS oil- and gas-related activities on a lease, are expected to be effective at identifying possible 

archaeological sites. A proposed action’s postlease activities, including the drilling of wells and 

installation of platforms, installation of pipelines, anchoring, and removal of platforms and other 

structures installed on the seafloor and site clearance activities, as well as accidental events such as 

loss of debris, may result in negligible to major impacts to archaeological sites. Major impacts 

could potentially occur if the mitigations described above were not applied to postlease activities.

With identification, evaluation, and avoidance or mitigation of archeological resources, the 

incremental contribution of a proposed action is expected to result in negligible, long-term 

cumulative impacts to archeological resources; however, if an archaeological site were to be 

impacted, impacts to that specific site may range from negligible to major. Alternative E would 

result in BOEM cancelling a proposed lease sale; therefore, the impact-producing factors mentioned 

above would not take place for that proposed lease sale, and any impact that these actions could 

cause would not occur. A full analysis of archaeological resources can be found in Chapter 4.13. 
2-50 Gulf of Mexico Multisale EIS

2.4.14 Human Resources and Land Use (Including Environmental Justice) 

2.4.14.1 Land Use and Coastal Infrastructure

Oil and gas exploration, production, and development activities on the OCS are supported by 

an expansive onshore network of coastal infrastructure that includes hundreds of large and small 

companies. Because OCS oil- and gas-related activities are supported by this long-lived, expansive 

onshore network, a proposed action is not expected to produce any major impacts to land use and 

coastal infrastructure. The impact of routine operations would range from negligible to moderate. 

The impacts of reasonably foreseeable accidental events such as oil spills, chemical and drilling fluid 

spills, and vessel collisions are not likely to last long enough to adversely affect overall land use or 

coastal infrastructure in the analysis area and would therefore be negligible to moderate. In the 

cumulative analysis, activities relating to all past, present, and future OCS oil- and gas-related 

activities and State oil and gas production are expected to minimally affect the current land use of 

the analysis area because most subareas have strong industrial bases and designated industrial 

parks. Non-OCS oil- and gas-related factors contribute substantially to the cumulative impacts on 

land use and coastal infrastructure, while there is only a minor incremental contribution of a 

proposed lease sale.

The cumulative impacts on land use and coastal infrastructure could range from beneficial

to moderate for OCS oil- and gas-related activities and beneficial to major for non-OCS oil- and 

gas-related activities depending on the specifics of each situation, whether the impacts are 

measurable, how long the impacts would last, and the size of the affected geographic area as 

defined in Chapter 4.14.1. Alternative E would result in no lease sale and, thus, the direct impacts 

as a result of a proposed lease sale would be none and no incremental contribution of impacts to 

land use and coastal infrastructure beyond a temporary negative economic impact for the oil and gas 

industry and coastal states, such as Louisiana, that are more dependent on oil and gas revenues. A 

full analysis of land use and coastal infrastructure can be found in Chapter 4.14.1. 

2.4.14.2 Economic Factors

A proposed action would lead to beneficial (low) impacts arising from industry expenditures, 

government revenues, corporate profits, and other market impacts. Some of these impacts would 

be concentrated along the Gulf Coast, while others would be widely distributed. A proposed action 

would also lead to negative economic impacts arising from accidental events and other sources. 

There would be some differences in economic impacts among Alternatives A-D, corresponding to 

the differences in the scales and distributions of likely activities. Alternatives A-D should be viewed 

in light of the OCS Program, as well the numerous forces that can affect energy markets and the 

overall economy. Most of the incremental economic impacts of a proposed action are forecast to be 

beneficial, although there would be some minor adverse impacts. Alternative E, the cancellation of 

a proposed lease sale, would negatively impact firms and employees that depend on recurring 

leases; therefore, the impacts of Alternative E would be negligible to minor, with some partially 

offsetting beneficial impacts. A full analysis of economic factors can be found in Chapter 4.14.2. 
Alternatives Including the Proposed Actions 2-51

2.4.14.3 Social Factors (Including Environmental Justice) 

Potential social impacts resulting from a proposed action would occur within the larger 

socioeconomic context of the GOM region. The affected environment of the analysis area is quite 

large geographically and in terms of population (133 counties and parishes with over 22.7 million 

residents). The impacts from routine activities related to a proposed action are expected to be 

negligible to moderate, widely distributed, and to have little impact because of the existing 

extensive and widespread support system for the petroleum industry and its associated labor force. 

Outside of a low-probability catastrophic oil spill, which is not reasonably foreseeable and not part of 

a proposed action, any potential accidental events are not likely to be of sufficient scale or duration 

to have adverse and disproportionate long-term impacts for people and communities in the analysis 

area and would therefore range from negligible to moderate. In the cumulative analysis, impacts 

from OCS oil- and gas-related activities would range from beneficial to moderate. Non-OCS oiland gas-related activities, which include all human activities, natural events, and processes, actually 

contribute more to cumulative impacts than do factors related to OCS oil- and gas-related activities 

alone and result in beneficial to major impacts. The incremental contribution to cumulative impacts 

of a proposed action would be minor. Alternative E would result in no lease sale and, thus, overall 

incremental impacts as a result of alternative E would be none. A full analysis of social factors can 

be found in Chapter 4.14.3. 

Environmental Justice Determination: The oil and gas industry in the GOM region is 

expansive and long-lived over several decades with substantial infrastructure in place to support 

both onshore and offshore activities. BOEM’s scenario estimates call for 0-1 new gas processing 

plant and 0-1 new pipeline landfall over the 50-year life of a single proposed action. Impacts to 

GOM populations from a proposed action would be immeasurable for environmental justice since 

these low-income and minority communities are located onshore, distant from Federal OCS oil- and 

gas-related activities. Also, since these vulnerable populations are located within the larger context 

of onshore and State-regulated nearshore oil and gas activities that are connected to downstream 

infrastructure over which BOEM has no regulatory authority, BOEM has determined that a proposed 

action would not produce environmental justice impacts in the GOM region. A full analysis of social 

factors and an environmental justice determination can be found in Chapter 4.14.3. 

CHAPTER 3 

IMPACT-PRODUCING FACTORS AND SCENARIO

Impact-Producing Factors and Scenario 3-3 

What’s in This Chapter?

BOEM develops scenarios that describe OCS oil- and gas-related routine activities and 

accidental events from a single proposed lease sale, the OCS oil and gas cumulative activities

of multiple lease sales, and the non-OCS oil- and gas-related activities and/or events.

• Routine activities for a single proposed lease sale include the following:

− Exploration and Delineation – geological and geophysical surveys, and drilling 

exploration and delineation wells.

− Offshore Development and Production – drilling production wells, infrastructure

emplacement, and work-overs and abandonment of wells. 

− Transport – resource transportation (e.g., pipelines and tankers) as well as 

service transportation (e.g., service vessels and helicopters).

− Discharges and Wastes – includes operational wastes produced by facilities 

and vessels, and the disposal of wastes.

− Decommissioning and Removal Operations – the removal and/or 

abandonment of platforms and pipelines. 

− Coastal Infrastructure – information on all the types of infrastructure that 

supports the offshore oil and gas industry (e.g., construction, transport, and 

processing facilities).

− Air Emissions – the types of emissions that can be expected.

− Noise – the types of noise routinely produced during a lease.

− New and Unusual Technology – the technologies that have evolved to meet 

the technical, environmental, and economic challenges of deepwater

development.

• Accidental events for a single proposed lease sale could include the following (analyses 

based on historical data and trends): 

− Oil Spills – information on coastal and offshore spills. 

− Losses of Well Control – the process of a loss of well control event.

− Accidental Air Emissions – instances that might result in accidental air 

emissions, including hydrogen sulfide (H2S). 

− Pipeline Failures – instances that might result in a pipeline failure). 

− Vessel and Helicopter Collisions – instances that might result in a vessel or 

helicopter collision and the history of these incidences. 

− Chemical and Drilling-Fluid Spills – instances that might result in a chemical or 

drilling-fluid spill.

− Spill Response – the spill-response requirements and initiatives, offshore 

response, and the activities involved in an onshore response and cleanup.

• Cumulative activities include the following:

− Cumulative OCS Oil and Gas Program – all activities (i.e., the routine activities 

projected to occur and the accidental events that could occur, as listed above) from 

past, proposed, and future lease sales. 

− Non-OCS Oil- and Gas-Related Activities – impact-producing factors from the broad

range of other activities taking place within the proposed lease sale area.

3 IMPACT-PRODUCING FACTORS AND SCENARIO

3.0 INTRODUCTION

This chapter describes the offshore infrastructure and activities (impact-producing factors) 

associated with Alternative A or a regionwide proposed action (i.e., a typical lease sale that would 
3-4 Gulf of Mexico Multisale EIS

result from a proposed action), which would encompass all acreage available for lease within the 

WPA, CPA, and EPA (not under moratorium) that could potentially affect the biological, physical, and 

socioeconomic resources of the Gulf of Mexico. This chapter also describes the offshore 

infrastructure and activities associated with two alternatives that would offer proposed lease sales by 

individual planning area, which would consist of a single proposed lease sale for all acreage 

available for lease and not under moratorium either within the CPA and EPA combined

(Alternative B) or the WPA (Alternative C). Under Alternative D, the number of blocks that would 

become unavailable for lease represents only a small percentage (<4%) of the total number of 

blocks to be offered under Alternative A, B, or C. Therefore, Alternative D could reduce or delay 

offshore infrastructure and activities but may only shift the location of offshore infrastructure and

activities farther from sensitive topographic zones and not lead to a reduction in offshore 

infrastructure and activities. Since the ranges given for Alternatives A, B, and C are broad and 

represent the low and high levels of forecasted activity, any reduction of activity from choosing 

Alternative D is still expected to fall within those ranges; therefore, the scenarios do not change 

when considering Alternative D. The potential impacts associated with selecting Alternative D are 

discussed in Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information on 

Alternative D. In addition, Chapter 3.3.1 describes the Cumulative OCS Oil and Gas Program 

scenario or activity resulting from past and future lease sales in the GOM that could potentially affect 

the biological, physical, and socioeconomic resources of the GOM within the WPA, CPA, and EPA.

What is an Impact-Producing Factor?

An impact-producing factor is an activity or process, as a result of a proposed lease sale,

that could cause impacts on the environmental or socioeconomic setting. The impact analyses

determine the context and intensity of effects caused by any source on environmental resources 

(Chapter 4) including OCS oil- and gas- related activity and other ecological, economic, or social 

effects. Each phase of oil- and gas-related operation would have a set of impact-producing factors 

that may affect physical or environmental conditions and/or may affect one or more natural, cultural, 

or socioeconomic resources.

How are the Impact-Producing Factors Categorized?

Routine Activities. These activities generally occur on a regular basis during 

the lifetime of a lease. The operations are broken down by phase and include 

exploration, development, oil or gas production and transport, and 

decommissioning. Examples of routine activity include drilling wells, installing 

production structures, and decommissioning, etc. Routine operations are 

discussed in Chapter 3.1.

Accidental Events. Though not planned or intended, BOEM recognizes that 

there is potential for accidental releases, based on historical trends. Types of 

accidental events include releases into the environment (e.g., oil spills, loss of 

well control, accidental air emissions, pipeline failures, chemical and drilling 

fluid spills, and trash and debris), collisions (e.g., helicopters, service vessels, 
Impact-Producing Factors and Scenario 3-5 

Scenario development is the 

process of analyzing and 

projecting future activities that 

could occur as a result of each 

action alternative (i.e., Alternative 

A, B, C, or D).

How are ranges determined? The 

low and high production scenarios, 

and the factors that influence them,

are used to create the range in 

anticipated oil and gas activity.

and platforms), and spill-response activities. Reasonably foreseeable 

accidental events are discussed in Chapter 3.2. 

Cumulative Impacts. The impact-producing factors considered in this chapter 

are defined as other past, present, and reasonably foreseeable future activities 

occurring within the same geographic range and within the same timeframes as 

the aforementioned projected routine activities and potential accidental events, 

including BOEM’s Cumulative OCS Oil and Gas Program. Cumulative 

activities are discussed in Chapter 3.3. 

What is a Scenario?

A scenario describes the offshore activities that could 

occur for a single proposed lease sale under each alternative. 

BOEM’s Gulf of Mexico OCS Region developed these 

scenarios to support the detailed analyses of the proposed 

lease sales’ potential impacts whether regionwide or for

individual planning areas, as defined in the alternatives in 

Chapter 2.2.2. Each scenario is a hypothetical framework of 

assumptions based on estimated amounts, timing, and 

general locations of OCS exploration, development, and production for offshore and onshore 

activities and facilities. The scenario for each alternative is defined as a set of ranges for resource 

estimates, projected exploration and development activities, and impact-producing factors.

The scenarios do not predict future oil and gas activities with absolute certainty, even though 

they were formulated using historical information and current trends in the oil and gas industry. 

These scenarios are only approximate since future factors such as the economic climate, the future 

availability of support facilities, and future pipeline capacities are all unknown. The scenarios used 

in this Multisale EIS represent the best assumptions and estimates of a set of future conditions that 

are considered reasonably foreseeable and suitable for presale impact analyses. The development 

scenarios do not represent a BOEM recommendation, preference, or endorsement of any level of 

leasing or offshore operations or of the types, numbers, and/or locations of any onshore operations 

or facilities.

How are the Scenarios Developed?

BOEM uses a series of spreadsheet-based data analyses tools to develop the forecasts of 

the oil and gas exploration, discovery, development, and production activity scenario for each action 

alternative presented in this Multisale EIS. The activity 

level associated with a proposed lease sale could vary 

based on a number of factors, including the price of oil, 

hydrocarbon resource potential, cost of development, and 

resource availability (e.g., drilling rig availability) among 

other things. The scenario information presented takes 
3-6 Gulf of Mexico Multisale EIS

What does a range of activity

mean? A meaningful range 

provides a reasonable expectation 

of the lowest to highest oil and gas 

production and associated activity

anticipated from a single proposed 

lease sale.

into account historical oil and gas prices, price trends, oil and gas supply and demand, and related 

factors that influence oil and gas product-price and price volatility. The analyses are compared with 

actual historical activity and infrastructure data to ensure that historical precedent, as well as recent 

trends, are reflected in each activity forecast. Due to the inherent uncertainties associated with an 

assessment of undiscovered resources, probabilistic techniques were employed to develop the 

scenario and the results are reported as a range of values corresponding to probabilities of 

occurrence.

BOEM used these analyses to develop a 

reasonable low-activity scenario and a reasonable 

high-activity scenario for each alternative. BOEM does not 

expect every lease sale to reach the highest high or lowest 

low of the forecasted scenario ranges, but every proposed 

lease sale would fall within the ranges. The range of 

volumes described by these scenarios represents BOEM’s 

best estimate of the range of possible production volumes

and associated activity that can reasonably be expected 

from the acreage leased during a single proposed lease sale. These scenarios are developed to 

provide the environmental impact analyses in Chapter 4 the flexibility to develop impact metrics for 

the full range of potential impacts that could be possible from a single proposed lease sale. BOEM 

is confident that the analysis methodology, with adjustments and refinements based on recent 

activity levels and industry information, adequately project Gulf of Mexico OCS oil- and gas-related 

activities in both the short term and the long term for the Multisale EIS analyses.

3.1 IMPACT -PRODUCING FACTORS AND SCENARIO—ROUTINE OPERATIONS

3.1.1 Resource Estimates and Timetables

A single proposed lease sale scenario was developed for each 

alternative and is used to assess the potential impacts of a proposed lease 

sale within the geographic ranges of each alternative. The resource 

estimates for each alternative are based on two factors: (1) the conditional 

estimates of undiscovered, unleased, conventionally recoverable oil and gas resources in the 

proposed lease sale areas; and (2) the estimates of the portion or percentage of these resources 

assumed to be leased, discovered, developed, and produced as a result of a proposed action and 

each alternative. 

What is the Total Production Estimate for Each Alternative?

Table 3-1 and Figure 3-1 present the projected oil and gas production for a single proposed 

lease sale under each alternative and for the Cumulative OCS Oil and Gas Program (2017-2086). 

As stated above, the number of blocks that would become unavailable for lease under Alternative D 

represents only a small percentage (<4%) of the total number of blocks to be offered under 

Alternative A, B, or C. Therefore, Alternative D could reduce offshore infrastructure and activities; 
Impact-Producing Factors and Scenario 3-7 

however, it would likely only shift the location of offshore infrastructure and activities to be farther 

removed from sensitive topographic zones. Refer to Chapter 2.2.2.4 for more information on 

Alternative D. 

Table 3-1. Projected Oil and Gas in the Gulf of Mexico OCS. 

Reserve/Resource 

Production

Lease Sale

(2017-2066)

OCS Cumulative

(2017-2086)

Alternative A: Proposed Regionwide OCS Lease Sale

Oil (BBO) 0.211-1.118 15.482-25.806

Gas (Tcf) 0.547-4.424 57.875-108.513

Alternative B: Proposed Regionwide OCS Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area 

(Proposed Lease Sale in the CPA/EPA Portion 

of the Proposed Lease Sale Area)

Oil (BBO) 0.185-0.970 13.707-22.152

Gas (Tcf) 0.441-3.672 46.328-84.009

Alternative C: Proposed Regionwide OCS Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA Portions 

of the Proposed Lease Sale Area 

(Proposed Lease Sale in the WPA Portion 

of the Proposed Lease Sale Area)

Oil (BBO) 0.026-0.148 1.775-3.654

Gas (Tcf) 0.106-0.752 11.547-24.504

BBO = billion barrels of oil. 

Tcf = trillion cubic feet. 

Figure 3-1. Total Oil and Gas Production (BOE) in the Gulf of Mexico in the Low and High Production 

Scenario by Water Depth for a Single Proposed Lease Sale (2017-2066). 
3-8 Gulf of Mexico Multisale EIS

How Much and Where is Activity Expected to Occur for Each Alternative? 

To analyze the estimated hydrocarbon resources and associated activities and infrastructure

(including the number of exploration and delineation wells, production platforms, and development 

wells) and resulting impact-producing factors for each alternative, the geographic ranges of each 

alternative were divided into offshore subareas based upon ranges in water depth. Figure 3-2

depicts the location of the offshore subareas or water-depth ranges. The water-depth ranges were 

developed to reflect the technological requirements, related physical and economic impacts as a 

consequence of the oil and gas potential, exploration and development activities, and lease terms 

unique to each water-depth range. 

Figure 3-2. Offshore Subareas in the Gulf of Mexico. 

Estimates of associated activities and infrastructure or the major impact-producing factors 

related to the projected levels of exploration, development, and production activity were developed 

for each of the subareas (water-depth ranges) for Alternatives A, B, and C, and are presented in 

Table 3-2. 
Impact-Producing Factors and Scenario 3-9 

Table 3-2. Offshore Scenario Activities and Impact-Producing Factors Related to a Single Proposed 

Lease Sale for Alternative A, B, or C from 2017 through 2066. 

Activity Alternative1

Offshore Subareas (m)2

Totals3

0-60 60-200 200-800 800-

1,600 

1,600-

2,400 >2,400

Exploration 

and 

Delineation 

Wells

A 24-634 8-300 5-11 6-15 5-8 5-16 53-984

B 20-570 5-293 2-8 2-10 2-2 2-10 33-893

C 4-64 2-7 2-3 3-5 3-6 3-6 17-91

Development 

and 

Production 

Wells4

A Total 14-326 7-220 7-95 13-51 10-37 10-38 61-767

B Total 10-282 4-211 4-78 10-35 9-31 9-34 46-671

C Total 4-44 4-9 4-17 4-16 3-6 3-4 22-96

A Oil 1-35 0-23 3-46 6-22 5-19 4-19 19-164

B Oil 1-32 0-23 2-38 5-18 4-16 4-17 16-144

C Oil 0-5 0-1 2-9 1-5 1-4 1-3 5-27

A Gas 1-35 0-23 3-46 6-22 5-19 4-19 19-164

B Gas 5-169 2-120 0-17 1-7 1-6 1-7 10-326

C Gas 2-27 2-6 0-4 1-7 0-1 0-1 5-46

Installed 

Production 

Structures

A 8-183 4-85 1-4 1-3 1-2 1-3 16-280

B 7-158 3-81 1-3 1-2 1 1-2 14-247

C 3-25 2-4 1 1 1 1 9-33

Production 

Structures 

Removed 

Using 

Explosives

A 6-130 3-63 0 0 0 0 9-193

B 5-112 2-60 0 0 0 0 7-172

C 2-18 2-3 0 0 0 0 4-21

Total 

Production 

Structures 

Removed

A 8-183 4-85 1-4 1-3 1-2 1-3 16-280

B 7-158 3-81 1-3 1-2 1 1-2 14-247

C 3-25 2-4 1 1 1 1 9-33

Length of 

Installed 

Pipelines

(km)5

A 59-527 53-417 53-327 78-358 59-275 53-240 355-2,144

B 40-395 34-336 33-240 55-233 50-227 42-210 254-1,641

C 20-132 20-81 20-88 24-125 10-48 11-31 105-505

ServiceVessel Trips 

(1,000’s round 

trips)

A 9-265 4-126 6-51 7-38 7-26 7-36 43-541

B 8-229 3-120 6-39 6-26 6-15 6-25 38-452

C 3-36 2-6 6-13 6-13 6-12 6-11 30-89

Helicopter 

Operations 

(1,000’s round 

trips)

A 52-2,131 34-1,409 8-71 8-53 8-36 8-53 122-3,750

B 43-1,848 26-1,426 8-53 8-36 8-18 8-36 105-3,415

C 17-299 17-71 8-18 8-18 8-18 8-18 70-440

1 Alternative D could reduce activity values of the combined Alternative A, B, or C, but it may only shift the location of 

offshore infrastructure and activities farther from sensitive topographic zones. Refer to Chapter 2.2.2.4 for more 

information. Alternative A would a regionwide lease sale, Alternative B would be the CPA/EPA portions of the 

lease sale area, and Alternative C would be the WPA portion of the lease sale area. 2 Refer to Figure 3-1. 3 Subareas totals may not add up to the planning area total because of rounding. 4 Development and Production Wells includes some exploration wells that were re-entered and completed. These

wells were removed from the Exploration and Delineation well count. 5 Projected length of pipelines does not include length in State waters.
3-10 Gulf of Mexico Multisale EIS

When analyzing hydrocarbon resources and associated activities and infrastructure by 

planning area across the GOM, regardless of the alternative, the majority are located within the 

boundaries of the CPA. Therefore, for a proposed action under Alternative A, which would 

encompass all acreage available for lease within the WPA, CPA, and EPA, the majority of the 

activity would still be located in the CPA. An analysis of the scenario forecast for Alternative A 

suggests that a maximum of 88 percent of the oil production and associated activity and 83 percent 

of the gas production and associated activity is forecasted to occur within the CPA/EPA. A 

maximum of 13 percent of the oil production and associated activity and 19 percent of the gas 

production and associated activity from Alternative A is forecasted to occur within the WPA.

Finally, it is important to note that a single proposed lease sale, no matter which alternative is 

selected, would represent only a small proportion and small contribution to past, present, and future 

activity as a result of the overall forecasted Cumulative OCS Oil and Gas Program scenario or 

activity forecasted to occur between 2017 and 2086. This is represented in the table below.

Single Proposed 

Lease Sale 

(2017-2066)

Percent of Production of a Single Proposed Lease Sale in Relation to

Cumulative Production 

Regionwide 

(2017-2086)

Cumulative Production 

in the CPA/EPA 

(2017-2086)

Cumulative Production 

in the WPA 

(2017-2086)

Alternative A 1.2-4.2% – –

Alternative B 1.0-3.6% 1.2-4.4% –

Alternative C 0.2-0.6% – 1.2-3.5%

Note: Alternative D could reduce production values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Refer to Chapter 2.2.2.4 for more information.

Additional detailed information for activities or major impact-producing factors associated 

with a single proposed lease sale under each alternative are discussed in the following sections.

What is the Typical Timeline of a Lease?

The OCS oil- and gas-related activities generally occur in four phases: (1) exploration to 

locate viable oil or natural gas deposits; (2) development well drilling, platform construction, and 

pipeline infrastructure placement; (3) operation (oil or gas production and transport); and 

(4) decommissioning of facilities once a reservoir is no longer productive or profitable (Figure 3-3). 

Under the proposed action, most activities would occur on OCS leases only after a lease sale is held 

in the GOM. The two-dimensional (2D) and three-dimensional (3D) seismic surveying may occur on 

a lease to inform bidding prior to a lease sale (Chapter 3.1.2.1). A lease may range in length 

depending on hydrocarbon production on the lease; however, BOEM projects that the overwhelming 

majority of the oil and natural gas fields discovered as a result of each alternative would reach the 

end of their economic life within a time span of 50 years following a lease sale. Exploration and 

development activity forecasts become increasingly more uncertain as the length of time of the 

forecast increases due to an increasing number of influencing factors, and unusual cases may exist 

where activity on a lease may continue beyond 50 years. 
Impact-Producing Factors and Scenario 3-11

Figure 3-3. Typical Timeline for Offshore Oil and Gas Drilling.

3.1.2 Exploration and Delineation

The timeline for exploration and delineation activities during the life of a “typical” lease are 

shown in Figure 3-3. Exploration includes both geological and geophysical surveys and exploration 

drilling activities.

3.1.2.1 Geological and Geophysical Surveys

Geological and geophysical (G&G) surveys conducted as a result of a lease sale typically 

collect data on surficial or near-surface geology used to identify on-lease potential shallow geologic 

hazards for engineering and site planning for bottom-founded structures. The G&G regulations and 

processes are discussed in Appendix A.1. The G&G activities for oil and gas exploration are 

authorized on the basis of whether or not the proposed activities occur (1) before leasing takes place 

(prelease) and authorized by permits or (2) on an existing lease (postlease or ancillary) and 
3-12 Gulf of Mexico Multisale EIS

What is a shallow hazard? A shallow 

hazard is a buried channel up to 4,000 ft 

(1,219 m) below the seafloor filled with 

permeable sediment that presents 

hazards to drilling operations. Drilling 

through these channels may result in 

water flowing up and around the well 

casing, may deposit sand or silt on the 

seafloor within a few hundred feet of the 

wellhead, and could result in hydrate 

formation if gas is present. Unanticipated 

shallow hazards can lead to downhole 

pressure kicks that range from minor and 

controllable to significant and 

uncontrollable, and up to and including a 

serious blowout condition.

authorized by OCS plan approvals, plan revisions, or by a requirement for notification of BOEM 

before certain on-lease activities are undertaken. BOEM’s resource evaluation program oversees 

G&G data acquisition and permitting activities pursuant to regulations at 30 CFR parts 550 and 551. 

There are a variety of G&G activities that are conducted for oil and gas exploration and development 

as on-lease activities:

• various types of deep-penetration seismic airguns used almost exclusively for oil 

and gas exploration;

• electromagnetic surveys, deep stratigraphic and shallow test drilling, and various 

remote-sensing methods in support of oil and gas exploration;

• high-resolution geophysical (HRG) surveys (airgun and non-airgun) used to 

detect and monitor geohazards, archaeological resources, and certain types of 

benthic communities; and

• geological and geotechnical bottom sampling used to assess the suitability of 

seafloor sediments for supporting structures (e.g., platforms, pipelines, and 

cables), as well as to identify environmental resources such as chemosynthetic 

communities, gas hydrates, buried channels and faults, and archaeological 

resources. 

Airgun Surveys

Shallow-penetration airgun (HRG airgun) 

seismic surveys image shallow depths, typically 

1,000 m (3,280 ft) or less below the seafloor to 

produce high-resolution images. Shallowpenetration surveys, also commonly known as 

shallow hazard surveys, are conducted to 

investigate the shallow subsurface for geohazards 

and soil conditions and to identify potential benthic 

biological communities (or habitats) and 

archaeological resources. The shallow hazards 

survey is also used to identify and map geologic 

features in the vicinity of proposed wells, platforms, 

anchors and anchor chains, mounds or knolls, 

acoustic void zones, gas- or oil-charged sediments, 

or seeps associated with surface faulting that may 

be indicative of ocean-bottom chemosynthetic 

communities. 

Deep-penetration airgun seismic surveys are conducted to obtain data on geological 

formations as deep as 40,000 ft (12,192 m) below the seafloor. Further detailed information on 
Impact-Producing Factors and Scenario 3-13

airgun surveys may be found in BOEM’s Atlantic OCS Proposed Geological and Geophysical 

Activities: Mid-Atlantic and South Atlantic Planning Areas, Final Programmatic Environmental 

Impact Statement (Atlantic G&G Activities Programmatic EIS) (USDOI, BOEM, 2014a). A G&G 

Programmatic EIS is currently being developed for the GOM (refer to Chapter 1.7). Data from these 

surveys can be used to assess potential hydrocarbon structural and stratigraphic traps and 

reservoirs, and also help to optimally locate exploration, development, and production wells, thus 

maximizing extraction and production from a reservoir. BOEM’s resource evaluation staff uses deep 

2D and 3D seismic data for resource estimation and bid evaluation to ensure that the Government 

receives a fair market value for lease blocks offered.

The vast majority of the underwater sound generated during an airgun survey is attributable 

to the airgun or airgun arrays, survey vessel towing the airgun(s), and additional equipment such as 

electromechanical (HRG non-airgun) tools. An airgun or airgun array releases compressed air into 

the water, creating a sound energy pulse that can penetrate deep beneath the seafloor.

Airgun arrays are broadband sound sources that project energy over a wide range of 

frequencies, from less than 10 Hertz (Hz) to more than 2,000 Hz (2 kilohertz [kHz]). Most of the 

usable energy, however, is concentrated in the frequency range below 200 Hz. The energy level 

produced by an airgun array depends primarily on three factors:

• the firing pressure in pounds per square inch (psi) of the guns (2,000 psi for most 

of the surveys currently being conducted); 

• the number of airguns in the array (generally between 20 and 80); and

• the total volume in cubic inches of the array (generally between 1,500 and 

8,640 cubic inches). 

The output of an airgun array is directly related to the firing pressure and to the number of 

guns and is only proportional to the cube root of the volume. The airguns in the array are arranged 

to project the maximum amount of seismic energy vertically into the seafloor. Nonetheless, a 

significant portion of the sound energy from the array is emitted at off-vertical angles and spreads 

into the surrounding environment. Most of the sound energy is directed downward. The frequency 

spectrum of the sound spreading near-horizontally can differ markedly from that of the sound 

directed downward. There also can be substantial differences in the intensity and frequency 

spectrum of sound spreading in different horizontal directions.

Data acquisition generally takes place day and night and, depending on the size of the 

survey area, may continue for days, weeks, or months. A typical deep-penetration seismic airgun 

survey may experience approximately 20-30 percent of non-operational downtime due to a variety of 

factors, including technical or mechanical problems, standby for weather or other interferences, and 

performance of mitigating measures (e.g., ramp-up, pre-survey visual observation periods, and 

shutdowns).
3-14 Gulf of Mexico Multisale EIS

There are several different types/methods of performing airgun surveys dependent upon the 

data needs. These range from 2D, 3D, and 4D techniques more commonly used in the prelease 

phase to various vertical seismic profiling (VSP) techniques (e.g., zero-offset, multiple-offset, 

walk-away, and checkshot surveys), as well as HRG airgun surveys more commonly used during 

postlease operations.

Checkshot surveys are similar to zero-offset VSP but (1) are less complex and require less 

time to conduct, (2) produce less information, (3) are cheaper, (4) use a less sophisticated borehole 

seismic sensor, and (5) acquire shorter data records at fewer depths. During a checkshot survey, a 

seismic sensor is sequentially placed at a few depths (<20) in a well, and a seismic source (almost 

always an airgun) is hung from the side of the well platform. Only the first energy arriving at the 

sensor from the seismic source is permanently recorded. No reflection events are recorded and no 

sophisticated data processing like that for VSP surveys are required. The purpose of a checkshot 

survey is to estimate the velocity of sound in rocks penetrated by the well. Typically, the depths at 

which the sensors are placed are at, or near, the boundaries of prominent lithologic features. 

Checkshot surveys can be conducted much quicker than other VSP surveys, but they produce much 

less information. Because checkshot surveys are much less expensive and do not use the wellbore 

and the drilling rig as long, they are much more common than other VSP surveys. In most 

checkshot surveys, the seismic source is hung from the platform in a fixed location within the water 

column, so a surface vessel is not needed. Because reflection energy does not need to be acquired, 

the seismic source usually is smaller than those used for other VSP surveys. Detailed descriptions 

of other VSP survey methods are summarized in BOEM’s Atlantic G&G Activities Programmatic EIS 

(USDOI, BOEM, 2014a).

Both 2D and 3D towed-streamer seismic exploration surveys are conducted off-lease by 

geophysical contractors either on a proprietary or nonexclusive (multiclient) basis. Proprietary 

surveys usually cover only a few blocks for an individual client who will then own the data and 

therefore will have exclusive use of it. In contrast, nonexclusive (multiclient or speculative) survey 

data are owned by the contractor, are generally collected over large multi-block areas, and are 

licensed to as many clients as possible to recover costs and produce profits for the contractor.

Newer acquisition technology involves multiple vessels towing airgun arrays with additional 

vessels towing streamers. These 3D WAZ surveys increase the illumination of many subsurface 

areas, particularly areas that are overlain with salt, and eliminate unwanted noise attenuation. The 

3D coil surveys are a navigational variation of WAZ surveys and are acquired in a spiral fashion that 

allows for a longer acoustical distance between source and receivers for a better illumination of the 

acquired data and do not involve vessel turning and repositioning associated with linear acquisition. 

Detailed descriptions of the different airgun survey methods are summarized in BOEM’s Atlantic 

G&G Activities Programmatic EIS (USDOI, BOEM, 2014a).
Impact-Producing Factors and Scenario 3-15

Electromechanical/HRG Non-airgun Surveys

Electromechanical (also referred to as HRG non-airgun surveys) surveys use a higher 

frequency, low-energy sound signal that is emitted and reflected back to the source. The survey 

equipment is either mounted to the ship or remotely operated vehicle (ROV), conducted using an 

autonomous underwater vehicle, or towed behind a survey vessel. The sound source and receiver 

can be located in a single piece of equipment or the sound source is collected by towed 

hydrophones. When conducted for oil and gas exploration and development, these seafloor- to 

shallow-focused subbottom penetration surveys are used to identify benthic/biological 

communities/habitats, archaeological resources, seafloor bathymetry, geological hazards, and

seafloor engineering.

There are several different types of HRG non-airgun (electromechanical) equipment used to 

meet the data needs and different sound levels (frequencies) used for different mapping resolutions. 

The specific frequency used would depend on the manufacturer, water depth, purpose of the survey, 

and seabed characteristics in the area of interest. Detailed descriptions of the different 

electromechanical/HRG non-airgun survey methods are provided in BOEM’s Atlantic G&G Activities 

Programmatic EIS (USDOI, BOEM, 2014a). A G&G Programmatic EIS is currently being developed 

for the GOM (refer to Chapter 1.7).

Gravity and Electromagnetic Surveys

Measurements of the earth’s gravity and magnetic fields are useful in helping to determine 

geologic structures in the subsurface. Such data are useful in frontier exploration areas and as a 

complement to seismic data in well-explored areas. Gravity and magnetic surveys are conducted 

from ships, in conjunction with airgun and electromechanical surveys, aircraft, or, very rarely, are 

conducted using an autonomous underwater vehicle. The types of surveys that help map oil and 

gas resources by measuring earth’s magnetic and gravity fields are summarized in BOEM’s Atlantic 

G&G Activities Programmatic EIS (USDOI, BOEM, 2014a).

Geological Surveys

Geological surveys are conducted to obtain information about surface and subsurface 

geological and geotechnical characteristics. For oil and gas purposes, this information is used to aid 

in the following: 

• siting, design, construction, and operation of production facilities; 

• assessment of sediment, stratigraphy, and geology (i.e., potential hydrocarbon 

source rock) characteristics; and 

• evaluation of subsurface properties, such as the presence of gas hydrates or 

hazards to drilling and/or physical structures.
3-16 Gulf of Mexico Multisale EIS

There are several different types of survey methods used to obtain geological/geotechnical 

information, including grab and box sampling, geologic coring, and shallow test drilling. Detailed 

descriptions of the different geological surveys are summarized in BOEM’s Atlantic G&G Activities 

Programmatic EIS (USDOI, BOEM, 2014a). As noted earlier, a G&G Programmatic EIS is currently 

being developed for the GOM (refer to Chapter 1.7).

How Much G&G Surveying Activity Could Occur? 

Due to the cyclic nature in the acquisition of seismic surveys, a prelease seismic survey 

would be attributable to lease sales held up to several years after the survey. In preparing the G&G 

activity forecast, BOEM began with a short-term forecast of 2D and 3D G&G activities based on 

historical relationships. Between 1968 and 2014 about 1,860,000 line miles of 2D data were 

acquired. Between 1993 and 2014 about 250,000 OCS blocks of 3D data were acquired. In 

constructing the current forecast, BOEM projected the number of narrow azimuth (NAZ) and wide 

azimuth (WAZ) 3D survey blocks for each planning area. The NAZ and WAZ 3D survey blocks were 

then added to generate a baseline forecast which was then anchored to the level of exploratory well 

drilling activities. This process defined a level of exploration effort per block of 3D seismic acquired. 

This forecast was then compared with historical 2D line miles and 3D blocks actually acquired in the 

GOM since 1968 (1993 for 3D) to ensure that the long-term projections were within the range of 

historical values. For 2D line mile projections, the number of permits forecasted was then derived 

through the average number of miles per permit issued using historical data, exploration well drilling 

effort from the exploration and development scenarios, and data from currently pending applications. 

BOEM conservatively assumed that one HRG survey would occur for every block leased (estimated 

by the number of production structures predicted) and that one HRG survey would occur for every 

5 km (3 mi) of pipeline laid (the average length of a pipeline permit). To estimate VSP surveys, 

BOEM conservatively assumed that a VSP survey would be conducted on 15 percent of all 

exploration and development wells drilled. Table 3-3 reflects a reasonable level of G&G surveying 

activities that could be expected to occur leading up to and following scheduled lease sales in the 

Gulf of Mexico single proposed lease sale areas (2017-2066). 

Table 3-3. Estimated Exploration and Seismic Survey Activity Leading Up To and Following a Proposed

Lease Sale in the Gulf of Mexico. 

Survey Area

2D 

Surveys

(mi)

2D 

Permits

3D Lease 

Blocks 

3D 

Permits

Ancillary 

Permits

HRG

Surveys

VSP

Surveys

Regionwide 48,000-

650,000 31-310 13,400-185,000 25-128 19-214 87-709 17-263

CPA/EPA 47,000-

603,000 27-283 18,900-171,300 20-108 16-198 64-576 11-234

WPA 900-4,100 4-9 5,500-

25,100 6-21 3-26 30-134 5-29

2D = two-dimensional; 3D = three-dimensional; HRG = high-resolution geophysical; VSP = vertical 

seismic profiling.
Impact-Producing Factors and Scenario 3-17

The term exploration well generally 

refers to the first well drilled on a 

prospective geologic structure to confirm 

that a resource exists and to validate 

how much resource can be expected.

If any action is proposed in an area of archaeological concern, BOEM or BSEE’s Regional 

Directors may also require the preparation of an archaeological report (which may include a sitespecific survey) to accompany the exploration (EP), development operations and coordination 

document (DOCD), or development and production plan (DPP) under 30 CFR § 250.194(c) and 

30 CFR § 550.194(c). Refer to Chapter 4.1.3 for information on archaeological requirements and 

impacts to archaeological resources. 

Alternative A, B, or C*: For each alternative, seismic surveys are projected to follow the 

same trend as exploration drilling activities, which would peak in 2030-2040 and decline until 

2060, with regards to a particular lease sale. Geophysical surveys generally would be the first 

activities to occur within the Gulf of Mexico. The HRG surveys generally occur before exploratory

drilling, but they can also occur before development drilling, platform and pipeline installation, and 

decommissioning activities. It is important to note that the cycling of G&G data acquisition is not 

driven by the 50-year life cycle of a single productive lease but instead would tend to respond to 

new production or potential new production driven by new technology. Consequently, some areas 

would be resurveyed in 2-year cycles, while other areas, considered nonproductive, may not be 

surveyed for 20 years or more. The above estimates far exceed the number of blocks available 

for leasing in the entire Gulf of Mexico OCS. Data collection may be repeated on any one block 

as technology advances, or multiple surveys may be conducted over the same OCS blocks for 

different purposes (e.g., prelease exploratory surveys and shallow hazard surveys).

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

is expected to still fall within those ranges; therefore, the scenarios do not change when 

considering Alternative D. The potential impacts associated with selecting Alternative D are 

discussed in Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

3.1.2.2 Exploration and Delineation Plans and Drilling

Oil and gas operators use drilling terms that 

represent stages in the discovery and development of 

hydrocarbon resources. If a resource is discovered 

during the drilling of an exploration well in quantities 

appearing to be economically viable, one or more

follow-up delineation wells are drilled. Refer to Figure 

3-3 above for a typical exploration and production 

timeline of an oil or gas lease. Delineation wells are drilled to specific subsurface targets in order to 

obtain information about the reservoir that can be used by the operator to identify the lateral and 

vertical extent of a hydrocarbon accumulation. Following a discovery, an operator often temporarily 

plugs and abandons the well to allow time for a development plan to be generated and submitted for 

approval and for equipment to be built or procured.
3-18 Gulf of Mexico Multisale EIS

In the GOM, exploration and delineation wells are typically drilled with mobile offshore drilling 

units (MODUs) (i.e., jack-up rigs, semisubmersible rigs, submersible rigs, platform rigs, or drill ships). 

Non-MODUs, such as inland barges, are also used. The type of rig chosen to drill a prospect 

depends primarily on water depth, though the water-depth ranges for each type of drilling rig do 

overlap to a degree. Other factors such as availability and daily rates also play a large role when an 

operator decides upon the type of drilling rig to contract. The water-depth ranges for drilling rigs 

used in this analysis are listed below: 

MODU or Drilling Rig Type Water-Depth Range

Jack-up, submersible, and inland barges ≤100 m (≤328 ft)

Semisubmersible and platform rig 100-3,000 m (328-9,843 ft)

Drillship ≥600 m (≥1,969 ft)

Historically, drilling rig availability has been a limiting factor for activity in the GOM and is 

assumed to be a limiting factor for activity projected as a result of a proposed lease sale. Drilling 

activities may also be constrained by the availability of rig crews, shore-based facilities, risers, and 

other equipment.

The scenario for each alternative assumes that an average exploration well would require 

6-10 weeks to drill per well, and more than one well can be drilled at a location. The actual time 

required for each well depends on a variety of factors, including the depth of the prospect’s potential 

target zone, the complexity of the well design, and the directional offset of the wellbore needed to 

reach a particular zone. This scenario assumes that the average exploration or delineation well 

depth would be approximately 4,210-8,080 m (13,800-26,500 ft) below the mudline.

Some delineation wells may be drilled using a sidetrack technique. In sidetracking a well, a 

portion of the existing wellbore is plugged back to a specific depth, directional drilling equipment is 

installed, and a new wellbore is drilled to a different geologic location. The lessee may use this 

technology to better understand their prospect and to plan future wells. Use of this technology may 

also reduce the time and exploration expenditures needed to help evaluate the prospective horizons 

on a new prospect.

The cost of an average exploration well can be $40-$150 million or more, without certainty 

that objectives can be reached. Some recent ultra-deepwater exploration wells (>6,000-ft [1,829-m] 

water depth) in the GOM have been reported to cost upwards of $200 million. The actual cost for 

each well depends on a variety of factors, including the depth of the prospect’s potential target zone, 

the complexity of the well design, and the directional offset of the wellbore needed to reach a 

particular zone.
Impact-Producing Factors and Scenario 3-19

Figure 3-4 represents a generic 

well schematic for a relatively shallow 

exploration well in the deepwater GOM. 

This well design was abstracted from 

actual well-casing programs from 

projects in the Mississippi Canyon and 

De Soto Canyon Areas and from 

internal BOEM data. A generic well 

configuration cannot capture all of the 

possible influences that impact how a 

well is designed. These influences 

include (1) unique geologic conditions 

at a specific well location, (2) directional 

drilling requirements, (3) potential 

sidetrack(s), or (4) company 

preferences. For exploration wells, 

contingencies (such as anticipated 

water-flow zones in the formation) must 

also be considered in the casing 

program.

For exploration and 

development, deep water is defined as 

water ≥1,000 ft (≥305 m) deep and 

ultra-deepwater is defined as water

≥5,000 ft (≥1,524 m) deep. The drilling 

(spudding) of a deepwater exploration 

well begins with setting the conductor 

casing, one of the many sections or 

strings of casing (steel tube) installed in 

the wellbore. The first casing set in the 

sea bottom (or mudline) can be large, 

approximately 30-40 in (75-100 cm) in 

diameter. The larger diameter pipe may be necessary when drilling through salt to reach subsalt 

objectives because more casing strings may be needed to reach the well’s objective. The first string 

is emplaced by drilling or “jetting” out the unconsolidated sediment with a water jet as the largest 

casing pipe is set in place. The casing is cemented to the sea bottom and tested. Because the 

shallow sediments are frequently soft and unconsolidated, the next casing interval (1,000 ft [305 m] 

or more below mudline) is commonly drilled with treated seawater and without a riser (a steeljacketed tube that connects the wellhead to the drill rig and within which the drilling mud and cuttings 

circulate). Because a riser is not used, the formation cuttings are typically discharged from the 

wellbore directly to the sea bottom unless the location is near sensitive bottom areas (NTL 

2009-G40). Muds and cuttings are discussed further in Chapter 3.1.5.1.1. After the conductor 

Figure 3-4. General Well Schematic (USDOI, 2010) (not to 

scale). 
3-20 Gulf of Mexico Multisale EIS

casing is set, a blowout preventer (BOP) would be installed, commonly at the sea bottom, the riser 

connected, and circulation for drilling muds and cuttings between the well bit and the surface rig 

established.

Next, a repetitive procedure would take place until the well reaches its planned total depth: 

(1) drill to the next casing point; (2) install the casing; (3) cement the casing; (4) test the integrity of 

the seal; and (5) drill through the cement shoe and downhole until the next casing point is reached 

and a narrower casing string is then set.

As drilling activities occur in progressively deeper waters, operators may consider using 

MODUs that have onboard hydrocarbon storage capabilities. This option may be exercised if a well 

requires extended flow testing (1-2 weeks or longer) in order to fully evaluate potential producible 

zones and to justify the higher costs of deepwater development activities. The liquid hydrocarbons 

resulting from an extended well test could be stored onboard a rig and later transported to shore for 

processing. Operators may also consider barge shuttling hydrocarbons from test well(s) to shore. 

There are some dangers inherit with barging operations if adverse weather conditions develop 

during testing. If operators do not choose to store produced liquid hydrocarbons during the well 

testing, they must request and receive approval from BSEE to burn test hydrocarbons. The BSEE 

would only grant permission to flare or vent associated natural gas during well cleanup and for welltesting procedures for a limited period of time.

The regulation at 30 CFR part 550 subpart B specifies the requirements for the exploration 

plans (EPs) that operators must submit to BOEM for approval prior to deploying an exploration 

program. Refer to Appendix A.2 for a detailed discussion of regulations, processes, and 

environmental information requirements for lessees and operators related to EPs, operation plans, 

and DOCDs. Refer to Chapters 1.3.1 and 3.1.10, which provide a summary of new safety 

requirements.

How Much Exploratory Drilling Activity Would Likely Occur? 

Following a lease sale, exploratory drilling activity would likely occur over the course of each 

lease but could begin within 1 year. The majority of the exploratory drilling for all blocks leased 

would likely occur early and would generally be complete by the 25th year. Refer to Figure 3-5(A)

below. Table 3-2 and Figure 3-5(B, C) show the estimated range of exploration and delineation 

wells by water-depth range. Regardless of the production scenario or alternative, most exploration 

drilling activity is expected to be on the continental shelf (0-200 m [0-656 ft] water depth). 
Impact-Producing Factors and Scenario 3-21

Figure 3-5. (A) Number of Exploration and Delineation Wells Drilled over the Course of a Proposed 

Action under Alternative A for 50 Years. (B, C) Location of Exploration Wells Drilled during 

the Entire 50-Year Period. (Note: This drilling activity spans 40 years. These wells are not 

all drilled during the same time period. The most wells drilled in a given year is 64, and the 

most wells drilled in any given 5-year span is 298.) 

Alternative A*: BOEM estimates that 53-984 exploration and delineation wells would be 

drilled as a result of forecasted activity associated with Alternative A. 

Alternative B*: BOEM estimates that 33-893 exploration and delineation wells would be 

drilled as a result of forecasted activity associated with Alternative B.
3-22 Gulf of Mexico Multisale EIS

A development well is drilled to 

extract resources from a known 

hydrocarbon reservoir.

Alternative C*: BOEM estimates that 17-91 exploration and delineation wells would be 

drilled as a result of forecasted activity associated with Alternative C. 

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternative A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

3.1.3 Offshore Development and Production 

3.1.3.1 Development and Production Drilling

Delineation and production wells are sometimes 

collectively termed development wells. After a development 

well is drilled, the operator must decide whether or not to 

complete the well without delay, to delay completion with the 

rig on station so that additional tests may be conducted, or to 

temporarily abandon the well site and move the rig off station to a new location and drill another well. 

Sometimes an operator may decide to drill a series of development wells, move off location, and 

then return with a rig to complete all the wells at one time. If an exploration well is clearly a dry hole, 

the operator would typically permanently abandon the well without delay, but could convert the well 

into an injection well. An injection well is typically used to store CO2, dispose of produced water, or 

enhance oil production. 

Depending on the information obtained from delineation well drilling, these wells can be 

completed and prepared to serve as production wells. Production wells are wells that are drilled 

following the delineation stage of the development program. The production well would be drilled 

specifically for the purpose of extracting hydrocarbons from the subsurface and therefore positioned 

within the reservoir in locations where the greatest volume of production can be realized. Wells 

initially drilled as delineation wells that are later converted to production wells and wells drilled as 

production wells are sometimes collectively referred to as development wells.

Following the drilling of development wells, the operator of a field may decide to remain on 

location and immediately begin the next stage of the field development program, i.e., preparing the 

development wells for production. However, there are a number of reasons that the operator may 

decide to move off location and delay the work required to prepare the wells for production; for 

example, additional well tests may be required or the drilling rig may be committed to another 

location. When a decision to delay the work is chosen, each development well would be temporarily 

abandoned before the drilling rig can be moved to another location. It is also common for an 

operator to drill the required number of development wells in stages, leaving some time between the 
Impact-Producing Factors and Scenario 3-23

well drilling stages to evaluate the information obtained from the wells and, if necessary, use this 

information to modify the development program.

What is the Well Completion Process?

Should the operator decide to move forward with developing a well, completion operations 

must be undertaken. If it is decided that the well will not be completed, then it will be plugged and 

abandoned (Chapter 3.1.3.5). When the decision is made to perform a well completion, a new 

stage of activity begins to convert an individual borehole into an operational system for controlled 

recovery of underground hydrocarbon resources. Those activities include installation of the final well 

casings that isolate fluid migrations along the borehole length while also establishing perforated 

sections where needed to capture the hydrocarbons from the geologic reservoir into the production 

casing (National Petroleum Council, 2011).

Different geologic and reservoir properties will affect the completion process. The primary 

drivers of offshore completions in the GOM are sand control and formation stimulation with an 

extensive history of successful application. As described below, there is a wide range of variability in 

the particular activities that might be used in the completion process, depending on the specific 

characteristics of the well. Many of the terms used to describe these activities (e.g., fracking and 

acidization) do not have precise, fixed definitions in all contexts. Accordingly, two very different 

processes with different potential environmental impacts may both be called by the same name. For 

these reasons, the description of these activities in this chapter is meant to be a general description 

of the range of activities that may be involved in well completion. BOEM estimates that 

approximately 63-70 percent of wells drilled as development wells become producing wells. The 

majority of these production wells are anticipated to undergo some form of well stimulation during 

their production life, with many (>65% [Sanchez and Tibbles]) being frac-pack completions. 

Implementation of the well stimulation activities included in a proposed action would largely use 

existing infrastructure and would not result in bottom-disturbing activities, except potentially the 

drilling of new injection wells.

There is a wide variety of well completion techniques performed in the Gulf of Mexico, and 

the type of well completion used to prepare a drill well for production is based on the rock properties 

of the reservoir as well as the properties of the reservoir fluid. However, for the vast majority of well 

completions, the typical process includes installing or “running” the production casing, cementing the 

casing, perforating the casing and surrounding cement, injecting water, brine, or gelled brine as 

carrier fluid for a “frac pack”/sand proppant pack and gravel pack; treating/acidizing the reservoir 

formation near the wellbore; installing production screens; running production tubing; and installing a 

production tree. Cement is pumped into the well both to displace drilling fluids that remain in the well 

and also to fill in the space that exists between the casing and the face of the rock formations in the 

wellbore. The casing and cement would be perforated adjacent to the reservoir to allow the 

reservoir fluids to enter the wellbore.
3-24 Gulf of Mexico Multisale EIS

A gravel pack (a non-fracturing treatment) is a filtration system in which a metal screen is 

placed in the wellbore and the surrounding annulus is packed with prepared gravel of a size 

designed to provide a barrier preventing formation sand from entering the well with the 

hydrocarbons. The main objective of gravel packs is to stabilize the formation while causing minimal 

impairment to well productivity. The term “frac pack” has become an industry-recognized term for 

the completion process of fracturing and gravel packing and is the most widely used completion 

technique for sand control in the Gulf of Mexico. The “frac pack” process, which has been used in 

the Gulf of Mexico for more than 25 years, combines the production improvement from hydraulic 

fracturing (see below) with the sand control provided by gravel packing. Typically, about 

30-35 percent of the oil present in the reservoir at the start of production is recovered during primary 

recovery (Hyne, 2012). The use of well stimulation treatments supports the continued recovery of oil 

as primary recovery of an oil and/or gas reservoir declines. These activities are covered by a permit 

known as an Application for Permit to Modify. All Applications for Permit to Modify are reviewed and 

approved by BSEE. BOEM carries forward any established mitigating measures based upon lease 

stipulations/terms, regulatory requirements, etc., to the individual plan actions.

Well treatment, such as acidizing, is used to improve the flow of reservoir fluids into the 

wellbore by cleaning out and/or dissolving debris that accumulates in the wellbore and near-wellbore 

reservoir formation as a result of the drilling process. For moderate to high permeability reservoirs, 

today’s most technologically advanced well treatment and stimulation processes are designed not 

only to mitigate flow restrictions caused by a reduction in permeability in the near-wellbore region 

(also known as formation “damage”) but also to serve as another mechanism to help control the flow 

of sand into the wellbore and to enhance the flow rate of the well. Production tubing is run inside the 

casing. Production tubing protects the casing from wear and corrosion, and it provides a continuous 

conduit for the reservoir fluid to flow from the reservoir to the wellhead. The production tree is a 

wellhead device that is used to control, measure, and monitor the conditions of the reservoir and the 

well from the surface.

The term hydraulic fracturing covers a broad range of techniques used to stimulate and 

improve production from a well. Fracture fluid is injected into a wellbore at high pressure to break 

open the rock to create/improve the flow path for hydrocarbon to flow in to the well. The pressurized 

high-density, gelatin-like fluid also serves as the carrier agent for the mechanical agent or proppant 

that is mixed with the completion fluids. The mechanical agents, typically sand, manmade ceramics, 

or small microspheres (tiny glass beads), are injected into the small fractures and remain lodged in 

the fractures when the process is completed. The proppant serves to hold the fractures open, 

allowing them to perform as conduits to assist the flow of hydrocarbons from the reservoir formation 

to the wellbore. Well-treatment chemicals are also commonly used to improve well productivity. For 

example, acidizing is a common well-treatment procedure in the GOM as well. 

In contrast to the large-scale, induced hydraulic fracturing procedures, commonly referred to 

as “fracking,” used in onshore oil and gas operations for low-permeability “tight gas,” “tight oil,” and 

“shale gas” reservoirs, the vast majority of hydraulic fracturing treatments carried out on the OCS in 

the GOM are fracture packs, which are small scale by comparison and most commonly used for 
Impact-Producing Factors and Scenario 3-25

high-permeability formations to reduce the concentration of sand and silt in the produced fluids and 

to maintain high flow rates. The fracture pack or “frac-pack” completion process uses pressurized 

fluids, typically seawater, brine, or gelled brine, to create small fractures in the reservoir rock within a 

zone near the wellbore where the reservoir’s permeability was damaged by the drilling process. 

Since formation “damage” caused by drilling operations does not extend for large distances away 

from the reservoir-borehole interface, the fracturing induced by the procedure is also designed to 

remain in close proximity to the borehole, extending distances of typically 15-30 m (49-98 ft) from the 

borehole (Ali et al., 2002; Sanchez and Tibbles, 2007) to prevent the production of formation fines 

and sand. 

Additives used in fracture-pack operations are often similar, if not identical, to those used for 

shale or tight sand development in other regions and are used for similar purposes. The 

concentrations of some of these additives are typically different due to the GOM’s very different 

geologic characteristics of the producing formation. The most significant difference is that the GOM 

typically has much higher formation permeability and lower amounts of clay/shale in typical 

formations (API, 2015). Another factor that can substantially influence additive selection and use in 

offshore operations is the ability to discharge treated wastewaters that meet applicable regulatory 

requirements (API, 2015).

Boehm et al. (2001) notes 22 functional categories of additives and 2 categories of 

proppants used offshore in the GOM for fracturing activities:

—water-based polymers

—defoamers

—friction reducers

—oil gelling additives

—fluid loss additives

—biocides

—breakers 

—acid-based gel systems

—emulsifiers 

—water-based systems

—clay stabilizers 

—cross-linked gel systems

—surfactants

—alcohol/water systems

—non-emulsifiers

—oil-based systems

—pH control additives

—polymer plugs

—crosslinkers

—continuous mix gel concentrates

—foamers

—resin-coated proppants

—gel stabilizers

—intermediate-to-high strength ceramic 

proppants

Each of these is described in greater detail in the Boehm et al. (2001) study, along with other 

treatment and completion chemicals. The appendix to the study offers a chemical inventory with 

example products and Material Safety Data Sheets for those products. In general, discharges of any 

fluids, including those associated with well completion, are subject to the terms of National Pollution 

Discharge Elimination System (NPDES) permits issued by the USEPA under the Clean Water Act. 

These permits place limitations on the toxicity of selected effluents, as well as other requirements for 

monitoring and reporting. Wastes and discharges generated from OCS oil- and gas-related 

activities, including produced water and well completion fluids, are addressed in Chapter 3.1.5. 
3-26 Gulf of Mexico Multisale EIS

During a “frac pack,” the pumping equipment, sand (proppant), and additives are carried, 

mixed, and pumped from a specialized stimulation and treatment vessel. The base fluid that is used 

for the frac-pack operation would typically be treated seawater, although other brines may be used if 

conditions dictate (API, 2015). BOEM considers these large special purpose vessels (supporting 

fracturing operations) as offshore supply/service vessels (OSVs). In Table 3-2, the number of OSV 

trips is estimated by subareas (range of water depths) in the GOM. Potential impacts associated 

with OSVs are described in various chapters throughout this Multisale EIS; these impacts include 

operational wastes, noise, and air emissions related to vessel movement throughout the GOM.

What is explained above is a general procedure for “frac-pack” operation, but every 

fracturing job is case specific. In general, the fracturing process remains the same but chemical 

formulations, fluid and proppant volumes, pump time, and pressure will vary based on the depth and 

engineering/geologic parameters for a particular well completion. After a production test determines 

the desired production rate to avoid damaging the reservoir, the well is ready to go online and 

produce.

A deepwater operations plan is required for all deepwater development projects in water 

depths ≥1,000 ft (305 m) and for all projects proposing subsea production technology. A deepwater 

operations plan is required initially and is usually followed by a DOCD. The DOCD is the chief 

planning document that lays out an operator’s specific intentions for development. Refer to 

Appendix A.2 for a detailed discussion on regulations, processes, and environmental information 

requirements for lessees and operators related to EP’s, deepwater operations plans, and DOCDs.

How Much Development Activity Would Likely Occur? 

Development activity during a proposed action usually takes place over a 49-year period, 

beginning with the installation of a production platform on the first lease and ending with the drilling 

of the last development wells. The majority of development well drilling would likely occur in the first 

25 years of each lease. Production of oil and gas could begin by the third year after the lease sale 

and generally would conclude by the 50th year; refer to Figure 3-6(A) below. Table 3-2 and 

Figure 3-6(B, C) show the estimated range of development and production wells by water-depth 

range. In the low production scenario, development and production activity is expected to occur

fairly evenly spread between the continental shelf (0- to 200-m [0- to 656-ft] water depth) and deeper 

water depths (200-1,600 m; 656-5,249 ft) with a majority of activity in the CPA; however, for the high 

production scenario, most development and production drilling activity is expected to occur on the 

continental shelf (0- to 200-m [0- to 656-ft] water depth). 
Impact-Producing Factors and Scenario 3-27

Figure 3-6. (A) Number of Production Wells Drilled over the Course of a Proposed Action under 

Alternative A for 50 Years. (B, C) Total Number of Development and Production Wells 

Drilled in the Low and High Production Scenario by Water Depth for Alternative A. (Note: 

This drilling activity spans 40 years. Multiple wells can be drilled from a single structure. 

These wells are not all drilled during the same time period. The most wells drilled in a 

given year is 35, and the most wells drilled in any given 5 year span is 150.) 
3-28 Gulf of Mexico Multisale EIS

Alternative A*: It is estimated that 61-767 development and production wells would be 

drilled as a result of forecasted activity associated with Alternative A. Table 3-2 shows the 

estimated range of development wells by water depth.

Alternative B*: BOEM estimates that 46-671 development and production wells would be 

drilled as a result of Alternative B. 

Alternative C*: BOEM estimates that 22-96 development and production wells would be 

drilled as a result of Alternative C. Table 3-2 shows the estimated range of development and 

production wells by water-depth subarea.

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.
Impact-Producing Factors and Scenario 3-29

3.1.3.2 Offshore Production Systems

After the approval of an EP or 

DOCD, the operator submits 

applications for specific activities, 

including production systems, to BOEM 

for approval. Refer to Appendix A.3

for more information on permits and 

applications related to offshore 

production systems.

Development wells may be 

drilled from movable structures, such 

as jack-up rigs, fixed bottom-supported 

structures, floating vertically moored 

structures, floating production facilities, 

and drillships (either anchored or 

dynamically positioned drilling vessels) 

(Figure 3-7). The spectrum of these 

production systems is discussed in 

Chapter 3.1.3.2 below.

The type of production 

structure installed at a site depends 

mainly on water depth, but the total 

facility lifecycle, type and quantity of 

hydrocarbon production expected, number of wells to be drilled, and number of anticipated tie backs 

from other fields can also influence an operator’s procurement decision. The number of wells per 

structure varies according to the type of production structure used, the prospect size, and the 

drilling/production strategy deployed for the drilling program and for resource conservation. 

Production systems can be fixed, floating, or, increasingly in deep water, subsea. Advances in the 

composition of drilling fluids and drilling technology are likely to provide operators with the means to 

reduce rig costs in the deepwater OCS program.

Until recently, there had been a gradual increase of drilling depth (as measured in true 

vertical depth). Beginning in 1996, the maximum drilling depth increased rapidly, reaching depths 

below 30,000 ft (9,144 m) in 2002. In 2013, Cobalt International Energy drilled the Ardennes #1 

exploration well (Green Canyon Block 896), reaching a true vertical depth of 36,552 ft (11,141 m). 

The recent dramatic increase in true vertical depth may be attributed to several factors, including 

enhanced rig capabilities, deeper exploration targets, royalty relief for shallow water, deep gas 

prospects, and the general trend toward greater water depths.

Figure 3-7. Offshore Production Systems.
3-30 Gulf of Mexico Multisale EIS

BOEM has described and characterized production structures in its deepwater reference 

document (USDOI, MMS, 2000a). These descriptions are summarized below and were used in 

preparing the scenario for this Multisale EIS. In water depths of up to 400 m (1,312 ft), the scenarios 

assume that conventional, fixed platforms that are rigidly attached to the seafloor would be the type 

of structure preferred by operators. In water depths of <200 m (656 ft), 20 percent of the platforms 

are expected to be manned (defined as having sleeping quarters on the structure). In depths 

between 200 and 400 m (656 and 1,312 ft), all structures are assumed to be manned. It is also 

assumed that helipads would be located on 66 percent of the structures in water depths <60 m 

(197 ft), on 94 percent of structures in water depths between 60 and 200 m (656 ft), and on 

100 percent of the structures in water depths >200 m (656 ft). At water depths >400 m (1,312 ft), 

platform designs based on rigid attachment to the seafloor are not expected to be used. The 400-m 

(1,312-ft) isobath appears to be the current economic limit for this type of structure.

Fixed Platforms

A fixed platform consists of a welded tubular steel jacket, deck, and surface facility. The 

jacket and deck make up the foundation for the surface facilities. Piles driven into the seafloor 

secure the jacket. The water depth at the intended location dictates the height of the platform. Once 

the jacket is secured and the deck is installed, additional modules are added for drilling, production, 

and crew operations. Large, barge-mounted cranes position and secure the jacket prior to the 

installation of the topsides modules. While the base dimensions are typically around 200,000 ft2

(18,581 m2

), the topside modules is typically only 40,000 ft2 (3,716 m2). Economic considerations 

limit development of fixed (rigid) platforms to water depths no greater than 1,500 ft (457 m) (USDOI, 

MMS, 2000a).

A caisson is a fixed platform that consists of a single vertical column that rises from the 

seabed and supports a small surface facility above the water. This is termed a free-standing 

caisson. A braced caisson has the same general structure, but the column is laterally supported by 

one or more inclined braces. Caissons are not generally designed to be manned.

Compliant Towers

Compliant towers are similar to fixed platforms in that they have a steel tubular jacket that is 

used to support the surface facilities. Unlike fixed platforms, compliant towers yield to the water and 

wind movements in a manner similar to floating structures. Like fixed platforms, they are secured to

the seafloor with piles. The jacket of a compliant tower has smaller dimensions than those of a fixed 

platform and may consist of two or more sections. It can also have buoyant sections in the upper 

jacket with mooring lines from jacket to seafloor (guyed-tower designs) or a combination of the two. 

The water depth at the intended location dictates platform height. Once the lower jacket is secured 

to the seafloor, it acts as a base (compliant tower) for the upper jacket and surface facilities. Large 

barge-mounted cranes position and secure the jacket and install the surface facility modules. These 

differences allow the use of compliant towers in water depths ranging up to 3,000 ft (914 m). The 

base dimensions of a compliant tower are typically smaller than a fixed platform and is only around 

90,000 ft2 (8,361 m2

), and the topside modules are typically only 40,000 ft2 (3,716 m2). This range is 
Impact-Producing Factors and Scenario 3-31

generally considered to be beyond the economic limit for fixed jacket-type platforms (USDOI, MMS, 

2000a).

Spar

A spar is a deep-draft floating caisson, which is a hollow cylindrical structure approximately 

90-120 ft (27-36 m) in diameter similar to a very large buoy. Its four major systems are hull, 

moorings, topsides, and risers. The spar relies on a traditional mooring system (i.e., anchor-spread 

mooring) to maintain its position. About 90 percent of the structure is underwater and supports a 

conventional production deck (USDOI, MMS, 2000a). A third generation of spar design is the cell 

spar. The cell spar’s hull is composed of several identically sized cylinders surrounding a center 

cylinder. The cylinder or hull may be moored via a chain catenary or semi-taut line system 

connected to 6-20 anchors on the seafloor. Spars are now used in water depths up to 900 m 

(2,953 ft) and may be used in water depths of 3,000 m (9,843 ft) or deeper (NaturalGas.org, 2010; 

USDOI, MMS, 2006; Oynes, 2006).

Tension-Leg Platform

A tension-leg platform (TLP) is a buoyant platform held in place by a mooring system. The

TLPs are similar to conventional fixed platforms except that the platform is maintained on location 

through the use of moorings held in tension by the buoyancy of the hull. The mooring system is a 

set of tension legs or tendons attached to the platform and connected to a template or foundation on 

the seafloor. Tendons are typically steel tubes with dimensions of 2-3 ft (0.6-0.9 m) in diameter with 

up to 3 in (8 cm) of wall thickness, with the length depending on water depth. A typical TLP would 

be installed with as many as 16 tendons. The template is held in place by piles driven into the 

seafloor. This method dampens the vertical motions of the platform but allows for horizontal 

movements. The topside facilities (i.e., processing facilities, pipelines, and surface trees) of the TLP 

and most of the daily operations are the same as for a conventional platform (USDOI, MMS, 2000a).

Semisubmersible Production Structures 

Semisubmersible production structures (semisubmersibles) resemble their drilling rig 

counterparts and are the most common type of offshore drilling rig (NaturalGas.org, 2010). 

Semisubmersibles are partially submerged with pontoons that provide buoyancy. Their hull contains 

pontoons below the waterline and vertical columns that connect to the hull box/deck. The structures 

keep on station with conventional, catenary, or semi-taut line mooring systems connected to anchors 

in the seabed. Semisubmersibles can be operated in a wide range of water depths. Floating 

production systems are suited for deepwater production in depths up to 8,000 ft (26,437 m) 

(NaturalGas.org, 2010; USDOI, MMS, 2006; Oynes, 2006).

Subsea Production Systems

For some development programs, especially those in deep and ultra-deepwater, an operator 

may choose to use a subsea production system instead of a floating production structure. Although 

the use of subsea systems has recently increased as development has moved into deeper water, 
3-32 Gulf of Mexico Multisale EIS

subsea systems are not new to the GOM and they are not used exclusively for deepwater 

development. Unlike wells from conventional fixed structures, subsea wells do not have surface 

facilities directly supporting them during their production phases. A subsea production system has 

various bottom-founded components. Among them are well templates, well heads, “jumper” 

connections between well heads, flow control manifolds, in-field pipelines and their termination 

sleds, and umbilicals and their termination assemblies. A subsea production system can range from 

a single-well template connected to a nearby manifold or pipeline to a riser system at a distant 

production facility or a series of wells that are tied into the system. Subsea systems rely on a “host” 

facility for support and well control. Centralized or “host” production facilities in deep water or on the 

shelf may support several satellite subsea developments. A drilling rig would be brought on location 

to provide surface support to reenter a well for workovers and other types of well maintenance 

activities. In addition, should the production/safety system fail and a blowout result, surface support 

must be brought on location to regain control of the well.

Floating Production, Storage, and Offloading Systems

The category of floating production systems referred to as floating production, storage, and 

offloading systems (FPSOs) can normally be characterized as ship-shape vessels (tankers) that 

have been retrofitted (conversions) or purpose built (new built) for this application (USDOI, MMS, 

2000a). Floating systems are differentiated as follows:

• FPSO — floating production, storage, and offloading system; offloading of the 

crude oil to a shuttle tanker; these are typically converted or newly built tankers 

that produce and store hydrocarbons, which are subsequently transported by 

other vessels to terminals or deepwater ports.

• FPS — floating production system; universal term to refer to all production 

facilities that float rather than are structurally supported by the seafloor; included 

would be TLPs, spars, semisubmersibles, shipshape vessels, etc. The term is 

also frequently used to describe the general category of floating production 

facilities that do not have onsite storage. The term is also used by the American 

Bureau of Shipping to describe a classification of floating production facilities that 

do not have storage capability.

• FSO — floating storage and offloading system; like the FPSO, these are typically 

converted or newly built tankers. They differ from the FPSO by not incorporating 

the processing equipment for production; the liquids are stored for shipment to 

another location for processing.

BOEM’s predecessor, MMS, prepared an EIS on the potential use of FPSOs on the Gulf of 

Mexico OCS (USDOI, MMS, 2001). In accordance with the scenario provided by industry, the FPSO

environmental impact statement addresses the proposed use of FPSOs in the deepwater areas of 

the CPA and WPA only. In January 2002, this Agency announced its decision to accept applications 

for FPSOs after a rigorous environmental and safety review. Petrobras Americas Inc. developed the 
Impact-Producing Factors and Scenario 3-33

first FPSO to come online in the GOM and began production in June 2012 from two prospects. The 

Cascade Prospect (Walker Ridge Block 206 Unit) is located approximately 250 mi (402 km) south of 

New Orleans, Louisiana, and about 150 mi (241 km) from the Louisiana coastline in approximately 

8,200 ft (2,499 m) of water. The Chinook Prospect (Walker Ridge Block 425 Unit) is located about 

16 mi (26 km) south of the Cascade Prospect. A second FPSO, Shell Stones, began production in 

2016. 

3.1.3.3 Infrastructure Emplacement/Structure Installation and Commissioning Activities

Structures described in Chapter 3.1.3.2 may be placed over development wells to facilitate 

production from a prospect. These structures provide the means to access and control wells. They 

serve as a staging area to process and treat produced hydrocarbons from wells, initiate export of 

produced hydrocarbons, conduct additional drilling or reservoir stimulation, conduct workover 

activities, and carry out eventual abandonment procedures. There is a range of offshore 

infrastructure installed for hydrocarbon production. Among these are pipelines, fixed and floating

platforms, caissons, well protectors, casing, wellheads, and conductors.

Subsea wells may also be completed to produce hydrocarbons from on the shelf and in the 

deepwater portions of the GOM. The subsea completions would require a host structure to control 

their flow and to process their well stream. Control of the subsea well is accomplished via an 

umbilical from the host.

Pipelines are the primary means of transporting produced hydrocarbons from offshore oil 

and gas fields to distribution centers or onshore processing points. Pipelines range from smalldiameter (generally 4-12 in; 10-30 cm) gathering lines, sometimes called flowlines, that link 

individual wells and production facilities to large-diameter (as large as 36 in; 91 cm) lines, sometimes 

called trunk lines, for transport to shore. Pipelines would typically be installed by lay barges that are 

either anchored or dynamically positioned while the pipeline is laid. Pipeline sections may be 

welded together on a conventional lay barge as it moves forward on its route or they may be welded 

together at a fabrication site onshore and wound onto a large-diameter spool or reel. Once the reel 

barge is on location, the pipeline is straightened and lowered to the seafloor on its intended route. 

Both types of lay barge use a stinger to support the pipeline as it enters the water. The stinger helps 

to prevent undesirable bending or kinking of the pipeline as it is installed. In some cases, pipelines 

or segments of pipelines are welded together onshore or along a beach front area and then towed 

offshore to their location for installation. In a typical offshore operation, a lay barge would move one 

pipe length every 15 minutes, while third-generation barges may achieve rates of a mile per day 

(Wolbers and Hovinga, 2003). The rate of progress depends on the lay barge type, crew 

experience, and weather. Additional information on pipeline installation can be found in Chapter 

3.1.3.3.1 below.

Fixed, jacketed platforms are the most common surface structures of the GOM (refer to

Chapter 3.1.3.2) and account for about 60 percent of all bottom-founded surface structures on the 

shallow continental shelf. Fixed platforms are brought on location as a complete unit or in sections 
3-34 Gulf of Mexico Multisale EIS

on an installation barge towed by powerful tug boats. If the structure is fabricated in sections, it is 

generally composed of two segments: the jacket and the deck. Accidents have occurred during the 

vulnerable period when heavy equipment is held only by cranes. In December 1998, the 3,600-ton 

topside structure for the Petronius compliant tower was lost in 1,750 ft (533 m) of water as it was 

being lifted into place by the lift barge in Viosca Knoll Block 892.

The platform’s tubular-steel jacket would then be launched from the barge, upended, and 

lowered into position by a derrick barge with a large crane. The jacket is anchored to the seafloor by 

piles driven through the legs. The deck section with one or more levels is then lifted atop the jacket 

and welded to the foundation. The platform may have a helipad installed on its deck section. 

Platforms may or may not be manned continuously. The different types of floating platforms are 

discussed in Chapter 3.1.3.2. 

Caissons are the second most numerous and account for about 30 percent of bottomfounded, surface structures in the GOM. Caissons are typically located primarily on the shallow 

continental shelf. Simpler in design and fabrication than traditional jacketed platforms, most 

caissons consist of a steel pipe that generally ranges from 36 to 96 in (91 to 2.44 cm) in diameter. 

The caisson pipe is driven over existing well(s) to a depth that allows for shoring against varying sea 

states. Though primarily installed for well protection, some caissons may also be used as 

foundations for equipment and termination or relay points for pipeline operations.

Well protectors account for about 10 percent of all bottom-founded surface structures in the 

GOM. Well protectors are used primarily to safeguard producing wells and their production trees 

from boat damage and from battering by floating debris and storms. Similar to fixed platforms, well 

protectors consist of small piled jackets with three or four legs generally less than 36 in (91 cm) in 

diameter, which may or may not support a deck section.

In shallow-water installations, jackets, piles, and topsides are fabricated onshore and 

transported to the site on a cargo barge, and installation times usually range from 2-4 weeks. For 

most deepwater systems, installation activities would extend over a period of 2 or 3 months or more, 

and if a number of wells are subsea, drilling and completion activities may extend over several 

years. The time required to complete the myriad of operations to start production at a structure is 

dependent on the complexity of its facilities.

To keep floating structures on station, a mooring system would be designed and installed. 

Lines to anchors or piling arrays attach the floating components of the structure. With a TLP, 

tendons stem from a base plate on the sea bottom to the floating portion of the structure. 

Commissioning activities involve the emplacement, connecting, and testing of the structure's 

modular components that are assembled onsite.
Impact-Producing Factors and Scenario 3-35

How Much Offshore Support Infrastructure Could Be Developed?

Following a lease sale, support infrastructure installation would likely occur over the course 

of each lease but could begin within 1 year. The majority of platforms installed in early years would 

be caissons and small fixed platforms in shallow water. Floating structures installed in deeper water 

would take several years to construct and install. The highest number of platforms operating as a 

result of a lease sale would peak before year 10 in the low production scenario and around year 25 

for the high production scenario; refer to Figure 3-8(A) below. Table 3-2 and Figure 3-8(B, C)

show the estimated range installed production structures by water-depth range. Regardless of the 

production scenario or alternative, most support structure installation is expected to be on the 

continental shelf (0- to 200-m [0- to 656-ft] water depth). 

Alternative A*: It is estimated that 16-280 production structures would be installed as a 

result of a lease sale under Alternative A. 

Alternative B*: It is estimated that 14-247 production structures would be installed as a 

result of a lease sale under Alternative B. 

Alternative C*: It is estimated that 17-91 production structures would be installed as a 

result of a lease sale under Alternative C.

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.
3-36 Gulf of Mexico Multisale EIS

Figure 3-8. Number of Production Structures and Service Vessels Operating over the Course of a 

Proposed Action under Alternative A for 50 Years. (B, C) Total Number of Platforms 

Installed in the Low and High Production Scenario by Water Depth. 
Impact-Producing Factors and Scenario 3-37

3.1.3.3.1 Pipelines

Pipelines are the primary method used to transport a variety of liquid and gaseous products 

between OCS production sites and onshore facilities around the GOM (Table 3-4). A mature 

pipeline network exists in the GOM to transport oil and gas production from the OCS to shore. 

There are currently 144 pipeline landfalls (pipelines that have at one time carried hydrocarbon 

product) in the Louisiana Coastal Area (LCA) (Smith, official communication, 2015). Included in this 

number of pipeline landfalls is a subset of 121 pipeline systems under the U.S. Department of 

Transportation’s (DOT) jurisdiction originating in Federal waters and terminating onshore or in 

Louisiana State waters (Smith, official communication, 2015; Table 3-5). There are 14 OCS oil- and 

gas-related pipelines that transition into Texas State lands or that make landfall onshore, many of 

which switch back across this boundary. The BSEE and DOT share responsibility for pipeline 

regulation on the OCS in the transition between Federal and State waters. For more information on 

the regulation and permitting of pipelines, refer to Appendix A.3. 

Table 3-4. Oil Transportation Scenario under Alternatives A, B, and C. 

Activity Alternative1 Offshore Subareas (m)2Totals3

0-60 60-200 200-800 800-1,600 1,600-2,400 >2,400

Percent Oil 

Piped4

A 72-94% 100% 100% 100% 100% 100-66% 99.8-90.0%

B 70-94% 100% 100% 100% 100% 100-50% 98.8-84.6%

C 100% 100% 100% 100% 100% 100% 100%

Percent Oil 

Barged

A 28-6% 0% 0% 0% 0% 0% 0.2%

B 30-6% 0% 0% 0% 0% 0% 0.2%

C 0% 0% 0% 0% 0% 0% 0%

Percent 

Tankered5

A 0% 0% 0% 0% 0% 0-34% 0-9.8%

B 0% 0% 0% 0% 0% 0-50% 0-15.2%

C 0% 0% 0% 0% 0% 0% 0% 1 Alternative D could reduce activity values of the combined Alternative A, B, or C. Refer to Chapter 2.2.2.4 for 

more information. Percentage values indicated here would not change.

2 Refer to Figure 3-2. Ranges are reported from the low production scenario to the high production scenario.

3 Subareas totals may not add up to the planning area total because of rounding.

4 100% of gas is assumed to be piped.

5 Tankering is forecasted to occur only in water depths >1,600 m (5,249 ft). 
3-38 Gulf of Mexico Multisale EIS

30 CFR § 250.1003

Pipelines greater than 8 5/8 inches in 

diameter and installed in water depths of 

less than 200 feet shall be buried to a 

depth of at least 3 feet unless they are 

located in pipeline congested areas or 

seismically active areas as determined 

by the Regional Supervisor.

Table 3-5. Existing Coastal Infrastructure Related to OCS Oil- and Gas-Related Activities in the Gulf 

of Mexico. 

Infrastructure Texas Louisiana Mississippi Alabama Florida Total

Pipeline Landfalls1 14 122 3 5 0 144

Platform Fabrication Yards2 12 37 4 1 0 54

Shipyards2 32 64 9 18 14 137

Pipe Coating Facilities2 9 6 0 2 2 19

Supply Bases2 32 55 2 7 0 96

Ports2 11 14 3 1 5 34

Waste Disposal Facilities2 16 29 3 3 2 53

Natural Gas Storage Facilities2 13 8 0 1 0 22

Helicopter Hubs2 118 115 4 4 0 241

Pipeline Shore Facilities2 13 40 0 0 0 53

Barge Terminals2 110 122 6 6 8 252

Tanker Ports2 4 6 0 0 0 10

Gas Processing Plants2 39 44 1 13 1 98

Refineries3 20 16 3 3 0 42

Petrochemical Plants2 126 66 2 9 13 216

1 Source: Smith, 2015.

2 Source: Dismukes, 2011.

3 Source: USDOE, Energy Information Administration, 2015a.

Newer installation methods have allowed the pipeline infrastructure to extend farther into 

deep water. The gas pipeline supporting the Shell Stones FPSO is expected to be the deepest 

pipeline in the GOM at 2,900 m (9,500 ft). More than 500 pipelines reach water depths of 400 m 

(1,312 ft) or more, and over 400 of those pipelines reach water depths of 800 m (2,625 ft) or more. 

These technical challenges are described in more detail in Deepwater Gulf of Mexico 2006: 

America’s Expanding Frontier (USDOI, MMS, 2006).

Pipeline Installation and Maintenance

Pipelines constructed in water depths <200 ft 

(61 m) are potential snags for anchors and trawls and 

must be buried according to BSEE’s regulations. 

These pipelines account for 56 percent of the total 

pipeline length in Federal waters. The regulations also 

provide for the burial of any pipeline, regardless of 

size, if BSEE determines that the pipeline may 

constitute a hazard to other uses of the OCS; in the 

Gulf of Mexico, BSEE has determined that all pipelines 

installed in water depths <60 m (197 ft) must be 

buried. The purpose of these requirements is to reduce the movement of pipelines by high currents 

and storms, protect the pipeline from the external damage that could result from anchors and fishing 

gear, reduce the risk of fishing gear becoming snagged, and minimize interference with the 
Impact-Producing Factors and Scenario 3-39

operations of other users of the OCS. For pipelines >85/8 in (22.9 cm), a waiver of the burial 

requirement may be requested and may be approved if the line is to be laid in an area where the 

character of the seafloor would allow the weight of the line to cause it to sink into the sediments 

(self-burial). For a pipeline that crosses a fairway or anchorage in Federal waters in depths ≤60 m 

(197 ft), any length of pipeline must be buried to a minimum depth of 10 ft (3 m) below mudline 

across a fairway and a minimum depth of 16 ft (5 m) below mudline across an anchorage area. 

Some operators voluntarily bury these pipelines deeper than the minimum.

Where pipeline burial is necessary, a jetting sled would be used. Such sleds are mounted 

with high-pressure water jets and pulled along the seafloor behind the pipe-laying barge. The water 

jets are directed downward to dig a trench; the sled guides the pipeline into the trench. Such an 

apparatus can jet pipe at an average of 1.6 km/day (1.0 mi/day). The cross section of a typical jetted 

trench for the flowline bundles would be about 4 m2 (43 ft2

); for deeper burial when crossing a 

fairway, the cross section would be about 13 m2 (140 ft2

). The cross section of a typical jetted trench 

for the export and interconnecting export pipelines would be about 5 m2 (54 ft2

); for a pipeline trench 

crossing a fairway, the cross section would be about 15 m2 (161 ft2

).

Jetting disperses sediments over the otherwise undisturbed water bottom that flanks the 

jetted trench. The area covered by settled sediment and the thickness of the settled sediment 

depends upon variations in bottom topography, sediment density, and currents. Newer installation 

methods have allowed the pipeline infrastructure to extend to deeper water.

The following information is discussed more thoroughly in this Agency’s Deepwater Gulf of 

Mexico 2006: America’s Expanding Frontier (USDOI, MMS, 2006). Pipeline installation activities in 

deepwater areas can be difficult both in terms of route selection and construction. Depending on the 

location, the sea-bottom surface can be extremely irregular and present engineering challenges 

(e.g., high hydrostatic pressure, cold temperatures, and darkness, as well as varying subsurface and 

bottom current velocities and directions). Rugged seafloor may cause terrain-induced pressures 

within the pipe that can be operationally problematic, as the oil must be pumped up and down steep 

slopes. An uneven seafloor could result in unacceptably long lengths of unsupported pipeline, 

referred to as “spanning,” which in turn could lead to pipe failure from bending stress early in the life 

of the line. It is important to identify areas where substantial lengths of pipeline may go 

unsupported. Accurate, high-resolution geophysical surveying becomes increasingly important in 

areas with irregular seafloor. Recent advances in surveying techniques have significantly improved 

the capabilities for accurately defining seafloor conditions, providing the resolution needed to 

determine areas where pipeline spans may occur. After analyzing survey data, the operator 

chooses a route that minimizes pipeline length and avoids areas of seafloor geologic structures and 

obstructions that might cause excessive pipe spanning, unstable seafloor, and potential benthic 

communities.

The BSEE’s minimum cathodic protection design criteria for pipeline external corrosion 

protection is 20 years. For the most part, pipelines have a designed life span greater than 20 years 

and, if needed, can be retrofitted to increase the life span (Chapter 3.1.6.1). Should a pipeline need 
3-40 Gulf of Mexico Multisale EIS

to be replaced because of integrity issues, a replacement pipeline is installed or alternate routes are 

used to transport the products, or a combination of the two. Besides replacement because of 

integrity issues, a pipeline may also be required to be replaced as a result of storm or other 

damages. The BSEE estimates that the overall pipeline replacement over the past few years is 

about 1 percent of the total installed.

The greater pressures and colder temperatures in deep water present difficulties with respect 

to maintaining the flow of crude oil and gas through pipelines. Under these conditions, the physical 

and chemical characteristics of the produced hydrocarbons can lead to the accumulation of gas 

hydrate, paraffin, and other substances within the pipeline. These accumulations can restrict and 

eventually block flow if not successfully prevented and/or abated. There are physical (including 

“pigging” devices) and chemical techniques (e.g., methanol or ethylene glycol) that can be applied to 

manage these potential accumulations. Companies are continuously looking for and developing 

new technologies, such as electrically and water-heated pipelines and burial of pipelines in 

deepwater for insulation purposes.

Long-distance transport of multiphase well-stream fluids can be achieved with an effectively 

insulated pipeline. There are several methods to achieve pipeline insulation: pipe-in-pipe systems, 

which included electrically and water-heated pipelines; pipe with insulating wrap material; and as 

previously mentioned, buried pipelines where the soils act as an insulator. The design of all of these 

systems seeks a balance between the high cost of the insulation, the intended operability of the 

system, and the acceptable risk level.

Clearance of pipeline interiors is carried out by “pigs.” Pigging is a term used to describe a 

mechanical method of displacing a liquid in a pipeline or to clean accumulated paraffin (a waxy 

buildup) from the interior of the pipeline by using a mechanized plunger or pig. Paraffin deposits will 

form inside pipelines that transport liquid hydrocarbons and, if some remedial action such as pigging 

is not taken, the deposited paraffin will eventually completely block all fluid flow through the line. 

The frequency of pigging could range from several times a week to monthly or longer, depending on 

the nature of the produced fluid. In cases where paraffin accumulation cannot be mitigated, extreme 

measures can be taken in some cases such as coil tubing entry into a pipeline to allow washing 

(dissolving) of paraffin plugs. If that fails, then it could result in having to replace a pipeline.

Leaks in pipelines are detected through a series of pressure gauges mandated in 30 CFR

250.1004. Additionally, each DOI pipeline route in the GOM is inspected at least monthly for an 

indication of pipeline leakage. These inspections are made by using a helicopter, marine vessel, or 

other approved means (USDOI, MMS, 1991). Refer to Chapter 3.2.1 for more information on oil 

spills. 

How Much Pipeline Infrastructure Would Likely Be Developed?

BOEM projects that the majority of new pipelines constructed as a result of a proposed 

action would connect to the existing pipeline infrastructure. In the rare instance that a new pipeline 
Impact-Producing Factors and Scenario 3-41

to shore would need to be constructed, it would likely be because there are no existing pipelines 

reasonably close and because constructing a pipeline to shore is considered more cost effective, 

although it is highly unlikely for an operator to choose this contingency (Dismukes, official 

communication, 2011a). BOEM anticipates that pipelines from most of the new offshore production 

facilities would tie-in to the existing pipeline infrastructure offshore or in State waters, which would 

result in few new pipeline landfalls. Pipeline emplacement resulting from a proposed action would 

increase the capacity and potentially the maximum extraction rate of oil and gas. 

The length of new pipelines was estimated using the amount of production, the number of 

structures projected as a result of each alternative, and the location of the existing pipelines. The 

range in length of pipelines projected is because of the uncertainty of the location of new structures, 

which existing or proposed pipelines would be used, and where they tie-in to existing lines. Many 

factors would affect the actual transport system, including company affiliations, amount of 

production, product type, and system capacity.

Alternative A*: BOEM projects 355-2,144 km (220-1,332 mi) of new pipelines under 

Alternative A (Table 3-2). About 16-25 percent of the new pipeline length would be in water 

depths <60 m (197 ft), requiring burial.

Alternative B*: BOEM projects 254-1,641 km (157-1,020 mi) of new pipelines under 

Alternative B (Table 3-2). About 15-24 percent of the new pipeline length would be in water 

depths <60 m (197 ft), requiring burial.

Alternative C*: BOEM projects 105-505 km (65-314 mi) of new pipelines under 

Alternative C (Table 3-2). About 19-26 percent of the new pipeline length would be in water 

depths <60 m (197 ft), requiring burial.

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

Pipeline Landfalls

The OCS oil- and gas-related pipelines nearshore and onshore may join pipelines carrying 

production from State waters or territories for transport to processing facilities or to distribution 

pipelines located farther inland. Oil and gas companies have a strong financial incentive to reduce 

costs by utilizing, to the fullest extent possible, the mature pipeline network that already exists in the 

GOM. Economies of scale are a factor in pipeline transportation; maximizing the amount of product 

moved through an already existing pipeline decreases the long-term average cost of production. 
3-42 Gulf of Mexico Multisale EIS

Additional considerations include mitigation costs for any new wetland and environmental impacts 

and various landowner issues at the landfall point. Because of these strong incentives to move new 

production into existing systems and to avoid creating new landfalls, the 5-year moving average of 

new OCS pipeline landfalls has been below two per year since 1986. Over the last 15 years 

(1999-2014), there has been an average of slightly over one new OCS pipeline landfall every 

2 years (0.53 per year). Table 3-6 lists the OCS pipeline landfalls that have been installed since 

1996. While no new pipelines landfalls have been installed in the last 5 years, pipeline landfalls 

have been approved during that time. To project the likely number of new OCS pipeline landfalls, 

BOEM examined the historical relationships between new pipeline landfalls and a variety of factors 

including platforms installed, oil and gas production, and the total number of new pipelines. Based 

on this examination, BOEM assumes that the majority of new Federal OCS oil and gas pipelines 

would connect to the existing pipelines in Federal and State waters and that very few would result in 

new pipeline landfalls.

Table 3-6. OCS Pipeline Landfalls Installed from 1996 to 2014.

Segment 

Number 

Year of 

Installation* Product Type Size (in) Company State

10631 1996 Oil 24 Equilon Pipeline Company LLC LA

12470 1996 Oil 24 Manta Ray Gathering Company LLC LA

11217 1997 Gas 30 Enbridge Offshore LA

11496 1997 Oil 12 ExxonMobil Pipeline Company LA

11952 2000 Oil 18-20 ExxonMobil Pipeline Company TX

14470 2004 Oil 10 Chevron USA Inc. LA

13972 2004 Oil 24 Manta Ray Gathering Company LLC TX

13987 2004 Oil 24 Manta Ray Gathering Company LLC TX

13534 2005 Oil 30 BP Pipelines (North America) LA

13534 2005 Oil 30 Mardi Gras Endymion Oil Pipeline

Co. LA

17108 2007 Gas/Condensate 16 Stone Energy Corporation LA

17691 2009 Gas/Oil 8 Stone Energy Corporation LA

*Year when the initial hydrostatic test occurred.

Source: Smith, official communication, 2015.

Alternative A, B, or C*: Up to one (i.e., 0-1) new pipeline landfall could result under 

Alternative A, B, or C.

*Alternative D is not expected to affect pipeline landfalls. Refer to Chapter 2.2.2.4 for 

more information.

3.1.3.3.2 Bottom-Area Disturbance

Structures emplaced or anchored on the OCS to facilitate oil and gas exploration and 

production include drilling rigs or MODUs (i.e., jack-ups, semisubmersibles, and drillships), pipelines, 
Impact-Producing Factors and Scenario 3-43

and fixed surface, floating, and subsea production systems; these structures are discussed in 

Chapters 3.1.3.2 above. The emplacement or removal of these structures disturbs small areas of 

the sea bottom beneath or adjacent to the structure. If mooring lines of steel, chain, or synthetic 

polymer are anchored to the sea bottom, areas around the structure could also be directly affected 

by their emplacement. This disturbance includes physical compaction or crushing beneath the 

structure or mooring lines and the resuspension and settlement of sediment caused by the activities 

of emplacement. Movement of floating types of facilities would also cause the movement of the 

mooring lines in its array. Small areas of the sea bottom would be affected by this kind of 

movement. 

Wells drilled in shallow water create a splay of drilling muds and cuttings that spread 250 m 

(820 ft) from the well, and in deepwater (over 300-m [984-ft] water depth) the coverage area would 

be approximately 500 m (1,640 ft) from the well. Muds and cuttings are discussed further in 

Chapter 3.1.5.1.1. There are numerous studies about splays from various areas of the GOM and 

other locations around the world (Neff et al., 2000; USEPA, 2000a; International Association of Oil 

and Gas Producers, 2003). These splays on the seafloor vary from one location to the next and vary 

by well depth, which controls the total volume of cuttings available for disbursement. Variation in 

splay size are caused by water depth, well depth, drilling fluid type (cuttings from oil-based or 

synthetic mud are taken to shore for disposal), and currents. A typical splay is not in a uniform 

circular shape but rather in the shape of a fan that is influenced by prevailing currents and the fall 

rate of drill cuttings; however, for this calculation, disturbance is considered a possibility in all 

directions from a well. The model used here is an oversimplification in order to obtain a conservative 

estimate of disturbance per offshore production system. Given that a splay from a well generally 

overlays the footprint of an offshore production system and creates a larger surface area of 

disturbance, only bottom disturbance from the splay is considered when evaluating overall bottom 

disturbance. 

Subsea production systems located on the ocean floor are connected to surface topsides by

a variety of components. These bottom-founded components are an integrated system of flowlines, 

manifolds, flowline termination sleds, umbilicals, umbilical sleds, blowout preventers, well trees, and 

production risers. Richardson et al. (2008) indicated that all currently operating subsea systems are 

tied to an offshore production system. 

Emplacement of flowlines and export pipelines that cross a fairway disturb between 0.5 and 

1.0 ha (1.2 and 2.5 ac) of seafloor per kilometer of pipeline (Cranswick, 2001). Pipe-laying vessels 

operating in the deepwater Gulf of Mexico rely on dynamic positioning rather than conventional 

anchors to maintain their position during operations and do not require trenching, so deepwater pipelaying is assumed to disturb 0.32 ha (0.79 ac). The variation lies in BSEE’s requirement to bury 

pipelines in water depths <200 ft (61 m) to a depth of 3 ft (1 m). Burial is typically done by water 

jetting a trench followed by placing the pipeline into it.
3-44 Gulf of Mexico Multisale EIS

Alternative A*: Bottom-area disturbance is calculated as a relationship between the 

structures projected (i.e., platforms, wells, subsea structures, and pipeline miles installed

[Chapter 3.1.3.3.1]) and the associated disturbance of each. Under Alternative A, between 

1,226 and 21,158 ha (3,029 and 52,282 ac) of sea bottom is projected to be disturbed. This is 

<0.01-0.05 percent of the total area of the Gulf of Mexico. 

Alternative B*: Under Alternative B, between 1,056 and 18,648 ha (2,609 and 46,080 ac) 

of sea bottom is projected to be disturbed in the CPA/EPA. This is <0.01-0.03 percent of the total 

area of the Gulf of Mexico. 

Alternative C*: Under Alternative C, between 693 and 2,525 ha (1,712 and 6,239 ac) of 

sea bottom is projected to be disturbed in the WPA. This is <0.001-0.01 percent of the total area 

of the Gulf of Mexico. 

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

3.1.3.3.3 Sediment Displacement

Displaced sediments are those that have been physically moved “in bulk.” Displaced 

sediments cover or bury an area of the seafloor, while resuspended sediments cause an increase in 

turbidity of the adjacent water column. Resuspended sediments eventually settle, covering the 

surrounding seafloor. Resuspended sediments may include entrained heavy metals or 

hydrocarbons.

The chief means for sediment displacement is the overboard discharge of drill cuttings 

carried to the surface by drilling mud. Cuttings that outfall from surface platforms settle to the sea 

bottom as a mound or plume if influenced by the prevailing currents. Sediment displacement can 

also take place when anchored exploration rigs and production structures are subject to high current 

energy, such as GOM loop currents or hurricane sea states. Mooring lines in contact with the sea 

bottom can scrape sediment into heaps and mounds as the surface facility moves in response to 

currents.

Trenching for pipeline burial causes displacement or resuspension of seafloor sediments. 

Sediment displacement also occurs as a result of the removal of pipelines. It is projected that the 

number of pipeline decommissionings (or re-routings) would increase regionwide as the existing 

pipeline infrastructure ages (refer to Chapter 3.1.6.1). For each kilometer of pipeline removed in 
Impact-Producing Factors and Scenario 3-45

water depths <200 ft (61 m), approximately 5,000 m3 (176,573 ft3) of sediment would be displaced 

and resuspended (Cranswick, 2001). 

3.1.3.3.4 Navigation Channels

BOEM conservatively estimates that there are approximately 4,850 km (3,013 mi) of Federal 

navigation channels, bayous, and rivers potentially exposed to OCS traffic regionwide (Table 3-7; 

Figure 3-9) and that the average canal is widening at a rate of 0.99 m/yr (3.25 ft/yr) (Thatcher et al., 

2011). This would result in a total (OCS and non-OCS oil- and gas-related) annual land loss of 

approximately 831 ac/yr (336 ha/yr). Total land loss in these areas can be caused by multiple 

factors, including saltwater intrusion, hurricanes, and vessel traffic (refer to Chapter 3.3.2.8 below). 

Assuming that vessel traffic alone was the sole source of erosion, the rate of land loss would be 

related to the usage of those canals by both OCS Program-related vessels and other vessel traffic. 

Using the estimated proportion of OCS Program vessel traffic as a measurement of erosion, the 

numbers above are considered conservative because open waterways were included in the total 

length of Federal navigation channels, vessel size was not taken into consideration, and there are 

sources of erosion to navigation canals other than vessel traffic alone.

Table 3-7. Waterway Length, Depth, Traffic, and Number of Trips for 2012. 

Waterway

Canal 

Length 

(km)

Maintained Depth 

(ft)

Traffic (1,000 

short tons)

Number of Trips

Foreign Domestic

Gulf Intracoastal Waterway (GIWW)

Apalachee Bay to Panama City, FL 217 12 607 0 329

Panama City to Pensacola Bay, FL 177 12 1,610 0 1,114

Pensacola Bay, FL to Mobile Bay, 

AL 74 12 3,962 0 3,646

Mobile Bay, AL to New Orleans, LA 215 12, 14 18,209 0 13,585

Mississippi River, LA to Sabine River, 

TX 428 12, 10 63,911 0 52,435

Sabine River to Galveston, TX 135 12 59,577 0 33,113

Galveston to Corpus Christi, TX 305 11, 11, 10.2 29,314 0 21,178

Corpus Christi, TX to Mexican 

Border 214 10, 12, 7 1,920 0 1,483

Morgan City – Port Allen Route, LA 103 10 18,832 0 9,463

Florida Harbors, Channels, and Waterways

Escambia and Conecuh Rivers, FL 

and AL; Escambia Bay, FL 12 10 1,664 0 1,930

La Grange Bayou, FL 3 9 219 0 70

Panama City Harbor, FL 9 34, 32, 10 2,326 308 674

Pensacola Harbor, FL 21 35, 33, 15, 14 879 471 435

St. Marks River, FL 61 9 72 0 36

Tampa Harbor, FL 141 45, 43, 34, 12, 9 31,650 834 1,459

Port Manatee, FL 5 40 3,397 219 30
3-46 Gulf of Mexico Multisale EIS

Waterway

Canal 

Length 

(km)

Maintained Depth 

(ft)

Traffic (1,000 

short tons)

Number of Trips

Foreign Domestic

Alabama Harbors, Channels, and Waterways

Mobile Harbor, AL 71 47, 45, 40, 13-39 54,888 1,338 17,965

Theodore Ship Channel, AL 13 40 4,646 212 1,357

Mississippi Harbors, Channels, and Waterways

Biloxi Harbor, MS 39 12, 10, 12 1,047 0 1,106

Gulfport Harbor, MS 34 30, 32, 8 1,888 200 406

Pascagoula Harbor, MS 18 40, 38, 38, 22, 12 33,785 601 3,110

Bayou Casotte, MS 2 38 33,467 518 2,837

Louisiana Harbors, Channels, and Waterways

Atchafalaya River (Lower), LA 62 20 983 332 11,050

Barataria Bay Waterway, LA 66 17, 10 288 13 5,146

Bayou Lafourche and Bayou 

Lafourche-Jump Waterway 80 28, 27, 27, 9 6,092 2,342 16,463

Bayou Little Caillou, LA 56 12 68 0 305

Bayou Teche, LA 171 3,3,4,7 474 0 321

Bayou Teche and Vermilion River, 

LA 83 8,11,9,8,5 601 17 1,541

Bayou Terrebonne, LA 61 10 134 0 692

Calcasieu River and Pass, LA 176 42, 42, 41-42, 36, 12, 7 54,382 1,318 32,207

Freshwater Bayou, LA 34 12 493 57 4,989

Houma Navigation Canal, LA 59 16, 15, 16 473 30 1,812

Mermentau River, LA 131 4, 7, 12, 10, 10, 9, 11,

6, 8, 4, 4, 7 311 0 1,802

Mermentau River, Bayou Nezpique, 

and Des Cannes, LA 122 9, 14, 10 443 0 649

Mississippi River, Baton Rouge LA 

to the Mouth of Passes 437 45, 13 456,551 5,635 216,588

Port of New Orleans, LA 83 45, 30, 32, 36, 37, 12 79,342 1,852 26,820

Port of Baton Rouge, LA 144 45, 40, 9, 12 59,993 664 47,602

Port of South Louisiana 86 45 252,069 2,451 67,601

Port of Plaquemines, LA 131 45 58,280 654 74,951

Passes of the Mississippi River, LA 57 13, 45 230,048 5,635 3,707

Mississippi River Gulf Outlet via 

Venice Vicinity Consolidation 22 16, 14, 14 1,585 13 6,276

Petit Anse, Tigre, and Carlin 

Bayous 28 6, 9, 5, 7 1,563 0 1,243

Port of Iberia 14 13 ~2,200 NA NA

Port of Morgan City, LA – 12 1,771 202 12,474
Impact-Producing Factors and Scenario 3-47

Waterway

Canal 

Length 

(km)

Maintained Depth 

(ft)

Traffic (1,000 

short tons)

Number of Trips

Foreign Domestic

Waterway from Empire, LA to the 

Gulf of Mexico 17 6,9,14 1,044 0 7,292

Waterway from Intracoastal 

Waterway to Bayou Dulac, LA 61 14 145 0 1,271

Texas Harbors, Channels and Waterways

Brazos Island Harbor, TX 47 36.5, 38, 31, 38, 12, 14, 

7 5,614 251 1,155

Cedar Bayou, TX 22 11 1,349 0 1,222

Channel to Aransas Pass, TX 11 14 782 20 749

Channel to Port Bolivar, TX 17 12 0 0 56,583

Corpus Christi Ship Channel, TX 64 47, 45, 46, 47, 14, 9 69,001 1,349 102,837

Dickenson Bayou, TX 34 9 47 0 25

Freeport Harbor, TX 14 44, 37, 18, 40 22,085 716 3,207

Galveston Channel, TX 6 41 11,618 2,843 61,016

Houston Ship Channel, TX 112 45, 40, 32-39, 9, 7, 35-

37, 7, 40, 12 238,186 6,262 81,048

Matagorda Ship Channel, TX 91 35, 9.8, 10, 12.8, 2 9,333 329 1,847

Sabine-Neches Waterway, TX 160 40, 37, 39, 32, 27, 20, 

9, 8 137,218 1,908 31,828

Texas City Channel, TX 14 43, 41, 42, 42 57,758 776 6,625

Source: U.S. Dept. of the Army, COE, 2012.

While a proposed lease sale under Alternative A, B, or C would contribute to the continued 

need for maintenance dredging of existing navigation channels, a mature network of navigation 

channels already exists in the analysis area; therefore, no new navigation channel construction 

would be expected as a direct result of a proposed lease sale under Alternative A, B, C, or D. 
3-48 Gulf of Mexico Multisale EIS

Alternative A*: Assuming that vessel traffic alone was the sole source of erosion, there 

would be an average annual loss of 0.40-5.02 ha (0.99-12.40 ac) for Alternative A. All service 

vessels associated with EPA blocks are assumed to use CPA navigational canals while inland and 

constitute less than 1 percent of the total vessel traffic. Service vessels associated with CPA 

leases are assumed to use CPA navigational canals and constitutes less than 2 percent of the 

total traffic. Service vessels associated with WPA leases are assumed to use WPA navigational 

canals and constitute less than 1 percent of the total traffic in the GOM.

Alternative B*: Assuming that vessel traffic alone was the sole source of erosion, there 

would be an annual loss of 0.46-5.53 ha (1.15-13.66 ac) for Alternative B.

Alternative C*: Assuming that vessel traffic alone was the sole source of erosion, there 

would be an annual loss of 0.18-0.54 ha (0.45-1.34 ac) for Alternative C.

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.
 

Impact-Producing Factors and Scenario

3-49

Figure 3-9. Gulfwide OCS Oil- and Gas-Related Service Bases and Major Waterways.
3-50 Gulf of Mexico Multisale EIS

BOEM’s data indicate that the total area 

lost due to the presence of production 

platforms has historically been and 

would continue to be less than 1 percent 

of the total surface area available.

3.1.3.4 Infrastructure Presence

3.1.3.4.1 Anchoring

Most exploration drilling, platform, and pipeline emplacement operations on the OCS require 

anchors to hold the rig, topside structures, or support vessels in place. Anchors disturb the seafloor 

and sediments in the area where dropped or emplaced. Anchoring can cause physical compaction 

beneath the anchor and chains or lines, as well as resuspended sediment. A disturbed area on the 

sea bottom forms by the swing arc formed by anchor lines scraping across bottom within the range 

of the anchoring system configuration. Dynamically positioned rigs, production structures, and 

vessels are held in position by four or more propeller jets and do not cause anchoring impacts. 

Conventional pipe-laying barges use an array of eight 9,000-kg (19,842-lb) anchors to position the 

barge and to move it forward along the pipeline route. These anchors are continually moved as the 

pipe-laying operation proceeds. The area actually affected by these anchors depends on water 

depth, wind, currents, chain length, and the size of the anchor and chain. Mooring buoys may be 

placed near drilling rigs or platforms so that service vessels need not anchor or for when they cannot 

anchor (in deeper water). The temporarily installed anchors for these buoys would most likely be 

smaller and lighter than those used for vessel anchoring and, thus, would have less impact on the 

sea bottom. Moreover, installing one buoy would preclude the need for numerous individual vesselanchoring occasions. Service-vessel anchoring is assumed not to occur in water depths >150 m 

(492 ft) and only occasionally in shallower waters (vessels would always tie up to a platform or buoy 

in water depths >150 m [492 ft]). Barges are assumed to tie up to a production system rather than 

anchor. Barges and other vessels are also used for both installing and removing structures. Barge 

vessels use anchors placed away from their location of work.

3.1.3.4.2 Space-Use Requirements

Leasing on the OCS results in operations that 

temporarily occupy sea bottom and water surface area 

for dedicated uses. The OCS oil- and gas-related 

operations include the deployment of seismic vessels, 

bottom surveys, and the installation of surface or 

subsurface bottom-founded production structures with 

anchor cables and safety zones. While in use, these 

areas would become unavailable to commercial fishermen, sand borrowing, or any other competing 

use.

The G&G surveys can occur in both shallow and deepwater areas. Usually, fishermen are 

precluded from a very small area for several days during active G&G surveying. Exploratory drilling 

rigs spend approximately 40-150 days onsite and are a short-term interference to commercial 

fishing. A major bottom-founded production platform in water depths less than 450 m (1,476 ft), with 

a surrounding 100-m (328-ft) navigational safety zone, requires approximately 6 ha (15 ac) of space. 

A bunkhouse structure needs about 4 ha (9 ac) and a satellite structure needs about 1.5 ha (3.7 ac) 

of space.
Impact-Producing Factors and Scenario 3-51

In water depths greater than 450 m (1,476 ft), production platforms would be compliant 

towers, floating production structures (such as TLPs and spars), and FPSOs. Even though 

production structures in deeper water are larger and individually would take up more space, there 

would be fewer of them compared with the great numbers of bottom-founded platforms in shallower 

water depths. Factoring in various configurations of navigational safety zones, deepwater facilities 

may require up to a 500-m (1,640-ft) radius safety zone or 78 ha (193 ac) of space (33 CFR 

§ 147.15). Production structures in all water depths have a life expectancy of 20-30 years.

Alternative A*: A maximum of 648 ha (1,598 ac) could be lost to other uses under

Alternative A. This number is based on a high of 108 production structures of approximately 6 ha 

(15 ac) of surface area operating simultaneously during the life of a proposed action. This is 

approximately 0.001 percent of the surface area of the Gulf of Mexico. 

Alternative B*: A maximum of 546 ha (1,347 ac) could be lost to other uses under 

Alternative B. This number is based on a high of 91 production structures of approximately 6 ha 

(15 ac) of surface area operating simultaneously during the life of Alternative B. This is 

approximately 0.0008 percent of the surface area of the Gulf of Mexico. 

Alternative C*: A maximum of 120 ha (296 ac) could be lost to other uses under 

Alternative C. This number is based on a high of 20 production structures of approximately 6 ha 

(15 ac) of surface area operating simultaneously during the life of Alternative C. This is 

approximately 0.0002 percent of the surface area of the Gulf of Mexico. 

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

3.1.3.4.3 Structure Lighting

The OCS oil- and gas-related structures in the GOM are illuminated from incandescent lights 

and from the glow of burning or flaring natural gas that cannot be stored or transported to shore. 

The U.S. Coast Guard (USCG) regulates workplace health and safety and maritime safety items, 

including lights illuminating working enviroments and navigational warning lights, on OCS platforms 

according to 33 CFR § 143.15. To assist in nighttime operations and aid navigation, manned

platforms are generally well illuminated by exterior floodlights. Platforms generally have two 

varieties of floodlights: high-pressure sodium or mercury vapor. High-pressure sodium lights emit 

yellow-orange light, whereas mercury vapor lights emit a perceptually blue-white light. Some 

initiative has been taken to move toward downward facing lighting and green light. Although there 

are differences between platforms, floodlights located between 20 and 40 m (66 and 132 ft) above 
3-52 Gulf of Mexico Multisale EIS

the water surface illuminate the structure and the surrounding water to a depth of at least 100-200 m 

(328-656 ft) and can often be observed several miles away from the platform (Keenan et al., 2007). 

Unmanned structures usually have minimal aid-to-navigation lights.

In addition to offshore lighting, coastal support infrastructure is also illuminated. Coastal 

infrastructure lighting may be specifically designed to emit horizontal or vertical light. Horizontal and 

near-horizontal light emittance increases the visibility of light sources from a distance and 

significantly increases the illuminated area, but it can also cause the encroachment of light into 

adjacent unlit areas. Light emitted horizontally or near-horizontally produces more sky glow than 

that emitted upward, and much more than light emitted downward (Gaston et al., 2012).

3.1.3.5 Workovers and Abandonments

Completed and producing wells may require periodic reentry that is designed to maintain or 

restore a desired flow rate. These procedures are referred to as a well “workover.” Workover 

operations are also carried out to evaluate or reevaluate a geologic formation or reservoir (including 

recompletion to another strata) or to permanently abandon a part or all of a well. Examples of 

workover operations are acidizing the perforated interval in the casing, plugging back, squeezing 

cement, milling out cement, jetting the well in with coiled tubing and nitrogen, and setting positive 

plugs to isolate hydrocarbon zones. Workovers on subsea completions require that a rig be moved 

on location to provide surface support. Workovers can take from 1 day to several months to 

complete depending on the complexity of the operations, with a median of 7 days. Current oil-field 

practices include preemptive procedures or treatments that reduce the number of workovers 

required for each well. On the basis of historical data, BOEM projects a producing well may expect 

to have seven workovers or other well activities during its lifetime. Workover fluids are discussed in 

Chapter 3.1.5.1.3 below.

There are two types of well abandonment operations—temporary and permanent. An 

operator may temporarily abandon a well to (1) allow detailed analyses or additional delineation 

wells while deciding if a discovery is economically viable, (2) save the wellbore for a future sidetrack 

to a new geologic bottom-hole location, or (3) wait on design or construction of special production 

equipment or facilities. The operator must meet specific requirements to temporarily abandon a well. 

Permanent abandonment operations are undertaken when a wellbore is of no further use to the 

operator (i.e., the well is a dry hole or the well’s producible hydrocarbon resources have been 

depleted). During permanent abandonment operations, equipment is removed from the well, and 

specific intervals in the well that contain hydrocarbons are plugged with cement. A cement surface 

plug is also required for the abandoned wells. This serves as the final isolation component between 

the wellbore and the environment.
Impact-Producing Factors and Scenario 3-53

3.1.4 Transport

3.1.4.1 Barges

The capacity of oil barges used offshore can range from 5,000 to 80,000 bbl. Barges 

transporting oil may remain offshore for as long as 1 week while collecting oil; each round trip is 

assumed to be 5 days.

How Much Barging Activity Would Likely Occur? 

Historically, barging in the GOM has remained less than 1 percent. In 2005, barging activity 

temporarily rose to 1.29 percent while pipelines that were damaged from hurricanes were repaired. 

In 2014, 0.08 percent of the total volume was transported by barge as compared with 0.13 percent in 

2010. The average amount of oil barged between 2010 and 2014 was 0.12 percent annually. The 

number of active barging systems has been reduced over time from approximately eight systems in 

2005 to four systems in 2010 and has remained constant since then. It is assumed that barging 

would continue to account for <1 percent of the oil transported for the entire OCS Program and for 

any single alternative. Table 3-4 provides the percentages of oil barged to shore by subarea for 

each alternative. 

In 2013, all “active” offshore barging locations were located in the CPA. The locations east 

of the Mississippi River accounted for roughly 78 percent of the total barged volume. Likewise, the 

locations located west of the Mississippi River accounted for the remaining 22 percent.

3.1.4.2 Oil Tankers

The FPSOs store crude oil in tanks in the hull of the vessel and periodically offload the crude 

to shuttle tankers or oceangoing barges for transport to shore. The FPSOs are used to develop 

marginal oil fields or are used in areas remote from the existing OCS pipeline infrastructure, 

especially development in the Lower Eocene Wilcox trend (Walker Ridge leasing area) that is far 

from most existing pipeline networks. The FPSO systems are suitable for the light and intermediate 

oils of the GOM, as well as heavier oil, such as the heavy oil Brazil plans to produce offshore in deep 

water. The use of FPSOs is only projected in water depths >1,600 m (5,250 ft). Shuttle tankers are 

used to transport crude oil from FPSO production systems to Gulf Coast refinery ports or to offshore 

deepwater ports such as the Louisiana Offshore Oil Port. Shuttle tanker design and systems are in 

compliance with USCG regulations, the Jones Act, and OPA requirements. As such, shuttle tankers 

are required to be double hulled. In the Gulf, the maximum size of shuttle tankers is limited primarily 

by the 34- to 47-ft (10- to 14-m) water depths. Because of these depth limitations, shuttle tankers 

are likely to be 500,000-550,000 bbl in cargo capacity.

Offloading operations involve the arrival, positioning, and hook-up of a shuttle tanker to the 

FPSO. Shuttle tankers can maintain their station during FPSO offloading operations using 

techniques that generally do not require anchoring. Offloading could occur at an average rate of 

50,000 bbl per hour. During the FPSO offloading procedure, the shuttle tanker would continue to 

operate its engines in an idle mode so that any necessary maneuvers of the vessel could be 
3-54 Gulf of Mexico Multisale EIS

promptly executed. Safety features, such as marine break-away offloading hoses and emergency 

shut-off valves, would be incorporated in order to minimize the potential for, and size of, an oil spill. 

In addition, weather and sea-state limitations would be established to further ensure that hook-up 

and disconnect operations would not lead to accidental oil release. A vapor recovery system 

between the FPSO and shuttle tanker would be employed to minimize the release of fugitive 

emissions from cargo tanks during offloading operations.

Tankering related to FPSO systems in the GOM began in 2012 at the Cascade Chinook 

Project. For additional information on FPSOs, refer to Chapter 3.1.3.2. The production transported 

by shuttle tankers related to this FPSO system accounted for 2.2 percent of the total volume

produced in the GOM during 2014. Forecasted tankering operations are presented in Table 3-4. 

During the production ramp up interval (the first 2 years of production operations), 8 offloads were 

made during the first 6 months followed by 15 offloads over the next year. During the 2nd full year of 

operation, 46 offloads were made. In the subsequent years of production, two shuttle tankers on a 

staggered schedule were predicted to perform one offload every week (52 trips a year). A second 

FPSO (Stones Project) in the GOM area (Walker Ridge) began production in 2016. This facility is 

also scheduled to transport the produced liquid hydrocarbons by shuttle tankers.

How Much Tankering Activity Would Likely Occur? 

To develop a scenario for analytical purposes, the following assumptions are made regarding 

future OCS oil transportation by shuttle tanker:

• advances in pipe-laying technology would keep pace with the expansion of the oil 

industry into the deeper waters of the Gulf beyond the continental slope;

• all produced gas would be piped;

• tankering would not occur from operations on the continental shelf;

• tankering would only take place from marginal fields or fields in areas remote 

from the existing OCS pipeline infrastructure; and

• maximum offloading frequency for an FPSO could be once every 3 days during 

peak production.

Alternative A*: BOEM projects 0-1 FPSO systems could result under Alternative A. The 

number of shuttle tanker trips to port in a given year is primarily a function of the FPSO production 

rate, the number of wells drilled, and the capacity of supporting shuttle tankers. Considering an 

FPSO operating at a peak production rate of 150,000 bbl/day, supported by shuttle tankers of 

500,000-bbl capacity, maximum offloading could occur once every 3.3 days. This would equate to 

a 54.75-MMbbl production with 110 offloading events and shuttle tanker transits to GOM coastal 

or offshore ports annually per FPSO.
Impact-Producing Factors and Scenario 3-55

Alternative B*: BOEM projects 0-1 FPSO systems would result under Alternative B. 

Because the FPSO projections are expected to occur in the CPA, a similar number of tanker trips 

would occur from an FPSO under Alternative B as would under Alternative A.

Alternative C*: BOEM projects no FPSO systems would result under Alternative C 

because no FPSO activity is expected to occur in the WPA; thus, no tankering is projected to 

occur under Alternative C.

*Because FPSOs are not expected to occur in the same area as the sensitive topographic 

features, Alternative D is not expected to affect FPSO system development. Refer to Chapter 

2.2.2.4 for more information.

3.1.4.3 Service Vessels

Service vessels are one of the primary modes of transporting personnel between service 

bases and offshore platforms, drilling rigs, derrick barges, and pipeline construction barges. In 

addition to offshore personnel, service vessels carry cargo (i.e., freshwater, fuel, cement, barite, 

liquid drilling fluids, tubulars, equipment, and food) offshore.

How Much Service Vessel Activity Would Likely Occur? 

Service vessels were evaluated for the following categories: wells (exploration and 

development drilling); plug and abandonment of wells; platform installation; platform operation; 

platform decommissioning; subsea installation; subsea removal; and pipeline installation. Other 

vessel operations, including G&G activity associated with a leasing event, is assumed to be covered 

in these estimates. Based on the model provided by Kaiser (2010), there were an average of 

4.46 supply vessels needed per week during exploration and development drilling in shallow water 

and 6.4 supply vessels needed per week during exploration and development drilling in deep water. 

Drilling operations in shallow water takes less time (5.9 weeks) when compared with deepwater 

drilling (10 weeks). A platform in shallow water (<800 m; 2,624 ft) is estimated to require one vessel 

trip every 3.1 days over the production life. A platform in deep water (≥800 m; 2,624 ft) is estimated 

to require one vessel trip every 1.2 days over the production life. All trips are assumed to originate 

from the designated service base to an offshore site and back. The duration vessels service an 

operational platform was considered to be between 11 and 31 years (low to high). Service-vessel 

operations are most closely tied to actual production activities. Visual representation of this can be 

seen in Figure 3-8. 

Alternative A*: Alternative A is estimated to generate 43,000-541,000 service-vessel trips 

over the 50-year period (Table 3-2) or 860-10,820 trips annually. Table 3-7 indicates that over 

875,000 service-vessel trips occurred on Federal navigation channels, ports, and OCS-related 

waterways in 2012. The number of service-vessel trips projected annually for Alternative A would 

represent <2 percent of the total annual traffic on these OCS-related waterways.
3-56 Gulf of Mexico Multisale EIS

Alternative B*: Alternative B is estimated to generate 38,000-452,000 service-vessel trips 

over the 50-year period (Table 3-2) or 760-9,040 trips annually. Table 3-7 indicates that over 

875,000 service-vessel trips occurred on Federal navigation channels, ports, and OCS-related 

waterways in 2012. The number of service-vessel trips projected annually for Alternative B would 

represent <2 percent of the total annual traffic on these OCS-related waterways.

Alternative C*: Alternative C is estimated to generate 30,000-88,500 service-vessel trips 

over the 50-year period (Table 3-2) or 600-1,770 trips annually. Table 3-7 indicates that over 

875,000 service-vessel trips occurred on Federal navigation channels, ports, and OCS-related 

waterways in 2012. The number of service-vessel trips projected annually for Alternative C would 

represent <1 percent of the total annual traffic on these OCS-related waterways.

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for AlternativeS A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

3.1.4.4 Helicopters

Helicopters are one of the primary modes of transporting personnel between service bases

and offshore platforms, drilling rigs, derrick barges, and pipeline construction barges. Helicopters 

are routinely used for normal crew changes and at other times to transport management and special 

service personnel to offshore exploration and production sites. In addition, equipment and supplies 

are sometimes transported. An operation is considered a roundtrip and includes takeoff and landing.

Deepwater operations require helicopters that travel farther and faster, carry more personnel, 

are all-weather capable, and have lower operating costs. Helicopter trips have been declining over 

the last 15 years. There are several issues that could be contributing to this decline, including 

competition with increasingly faster boats and the development of new technology such as subsea 

systems. These systems decrease the number of platforms and personnel needed offshore, 

therefore reducing the amount of transportation needed. Additionally, oil and gas companies are 

increasingly subcontracting all helicopter support to independent contractors who may use one fleet 

to service multiple oil and gas companies. The number of helicopters operating in the GOM is 

expected to decrease in the future, and helicopters that do operate are expected to be larger and 

faster.

The Federal Aviation Administration (FAA) regulates helicopter flight patterns. Because of 

noise concerns, FAA Circular 91-36C encourages pilots to maintain higher than minimum altitudes 

near noise sensitive areas. The Helicopter Safety Advisory Conference recommended practice

states that helicopters should maintain a minimum altitude of 750 ft (229 m) while in transit offshore 
Impact-Producing Factors and Scenario 3-57

and a maximum of 500 ft (152 m) while working between platforms and drilling rigs (Helicopter 

Safety Advisory Conference, 2010). When flying over land, the specified minimum altitude is 

1,000 ft (305 m) over unpopulated areas and coastlines, and 2,000 ft (610 m) over populated areas 

and sensitive areas including national parks, recreational seashores, and wildlife refuges. In 

addition, guidelines and regulations issued by NMFS under the authority of the Marine Mammal

Protection Act include provisions specifying helicopter pilots to maintain an altitude of 1,000 ft 

(305 m) within 100 yd (91 m) of marine mammals.

How Much Helicopter Activity Would Likely Occur? 

The scenarios for each alternative and the Cumulative OCS Oil and Gas Program scenarios 

(Chapter 3.3.1.7) below use the current level of activity as a basis for projecting future helicopter 

operations in relation to the production activity forecasted. According to the Helicopter Safety 

Advisory Conference (2015), from 1996 to 2014, helicopter operations (take offs and landings) in 

support of regionwide OCS operations have averaged, annually, about 1.2 million operations, 

2.7 million passengers, and 386,000 flight hours. There has been a decline in helicopter operations 

from 1,668,401 in 1996 to 741,201 in 2014 (Helicopter Safety Advisory Conference, 2015). Future 

projections are based on a high equal to the average number of flights over the last 15 years and a 

low equal to a continuing forecast of the current decline. A trip is considered the transportation from 

a service base to an offshore site and back, similar to service vessels.

Alternative A*: There are 122,000-3,750,000 helicopter trips projected over the 50-year 

period for Alternative A (Table 3-2), or 2,440-75,000 trips annually.

Alternative B*: There are 105,000-3,415,000 helicopter trips projected over the 50-year 

period for Alternative B (Table 3-2), or 2,100-68,300 trips annually.

Alternative C*: There are 70,000-440,000 helicopter trips projected over the 50-year 

period for Alternative C (Table 3-2), or 1,400-8,800 trips annually.

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for AlternativeS A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.
3-58 Gulf of Mexico Multisale EIS

3.1.5 Discharges and and Wastes

3.1.5.1 Operational Wastes and Discharges Generated by OCS Oil- and Gas-Related 

Facilities

The primary operational wastes and discharges generated during offshore oil and gas 

exploration and development are drilling fluids, drill cuttings, various waters (e.g., bilge, ballast, fire, 

and cooling), deck drainage, sanitary wastes, and domestic wastes. During production activities, 

additional waste streams include produced water, produced sand, and well-treatment, workover, and 

completion fluids. Minor additional discharges occur from numerous sources. These discharges 

may include desalination unit discharges, blowout preventer fluids, boiler blowdown discharges, 

excess cement slurry, several fluids used in subsea production, and uncontaminated freshwater and 

saltwater.

What Regulations Govern Operational Wastes and Discharges from OCS Oil- and GasRelated Facilities and How Are Those Regulations Managed?

The Clean Water Act (CWA) establishes conditions and permitting for discharges of 

pollutants into the waters of the United States under the NPDES and gives the USEPA the authority 

to implement pollution control programs such as setting wastewater standards for industry and to set 

water quality standards for all contaminants in surface waters. Accordingly, the USEPA regulates all 

waste streams generated from OCS oil- and gas-related activities through permits issued by the 

USEPA Region that has jurisdictional oversight.

The USEPA Region 4 has jurisdiction over the eastern portion of the Gulf of Mexico OCS, 

including all of the EPA and a portion of the CPA off the coasts of Alabama and Mississippi (Figure 

3-10). The USEPA Region 6 has jurisdiction over the rest of the CPA and all of the WPA. Each 

region issues general permits but can require an operator to apply for an individual permit. Each 

USEPA Region has promulgated general permits for discharges that incorporate the 1993 and 2000 

effluent guidelines (USEPA, 1993a and 2000b) for synthetic-based fluid (SBF)-wetted cuttings as a 

minimum. The permits are valid for 5 years. 

The current USEPA Region 4 general permit (GEG460000) was issued on March 15, 2010; 

became effective on April 1, 2010; and expired on March 31, 2015 (USEPA, 2010a). The renewal of 

the permit is being administratively continued for those operators who are already covered under the 

permit and request an extension. However, no new general permits will be granted until the permit 

is renewed. Operators may apply for an individual permit. The draft proposed permit was released 

on August 18, 2016. It includes the following changes: (1) new electronic reporting requirements; 

(2) new whole effluent toxicity testing sampling and reporting requirements for well treatment, 

completion, and workover fluids not discharged with produced wastewaters; (3) requirements to 

submit additional information pertaining to the chemicals and additives used in well treatment, 

completion and workover operations; and (4) clarification regarding types of operators (Federal 

Register, 2016b). In the preliminary Ocean Discharge Criteria Evaluation for the permit, the USEPA 

Region 4 reached a determination of no unreasonable degradation (USEPA, 2016a). The 
Impact-Producing Factors and Scenario 3-59

preliminary determination was made after reviewing the available data and incorporating a variety of 

technology-based, water quality-based, and Section 403-based requirements in the permit to ensure 

compliance with Section 403 of the Clean Water Act (USEPA, 2016b). The current USEPA 

Region 6 permit (GMG290000) was reissued with an effective date of October 1, 2012, expiring at 

midnight on. September 30, 2017 (USEPA, 2012a).

Figure 3-10. Boundaries for USEPA Regions 4 and 6. 

Permits issued under Section 402 (NPDES) of the CWA for offshore activities must comply 

with any applicable water quality standards and/or Federal water quality criteria, as well as Section 

403 (Ocean Discharge Criteria) of the CWA. Water quality standards consist of the waterbody’s 

designated uses, water quality criteria to protect those uses and to determine if they are being 

attained, and antidegradation policies to help protect high-quality waterbodies (refer to Chapter 4.2). 

Discharges from offshore activities near State water boundaries must comply with all applicable 

State water quality standards.

Section 403 of the CWA requires that NPDES permits for discharges to the territorial seas 

(baseline to 3 mi [5 km]), contiguous zone, and ocean be issued in compliance with USEPA’s 

regulations for preventing unreasonable degradation of the receiving waters. Prior to permit 

issuance, ocean discharges must be evaluated against the USEPA’s published criteria for 

determination of unreasonable degradation. Unreasonable degradation is defined in the NPDES 

regulations (40 CFR § 125.1211e) as the following:

• significant adverse changes in ecosystem diversity, productivity, and stability of 

the biological community within the area of discharge and surrounding biological 

communities;

• threat to human health through direct exposure to pollutants or through 

consumption of exposed aquatic organisms; and
3-60 Gulf of Mexico Multisale EIS

• loss of aesthetic, recreational, scientific, or economic values, which is 

unreasonable in relation to the benefit derived from the discharge.

Role of the U.S. Environmental Protection Agency in Adminstering NPDES Permits

In order for a facility to be covered by a general NPDES permit, the operator must submit a 

notice of intent (NOI) to be covered by the general permit. Region 6 developed an “electronic NOI 

(eNOI)” system so that coverage is immediate (USEPA, 2015a). The USEPA evaluates NOIs on a 

case-by-case basis and reserves the right to deny coverage if it is determined the facility is ineligible 

or has falsified information. The NPDES permit sets minimum requirements that every allowable 

discharge must meet. If a waste does not meet the requirements of the permit, the permit would be 

considered violated and the USEPA could take an enforcement action. Discharges are monitored 

and the data are reported to the USEPA through discharge monitoring reports (DMRs). These 

reports must be turned in quarterly and contain all of the information required by the permit for that 

discharge. Region 6 now has an electronic Discharge Monitoring Report (DMR) system known as 

“NetDMR,” which is now required for all facilities covered by their general permit (USEPA, 2015b). 

Failure to submit any information or monitoring results required by the permit is considered a 

violation. Data from submitted NetDMRs populate the USEPA’s national Integrated Compliance 

Information System database. Region 6 reviews the Integrated Compliance Information System’s

data to identify facilities violating the permit conditions or reporting requirements. Violations are 

reviewed and enforcement actions are taken as deemed appropriate, particularly for serious single 

event violations, an ongoing pattern of noncompliance, or significant noncompliance (noncompliance 

for two running quarters or more). Depending on the type of violation, severity, length of violation, 

environmental damage, or illegal activity, the USEPA may request more information, issue a warning 

letter or order corrective actions, assess a penalty, or refer it to the U.S. Department of Justice or 

Criminal Investigation Division. The USEPA may use information, pictures, and other documentation 

from BSEE, BOEM, or USCG to support its enforcement cases. The public may view violations and 

enforcement actions in the Enforcement and Compliance History Online database (USEPA, 2015c), 

which is updated every 30 days from the Integrated Compliance Information System’s database.

Role of the Bureau of Safety and Environmental Enforcement

In addition to facilities’ inspections in Federal waters in the Gulf of Mexico (refer to Chapter 

1.3.2), BSEE performs NPDES inspections on behalf of the USEPA Region 6 for production 

platforms and drilling rigs through a 1984 Memorandum of Understanding between the 

U.S. Department of the Interior, the USEPA, and the U.S. Department of Transportation (USDOI, 

MMS, 1983) and a 1989 Memorandum of Agreement between between MMS (BOEM and BSEE’s 

predecessor) and the USEPA Region 6 (USDOI, MMS, 1989). According to the Memorandum of 

Agreement, BSEE inspects a maximum of 50 OCS facilities per year for compliance with NPDES 

permit provisions. The Region 6 NPDES inspection responsibility officially transitioned from BSEE’s 

Districts to BSEE’s Environmental Enforcement Branch, Environmental Inspection and Enforcement 

Unit on September 18, 2014, in preparation for the 2015 inspection cycle (Sanders, official 

communication, 2015). The scope of those inspections does not include sampling. Coordination of 
Impact-Producing Factors and Scenario 3-61

a potential Memorandum of Agreement between BSEE and USEPA Region 4 concerning NPDES 

inspection needs is ongoing.

Facility inspections are chosen on a variety of parameters such as pollution history, the 

USEPA’s reporting anomalies and errors, and general frequency for a lack of past inspection visits, 

among others. An inspection or audit may also be triggered by a major pollution release event 

triggering a rapid visit turnaround. The BSEE utilizes the U.S. Environmental Protection Agency’s 

ICIS database where DMRs are reported for the permitted features specific to the facility, and 

deviations and violations are noted. A thorough review of these data is included and evaluated for 

every inspection. When completed, an inspection report is prepared and sent to the USEPA where 

the noncompliances observed during the inspection are summarized and formally referred to them 

for support of potential further enforcement action. If violations or concerns are observed during the 

inspection, as per any of BSEE regulations from 30 CFR parts 200-699, then BSEE-driven incidents 

of noncompliance are prepared and sent directly to the offending facility, and the USEPA is copied 

as a courtesy.

Pollution-related incidents of noncompliance are shown in Table 3-8. The BSEE posts some 

incidents of noncompliance on its website (USDOI, BSEE, 2015a), but as BSEE is working to 

improve its website postings, additional information can be requested through BSEE’s Freedom of 

Information Act office. Over 700 NPDES inspections were performed between 1999 and 2016

(Table 3-9).

Table 3-8. Pollution-Related Incidents of Noncompliance (INCs) Issued Since 1986. 

INC Number INC Description

Approximate 

Number of INCs 

Issued

E-100 The operator failed to prevent unauthorized

discharge of pollutants into offshore waters. 2,035

E-101 The lessee failed to dispose of drill cuttings, sand,

and other well solids as approved. 18

E-102

Facility is not equipped with curbs, gutters, drip 

pans, and drains necessary to collect all

contaminants not authorized for discharge. 

1,331

E-103

The sump system does not automatically maintain 

the oil at a level sufficient to prevent discharge of oil 

into offshore waters.

1,054

E-104

All hydrocarbon handling equipment for testing and 

production is not designed, installed, and operated 

to prevent pollution.

43

E-105

All gravity drains are not equipped with a water trap

or other means to prevent gas in the sump system 

from escaping through the drains.

194

E-106 Sump piles are used as processing devices. 48
3-62 Gulf of Mexico Multisale EIS

E-107

The lessee failed to adhere to the prohibition on the 

addition of petroleum-based substances to the mud 

system without prior approval of the district 

manager.

2 

E-108

The lessee failed to prevent the disposal of

equipment, cables, chains, containers, or other

materials into offshore waters.

49

Source: USDOI, BSEE, 2011.

Table 3-9. National Pollutant Discharge Elimination System Inspections from 

1999 through 2016. 

Calendar 

Year

Number of Platforms

Inspected

Number of Rigs 

Inspected Annual Totals

1999 34 16 50

2000 76 15 91

2001 40 12 52

2002 39 18 57

2003 30 10 40

2004 16 7 23

2005 22 11 33

2006 20 12 32

2007 25 4 29

2008 30 20 50

2009 26 23 49

2010 17 12 29

2011 18 21 39

2012 30 24 54

2013 37 32 69

2014 16 14 30

2015 38 1 39

2016 24 1 25

Total 538 253 791

(1) Data as of November 10, 2016.

(2) Inspections performed by the Minerals Management Service; Bureau of

Ocean Energy Management, Regulation and Enforcement; and Bureau of

Safety and Environmental Enforcement.

Sources: Sanders, official communication, 2015 and 2016.

3.1.5.1.1 Drilling Muds and Cuttings

Why Are Drilling Fluids or Drilling Muds Used?

Drilling fluids (also known as drilling muds) and cuttings represent a large quantity of the 

discharge generated by drilling operations. Drilling fluids are used in rotary drilling to remove 

cuttings from beneath the bit, to control well pressure, to cool and lubricate the drill string and its bit, 

and to seal the well. Drill cuttings are the fragments of rock generated during drilling and carried to 
Impact-Producing Factors and Scenario 3-63

Drilling fluids used on the OCS are 

divided into two categories: water-based 

fluids (WBFs) and nonaqueous-based 

fluids (OBFs or SBFs).

the surface with the drilling fluid. Drilling discharges of muds and cuttings are regulated by the 

USEPA through the NPDES permitting process.

What are the Different Types of Drilling Muds and Can They be Discharged to the OCS?

The composition of drilling fluids is complex. 

Drill cuttings are a different grain size and 

composition from the existing surface sediments. 

Drilling fluids used on the OCS are divided into two 

categories: water based and nonaqueous based. 

Water-based fluids (WBFs) have a water soluble 

continuous phase while nonaqueous-based fluids have a continuous phase that is not soluble in 

water. The base fluid can be freshwater or saltwater in WBFs, mineral or diesel oil-based fluids 

(OBFs), or synthetic-based fluids (SBFs). Thus, both OBFs and SBFs are nonaqueous-based fluids. 

Clays, barite, and other chemicals are added to the base fluid to improve the performance of the 

drilling fluid (Boehm et al., 2001).

On the OCS, the WBFs have been used for decades in drilling. In the GOM, they are the 

most commonly used drilling fluids for exploration and production wells. The discharge of WBFs and 

cuttings associated with WBFs is allowed on the OCS under the general NPDES permits issued by 

USEPA Regions 4 and 6, as long as the discharge meets the conditions required in the permit. 

Discharge of WBFs results in increased turbidity in the water column, alteration of sediment 

characteristics because of coarse material in cuttings, and the input of trace metal into the 

environment. Occasionally, formation oil may be discharged with the cuttings, adding hydrocarbons 

to the discharge. However, as noted in the NPDES permits, no free oil shall be discharged; static 

sheen tests must be performed once per week when discharging. In shallow environments, WBFs 

are rapidly dispersed in the water column immediately after discharge and rapidly descend to the 

seafloor (Neff, 1987). In deep waters, fluids dispersed near the water surface would disperse over a 

wider area than fluids dispersed in shallow waters.

The early nonaqueous drilling fluids, termed oil-based drilling fluids (OBF), were occasionally 

used for directional drilling and in drill-bore sections where additional lubricity was needed. Crude, 

diesel, and mineral oil were used. Diesel OBFs contains light aromatics such as benzene, toluene, 

and xylene. Mineral oil is advantageous over diesel because it is less toxic. Hydrocarbon 

concentration and impacts to benthic community diversity and abundance have been observed 

within 200 m (656 ft) of the drill site with diminishing impacts measured to a distance of 2,000 m 

(6,562 ft) (Neff, 1987). All OBFs and associated cuttings must be transported to shore for recycling 

or disposal unless reinjected. Due to the environmental concerns of OBFs, SBFs were created in 

the 1990s (Bakhtyar and Gagnon, 2012). The OBFs are rarely used because of the many 

advantages of SBFs. The SBFs are manufactured hydrocarbons. The SBF mud system also 

contains additives such as emulsifiers, clays, wetting agents, thinners, and barite. Since the SBFs 

are not petroleum based, they do not contain the aromatic hydrocarbons and polycyclic aromatic 

hydrocarbons (PAH) that contributed to OBF toxicity and persistence on the seafloor (Bakhtyar and 
3-64 Gulf of Mexico Multisale EIS

Gagnon, 2012). In fact, SBFs have several additional advantages over OBFs, which include that 

they are well characterized, have lower toxicity and bioaccumulation potentials, and biodegrade 

faster. Since 1992, SBFs have been increasingly used, especially in deep water, because they 

perform better than WBFs and OBFs. The SBFs reduce drilling times and costs incurred from 

expensive drilling rigs. By 1999, about 75 percent of all wells drilled in waters deeper than 305 m 

(1,000 ft) were drilled with SBFs in the Gulf of Mexico (CSA, 2004a). Although there are many types 

of SBFs, esters, internal olefins, and linear alpha olefins are most commonly used in the GOM.

A literature review (Neff et al., 2000) discussed knowledge about the fate and effects of 

SBFs discharges on the seabed. Like OBFs, the SBFs are hydrophobic, meaning they are not 

soluble in the water column and therefore are not expected to adversely affect water quality. The 

SBF-wetted cuttings settle close to the discharge point and affect the local sediments. Cuttings piles 

with a maximum depth of 8-10 in (20-25 cm) were noted in a seabed study of shelf and slope 

locations where cuttings drilled with SBF were discharged. The SBF discharge can alter sediment 

grain size and add organic matter, which can result in localized anoxia while SBF degrades (Melton 

et al., 2004). Different formulations of SBFs use base fluids that degrade at different rates, thus 

affecting the duration of the impact. Esters and olefins are the most rapidly biodegraded SBFs. 

Ongoing research is aimed at understanding the relationships between the chemical structure in 

SBFs and the environmental fates and effects, which would provide the design basis for fluids with 

better environmental performance. For example, recent testing showed that less branching of alpha 

and internal olefins positively impacted both sediment toxicity and anaerobic biodegradation (Dorn 

et al., 2011).

Bioaccumulation tests indicate that SBFs and their degradation products should not 

bioaccumulate (Neff et al., 2000). In a study to measure degradation rates of SBFs on the seafloor, 

biodegradation proceeded after a lag period of up to 28 weeks, which was influenced by both the 

SBF type and prior exposure of the sediments to SBFs (Roberts and Nguyen, 2006). Sediment 

sulfate depletion due to microbial activity coincided with SBF degradation. Decreased SBF 

concentrations indicated that recovery in sediments occurred in the year between sample 

collections. Deposited cuttings and measurable sediment effects indicative of organic enrichment 

were concentrated within a distance of 250 m (820 ft) in both shelf and slope sites (CSA, 2004a).

The discharge of the base SBF drilling fluid is prohibited. The SBFs and cuttings must meet 

environmental requirements. Both USEPA Regions 4 and 6 permit the discharge of cuttings wetted 

with SBF as long as the retained SBF amount is below a prescribed percent, meets biodegradation 

and toxicity requirements, and is not contaminated with the formation oil or PAH.

Typically, the upper portion of the well is drilled with WBF and the remainder is drilled with 

SBF. The upper sections would be drilled with a large diameter bit; progressively smaller drill bits 

are used with increasing depth. Therefore, the volume of cuttings per interval (length of wellbore) in 

the upper section of the well would be greater than the volume generated in the deeper sections.
Impact-Producing Factors and Scenario 3-65

What is Barite and What Does It Have to do with Drilling Muds?

Barite, a barium sulfate (BaSO4) mineral, is used as a weighting agent to increase the 

hydrostatic pressure of drilling muds in order to control high-pressure zones encountered during 

drilling. Because barite is also soft, it does not erode equipment but instead acts essentially as a 

lubricant (Mills, 2006). Additionally, barite is inert and does not react with other additives in the 

drilling fluid. Because of barite’s useful qualities, barite is a major component of all types of drilling 

fluid, but its use has somewhat declined due to advances in synthetic-based mud formulations and 

drilling technology. A study of 81 wells noted that, from 1998 to 2002, the quantity of barite 

discharged for a shallow well (2,936 m; 9,634 ft average) to a deep well (5,140 m; 16,864 ft average) 

is 110 tons barite per well and 586 tons barite per well, respectively (Candler and Primeaux, 2003).

Since barite is a natural mineral, it can have natural impurities associated with it. The 

impurities of concern in barite are trace metals such as mercury (Hg), cadmium (Cd), copper (Cu), 

zinc (Zn), and lead (Pb) that are often found in other mineral phases that were formed on or in the 

barite mineral deposit (Crecelius et al., 2007). However, the American Petroleum Institute (API) has 

set specifications for the barite used in the oil industry, which includes that the amount of watersoluble alkaline earth metals must be below 250 milligrams/kilogram (parts per million [ppm]) (Mills, 

2006). More importantly, since 1993, the USEPA has required the concentrations of Hg and Cd to 

be less than or equal to 1 ppm and 3 ppm, respectively, in the stock barite used to make up drilling 

muds (USEPA, 1993a and 2000b). Through Hg and Cd regulation, the USEPA can also control 

levels of other trace metals in barite. This reduces the addition of Hg to sediments to values similar 

to the concentration of Hg found in marine sediments throughout the GOM (Neff, 2002). 

Furthermore, barite is nearly insoluble in seawater, which means that it remains in the solid form 

where it is not readily available to biota unless the mineral particles themselves are directly digested.

Despite atmospheric Hg deposition being considered the main source of anthropogenic Hg 

inputs into the marine environment, the availability of Hg in barite was studied to confirm that barite 

in drilling muds was not a significant or available source of Hg in the marine environment. Crecelius 

et al. (2007) studied the solubility of barite and the rate at which it dissolves (and thereby releases 

associated metals such as Hg from the solid phase into the aqueous phase), the amount of metals 

released from barite, and the rate of dissolution of barite and release of metals after burial under 

simulated seafloor conditions. The research used three grades of barite: one commercially 

available barite ore used in drilling fluids, which meets the USEPA’s trace metal criteria; and two 

grades of barite to represent those used in the GOM prior to the 1993 USEPA regulation enacted to 

reduce the concentrations of Hg and Cd in drilling fluid. During a 1-week exposure of barite in 

seawater, in the pH range of 7.3 to 8.3, <1 percent of the Hg dissolved from the barite. The studies 

conducted at varying pH levels to mimic digestive tract conditions showed that very little (<0.1%) of 

the Hg in barite became available within 48 hours. When barite is added to anoxic sediments, the 

concentrations of methylmercury (methyl-Hg) and Hg were not elevated as compared with the same 

anoxic sediment without the addition of barite.
3-66 Gulf of Mexico Multisale EIS

Crecelius et al. (2007) confirmed that trace metal contaminants in barite were in sulfide 

mineral inclusions dispersed within the barite matrix. In seawater with a pH of 7.3 to 8.3 over the 

period of 1 week, <1 percent of the Cu and Pb, 3 percent of the Zn, and 15 percent of the Cd 

dissolved from the inclusions within the barite. Thus, a small amount of these metals are soluble in 

seawater at this pH range. Since low-metal barite (barite that meets current USEPA standards) 

releases little of these metals to seawater, low-metal barite is not likely to cause environmental 

effects to organisms living in the water column. However, in acidic conditions simulating the gut of 

deposit-feeding benthic animals, a major portion of the Cd, Cu, Pb, and Zn are soluble, and 

<1 percent of the barium (Ba) are soluble in 48 hours.

In addition to laboratory studies, field studies have also been conducted to examine the role 

that barite plays in sediment Hg levels. Concentrations of total mercury in uncontaminated estuarine 

and marine sediments generally are 0.2 micrograms/gram (μg/g) dry weight or lower. Surface 

sediments collected 20-2,000 m (66-6,562 ft) away from four oil production platforms in the 

northwestern GOM contained 0.044-0.12 μg/g total mercury. These amounts are essentially 

background concentrations for mercury in surficial sediments on the Gulf of Mexico OCS (Neff, 

2002). A comparative study of surface and subsurface sediment samples from six offshore drill 

locations showed higher levels of total mercury found in the sediments closest to the drilling sites as 

compared with the sites greater than 3 km (1.9 mi) distant. Higher total mercury concentrations 

corresponded to higher barium concentrations also present. Higher total mercury levels in nearfield 

sediments did not translate to higher methyl-Hg concentration in those sediments, with a few 

exceptions (Trefry et al., 2007). Sediment redox conditions and organic content influence 

methylmercury formation. For more information on sediment and water quality, refer to Chapter 4.2. 

3.1.5.1.2 Produced Waters

What is Produced Water?

Produced water is brought up from the hydrocarbon-bearing strata along with produced oil 

and gas. This waste stream can include formation water; injection water; well-treatment, completion, 

and workover compounds added downhole (including flowback water); and compounds used during 

the oil and water separation process. Formation water (brine) originates in the permeable 

sedimentary rock strata and is brought up to the surface commingled with the oil and gas. Injection 

water is water that was injected to enhance oil production and is used in secondary oil recovery. 

Flowback fluid (or water) is fluid that has been returned uphole after being injected into the formation 

for stimulation purposes. This includes water and chemicals used for hydraulic fracturing practices, 

as that would be considered a stimulation practice; fracture pack or “frac packs” are often used in the 

Gulf of Mexico during the completion process to clean and stimulate the area around the wellbore as 

well as for sand control (refer to Chapter 3.1.3.1 for more information on hydraulic fracturing 

processes used offshore in the Gulf of Mexico).

In addition to the added chemical products, produced water contains chemicals that have 

dissolved into the water from the geological formation where the water was stored. The amount of 

dissolved solids can be more concentrated than is found in seawater. Produced water contains 
Impact-Producing Factors and Scenario 3-67

inorganic and organic chemicals and radionuclides (226Ra and 228Ra). The composition of the 

discharge can vary greatly in the amounts of organic and inorganic compounds.

Can Produced Water be Discharged to the OCS?

Both USEPA Region 4 and Region 6 general permits allow the discharge of produced water 

on the OCS provided that they meet discharge criteria. The produced water is treated to separate 

free oil from the water. Since the oil and water separation process does not completely separate all 

of the oil, some hydrocarbons remain with the produced water and often the water is treated to 

prevent the formation of sheen. Produced water may be discharged if the oil and grease 

concentration does not exceed 42 milligrams per liter (mg/L) daily maximum or 29 mg/L monthly 

average. The discharge must also be tested for toxicity; the toxicity test is primarily for chronic 

exposure, but it can include acute exposure. Both USEPA Region 4 and Region 6 permits require 

no discharge within 1,000 m (3,281 ft) of an area of biological concern (areas of biological concern 

are identified by USEPA in consultation with DOI). Region 4 also requires no discharge within 

1,000 m (3,281 ft) of any federally designated dredged material ocean disposal site.

As noted above, completion fluids, including fluids from fracture packs or “frac-packs,” not 

returned to the deck of the platform during the completion job may be co-mingled and discharged 

with produced water if they meet the conditions of the appropriate NPDES permit. However, if the 

fluid composition is not compatible with the production system, the operator may decide to separate 

the returning well fluids from the production fluids and treat the fluids in temporary treatment systems 

or collect the fluids for onshore disposal depending upon logistics (e.g., treatability of well fluid, 

volume of fluid, personnel limitations, treatment unit capacity, space on deck, weather, etc.).

How Much Nitrogen and Phosphorus does Produced Water Contain? 

The USEPA Region 6 NPDES permit required participation in the Produced Water Hypoxia 

Study, in which produced water was collected from 50 platforms that discharge into the hypoxic zone 

and analyzed for oxygen-demanding characteristics (Veil et al., 2005; Rabalais, 2005). In 

comparison to loadings from the Mississippi and Atchafalaya Rivers, the total nitrogen loading from 

produced water is about 0.16 percent and total phosphorus loading is about 0.013 percent of the 

nutrient loading coming from the rivers. For more information on hypoxia and water quality in the 

Gulf of Mexico, refer to Chapters 3.3.2.12 and 4.2.

How Much Produced Water may be Generated? 

Estimates of the volume of produced water generated per well vary because the percent of 

water is related to well age and hydrocarbon type. Usually, produced-water volumes are small 

during the initial production phase and increases over time as the formation approaches 

hydrocarbon depletion. Produced-water volumes range from 2 to 150,000 bbl/day (USEPA, 1993a). 

In some cases, a centralized platform is used to process water from several surrounding platforms. 

Some of the produced water may be reinjected into the well. Reinjection occurs when the produced 

water does not meet discharge criteria or when the water is used as part of operations. However, 
3-68 Gulf of Mexico Multisale EIS

the vast majority of produced water is discharged per the conditions of the relevant U.S. 

Environmental Protection Agency NPDES permit. For example, in 2007, 48,673,102 bbl were used 

for enhanced recovery purposes, 1,298,417 bbl of produced water were reinjected, and 

537,352,846 bbl were discharged after treatment (Clark and Veil, 2009). In 2012, of a total 

produced-water volume of 509,159,846 bbl, 52,043,434 bbl were injected while an estimate of 

457,116,412 bbl were discharged (Veil, 2015).

BOEM maintains records of the volume of water produced from each block on the OCS and 

its disposition―injected on lease, injected off lease, transferred off lease, or discharged overboard. 

The amount discharged overboard for the years 2000-2014 is summarized by water depth in 

Table 3-10. The total volume for all water depths during this 15-year period ranged from 485.6 to 

648.2 MMbbl, with the largest contribution (68-88%) coming from operations on the shelf. The total 

volume of produced water generally decreased after 2004, reflecting an overall decrease in 

contributions from operations on the shelf. The contribution of produced water from operations in 

deep water (>400-m [1,312-ft] water depth) and ultra-deepwater (>1,600-m [5,249-ft] water depth) 

production has been increasing. From 2000 to 2014, the contribution from these operations (deep 

and ultra-deepwater together) increased from 6 percent (37.8 MMbbl) to 31 percent (150.0 MMbbl) 

of the total produced-water volume (calculated from data in Table 3-10). The low-temperature and 

high-pressure conditions found in deeper water can result in flow problems such as hydrate 

formation in the lines. Additional quantities of chemicals are used to assure production, and even 

with recovery systems, some of these chemicals will be present in produced water (USDOI, MMS, 

2000a). For deepwater operations, new technologies are being developed that may discharge or 

reinject produced water at the seafloor or at “minimal surface structures” before the production 

stream is transported by pipeline to the host production facility.
Impact-Producing Factors and Scenario 3-69

Table 3-10. Annual Volume of Produced Water Discharged by Depth (millions of bbl). 

Year Shelf

0-60 m

Shelf

60-200 m

Slope

200-400 m

Deepwater

400-800 m

Deepwater

800-1,600 m

UltraDeepwater

1,601-2,400 m

UltraDeepwater

>2,400 m

Total

2000 370.6 193.1 35.5 25.6 12.2 0.0 0.0 637.0

2001 364.2 185.2 35.0 32.0 16.6 0.0 0.0 633.0

2002 344.6 180.4 32.5 35.2 21.4 0.0 0.0 614.1

2003 359.4 182.9 31.2 39.0 35.5 0.2 0.0 648.2

2004 346.7 160.5 29.3 36.9 39.2 1.8 0.0 614.4

2005 270.0 113.5 23.1 33.5 43.0 5.8 0.0 488.9

2006 260.3 99.6 20.6 35.0 61.6 12.4 0.0 489.5

2007 307.0 139. 3 22.2 40.0 70.6 15.5 0.1 594.7

2008 252.7 118.6 15.9 32.7 60.2 16.1 0.1 496.3

2009 265.2 109.2 19.9 39.2 65.6 25.0 0.1 524.2

2010 278.4 115.7 20.9 40.7 56.8 32.5 0.1 545.1

2011 273.7 117.0 20.7 39.7 67.7 32.2 0.1 551.1

2012 240.8 108.9 20.8 35.0 71. 5 32.3 0.1 509.4

2013 248.8 104.2 20.0 33.1 76.0 36.9 0.3 519.3

2014 248.7 97.2 18.5 35.7 79.3 50 1.0 530.4

2015 243.9 102.1 15.0 40.8 83.3 50.6 1.3 537.0

Source: Gonzales, official communication, 2015.

3.1.5.1.3 Well-Treatment, Workover, and Completion Fluids

What are Completion Fluids?

Wells are drilled using a base fluid and a combination of other chemicals to aid in the drilling 

process. Fluids (drilling muds) present in the borehole can damage the geologic formation in the 

producing zone. Completion fluids are used to displace the drilling fluid and protect formation 

permeability. “Clear” fluids consist of brines made from seawater mixed with calcium chloride, 

calcium bromide, and/or zinc bromide. These salts can be adjusted to increase or decrease the 

density of the brine to hold back-pressure on the formation. Additives, such as defoamers and 

corrosion inhibitors, are used to reduce problems associated with the completion fluids. Recovered 

completion fluids can be recycled for reuse.

What are Workover Fluids?

Workover fluids are used to maintain or improve existing well conditions and production rates 

on wells that have been in production. Workover operations include casing and subsurface 

equipment repairs, re-perforation, acidizing, and stimulating via hydraulic fracturing. In the Gulf of 

Mexico, the type of hydraulic fracturing commonly used are fracture-pack or “frac packs” (refer to

Chapter 3.1.3.1 for more information on these processes). During some of the workover operations, 

the producing formation may be exposed, in which case fluids like the aforementioned completion 

fluids are used. In other cases, such as acidizing and hydraulic fracturing, including “frac-packs” 

(also considered stimulation or well treatment), hydrochloric and other acids are used. Both 

procedures are used to increase the permeability of the formation. The acids dissolve limestone, 
3-70 Gulf of Mexico Multisale EIS

sandstone, and other deposits. Because of the corrosive nature of acids, particularly when hot, 

corrosion inhibitors are added. Since the fluids are altered with use, they are not recovered and 

recycled; however, these products may be mixed with the produced water and disposed of as 

described in Chapter 3.1.5.1.2 above.

What are Well Treatment Fluids?

Production treatment fluids are chemicals applied during the oil and gas extraction process. 

Production chemicals are used to dehydrate produced oil or treat the associated produced water for 

reuse or disposal. A wide variety of chemicals are used, including corrosion and scale inhibitors, 

bactericides, paraffin solvents, demulsifiers, foamers, defoamers, and water treatment chemicals 

(Boehm et al., 2001). Some of the production chemicals mix with the production stream and are 

transported to shore with the product. Other chemicals mix with the produced water. Most produced 

water cannot be discharged without some chemical treatment. Even water that is reinjected 

downhole must be cleaned to protect equipment. The types and volumes of chemicals that are used 

changes during the life of the well. In the early stages, defoamers are used. In the later stages, 

when more water than oil is produced, demulsifiers and water-treatment chemicals are used more 

extensively.

Boehm et al. (2001) discusses completion, stimulation, and workover chemicals that are 

used in the Gulf of Mexico. These same chemicals are used for fracturing, including “frac packs,” 

gravel packs, and acidizing processes. The report lists and defines the types of chemicals used as 

well as providing examples for each category of chemical (Boehm et al. (2001), Table 3). BOEM 

has included an update to this study in their 2015-2017 Studies Development Plan 

(http://www.boem.gov/Environmental-Studies-Planning/). After the fluids used for fracturing have 

performed their desired function, they are disposed of in the same manner as completion fluids or 

may be combined with the produced water. If the fluids return topside as a part of the completion 

job, they are considered waste completion fluids and would be disposed of as such. After the 

completion job is finished, the fluid is removed from the tubing in the well in order to begin producing 

hydrocarbons; this fluid may be comingled with the produced water and discharged per the 

requirements for produced water. 

Can Well Treatment, Completion, and Workover Fluids be Discharged?

Both USEPA Regions 4 and 6 allow the discharge of well-treatment, completion, and 

workover fluids if they meet the condition of the NPDES permits. Both USEPA Regions 4 and 6 

prohibit the discharge of well-treatment, completion, and workover fluid with additives containing 

priority pollutants (e.g., benzene, toluene, lead, and mercury; the full list of priority pollutants can be 

found in Appendix A of 40 CFR part 423). Additives containing priority pollutants must be monitored. 

Some well-treatment, workover, and completion chemicals are discharged with the drilling muds and 

cuttings or with the produced-water streams. These discharges must meet the general toxicity limits 

in the NPDES general permit. Discharge and monitoring records must be kept.
Impact-Producing Factors and Scenario 3-71

As part of the NPDES general permit renewal process, USEPA Region 4 released a Draft 

Ocean Discharge Criteria Evaluation. Considering well treatment, completion, and workover fluids, 

the USEPA Region 4 concluded in the Draft Ocean Discharge Criteria Evaluation that the volume 

and constituents of the discharged material are not considered sufficient to pose a potential problem 

through bioaccumulation or persistence (USEPA, 2016a). However, to confirm the USEPA's 

decision and as a precaution against any changes in operational practices that could change the 

USEPA's assumptions, the discharged volumes of well treatment, completion, and workover fluids 

must be recorded monthly and reported once each year on the compliance monitoring report as a 

condition of the draft permit.

3.1.5.1.4 Production Solids and Equipment

As defined by the USEPA in the discharge guidelines (Federal Register, 1993), produced 

sands are slurried particles, which surface from hydraulic fracturing, and the accumulated formation 

sands and other particles including scale, which is generated during production. This waste stream 

also includes sludges generated in the produced-water treatment system, such as tank bottoms from 

oil/water separators and solids removed in filtration. The guidelines do not permit the discharge of 

produced sand, which must be transported to shore and disposed of as nonhazardous oil-field waste 

according to State regulations. Estimates of total produced sand expected from a platform are from 

0 to 35 bbl/day according to the USEPA (1993a). A variety of solid wastes are generated, including 

construction/demolition debris, garbage, and industrial solid waste. No equipment or solid waste 

from a facility may be disposed of in marine waters.

3.1.5.1.5 Bilge, Ballast, and Fire Water

Bilge, ballast, and fire water all constitute minor discharges generated by offshore oil and gas 

production activities, which are allowed to be discharged to the ocean, as long as the USEPA’s 

guidelines are followed. Ballast water is untreated seawater that is taken on board a vessel to 

maintain stability. Ballast water contained in segregated ballast tanks never comes into contact with 

either cargo oil or fuel oil. Newly designed and constructed floating storage platforms use 

permanent ballast tanks, in which the ballast in those tanks rarely becomes contaminated. Bilge 

water is seawater that becomes contaminated with oil and grease and with solids such as rust when 

it collects at low points in the facility. Uncontaminated bilge and ballast water are included in the 

miscellaneous discharges category of the USEPA Region 4 and Region 6 general permits (USEPA, 

2010a and 2012a). With the right equipment on board, dirty bilge and ballast water can be 

processed in a way that separates most of the oil from the water before it is discharged into the sea 

(USEPA, 1993a). The discharge of any oil or oily mixtures is prohibited under 33 CFR § 151.10. 

The USEPA requires monitoring for visual sheen related to miscellaneous discharges, such as bilge 

and ballast water.

Offshore drilling rigs and the offshore production facilities used to process oil have special 

fire protection requirements. Fire water is defined in the USEPA Region 4 and Region 6 general 

permits as excess seawater or freshwater that permits the continuous operation of fire control 

pumps, as well as water released during training of personnel in fire protection. Fire control system 
3-72 Gulf of Mexico Multisale EIS

test water is seawater, sometimes treated with a biocide that is used as test water for the fire control 

system on offshore platforms. This test water is discharged directly to the sea as a separate waste 

stream (USEPA, 1993a). As well, fire protection can also include a barrier of water that is 

sometimes used during flaring to provide protection between flaring systems and personnel, 

equipment, and facilities. The USEPA Region 4 and Region 6 general permits allow for the 

discharge of fire water that meets their specified limitations. The requirements include regulations 

and monitoring for treatment chemicals, discharge rate, free oil, and toxicity.

3.1.5.1.6 Cooling Water

Cooling water is defined as water used for contact or noncontact cooling, including water 

used for equipment cooling, evaporative cooling tower makeup, and dilution of effluent heat content. 

Seawater is drawn through an intake structure on the drilling rig, ship, or platform to cool power 

generators and other machinery, and produced oil or water. Drillship cooling water structures have 

been noted to intake 16-20 million gallons/day while semisubmersibles have been noted to intake 

2 to over 10 million gallons/day from a water depth >400 ft (122 m) from the water’s surface 

(USEPA, 2006). However, newer semisubmersible units were noted to have an intake capacity of 

35 million gallons per day. Not all intake water is necessarily used as cooling water; some may be 

use for ballast water, cleaning, firewater, and testing. Organisms may be killed through impingement 

or entrainment. When fish and other aquatic life become trapped against the screen at the entrance 

to the cooling water intake structure through the force of the water being drawn through the intake 

structure, it is termed impingement. When eggs and larvae are sucked into the heat exchanger and 

eventually discharged from the facility, it is termed entrainment (Chapter 4.7; Federal Register, 

2006a).

The Clean Water Act, Section 316(b) Phase III, established categorical regulations for 

offshore oil and gas cooling water intake structures. The NPDES permit began incorporating these 

regulations in NPDES General Permit GMG290000 for the USEPA Region 6 in 2007 and General 

Permit GEG460000 for the USEPA Region 4 in 2010 for new facilities that began construction after 

July 17, 2006, and that take in more than 2 million gallons per day of seawater, of which more than 

25 percent is used for cooling (USEPA, 2010a and 2012a). The requirements have several tracks 

depending on whether the facility is a fixed or nonfixed facility and whether it has a sea chest intake 

or not. Some of the requirements include cooling water intake structure design requirements to 

meet a velocity of <0.5 ft (0.2 m) per second, construction to minimize impingement and/or 

entrainment, entrainment monitoring, recordkeeping, and completion of a source water biological 

study. Alteration to a sea chest intake structure on a mobile facility could render the facility less 

seaworthy, so it is not required. The requirements include a baseline study that characterizes the 

biological community in the vicinity of the structure or monitoring. A Joint Industry Biological 

Baseline Study was completed for USEPA Region 6 in June 2009 (LGL Ecological Research 

Associates, Inc., 2009), and an industry-wide cooling water intake structure entrainment monitoring

study, approved by USEPA Region 6, was completed in 2014 (CSA and LGL Ecological Research 

Associates, Inc., 2014). For more information on the specifics regarding potential impacts to 

fisheries, refer to Chapter 4.7. 
Impact-Producing Factors and Scenario 3-73

3.1.5.1.7 Deck Drainage

Deck drainage includes all wastewater resulting from platform washings, deck washings, 

rainwater, and runoff from curbs, gutters, and drains, including drip pans and work areas. The 

USEPA’s general guidelines for deck drainage require that no free oil be discharged, as determined 

by visual sheen.

The quantities of deck drainage vary greatly depending on the size and location of the 

facility. An analysis of 950 GOM platforms during 1982-1983 determined that deck drainage 

averaged 50 bbl/day/platform (USEPA, 1993a). The deck drainage is collected, the oil is separated, 

and the water is discharged to the sea.

3.1.5.1.8 Treated Domestic and Sanitary Wastes

Domestic wastes originate from sinks, showers, laundries, and galleys. Sanitary wastes 

originate from toilets. For domestic waste, no solids or foam may be discharged. In addition, the 

discharge of all food waste within 12 nmi (14 mi; 22 km) from the nearest land is prohibited. In 

sanitary waste, floating solids are prohibited. Facilities with 10 or more people must meet the 

requirement of total residual chlorine greater than 1 mg/L and maintained as close to this 

concentration as possible. There is an exception in both general permits for the use of marine 

sanitation devices.

In general, a typical manned platform would discharge 35 gallons/person/day of treated 

sanitary wastes and 50-100 gallons/person/day of domestic wastes (USEPA, 1993a). It is assumed 

that these discharges are rapidly diluted and dispersed.

3.1.5.1.9 Minor/Miscellaneous Discharges

Minor and miscellaneous discharges include all other discharges not already discussed that 

may result during oil and gas operations. Minor or miscellaneous wastes may include desalination 

unit discharge, blowout preventer fluid, boiler blowdown, excess cement slurry, uncontaminated 

freshwater and saltwater, and miscellaneous discharges at the seafloor, such as subsea wellhead 

preservation and production control fluid, umbilical steel tube storage fluid, leak tracer fluid, and riser 

tensioner fluids. These discharges are regulated by the USEPA Region 4 and Region 6 NPDES 

permits. In all cases, no free oil shall be discharged with the waste. Unmanned facilities may 

discharge uncontaminated water through an automatic purge system without monitoring for free oil. 

The discharge of freshwater or seawater that has been treated with chemicals is permitted providing 

that the prescribed discharge criteria are met.

3.1.5.2 Operational Wastes and Discharges Generated by Service Vessels

Service vessels are discussed in Chapter 3.1.4.3. Discharges from supply/service vessels 

equal to or greater than 79 ft (24 m) in length are regulated by the U.S. Environmental Protection 

Agency’s NPDES under the Vessel General Permit (VGP). The Final 2013 VGP was issued on 

March 28, 2013, became effective on December 19, 2013, and expires on December 19, 2018 
3-74 Gulf of Mexico Multisale EIS

(USEPA, 2013a). The Final 2013 VGP regulates 26 specific discharge categories, including numeric 

ballast-water discharge limits for most vessels, and ensures that ballast-water treatment systems are 

functioning correctly.

Discharges incidental to the normal operation of nonmilitary, nonrecreational vessels less 

than 79 ft (24 m) (i.e., "small vessels"), operating in a capacity as a means of transportation, are 

regulated under the Small Vessel General Permit (sVGP). The Final 2014 sVGP was issued on

September 10, 2014, became effective on December 19, 2014, and will expire on December 18, 

2019 (USEPA, 2014a). The USEPA issued the sVGP in anticipation of the December 18, 2014, 

expiration date of the then-existing moratorium on permitting small vessels, which specified that 

neither the USEPA nor the States may require NPDES permits, other than for ballast water, for 

incidental discharges from these small vessels. However, on December 18, 2014, President Obama 

signed into law the Howard Coble Coast Guard and Maritime Transportation Act of 2014, which 

extended that moratorium until December 18, 2017. Ballast-water discharges from small vessels still 

require NPDES permit coverage under the sVGP.

Operational wastes generated from supply/service vessels that support OCS oil- and gasrelated operations include bilge and ballast waters (Chapter 3.1.5.1.5), trash and debris (Chapter 

3.2.7), and sanitary and domestic wastes (Chapter 3.1.5.1.8). 

Bilge water is water that collects in the lower part of a ship. The bilge water is often 

contaminated by oil that leaks from the machinery within the vessel. The discharge of any oil or oily 

mixtures is prohibited under 33 CFR § 151.10; however, discharges may occur in waters greater 

than 12 nmi (14 mi; 22 km) from land if the oil concentration is less than 100 ppm. Discharges may 

occur within 12 nmi (14 mi; 22.5 km) of land if the concentration is less than 15 ppm.

Ballast water is used to maintain stability of the vessel and may be pumped from coastal or 

marine waters. Generally, the ballast water is pumped into and out of separate compartments and is 

not usually contaminated with oil; however, the same discharge criteria apply as for bilge water 

(33 CFR § 151.10). Ballast water discharged from ships is one of the pathways for the introduction 

and spread of aquatic nuisance species. To address this issue, USCG’s ballast-water discharge 

standard final rule, which was published on March 23, 2012 (Federal Register, 2012) and became

effective on June 21, 2012, established a standard for the allowable concentration of living 

organisms in ballast water discharged from ships in U.S. waters.

The discharge of trash and debris is prohibited (33 CFR §§ 151.51-151.77) unless it is 

passed through a comminutor and can pass through a 25-millimeter (mm) (1-in) mesh screen. All 

other trash and debris must be returned to shore for proper disposal with municipal and solid waste.

All vessels with toilet facilities must have a marine sanitation device that complies with 

40 CFR part 140 and 33 CFR part 159. Vessels complying with 33 CFR part 159 are not subject to 

State and local marine sanitation device requirements. However, a State may prohibit the discharge 

of all sewage within any or all of its waters. Domestic waste consists of all types of wastes
Impact-Producing Factors and Scenario 3-75

generated in the living spaces on board a ship, including gray water that is generated from 

dishwasher, shower, laundry, bath, and washbasin drains. Gray water from vessels is not regulated 

under the NPDES in the Gulf of Mexico. Gray water should not be processed through the marine 

sanitation device, which is specifically designed to handle sewage.

3.1.5.3 Onshore Disposal of Waste and Discharge Generated Offshore or Onshore

3.1.5.3.1 Onshore Disposal of Wastes Generated from OCS Oil- and Gas-Related Facilities

Most wastes, other than produced water and water-based drilling muds and cuttings, are 

regulated by the USEPA and must be transported to shore or reinjected downhole. Additionally, 

wastes may be disposed of onshore because they do not meet permit requirements or because 

onshore disposal is economically advantageous. Wastes that are typically transported to shore 

include produced sand, aqueous fluids such as wash water from drilling and production operations, 

naturally occurring radioactive materials such as tank bottoms and pipe scale, industrial wastes, 

municipal wastes, and other exploration and production wastes (Dismukes, 2010). Most OBF muds 

and some SBF muds are recycled. If the physical and chemical properties of muds degrade, they 

may be disposed of or treated and reused for purposes other than drilling, instead of being recycled. 

Different reuses of treated muds include, among others, fill material, daily cover material at landfills, 

aggregate or filler in concrete, and brick or block manufacturing. The OBF cuttings are disposed of 

onshore or are injected onsite (USEPA, 1999). Both USEPA Regions 4 and 6 permit the discharge 

of SBF-wetted cuttings, provided the cuttings meet the criteria with regard to percent SBF retained, 

PAH content, biodegradability, and sediment toxicity. The SBF is either recycled or transferred to 

shore for regeneration and reuse or disposal. For information on OBF or SBF, refer to Chapter 

3.1.5.1.1. Drill cuttings contaminated with hydrocarbons from the reservoir fluid must be disposed of 

onshore or reinjected.

The USEPA allows treatment, workover, and completion fluids to be commingled with the 

produced-water stream if the combined produced-water/ treatment, workover, and completion 

discharges pass the toxicity test requirements of the NPDES permit. Facilities with less than 

10 producing wells may not have enough produced water to be able to effectively commingle the 

treatment, workover, and completion fluids with the produced-water stream to meet NPDES 

requirements (USEPA, 1993b). Spent treatment, workover, and completion fluid is stored in tanks 

on tending workboats or is stored on platforms and later transported to shore on supply boats or 

workboats. Once onshore, the treatment, workover, and completion wastes are transferred to 

commercial waste-treatment facilities and disposed of in commercial disposal wells. Offshore wells 

are projected to generate an average volume of 200 bbl from either a well treatment or workover job 

every 4 years. Each new well completion would generate about 150 bbl of completion fluid.

Operators are prohibited in the GOM from discharging any produced sands offshore. Cutting 

boxes (15- to 25-bbl capacities), 55-gallon steel drums, and cone-bottom portable tanks are used to 

transport the solids to shore via offshore service vessels. Total produced sand from a typical 

platform is estimated to be 0-35 bbl/day (USEPA, 1993b). Refer to Chapter 3.1.5.1.4 for more 
3-76 Gulf of Mexico Multisale EIS

information on produced sands. Both Texas and Louisiana have State oversight of exploration and 

production waste-management facilities (Veil, 1999).

3.1.5.3.2 Onshore Disposal and Storage Facilities Supporting OCS-Generated Operational 

Wastes

BOEM-funded research by Dismukes et al. (2007) further supports past conclusions that 

existing solid-waste disposal infrastructure is adequate to support both existing and projected 

offshore oil and gas drilling and production needs. Recently, there is a trend toward incorporating 

more innovative methods for waste handling in an attempt to reduce the chance of adverse 

environmental impacts. Some of these innovative methods include hydrocarbon recovery/recycling 

programs, slurry fracture injection, treating wastes for reuse as road base or levee fill, and 

segregating waste streams to reduce treatment time and improve oil recovery (Dismukes, official 

communication, 2011b). Research shows that the volume of OCS-generated waste is closely 

correlated with the level of offshore drilling and production activity. For each alternative (A, B, C, 

or D), existing onshore facilities would continue to be used to dispose of wastes generated offshore. 

However, no new disposal facilities are expected to be licensed as a direct result of Alternative A, B, 

C, or D. There is no current expectation for new onshore waste disposal facilities to be authorized 

and constructed during the 2017-2066 period as a direct result of each alternative (A, B, C, or D). If 

needed, existing facilities may undergo expansion, but no new disposal facilities are expected.

3.1.5.3.3 Discharges from Onshore Support Facilities

The primary onshore facilities that support offshore oil- and gas-related activities include 

service bases, helicopter hubs at local ports/service bases, construction facilities (i.e., platform 

fabrication yards, pipeyards, and shipyards), processing facilities (i.e., refineries, gas processing 

plants, and petrochemical plants), and terminals (i.e., pipeline shore facilities, barge terminals, and 

tanker port areas). Water discharges from these facilities are from either point sources, such as a 

pipe outfall, or nonpoint sources, such as rainfall run-off from paved surfaces. The USEPA or the 

USEPA-authorized State program regulates point-source discharges as part of the NPDES. 

Facilities are issued general or individual permits that limit discharges specific to the facility type and 

the waterbody receiving the discharge. Other wastes generated at these facilities are handled by 

local municipal and solid-waste facilities, which are also regulated by the USEPA or an USEPAauthorized State program. 

3.1.6 Decommissioning and Removal Operations

During exploration, development, and production operations, the seafloor around activity 

sites within a proposed lease sale area becomes the repository of temporary and permanent 

equipment and structures. Regulations and processes related to structure and site clearance are 

discussed in Appendix A.13. The structures are generally grouped into two main categories 

depending upon their relationship to the platform/facilities (i.e., piles, jackets, caissons, templates, 

mooring devises, etc.) or the well (i.e., wellheads, casings, casing stubs, etc.).
Impact-Producing Factors and Scenario 3-77

A varied assortment of severing devices and methodologies has been designed to cut 

structural targets during the course of decommissioning activities. These devices are generally 

grouped and classified as either nonexplosive or explosive, and they can be deployed and operated 

by divers, ROVs, or from the surface. Which severing tool the operators and contractors use takes 

into consideration the target size and type, water depth, economics, environmental concerns, tool 

availability, and weather conditions.

Nonexplosive severing tools are used on the OCS for a wide array of structure and well 

decommissioning targets in all water depths. Based on 10 years of historical data (1994-2003), 

nonexplosive severing is employed exclusively on about 58 (~37%) removals per year (USDOI, 

MMS, 2005). Since many decommissionings use both explosive and nonexplosive technologies 

(prearranged or as a backup method), the number of instances may be much greater. Common 

nonexplosive severing tools consist of abrasive cutters (e.g., sand cutters and abrasive water jets), 

mechanical (carbide) cutters, diver cutting (e.g., underwater arc cutters and the oxyacetylene/oxyhydrogen torches), and diamond wire cutters.

With the exception of minor air and water quality concerns (i.e., exhaust from support 

equipment and toxicity of abrasive materials), nonexplosive severing tools generally cause little to no 

environmental impacts; therefore, there are very few regulations regarding their use. However, the 

use of nonexplosive cutters leads to greater human health and safety concerns, primarily because 

(1) divers are often required in the methodology (e.g., torch/underwater arc cutting and external tool 

installation and monitoring), (2) more personnel are required to operate them (increasing their risks 

of injury in the offshore environment), (3) lower success rates require that additional cutting attempts 

be made, and (4) the cutters can only sever one target at a time, taking on average 30 minutes to 

several hours for a complete cut (USDOI, MMS, 2005). The last two items are often hard to quantify 

and to assign risks to the cutters, but the main principle is that there is a linear relationship between 

the length of time any offshore operation is staged and on-site (exposure time) and the potential for 

an accident to occur (Twachtman, Snyder, & Byrd, Inc. and Louisiana State University, Center for 

Energy Studies, 2004). Therefore, even if there are no direct injuries or incidents involving a diver or 

severing technicians, the increased “exposure time” needed to successfully sever all necessary 

targets could result in unrelated accidents involving other barge/vessel personnel.

Explosive severance tools can be deployed on almost all structural and well targets in all 

water depths. Historically, explosive charges are used in about 98 (~63%) decommissioning

operations annually (USDOI, MMS, 2005), often as a back-up cutter when other methodologies 

prove unsuccessful. Explosives work to sever their targets by using (1) mechanical distortion 

(ripping), (2) high-velocity jet cutting, and (3) fracturing or “spalling.”

Mechanical distortion is best exhibited with the use of explosives such as standard and 

configured bulk charges. If the situation calls for minimal distortion and an extremely clean severing, 

then most contractors rely upon the jet-cutting capabilities of shaped charges. In order to “cut” with 

these explosives, the specialized charges are designed to use the high-velocity forces released at 

detonation to transform a metal liner (often copper) into a thin jet that slices through its target. The 
3-78 Gulf of Mexico Multisale EIS

least used method of severing currently in use on the Gulf of Mexico OCS is fracturing, which uses a 

specialized charge to focus pressure waves into the target wall and use refraction forces to spall or 

fracture the steel on the opposing side (NRC, 1996).

In water depths >800 m (2,625 ft), OCS regulations offer the lessees the option to avoid the 

jetting by requesting alternate removal depths for well abandonments (30 CFR § 250.1716(b)(3)) 

and facilities (30 CFR § 250.1728(b)(3)). Above mudline cuts would be allowed for depths >800 m 

(2,625 ft), with reporting requirements on the remnant’s description and height off of the seafloor to 

BOEM; this is data necessary for subsequent reporting to the U.S. Navy. With the exception of 

several dynamically positioned vessels, deepwater drilling operations most often use moored 

semisubmersibles. Coupled with the growing number of TLPs, spars, and MODUs, operators and 

contractors have to contend with new demands for quick-disconnect and line severing tools that may 

be necessary during emergencies and decommissioning operations when the anchor cannot be 

retrieved. 

Some of the mooring systems used in deepwater operations have quick-disconnect 

technology built into their designs. Using several varieties of exploding bolts, electromechanical 

couplings, and/or hydraulic-actuated connections, these release mechanisms can be controlled from 

the vessel and triggered on short notice. In situations where the mooring system disconnects were 

not employed or become disabled, severing contractors have several mechanical and explosive 

cutting tools at their disposal for shearing cables, lines, and chains from their moorings. Mechanical 

cutters such as wheel and guillotine saws, hydraulic shears, and diamond wire cutters can be 

deployed using ROVs, allowing the cuts to be performed as close to the anchors as possible. In 

much the same way, small explosive shaped-charge devices can be positioned onto the mooring 

targets by ROVs. These external cutters are generally designed with hydraulic/electric actuators 

and hinge systems that allow the shaped charge to be “clamped” over the target and then detonated 

after the ROV is removed to a safe distance. Together, these effective severing methods and the 

deep-diving capabilities of the ROVs allow for full recovery of the lines/cables/chains, which could 

present a future hazard to commercial fishing gear and navigation.

After bottom-founded objects are severed and the structures are removed, operators are 

required to use trawling or sonar searches to verify that the site is clear of any obstructions that may 

conflict with other uses. Refer to Appendix A.13 for a more detailed discussion of site-clearance 

processes.
Impact-Producing Factors and Scenario 3-79

The Bureau of Ocean Energy Management, 

Regulation and Enforcement issued NTL 

2010-G05 to establish guidelines for 

decommissioning structures within the 

timeframes established by regulations, 

conditions of approval, and lease instruments. 

Alternative A*: Table 3-2 shows platform removals by water-depth subarea as a result of 

Alternative A. Of the 16-280 production structures estimated to be removed as a result of a 

proposed action under Alternative A, 9-193 production structures (installed landward of the 800-m 

[2,625-ft] isobath) could likely be removed using explosives. While production structures are

removed, it is anticipated that multiple appurtenances or types of equipment (e.g., subsea 

systems, pipelines, umbilical lines, etc.) would not be removed from the seafloor if placed in 

waters exceeding 800 m (2,625 ft) as allowed under certain conditions in 30 CFR § 250. An 

estimate of the well stubs and other various subsea structures that may be removed using 

explosives is not possible at this time. For the purposes of impact assessment, the prudent 

assumption should be that charges used for well severance behave in the same manner and 

produce parameters of the same magnitude as do charges detonated on the bottom in open 

water.

Alternative B*: Table 3-2 shows platform removals by water-depth subarea as a result of 

Alternative B. Of the 14-247 production structures estimated to be removed as a result of 

Alternative B, 7-172 production structures (installed landward of the 800-m [2,625-ft] isobath) 

could likely be removed using explosives. It is anticipated that multiple appurtenances would not 

be removed from the seafloor if placed in waters exceeding 800 m (2,625 ft).

Alternative C*: Table 3-2 shows platform removals by water-depth subarea as a result of 

Alternative C. Of the 9-33 production structures estimated to be removed as a result of Alternative 

C, 4-21 production structures (installed landward of the 800-m [2,625-ft] isobath) could likely be 

removed using explosives. It is anticipated that multiple appurtenances would not be removed 

from the seafloor if placed in waters exceeding 800 m (2,625 ft).

*Alternative D could reduce activity values of the combined Alternative A, B, or C, but it 

may only shift the location of offshore infrastructure and activities farther from sensitive 

topographic zones. Since the ranges given for Alternatives A, B, and C are broad and represent 

the low and high levels of forecasted activity, any reduction of activity from choosing Alternative D 

would still fall within those ranges; therefore, the scenarios do not change when considering 

Alternative D. The potential impacts associated with selecting Alternative D are discussed in 

Chapter 4 under each resource. Refer to Chapter 2.2.2.4 for more information.

3.1.6.1 Structure Age and Idle Iron

Federal regulations require that offshore 

leases be cleared of all structures within 1 year 

after production on the lease ceases, but a 

producing lease can hold infrastructure idle for 

as long as the lease is producing (30 CFR § 

250.112). Refer to Chapter 3.1.6 and 

Appendix A.13 for more information on 

decommissioning. As of 2015, the average age 
3-80 Gulf of Mexico Multisale EIS

of all removed offshore structures was 19 years. Simpler structures like caissons had an average 

lifespan of 17 years when decommissioned, and more complex structures like fixed platforms had an 

average lifespan of 20 years. The average age of all active platforms is 29 years, with some 

platforms from previous lease sales still in production after 60 years (Casselman, 2010). For this 

proposed action, no platforms are expected to be in operation beyond the 50-year analysis period 

(refer to Figure 3.8). Although accidents, storm damage, and unforeseen geological problems may 

cause platforms to be removed early, the discrepancy between the assumed and actual life of 

platforms is probably explained by the end of economic production from the field rather than by 

design or engineering factors unique to each platform. Most of the hurricane-related spills resulted 

from storm damage to older pipelines and other aging infrastructure. Past studies have shown that 

there is a direct relationship between older offshore production facilities and the potential for 

accidents and spills (Pulsipher et al., 1998). It is expected that, in the future, more of these facilities 

would be taken out of production or be replaced as new infrastructure is brought on line. With the 

placement of new infrastructure, combined with the continual updating of safety regulations and 

programs, it is expected future spills would be greatly reduced. More complex operations such as 

mooring, station keeping, riser management, and deepwater well control may complicate operations 

and increase the number of procedures prone to errors and equipment prone to failure. The newest 

platforms incorporate advanced technology about which few data on long-term success or incidents 

have been gathered (USDOI, GS, 2011). Refer to Chapter 3.2 for other accidental events. Any 

infrastructure that is decommissioned and no longer “economically viable,” severely damaged, or 

idle on active leases is considered “idle iron” according to NTL 2010-G05, “Decommissioning 

Guidance for Wells and Platforms.” 

The BSEE’s idle iron policy keeps inactive facilities and structures from littering the Gulf of 

Mexico by requiring companies to dismantle and responsibly dispose of infrastructure after they plug 

nonproducing wells. BSEE enforces these lease agreements primarily for two reasons beyond the 

CFR requirement:

• Environmental Effects – Toppled structures pose a potential environmental 

hazard due to the topsides and the associated equipment, electronics, wiring, 

piping, tanks, etc., that are left on the bottom of the Gulf of Mexico. These items 

pose a financial, safety, and environmental burden, and must be removed from 

the bottom. 

• Safety – Severe weather such as hurricanes have toppled, severely damaged, or 

destroyed the structures associated with oil and gas production. While any 

structure could be destroyed during a hurricane, idle facilities pose an 

unnecessary risk of leaks from wells into the environment and potential damage 

to the ecosystem, passing ships, and commercial fishermen.

The typical life span of a pipeline has been estimated to be 20-40 years, but with current 

corrosion management, that lifetime has been substantially increased. One technique for extending 

the life of a gas pipeline is to coat the inside of the pipe periodically with a corrosion-inhibiting 
Impact-Producing Factors and Scenario 3-81

substance. The coating may be applied as either an aerosol pumped in with the production stream 

or as a liquid “slug” pushed through the pipe with a pig. The slug treatment provides greater 

protection (Cranswick, 2001). Corrosion can lead to major accidents on platforms. In 2011, a 

platform owned by Mariner Energy, about 100 mi (161 km) off the Louisiana shore, was using a 

piece of steel heating equipment that had corroded over its 30-year life, causing it to leak 

hydrocarbons that ignited the platform (Sebastian, 2011). 

Subsea wells, in which the wellhead, Christmas tree, and production-control equipment are 

all located on the seafloor, were introduced in the 1970’s and started to grow especially popular in 

the 1980’s and 1990’s. Older generations of subsea wells had a designed life of 15-20 years, and 

many of those devices are reaching the end of that time span (Holeywell, 2014). 

3.1.6.2 Artificial Reefs

Although BSEE supports and encourages the reuse of obsolete oil and gas structures as 

artificial reefs and is a cooperating agency in implementing the National Artificial Reef Plan, specific 

requirements must be met for a departure to be granted. More information on these regulations and 

processes can be found in Appendix A.15. Structure-removal permit applications requesting a 

departure under the Rigs-to-Reefs Policy undergo technical and environmental reviews. The policy 

document details the minimum engineering and environmental standards that operators/lessees 

must meet to be granted approval to deploy a structure as an artificial reef. Conditions of approval 

are applied as necessary to minimize the potential for adverse effects to sensitive habitat and 

communities in the vicinity of the structure and proposed artificial reef site. Additionally, structures 

deployed as artificial reefs must not threaten nearby structures or prevent access to oil and gas, 

marine mineral, or renewable energy resources.

Routine activities include the decommissioning of structures, but redeployment and reefing is 

considered a State activity. Refer to Chapter 3.3.2.1.2 for more information on artificial reefs. 

3.1.7 Coastal Infrastructure

The following chapters discuss coastal impact-producing factors and provide scenario 

projections for onshore coastal infrastructure that may potentially result from a proposed lease sale 

under Alternative A, B, or C in the 2017-2022 Five-Year Program. Under Alternative D, the number 

of blocks that would become unavailable for lease represents only a small percentage (<4%) of the 

total number of blocks to be offered under Alternative A, B, or C. Therefore, Alternative D could 

reduce offshore infrastructure and activities, but it could only shift the location of offshore 

infrastructure and activities farther from sensitive topographic zones and not lead to a reduction in 

offshore infrastructure and activities. Refer to Chapter 2.2.2.4 for more information on Alternative D. 

This discussion describes the potential need for new facility construction and for expansions at 

existing facilities. A detailed description of the baseline affected environment for land use and 

coastal infrastructure in the GOM can be found in Chapter 4.14.1.1. 
3-82 Gulf of Mexico Multisale EIS

Oil and gas exploration, production, and development activities on the OCS are supported by 

an expansive onshore infrastructure industry that includes large and small companies providing an 

array of services from construction facilities, service bases, and waste disposal facilities to crew, 

supply, and product transportation, as well as processing facilities. It is an extensive and mature 

system providing support for both offshore and onshore oil and gas activities in the GOM region

(Figure 3-11). The extensive presence of this coastal infrastructure is not subject to rapid 

fluctuations and results from long-term industry trends. Existing oil and gas infrastructure is 

expected to be sufficient to handle development associated with a proposed action. Should there be 

some expansion at current facilities, the land in the analysis area is sufficient to handle such 

development.

Impact-producing factors associated with coastal infrastructure include service bases, gas 

processing plants, pipeline landfalls, navigation channels, and waste disposal facilities. Chapter 

3.1.5.1.3 addresses onshore waste disposal. Chapter 3.1.3.3.1 discusses pipeline landfalls. While 

no single proposed lease sale under Alternative A, B, or C is projected to substantially change 

existing OCS-related service bases or require any additional service bases, it would contribute to the 

use of existing service bases. Sufficient land exists to construct a new gas processing plant in the 

unlikely event that one should be needed. However, because the current spare capacity at existing 

facilities should be sufficient to satisfy new gas production, the need to construct a new facility would 

possibly materialize only toward the end of the life of a proposed action. Therefore, BOEM projects 

0-1 new gas processing plants to result from a proposed lease sale under Alternative A, B, or C. 

While a proposed action would contribute to the continued need for maintenance dredging of 

existing navigation channels, a mature network of navigation channels already exists in the analysis 

area; therefore, no new navigation channel construction would be expected as a direct result of a 

proposed lease sale under Alternative A, B, or C (Dismukes, official communication, 2015).

BOEM continuously collects new data and monitors changes in infrastructure demands in 

order to support scenario projections that reflect current and future industry conditions. The scenario 

projections outlined below reflect the already well-established industrial infrastructure network in the 

GOM region and fluctuations in OCS oil- and gas-related activity levels. To prevent underestimating 

potential effects, BOEM makes conservative infrastructure scenario estimates; therefore, a 

projection of between 0 and 1 is more likely to be 0 than 1.
Impact-Producing Factors and Scenario 3-83

Figure 3-11. Onshore Infrastructure. 
3-84 Gulf of Mexico Multisale EIS

The following chapters provide the current trends, or outlook scenario projections, for the 

varied infrastructure categories. The primary sources for all of the information on coastal 

infrastructure and activities presented here are BOEM’s Gulf of Mexico OCS Region’s fact books: 

(1) OCS-Related Infrastructure in the Gulf of Mexico Fact Book (The Louis Berger Group, Inc., 

2004); (2) Fact Book: Offshore Oil and Gas Industry Support Sectors (Dismukes, 2010); and 

(3) OCS-Related Infrastructure Fact Book; Volume I: Post-Hurricane Impact Assessment and 

Volume II: Communities in the Gulf of Mexico (Dismukes, 2011).

3.1.7.1 Construction Facilities

3.1.7.1.1 Platform Fabrication Yards

Facilities where platforms (and drilling rigs) are fabricated are called platform fabrication 

yards. Most platforms are fabricated onshore and then towed to an offshore location for installation. 

When an oil and/or gas discovery occurs, an exploratory drilling rig would be either replaced with, or 

converted to, a production platform assembled at the site using a barge equipped with heavy lift 

cranes. Platform fabrication is highly dependent on the structural nature of the oil and gas industry. 

As oil prices fluctuate, platform fabrication yards adjust accordingly. When oil prices are low, they 

diversify their operations into other marine-related activities or scale back on the overall scope of 

their operations. The variety of diversification strategies may include drilling rig maintenance and 

re-builds, barge or vessel fabrication, dry-docking, or equipment survey.

The existing fabrication yards do not operate as “stand alone” businesses; rather, they rely 

heavily on a dense network of suppliers of products and services. Also, since such a network has 

been historically evolving in the GOM region for many decades, existing fabrication yards possess a 

compelling force of economic concentration to prevent the emergence of new fabrication yards. 

There are 54 platform fabrication yards in the analysis area, with the highest concentration in 

Louisiana at 37 and followed by Texas at 12 (Table 3-5). Given the large size of offshore platforms, 

fabrication yards necessarily span several hundred acres. The location of platform fabrication yards 

is tied to the availability of a navigable channel sufficiently large enough to allow the towing of bulky 

and long structures, such as offshore drilling and production platforms. Thus, platform fabrication 

yards are located either directly along the Gulf Coast or inland along large navigable channels, such 

as the Intracoastal Waterway.

Alternative A, B, C, or D: No new facilities are expected to be constructed as a result of 

Alternative A, B, C, or D. The potential exists for some current yards to close, be bought out, or 

merge over the 50-year analysis period (2017-2066), resulting in fewer active yards in the analysis 

area.

3.1.7.1.2 Shipbuilding and Shipyards

There are several kinds of shipyards throughout the Gulf Coast region that build and repair 

all manner of vessels, many of which are not related to OCS oil- and gas-related activities. These 

marine vessels are perhaps the most important means of transporting equipment and personnel 
Impact-Producing Factors and Scenario 3-85

from onshore bases and ports to offshore drilling and production structures. The shipbuilding and 

repair industry has struggled over the last few decades. Since the mid-1990’s, there has been some 

industry stabilization, but the outlook for shipbuilding and shipyards is uncertain. The industry is 

overly dependent on military contracts and faces numerous economic challenges, such as the lack 

of international competitiveness, workforce development challenges, availability of capital, and the 

lack of research and development funding. In the GOM region, there is a direct correlation between

OCS oil- and gas-related activities and the demand or opportunities for expanding shipbuilding and 

offshore support vessels. There are 137 shipyards located within the analysis areas (Table 3-5). To 

a great extent, growth would be based on a successful resolution of several pertinent issues that 

have affected and continue to affect shipbuilding in the U.S. and particularly in the analysis area: 

maritime policy; declining military budget; foreign subsidies; USCG regulations; Oil Pollution Act of 

1990; financing; and an aging fleet. Generally, as oil and gas drilling and production increase, the 

demand for an expanded shipbuilding effort also increases. However, despite the drop in oil and 

gas prices at the end of 2014 and beginning of 2015, Louisiana-based Bollinger Shipyards began 

construction on four massive dry docks able to service 300-ft (91-m) or larger vessels (Jervis, 2015).

Alternative A, B, C, or D: No new facilities are expected to be constructed as a result of 

Alternative A, B, C, or D. There is more than an adequate supply of shipyard resources in the 

GOM region. Some shipyards may close, be bought out, or merge over the 50-year analysis 

period (2017-2066), resulting in fewer active yards in the analysis area.

3.1.7.1.3 Pipe-Coating Facilities and Yards

Pipe-coating plants generally receive manufactured pipe by rail or water at either their plant 

or pipeyard depending on their inventory capabilities. At the plant, pipes that transport oil and gas 

are coated on the interior and exterior to protect from corrosion and abrasion. There are 

19 pipe-coating plants in the analysis areas (Table 3-5). Pipe-coating facilities receive 

manufactured pipe, which they then coat the surfaces of with metallic, inorganic, and organic 

materials to protect from corrosion and abrasion and to add weight to counteract the water’s 

buoyancy. Two to four sections of pipe are then welded at the plant into 40-ft (12-m) segments. The 

coated pipe is stored (stacked) at the pipe yard until it is needed offshore.

To meet deepwater demand, pipe-coating companies were expanding capacity or building 

new plants before the Deepwater Horizon explosion, oil spill, and response; afterwards, activity 

levels dropped temporarily, then rebounded until the oil price drop and economic downturn of late 

2014/early 2015, resulting in a decrease in OCS activity levels and less demand for pipe-coating 

services. As activity levels fluctuate in the GOM, the demands for pipe-coating services fluctuate 

accordingly.

Alternative A, B, C, or D: No new facilities are expected to be constructed as a result of 

Alternative A, B, C, or D. Current capacity, supplemented by expansions at already existing 

facilities, is anticipated to meet OCS Program demand.
3-86 Gulf of Mexico Multisale EIS

3.1.7.2 Support Facilities and Transportation

3.1.7.2.1 Service Bases and Ports

A service base is a community of businesses that load, store, and supply equipment, 

supplies, and personnel needed at offshore work sites. A service base may also be referred to as a 

supply base or terminal and may be associated with a port. A proposed lease sale under Alternative 

A, B, or C is expected to utilize only those ports that currently have facilities used by the oil and gas 

industry as offshore service bases. Although a service base may primarily serve the adjacent OCS 

planning area and Economic Impact Areas (EIAs) in which it is located, it may also provide 

substantial services for the other OCS planning areas and EIAs. Table 3-11 shows the 50 services 

bases organized by EIA, and Figure 3-9 shows the geographic location of the service bases.

Table 3-11. OCS Oil- and Gas-Related Service Bases. 

State EIA County/Parish

Texas

TX-1 Port Isabel (Cameron) Port Mansfield (Willacy)

TX-2 

Aransas Pass (Nueces)

Bayside (Aransas)

Corpus Christi (Nueces)

Harbor Island (Nueces)

Ingleside (San Patricio)

Port Aransas (Nueces)

Port O’Connor (Calhoun)

Rockport (Aransas)

TX-3 Freeport (Brazoria)

Galveston (Galveston)

Pelican Island (Galveston) Surfside (Harris)

TX-5 Port Arthur (Jefferson)

Sabine Pass (Jefferson)

Louisiana

LA-1 Cameron (Cameron) Grand Chenier (Cameron) Lake Charles (Calcasieu)

LA-3 Amelia (St. Mary)

Bayou Boeuf (St Mary)

Berwick (St. Mary) Cocodrie (Terrebonne)

LA-4 

Amelia (St. Mary)

Bayou Boeuf (St. Mary)

Berwick (St. Mary)

Cocodrie (Terrebonne)

Dulac (Terrebonne)

Fourchon (Lafourche)

Gibson (Terrebonne)

Houma (Terrebonne)

Leeville (Lafourche)

Louisa (St. Mary)

Morgan City (St. Mary)

New Iberia (Iberia)

Patterson (St. Mary)

Theriot (Terrebonne)

Weeks Island (Iberia)

LA-6 Empire (Plaquemines)

Grand Isle (Jefferson)

Harvey (Jefferson)

Hopedale (St. Bernard)

Paradis (St. Charles)

Venice (Plaquemines)

Mississippi MS-1 Pascagoula (Jackson)

Alabama AL-1 Bayou LaBatre (Mobile) Mobile (Mobile) Theodore (Mobile)

Florida FL-1 Panama City (Bay)

EIA = Economic Impact Area.

As the industry continues to evolve, so do the requirements of the onshore support network. 

With advancements in technology, the shore-side supply network would continue to be challenged to 

meet the needs and requirements. The intermodal nature of oil and gas operations gives ports 

(which traditionally have water, rail, and highway access) a natural advantage as ideal locations for 

onshore activities and intermodal transfers (Figure 3-12). Therefore, ports would continue to be a 

vital factor in the total process and must incorporate the needs of the offshore oil and gas industry 

into their planning and development efforts, particularly with regard to determining their future 

investment needs. In this manner, both technical and economic determinants influence the 

dynamics of port development.
Impact-Producing Factors and Scenario

3-87

Figure 3-12. OCS-Related Ports and Waterways in the Gulf of Mexico.
3-88 Gulf of Mexico Multisale EIS

Expansion of some existing service bases is expected to occur to capture and accommodate 

the current and future oil and gas business that is generated by development on the OCS. In early 

2015, for example, Louisiana-based Bollinger Shipyards was constructing four massive dry docks 

able to service 300-plus-foot (91-plus-meter) vessels at Port Fourchon while Schlumberger was 

expanding its Port Fourchon operations (Jervis, 2015). Some channels in and around the service 

bases would need to be deepened and expanded in support of deeper draft vessels and other port 

activities, some of which would be OCS related. Channel depths at most major U.S. ports typically 

range from 35 to 45 ft (11 to 14 m). The current generation of new large ships that service the 

offshore industry requires channels from 45 to 53 ft (14 to 16 m).

Alternative A, B, C, or D: Alternative A, B, C, or D would not change identified service 

bases or require any additional service bases. The OCS oil- and gas-related activities over the 

course of the 50-year analysis period (2017-2067) would continue to contribute to the ongoing 

trend of consolidating activities at specific ports, especially with respect to deepwater activities 

(i.e., Port Fourchon and Galveston).

3.1.7.2.2 Helicopter Hubs

There are 241 identified heliports within the GOM region that support OCS oil- and 

gas-related activities; 118 are located in Texas, 115 in Louisiana, 0 in Florida, 4 in Mississippi, and 

4 in Alabama (Table 3-5). Chapter 3.1.4.4 provides information on helicopter operation projections.

Alternative A, B, C, or D: No new helicopter hubs are projected as a result of a proposed 

lease sale or the OCS Program; however, if activity levels increase, they may expand at current 

locations.

3.1.7.2.3 Tanker Port Areas

The transport of OCS-produced oil from FPSO operations to inside or shore-side facilities 

would be accomplished with shuttle tankers rather than oil pipelines. The following tanker ports 

were identified as destinations for shuttle tankers transporting crude oil from FPSO operations in the 

GOM: Houston or the Louisiana Offshore Oil Port are most likely candidates, followed by possibly 

Corpus Christi, Freeport, and Port Arthur/Beaumont, Texas, although it would be most likely for oil to 

be transported to Port Arthur/Beaumont via pipeline (Dismukes, official communication, 2011a). 

Tankers that offloaded oil from Petrobras’ Cascade Chinook delivered to the following areas: 

Nederland, Texas; Pascagoula, Mississippi; Mobile, Alabama; Port Arthur, Texas; Garyville, 

Louisiana; Houston, Texas; Lake Charles, Louisiana; Saint Rose, Louisiana; Galveston Bar, Texas;

Texas City, Texas; Corpus Christi, Texas; Baton Rouge, Louisiana; the Louisiana Offshore Oil Port;

and Yabucoa, Puerto Rico. Chapter 3.1.4.2 provides BOEM’s current tankering projections. 

Alternative A, B, C, or D: Tanker trips associated with Alternative A, B, C, or D would 

represent a small percentage of annual tanker trips into identified tanker ports. Therefore, no new 

tanker port facilities are projected to result from Alternative A, B, C, or D. 
Impact-Producing Factors and Scenario 3-89

3.1.7.2.4 Barge Terminals

The OCS oil barged from offshore platforms to onshore barge terminals represents a small 

portion of the total amount of oil barged in coastal waters. While there is a tremendous amount of 

barging that occurs in the coastal State waters of the GOM, no estimates exist of the volume of this 

barging that is directly attributable to the OCS industry. Secondary barging of OCS oil often occurs 

between terminals or from terminals to refineries. Oil that is piped to shore facilities and terminals is 

often subsequently transported by barge up rivers, through the Gulf Intracoastal Waterway, or along 

the coast. Chapter 3.1.4.1 provides BOEM’s current barging projections.

Alternative A, B, C, or D: Barging of OCS production is expected to remain stable. No 

major modifications or new barge terminals are expected to be constructed as a direct result of a 

proposed lease sale or OCS Program operations.

3.1.7.2.5 Pipeline Shore Facilities

The term “pipeline shore facility” is a broad term describing the onshore location where the 

first stage of processing occurs for OCS pipelines carrying different combinations of oil, condensate, 

gas, and produced water. Some processing may occur offshore at the platform; only onshore 

facilities are addressed in this discussion. Pipelines carrying only dry gas do not require pipeline 

shore facilities; the dry gas is piped directly to the gas processing plant. Therefore, new pipeline 

shore facilities are projected to only result from oil pipeline landfalls. A pipeline shore facility may 

support one or several pipelines; therefore, new pipeline shore facilities are projected to only result 

from larger pipelines (>12 in; 30 cm). Although older facilities may be located in wetlands, current 

permitting programs prohibit or discourage companies from constructing any new facilities in 

wetlands. Also, it is more cost effective for companies to tie into the existing offshore pipeline 

network. Chapter 3.1.3.3.1 provides BOEM’s current pipeline landfall projections.

Alternative A, B, C, or D: No new pipeline shore facilities are projected as a result of 

Alternative A, B, C, or D, which would represent a small percent of the resources handled by 

existing shore facilities. 

3.1.7.2.6 Waste Disposal Facilities

A variety of different types of wastes are generated by offshore oil and gas exploration and 

production activities along the GOM. Some wastes are common to any manufacturing or industrial 

operation (e.g., garbage, sanitary waste [toilets], and domestic waste [sinks and showers]) while 

others are unique to the oil and gas industry (e.g., drill fluids and produced water). Most waste must 

be transported to shore-based facilities for storage and disposal. In the analysis area, there are 

16 waste disposal facilities in Texas, 29 in Louisiana, 3 each in Mississippi and Alabama, and 2 in 

Florida. Refer to Chapter 3.1.5.3 for more information. 
3-90 Gulf of Mexico Multisale EIS

Alternative A, B, C, or D: No new waste disposal facilities are expected to be constructed 

as a result of Alternative A, B, C, or D. Chapter 3.1.5.3 provides BOEM’s current scenario 

analysis for waste disposal facilities.

3.1.7.2.7 Natural Gas Storage Facilities

Most of the natural gas storage facilities in the GOM region are salt caverns. The 

overwhelming majority of all salt cavern storage facilities operating in the U.S. are located along the 

GOM. Gulf Coast salt caverns account for only 4.2 percent of total U.S. working gas capacity and 

15.5 percent of total U.S. deliverability. In the GOM, Texas has 14 salt cavern sites with 78 billion 

cubic feet per day (Bcf/day) of working gas capacity and Louisiana has 7 sites with 48 Bcf/day of 

working gas capacity, Mississippi has 3 sites with 32 Bcf/day of working gas capacity, and Alabama 

has 1 site with 7 Bcf/day of working gas capacity (USDOE, Energy Information Administration, 

2007). Not all of these facilities are located within the BOEM-defined EIAs. More specifically, there 

are 22 underground natural gas storage facilities in the BOEM-defined EIAs. These facilities total 

165 Bcf/day of working gas capacity.

Alternative A, B, C, or D: No new natural gas storage facilities are projected as a result of 

Alternative A, B, C, or D. Any expansions or new facilities would be the result of onshore rather 

than offshore production.

3.1.7.3 Processing Facilities

The following chapters discuss various processing facilities, i.e., gas processing facilities, 

refineries, and LNG facilities. These are included as the final endpoint for OCS oil and gas; 

however, at the time that OCS product reaches these facilities, it has already been joined with nonOCS product from State waters and onshore activities. The percentage of oil and gas product 

processed by these facilities that actually originated from OCS waters has not been determined and 

is not likely to ever be possible to discover since it is due to a number of factors unrelated to the 

delivery of OCS product, such as downstream demand. Therefore, in contrast to most other 

infrastructure types, scenario projections for processing facilities are inherently limited with no direct 

correlation to OCS oil- and gas-related activities. 

Alternative A, B, C, or D: It is most likely that existing facilities would experience 

equipment switch-outs, upgrades, or expansions to meet increases in demand. The OCS oil- and 

gas-related activities that result from Alternative A, B, C, or D would contribute to the likelihood of 

0-1 new gas processing facilities.

3.1.7.3.1 Gas Processing Plants

All natural gas is processed in some manner to remove unwanted water vapor, solids, and/or 

other contaminants that would interfere with pipeline transportation or marketing of the gas. After 

processing, gas is then moved into a pipeline system for transportation to an area where it is sold. 
Impact-Producing Factors and Scenario 3-91

More than half (54%) of the natural gas processing plant capacity in the U.S. is located along the 

Gulf Coast and is available for supporting Federal offshore production (USDOE, Energy Information 

Administration, 2011). In the GOM region, the majority of gas processing plants are located in 

Louisiana (44) and Texas (39), followed by Alabama (13), Mississippi (1), and Florida (1) 

(Table 3-5). While natural gas production on the OCS shelf (shallow water) has been declining, 

deepwater gas production has been increasing, but not at the same pace. Overall, the combined 

trends of increasing onshore shale gas development, declining offshore gas production, and 

increasing efficiency and capacity of existing gas processing facilities have lowered demands for 

new gas processing facilities along the Gulf Coast. Spare capacity at existing facilities should be 

sufficient to satisfy new gas production for many years, although there remains a slim chance that a 

new gas processing facility may be needed by the end of the 50-year life of a proposed lease sale. 

Expectations for new gas processing facilities being built during the analysis period (2017-2066) are 

dependent on long-term market trends that are not easily predicable over the next 50 years 

(Dismukes, official communication, 2015).

Alternative A, B, C, or D: It is most likely that existing facilities would experience 

equipment switch-outs, upgrades, or expansions to meet increases in demand. The OCS oil- and 

gas-related activities that result from Alternative A, B, C, or D would contribute to the likelihood of 

0-1 new gas processing facilities.

3.1.7.3.2 Refineries

The U.S. Department of Energy’s Energy Information Administration updates national energy 

projections annually, including refinery capacity. Most of the GOM region’s refineries are located in 

Texas and Louisiana (Table 3-5). Texas EIAs contain 20 operable refineries, with an operating 

capacity of over 4.5 MMbbl/day, which is over 25 percent of the total U.S. capacity. Louisiana EIAs 

contain 16 operable refineries, with an operational capacity of over 3.2 MMbbl/day, which is over 

18 percent of the total U.S. capacity (USDOE, Energy Information Administration, 2015c). There 

has been a trend toward constructing simple refineries instead of complex refineries. In the United 

States, the last complex refinery started operating in 1977 in Garyville, Louisiana. In the GOM 

analysis area, a new simple refinery was constructed in 2014 in Galena Park, Texas (USDOE,

Energy Information Administration, 2015d).

Alternative A, B, C, or D: No new facilities are expected to be constructed as a direct 

result of Alternative A, B, C, or D.

3.1.7.3.3 Onshore Liquefied Natural Gas Facilities

The wide variety of pipeline systems and delivery markets makes the GOM attractive for 

LNG developers. Onshore natural gas production has increased to the extent that LNG facilities 

along the GOM are seeking and receiving approval to export natural gas to foreign countries. There 

are six existing LNG import/export terminals in the GOM region—two in Texas, three in Louisiana, 

and one in Mississippi (USDOE, Federal Energy Regulatory Commission, 2015a). There are 
3-92 Gulf of Mexico Multisale EIS

16 proposed LNG export terminals in the GOM region—8 in Texas, 7 in Louisiana, and 1 in 

Mississippi (USDOE, Federal Energy Regulatory Commission, 2015a). Facilities with export 

approval that are under construction are located in Sabine and Hackberry, Louisiana; and Freeport 

and Corpus Christi, Texas. Also approved for export but not yet under construction is Sabine Pass 

Liquefaction in Sabine Pass, Louisiana (USDOE, Federal Energy Regulatory Commission, 2015a). 

In 2014, New Orleans-based Harvey Gulf International Marine began construction of an LNG 

bunkering facility at Port Fourchon, Louisiana. The first of its kind in the United States, the LNG 

facility will provide LNG fuel to the growing supply of LNG-operated vessels servicing the OCS, as 

well as over-the-road vehicles fueled by LNG (Schuler, 2014).

Alternative A, B, C, or D: BOEM projects that expansions at existing facilities and 

construction of new facilities would not occur as a direct result of Alternative A, B, C, or D. Any 

expansions or new facilities would be the result of onshore rather than offshore production.

3.1.7.3.4 Petrochemical Plants

Petrochemical plants are usually located in areas with close proximity to the raw material 

supply (petroleum-based) and multiple transportation routes, including rail, road, and water. Texas, 

New Jersey, Louisiana, North Carolina, and Illinois are the top domestic chemical producing states. 

However, most of the basic chemical production is concentrated along the Gulf Coast where 

petroleum and natural gas feedstock are available from refineries. Of the top 10 production 

complexes in the world, 5 are located in Texas and 1 is located in Louisiana.

Along the Gulf Coast, the petrochemical industry is heavily concentrated in coastal Texas 

and south Louisiana and in various counties along the Alabama, Mississippi, and Florida coasts. 

The vast majority of petrochemical plants in the Gulf region are located along coastal Texas (126) 

and south Louisiana (66). Table 3-5 provides the numerical distribution for each state in the 

analysis area, and Figure 3-11 illustrates the geographical distribution of petrochemical facilities 

across the 133 Gulf counties and parishes within analysis area.

Alternative A, B, C, or D: No new facilities are expected to be constructed as a direct 

result of Alternative A, B, C, or D.

3.1.8 Air Emissions

Section 328(a) of the 1990 Clean Air Act Amendments gives the USEPA air quality

responsibility for the OCS area in the Gulf of Mexico east of 87.5o W. longitude, and BOEM retains 

air quality jurisdiction for OCS operations west of the same longitude in the Gulf of Mexico. In 

addition, Section 328(b) of the Clean Air Act Amendments requires BOEM to assure coordination of 

air-pollution control regulations between emissions in the Gulf of Mexico OCS and emissions in 

adjacent onshore areas. The Clean Air Act Amendments requires the USEPA to set the NAAQS 

and to periodically review and update the standards, as necessary, to ensure they provide adequate 

health and environmental protection. Consequently, there would be a continuing need for emission 
Impact-Producing Factors and Scenario 3-93

inventories and modeling to ensure that the NAAQS are being met, as well as for Coastal Zone 

Management Act and State Implementation Plans planning requirements.

The Outer Continental Shelf Lands Act (43 U.S.C. § 1334(a)(8)) tasks the U.S. Department 

of the Interior to assure that air pollutant emissions from offshore oil and gas exploration, 

development, and production sources do not significantly affect the air quality of any state. In 

particular, BOEM is responsible for determining if air pollutant emissions from offshore oil and gas 

activities in the Gulf of Mexico influence the NAAQS compliance status of Texas, Louisiana, 

Mississippi, Alabama, and Florida. BOEM’s air quality regulations in 30 CFR §§ 550.302, 550.303, 

and 550.304 were promulgated as mandated by Section 5(a)8 of the OCSLA. As previously 

mentioned, Section 328(a) of the Clean Air Act Amendments splits air quality jurisdicition in the GOM 

between BOEM and USEPA, while Section 328(b) of the Clean Air Act Amendments requires BOEM 

to assure coordination of air-pollution control regulations between emissions in the Gulf of Mexico 

and emissions in adjacent onshore areas. To.assess offshore oil- and gas-related activities and 

their associated emissions, BOEM conducted a series of studies. BOEM has published the following 

study documents: in 1995, the Gulf of Mexico Air Quality Study (System Applications International et 

al., 1995); in 2004, the Gulfwide Emission Inventory Study for the Regional Haze and Ozone 

Modeling Effort (Wilson et al., 2004) and the Data Quality Control and Emissions Inventories of OCS 

Oil and Gas Production Activities in the Breton Area of the Gulf of Mexico (Billings and Wilson, 

2004); in 2007, the Year 2005 Gulfwide Emission Inventory Study (Wilson et al., 2007); and in 2010, 

the Year 2008 Gulfwide Emission Inventory Study (Wilson et al., 2010). Due to new and updated 

NAAQS, drilling in deep water, and offshore sources changing because of new technology, BOEM 

continues to update the emissions inventories every 3 years to coincide with the USEPA and State 

agency inventory process. Since the emission inventories also include greenhouse gas emissions, 

OCS operators can use the data to report their greenhouse gas emissions to the USEPA.

To build on the previously conducted studies, BOEM completed the Year 2011 Gulfwide 

Emission Inventory Study (Wilson et al., 2014) with a goal of having a calendar year 2011 inventory 

air pollution emissions for all OCS oil and gas production-related sources in the Gulf of Mexico. 

Pollutants covered in this inventory are the criteria pollutants such as carbon monoxide (CO), 

nitrogen oxides (NOx), particulate matter (PM), and sulfur dioxide (SO2); and volatile organic 

compounds (VOCs), as well as major greenhouse gases such as carbon dioxide (CO2), methane 

(CH4), and nitrous oxide (N2O). Ozone (O3), a criteria pollutant, is formed by photochemical 

reactions of NOx and VOC in the atmosphere. Although ozone is not covered in this inventory, 

ozone precursors (NOx and VOCs) are covered. Lead (Pb), another criteria pollutant, is not covered 

in this inventory due to the lack of credible emission factors for this pollutant. Benzene, toluene, 

ethylbenzene, and xylene (BTEX) is a category of VOCs that occur naturally in crude oil, as well as 

during the process of making gasoline and other fuels from crude oil. Although BTEX is not 

individually addressed in this inventory, VOCs are covered.

The Year 2011 Gulfwide Emission Inventory Study presents a full description of monthly 

activity data from platform and non-platform sources, and it additionally updates those procedures 

used in previous inventories by taking the most recent emission factors from the USEPA and the 
3-94 Gulf of Mexico Multisale EIS

Emission Inventory Improvement Program to develop a comprehensive criteria pollutant and 

greenhouse gas emissions inventory. A Year 2014 Gulfwide Emission Inventory Study, which is 

currently in progress, is built upon previous studies to develop a base year 2014 air pollution 

emissions inventory for all OCS oil and gas production-related sources in GOM. Furthermore, the 

study will cover well stimulation vessels and develop hazard air pollutant emission estimates for 

select oil and natural gas production platform emission sources. Refer to Chapter 4.1 for more 

information.

A Fugitive Emissions Update study, which is in the process of being awarded, would update 

fugitive emission factors, component counts and stream compositions for both shallow water and 

deepwater oil and gas facilities in the Gulf of Mexico Region OCS. Specifically, the objectives are to

update the calculation of fugitive emissions in the OCS emissions inventories by updating the default 

component count to include larger deepwater platforms, to update the default speciation weight 

fractions for total hydrocarbon (THC) emissions by stream type, and to quantify the expected 

methane emissions reductions that would result from replacement of high bleed pneumatic 

controllers with low bleed pneumatic controllers. This study is expected to be complete by 2019.

3.1.8.1 Drilling

Refer to Chapter 3.1.3.1 for the description of drilling operations and activities. Refer to 

Chapter 4.1.2 and Figures 4-9 and 4-10 for emissions in tons per year for criteria pollutants and 

greenhouse gases from these activities. Emissions associated with drilling from OCS oil- and 

gas-related activities are attributed to gasoline, diesel, and natural gas fuel usage in engines such as 

propulsion engines, prime engines, mud pumps, draw works, and emergency power. Pollutants 

emitted during drilling activities include combustion gases (i.e., CO, NOx, PM, SO2, CO2, CH4, and 

N2O), as well as noncombustion sources (i.e., VOCs, PM, and CH4). To understand further how 

emissions criteria pollutants are estimated, refer to NTL 2008-G04, “Information Requirements for 

Exploration Plans and Development Operations Coordination Documents.”

3.1.8.2 Production

Refer to Chapter 3.1.3.1 for the description of production operations and activities. 

Emissions associated with production from OCS oil- and gas-related activities are attributed to 

boilers, diesel engines, combustion flares, fugitives, glycol dehydrators, natural gas engines, 

turbines, pneumatic pumps, pressure/level controllers, storage tanks, cold vents, and others. 

Pollutants emitted during production activities include CO, NOx, PM, SO2, VOCs, CO2, CH4, and 

N2O.

3.1.8.3 Vessel Support Operations and Activities during Offshore Oil and Gas Activities

Refer to Chapter 3.1.4 for the description of vessel support operations and activities during 

OCS oil- and gas-related activities. Emissions associated with support vessels from OCS oil- and 

gas-related activities are attributed to the operations of the primary diesel engine used for propulsion 

and other smaller diesel engines that are used to run generators or small cranes and winches for 
Impact-Producing Factors and Scenario 3-95

loading and unloading the vessels. Pollutants emitted during drilling activities include combustion 

gases (i.e., CO, NOx, PM, SO2, CO2, CH4, and N2O) and VOCs. 

3.1.8.4 Flaring and Venting

The availability of a flare or vent is essential in oil and gas operations, primarily for safety 

reasons. It ensures that associated natural gas can be safely disposed of in emergency and 

shutdown situations.

Flaring is the controlled burning of natural gas and is a common practice in oil and gas 

exploration, production, and processing operations. The burning occurs at the end of a stack or 

boom. Flares generate heat and noise. Pollutants emitted during flaring include CO, NOx, PM, SO2, 

VOCs, CO2, CH4, and N2O.

Venting is the controlled release of unburned gases into the atmosphere in the course of oil 

and gas production operations. In venting, the natural gases associated with oil production are 

released directly into the atmosphere and not burned. Vents produce less noise and are less visible. 

Pollutants emitted during venting include VOCs, CO2, and CH4. 

Flaring and venting can have environmental impacts. Flaring may involve the disposal of 

sweet gas or sour gas. Sweet gas is natural gas that does not contain hydrogen sulfide (H2S) while 

sour gas is natural gas that does contain H2S. Flaring produces predominantly CO2 emissions, while 

venting produces predominantly CH4 emissions. Both carbon dioxide and methane are known as 

greenhouse gases associated with concerns about global warming. The global warming potential of 

a kilogram of methane is estimated to be 21 times that of a kilogram of carbon dioxide when effects

are considered over 100 years. Therefore, flaring is often considered to be the preferred method to 

dispose of natural gas in oil and gas operations. Although the global warming potential of methane 

when compared with carbon dioxide usually suggests that flaring is a more environmentally 

attractive option than venting, neighbors of onshore oil and gas developments prefer venting 

because it is less visible and produces less noise. Flaring and venting systems are used to burn off 

waste gas and surplus gases, and they are also a safety means to protect process equipment, the 

system’s processes, and the environment. Therefore, the activities can be divided into routing 

flaring and venting, and nonroutine (emergency) flaring and venting. Flares usually operate 

continuously; however, some are used only for process upsets. Natural gas discharges via venting 

can be due to routine or emergency releases.

Routine Flaring and Venting

Routine flaring occurs on a regular basis due to the normal operations of a facility. Flares 

can be used routinely to control emissions from storage tanks, loading operations, glycol dehydration 

units, vent collection system, and amine units. Natural gas discharges via venting can be due to 

routine or emergency releases. Vents receive exhaust streams from miscellaneous sources, as well 

as manifold exhaust streams from other equipment on the same platform such as amine units, glycol 

dehydrators, loading operations, and storage tanks.
3-96 Gulf of Mexico Multisale EIS

3.1.8.5 Fugitive Emissions

Fugitive emissions are leaks from sealed surfaces associated with process equipment. 

Leaks can occur from operating conditions (pressure, temperature, etc.), aging, deterioration of 

sealing devices, and equipment solidity. Specific fugitive source types include cold vents; 

hydrocarbon loading and unloading operations; and equipment components such as valves, flanges, 

connectors, pump seals, compressor seals, and open-ended lines. Pollutants emitted from fugitive 

emissions include VOCs and CH4. 

3.1.8.6 Greenhouse Gases

The gases that keep the solar heat budget in the lower atmosphere are called greenhouse 

gases. Naturally, the atmospheric layer close to the Earth surface partially captures the long wave 

radiation from the Sun and keeps the planet habitable. These gases include CO2, CH4, N2O, and a 

variety of manufactured chemicals. Greenhouse gases can be emitted from natural sources; others 

are anthropogenic, resulting from human activities.

In response to the FY 2008 Consolidated Appropriations Act, the USEPA issued 40 CFR 

part 98, which requires reporting of greenhouse gas emissions. Subpart C of the Green House Gas 

Reporting Rule requires operators to report greenhouse gas emissions from general stationary fuel 

combustion sources to the USEPA. Subpart W of the Greenhouse Gas Reporting Rule requires 

petroleum and natural gas facilities that emit 25,000 metric tons or more of CO2 equivalents (CO2e) 

per year to report emissions from equipment leaks and venting. Emissions associated with 

greenhouse gases from OCS oil- and gas-related activities are attributed to the combustion of fossil 

fuel, production and transportation of oil and natural gas, and equipment leaks. Pollutants emitted 

during these activities include CO2, CH4, N2O, and CO2e.

3.1.8.7 Decommissioning

Refer to Chapter 3.1.6 for the description of decommissioning operations and activities. 

Emissions associated with decommissioning from OCS oil- and gas-related activities are attributed 

to the exhaust of diesel engines from the vessels including mobile offshore work-over rigs and lift 

vessels involved in the removal of pipelines and field facilities. Pollutants emitted during 

decommissioning include combustion gases (CO2, NOx, CO, PM, SO2, CH4 and VOCs).

3.1.9 Noise

Noise associated with OCS oil- and gas-related exploration and development results from 

seismic surveys, the installation of structures, the operation of fixed structures such as offshore 

platforms and drilling rigs, the decommissioning and explosive severance of structures, and 

helicopter and service-vessel traffic. Acoustic sources can be described by their sound 

characteristics. For the regulatory process, they are generally divided into two categories: impulsive 

noise and nonimpulsive noise.
Impact-Producing Factors and Scenario 3-97

Impulsive Noise

Impulsive noises (e.g., explosives, airguns, and impact pile drivers) are generally considered 

powerful sounds with relatively short durations, broadband frequency content, and rapid rise times to 

peak levels.

Airguns produce an intense but highly localized sound energy that propagates throughout 

the water column, and they represent a noise source of acoustic concern. BOEM completed the 

Atlantic G&G Activities Programmatic EIS, which includes a detailed description of the seismic 

surveying technologies, energy output, and operations and which has appendices that provide 

details on marine mammal, sea turtle, and fish hearing (USDOI, BOEM, 2014a); these descriptions 

are hereby incorporated by reference.

Deepwater marine seismic surveys (refer to Chapter 3.1.2.1) direct low-frequency energy 

waves (generated by an airgun array) into the ocean floor and record the response of the reflected 

energy waves’ response from the subsurface. The firing times of the guns are staggered by 

milliseconds in an effort to make the farfield noise pulse as coherent as possible. In short, the intent 

of the airgun array is to have it emit a very symmetric packet of energy in a very short amount of 

time and with a frequency content that penetrates well into the earth at a particular location 

(Caldwell, 2001). In some airgun surveys (including WAZ), these sources are activated in sequence 

between source vessels. The noise generated by airguns is intermittent, with pulses generally less 

than 1 second in duration. Airgun arrays produce noise pulses with very high peak levels. The 

pulses are a fraction of a second long and repeat every 10-15 seconds (this range is for all airgun 

arrays). In other words, while airgun arrays are by far the strongest sources of underwater noise 

associated with OCS oil- and gas-related activities, because of the short duration of the pulses, the 

total energy is limited (Gordon and Moscrop, 1996). Acoustic calibration for the National Science 

Foundation’s R/V Marcus Langseth and its seismic array, conducted work by Tolstoy et al. (2009) in 

the GOM, suggests that, for deep water (~5,249 ft; 1,600 m), the 180-decibel (dB) radius would 

occur at less than 0.6 mi (1 km) from the source, while in shallow waters (~164 ft; 50 m), the 180-dB 

radius would be considerably larger (e.g., ~0.7 mi; 1.1 km).

Nonimpulsive Noise

Nonimpulsive noise generally includes all other noise (e.g., sonars and vibratory pile drivers) 

and includes continuous anthropogenic noise (e.g., vessel noise).

Ambient noise is an important aspect to the marine habitat and is an efficient way to transmit 

energy through the ocean; therefore, many marine organisms have evolved to utilize this. It is also 

the sound field against which animal signals must be detected and is a result of both natural and 

anthropogenic noise sources. Anthropogenic noise is generally low-frequency (10 to 500 Hz), 

sea-surface agitation falls within the medium-frequency range (500 Hz to 25 kHz), and 

high-frequency noise (>25 kHz) can be from thermal noise (Hildebrand, 2009). Anthropogenic noise 

is generated by many different activities, including shipping, fishing, boating, research, and activities 

related to oil and gas exploration, development, and production. The activities encompass areas 
3-98 Gulf of Mexico Multisale EIS

that represent important marine habitat (Hildebrand, 2009). The OCS oil- and gas-related noise 

generated from these activities can be transmitted through both air and water, and may be long- or 

short-lived in time, distance, and sound level. The intensity level and frequency of the noise 

emissions are highly variable, both between and among the various types of sound sources. Noise 

from proposed OCS oil- and gas-related activities may affect resources near the activities.

It is generally recognized that commercial shipping is a dominant component of the ambient, 

low- and medium-frequency background noise in modern world oceans (Gordon and Moscrop, 1996) 

and that OCS oil- and gas-related, service-vessel traffic would contribute to this. Another sound 

source more specific to OCS operations originates from seismic operations.

Information on drilling noise in the GOM is unavailable to date. From studies mostly in 

Alaskan waters, drilling operations (these can include pile driving, generators, pumps, etc.) often 

produce noise that includes strong tonal components at low frequencies, including infrasonic 

frequencies in at least some cases. Drillships are noisier than semisubmersibles (Richardson et al., 

1995). Sound and vibration paths to the water are through either the air or the risers, in contrast to 

the direct paths through the hull of a drillship. This sound difference is due to the dynamic 

positioning systems on the drillships as compared with anchored MODUs. Richardson et al. (1995) 

stated that sound was measured at three ring-caisson sites in the Arctic. Sound was measured from 

the 20- to 1,000-Hz band levels at a range of 1.8 km (1.1 mi) at levels of 113-126 dB re: 1μPa 

(decibels referenced 1 microPascal). The received sound levels varied based on the activity of the 

support vessels. These estimated levels were higher than drilling activities on an artificial island but 

lower than on drillships (Richardson et al., 1995).

Machinery noise generated during the operation of fixed structures can be continuous or 

transient, and variable in intensity. Underwater noise from fixed structures ranges from about 20 to 

40 dB above background levels within a frequency spectrum of 30-300 Hz at a distance of 30 m 

(98 ft) from the source (Gales, 1982). These levels vary with type of platform and water depth. 

Underwater noise from platforms standing on metal legs would be expected to be relatively weak 

because of the small surface area in contact with the water and the placement of machinery on 

decks well above the water.

Aircraft and vessel support may further contribute to acoustic pollution around a production 

facility, as well as the transit area. Noise generated from helicopter and service-vessel traffic is 

transient in nature and extremely variable in intensity. Helicopter sounds contain dominant tones 

(resulting from rotors) generally below 500 Hz (Richardson et al., 1995). For example, a Bell 212 

helicopter may operate at a 22-Hz tone and have an estimated received level of 149 dB re: 1μPa 

(Richardson et al., 1995). Differences in the density sound speed of air and water reduce the sound 

that propagates into the water column from the air and generally restrict it to entry angles that are 

within about 11 degrees of perpendicular to the water’s surface. Helicopters often radiate more 

sound forward than backward; thus, underwater noise is generally brief in duration, compared with 

the duration of audibility in the air. In addition to the altitude of the helicopter, water depth and 

bottom conditions strongly influence propagation and levels of underwater noise from passing 
Impact-Producing Factors and Scenario 3-99

aircraft. Lateral propagation of sound is greater in shallow water than in deep water. Helicopters, 

while flying offshore, generally maintain altitudes above 700 ft (213 m) during transit to and from the 

working area and an altitude of about 500 ft (152 m) while between platforms.

Service vessels transmit noise through both air and water. The primary sources of vessel 

noise are propeller cavitation, propeller singing, and rotating machinery; other sources include 

auxiliaries, flow noise from water dragging along the hull, and bubbles breaking in the wake 

(Richardson et al., 1995). Propeller cavitation is usually the dominant noise source (broad band but 

with peak energy in low frequency). The intensity of noise from service vessels is roughly related to 

ship size, laden or not, and speed. Large ships tend to be noisier than small ones, and ships 

underway with a full load (or towing or pushing a load) produce more noise than empty vessels. For 

example, a 16-m (52-ft) crewboat may have a 90-Hz tone with a source level of 156 dB re: 1μPa, 

and a small ship may have a broadband source level of 170-180 dB re: 1μPa (Richardson et al., 

1995). For a given vessel, relative noise also tends to increase with increased speed. Commercial 

vessel noise is a dominant component of manmade ambient noise in the ocean (Jasny, 1999).

Information on the acoustic environment and marine sound can also be found in 

Chapter 4.2.2 of the Five-Year Program EIS.

3.1.10 New and Unusual Technology

Technologies continue to evolve to meet the technical, environmental, and economic 

challenges of deepwater development. BOEM’s predecessor prepared a Programmatic EA to 

evaluate the potential effects of deepwater technologies and operations (USDOI, MMS, 2000b). As 

a supplement to the EA, BOEM’s predecessor prepared a series of reference document that 

provides a profile of the different types of development and production structures that may be 

employed in the GOM deep water (USDOI, MMS, 2000a). The Programmatic EA and technical 

papers were used in the preparation of this Multisale EIS. Additional technologies introduced since 

the publication of the EA in 2000 include WAZ (Chapter 3.1.2.1) and duel-gradient drilling. Duelgradient drilling uses seawater-density fluid in place of the mud that would normally flow through a 

well and uses dense mud at the bottom of the well to maintain bottom-hole pressure. This 

technology allows operators to reach reservoirs 40,000 ft (12,192 m) below the seafloor, a depth that 

is otherwise affected by water depth.

The operator must identify new or unusual technology, as defined in 30 CFR § 550.200, in 

exploration and development plans. Some of the technologies proposed for use by the operators 

are actually extended applications of existing technologies and interface with the environment in 

essentially the same way as well-known or conventional technologies. These technologies are 

reviewed by BOEM for alternative compliance or departures that may trigger additional 

environmental review. Some examples of new technologies that do not affect the environment 

differently and that are being deployed in the regionwide OCS Program are synthetic mooring lines, 

subsurface safety devices, and multiplex subsea controls.
3-100 Gulf of Mexico Multisale EIS

Some new technologies differ in how they function or interface with the environment. These 

include equipment or procedures that have not been installed or used in Gulf of Mexico OCS waters. 

Having no operational history, they have not been assessed by BOEM through technical and 

environmental reviews. New technologies may be outside the framework established by BOEM’s

regulations and, thus, their performance (i.e., safety, environmental protection, efficiency, etc.) has 

not been studied by BOEM. The degree to which these new technologies interface with the 

environment and the potential impacts that may result are considered in determining the level of 

NEPA review that would be initiated if an operator wishes to deploy it.

BOEM has developed a new and unusual technologies’ matrix to help facilitate decisions on 

the appropriate level of engineering and environmental review needed for a proposed technology. 

All projects in the GOM using nonconventional production or completion technology require a 

deepwater operations plan and a review by BSEE. Technologies will be added to the new and 

unusual technologies’ matrix as they emerge, and technologies will be removed as sufficient 

experience is gained in their implementation. From an environmental perspective, the matrix 

characterizes new technologies into three components: technologies that may affect the 

environment; technologies that do not interact with the environment any differently than 

“conventional” technologies; and technologies for which BOEM does not have sufficient information 

to determine its potential impacts to the environment. In this latter case, BOEM would seek to gain 

the necessary information from operators or manufacturers regarding the technologies in order to 

make an appropriate determination on its potential effects on the environment.

Alternative Compliance and Departures: When an OCS operator proposes the use of 

technology or procedures not specifically addressed in established BOEM regulations, the 

operations are evaluated for alternative compliance or departure determination. BOEM, in 

coordination with BSEE’s Technical Assessment Section, conducts a project-specific engineering 

safety review to ensure that equipment proposed for use is designed to withstand the operational 

and environmental condition in which it would operate. Any new technologies or equipment that 

represent an alternative compliance or departure from existing BOEM regulation must be fully 

described and justified before it would be approved for use. For BOEM to grant alternative 

compliance or departure approval, the operator must demonstrate an equivalent or improved degree 

of protection as specified in 30 CFR § 550.141. Comparative analysis with other approved systems, 

equipment, and procedures is one tool that BOEM uses to assess the adequacy of protection 

provided by alternative technology or operations. Actual operational experience is necessary with 

alternative compliance measures before BOEM/BSEE would consider them as proven technology.

In addition to new and unusual technology for drilling, as a result of the Deepwater Horizon

explosion, oil spill, and response, many technologies or applications were developed in an attempt to 

stop the spill and cap the well in any future accidents. The NTL 2010-N10, “Statement of 

Compliance with Applicable Regulations and Evaluation of Information Demonstrating Adequate 

Spill Response and Well Containment Resources,” applies to operators conducting operations using 

subsea BOPs or surface BOPs on floating facilities. BOEM would assess whether each lessee has 

submitted adequate information demonstrating that it has access to and can deploy surface and 
Impact-Producing Factors and Scenario 3-101

subsurface containment resources that would be adequate to promptly respond to a blowout or other 

loss of well control. Containment resources could consist of, but are not limited to, subsea 

containment and capture equipment including containment domes and capping stacks, subsea utility 

equipment including hydraulic power, hydrate control, and dispersion injection equipment. 

3.2 IMPACT-PRODUCING FACTORS AND SCENARIO—ACCIDENTAL EVENTS

3.2.1 Oil Spills

As a consequence of activities related to the exploration, 

development, production, and transportation of oil and gas, the potential for 

accidental releases exists. Input through public scoping meetings, Federal 

and State agency consultation and coordination, and industry and 

nongovernmental organizations’ comments indicate that stakeholders continue to have concerns 

about oil spills and the threat they pose to the environment. Although oil-spill occurrence cannot be 

predicted, an estimate of its likelihood can be quantified using spill rates derived from historical data 

and projected volumes of oil production and transportation. The following chapters discuss the 

history of oil spills in the GOM, the processes that affect spilled oil, and a risk analysis for spills that 

may be reasonably foreseeable as a result of Alternative A, B, C, or D, as well as information on the 

number and size of spills from non-OCS oil- and gas-related sources. Under Alternative D, the 

number of blocks that would become unavailable for lease represents only a small percentage (<4%) 

of the total number of blocks to be offered under Alternative A, B, or C. Therefore, Alternative D 

could reduce offshore infrastructure when chosen in conjunction with Alternative A, B, or C, but it

could only shift the location of offshore infrastructure and activities farther from sensitive topographic 

zones and not lead to a reduction in offshore infrastructure and activities. Refer to Chapter 2.2.2.4

for more information on Alternative D. For an analysis of a low-probability catastrophic spill, which is 

not reasonably foreseeable as a result of a proposed action or the alternatives, refer to the 

Catastrophic Spill Event Analysis white paper (USDOI, BOEM, 2017) and Chapter 3.4 of the 

Five-Year Program EIS. 

3.2.1.1 Past OCS Spills

3.2.1.1.1. Trends in Reported Spill Volumes and Numbers

A summary of reported spill incidents is available from USCG in a report entitled Polluting 

Incidents In and Around U.S. Waters, A Spill/Release Compendium: 1969-2011 (USDHS, CG, 

2012). The data include reports of all releases involving oil and hazardous substances from various 

sources, including barges, tanks, pipelines, and waterfront facilities. A review of the information 

shows that the majority of spills are ≤1 bbl. While all spills must be reported to USCG through the 

National Response Center, BSEE’s regulations require that all OCS spills ≥1 bbl from an operator’s 

facility must also notify the Regional Supervisor (30 CFR § 254.46). In addition, all spills ≥50 have 

additional reporting requirements and in some cases are followed up by incident investigations. A 

recent report prepared by ABS Consulting, Inc. (2016) examined the occurrence rates for offshore oil 

spills and gathered data from a variety of sources including BSEE, USCG, and DOT’s Pipeline and 
3-102 Gulf of Mexico Multisale EIS

Hazardous Material Safety Administration. The report focused on all spills ≥1 bbl from offshore 

platforms, offshore pipelines, tankers, and barges. Figure 3-13 shows the number of oil spills ≥1 bbl 

that have occurred in the GOM and Figure 3-14 shows the total volume (bbl) of oil spilled for spills 

≥1 bbl in the GOM for the period 2001 through 2015. 

The study examined a number of causal factors including equipment failure, human error, 

weather/natural causes, and other/external factors. Spills from offshore production platforms and 

drilling rigs revealed two notable trends. First, hurricanes have had a substantial impact on the total 

number and volume of spills, as can be seen in Figures 3-13 and 3-14. Second, the dominant 

driver of reduced spill rates is likely a reduction in equipment failures as the number of events has 

steadily decreased since 1975, suggesting that technology advancements have played a large role 

in the improving spill rates. The analysis also examined additional causal factors related to pipeline

spills, including corrosion and vessel/anchor/trawl damage. The analysis reveals that, like platform 

spills, hurricanes have had a substantial impact on spill frequency and spill volume. The results also 

showed that the number of operational spills per year appears to follow a downward trend as the 

majority of pipeline spills in the last 15 years were caused by hurricanes (ABS Consulting, Inc., 

2016). Figures 3-15 and 3-16 show the relative contribution from offshore platforms versus offshore 

pipelines.

Figure 3-13. Number of Oil Spills ≥1 bbl That Have Occurred in the Gulf of Mexico for the Period 

2001 through 2015.
Impact-Producing Factors and Scenario 3-103

Figure 3-14. Total Volume (bbl) of Oil Spilled in Gulf of Mexico Waters for Spills ≥1 bbl for the Period 

2001 through 2015. (Notes: In 2005, the integrated tug-barge unit comprised of the 

tugboat Rebel and the double-hull tank barge DBL 152 struck the submerged remains 

of a pipeline service platform that previously collapsed during Hurricane Rita, releasing 

an estimated 45,846 bbl (1,925,532 gallons) of oil. In 2010, the Deepwater Horizon

explosion and oil spill released approximately 4,900,000 bbl (205,800,000 gallons) of 

oil over 87 days.) 
3-104 Gulf of Mexico Multisale EIS

Figure 3-15. Number of Platform and Pipeline-Related Oil Spills ≥1 bbl That Have Occurred in the 

Gulf of Mexico for the Period 2001 through 2015. 
Impact-Producing Factors and Scenario 3-105

Figure 3-16. Total Volume of Spilled Oil for Platform and Pipeline-Related Oil Spills ≥1 bbl That 

Have Occurred in the Gulf of Mexico for the Period 2001 through 2015.

In response to the damages sustained to oil and gas infrastructure as a result of hurricanes, 

the MMS (now BOEM and BSEE) imposed more stringent design and assessment criteria for both 

new and existing structures in the GOM. The rule incorporates three API bulletins to help increase 

survivability during hurricane conditions and reduce the number of damaged platforms, including 

(1) guidance for design and operation of MODU mooring systems; (2) recommendations to siting 

jackup MODUs and to recommend certain operational procedures to enhance jackup survivability 

and stationkeeping during drilling, workover, and while stacked (idled) at a non-sheltered location;

and (3) guidance to improve tie-down performance.

Oil-Spill Occurrence Rates

Previous work by Anderson and LaBelle (1990, 1994, and 2000) provided estimates of oilspill occurrence rates expressed and normalized in terms of the number of spills per volume of crude 

oil handled. This work was updated in Anderson et al. (2012) and utilized United States’ OCS 

platform and pipeline spill data from 1964 through 2010. Platform and pipeline spills included both 

crude oil and condensate, but platform spills may also include refined products such as diesel fuel. 

The report utilized the spill record from 1964 through 2010 but also examined shorter intervals to 
3-106 Gulf of Mexico Multisale EIS

identify trends and also to show how the Deepwater Horizon explosion, oil spill, and response 

influenced the spill statistics. The report notes several additional factors that have influenced spill 

rates, including six highly destructive hurricanes between 2002 and 2008 that destroyed or 

extensively damaged 305 platforms, 76 drilling rigs, and over 1,200 pipeline segments, and the 

inclusion of “passive spills” or petroleum missing based on pre-storm platform inventories. 

Recently, BSEE contracted ABS Consulting, Inc. (2016) to update the occurrence rates for 

offshore oil spills based on the previous work by Anderson and LaBelle (1990, 1994, and 2000) and 

Anderson et al. (2012) (Table 3-12). The report uses the most recent available data since the prior 

report to calculate rates consistent with current trends. When comparing the most recent 15 years of 

data (2001 through 2015) to the 1996 through 2010 rates in Anderson et al. (2012), platform spill 

rates remained at 0.25 spills per Bbbl for spills ≥1,000 bbl and 0.13 spills per Bbbl for spills 

≥10,000 bbl. Spill rates for OCS pipelines dropped from 0.88 to 0.38 spills per Bbbl for spills 

≥1,000 bbl and from 0.18 to 0.07 spills per Bbbl for spills ≥10,000 bbl.

Table 3-12. Spill Rates for Petroleum Spills ≥1,000 Barrels from OCS Platforms and Pipelines, 

1964 through 2010.

Spill 

Size and 

Source

Previous Rate, 1964-20101 Revised Rate, 1996-20101 Current Rate, 2001-20152

Volume 

Handled 

(Bbbl)

Number 

of Spills

Spill 

Rate

Volume 

Handled 

(Bbbl)

Number 

of Spills

Spill 

Rate

Volume 

Handled 

(Bbbl)

Number 

of Spills

Spill 

Rate

≥1,000 bbl

Platforms 15.8 of 18.1 5 of 13 0.32 8.0 2 0.25 8.0 2 0.25

Pipelines 9.6 of 18.1 9 of 20 0.94 8.0 7 0.88 8.0 3 0.38

≥10,000 bbl

Platforms 15.8 of 18.1 1 of 5 0.06 8.0 1 0.13 8.0 1 0.13

Pipelines 9.6 of 18.1 – 0.19 8.0 – 0.18 8.0 – 0.07

1

Anderson et al., 2012. 2

ABS Consulting, Inc., 2016.

3.2.1.1.2 Coastal Spills 

Coastal spills are defined here as spills in State offshore waters from barges and pipelines

carrying OCS-produced oil. These spills may occur at shoreline storage, processing, and transport 

facilities supporting the OCS oil and gas industry and could be spills of crude oil or spills of fuel oil 

used in vessels. Many reports of spills cannot be traced back to the source or type of oil and are 

recorded as unknown. Similarly, for these small spills of unknown oil, the volume is also likely to be 

an estimate. Records of spills in coastal waters or State offshore waters are maintained by USCG 

(USDHS, CG, 2016). The source may be recorded, for example, as an offshore pipeline, but the 

database does not identify the source of the oil in the pipeline (OCS versus non-OCS domestic). A 

pipeline carrying oil from a shore base to a refinery may be carrying oil from both State and OCS 

production; imported oil might also be commingled in the pipeline. The USCG also records the type 

of oil spilled and whether it is crude oil, a refined product such diesel fuel or heavy fuel oil, or a type 

of commodity in transport, such as vegetable oil. The USCG data have some shortcomings that 
Impact-Producing Factors and Scenario 3-107

should be noted. For spills of unknown source, the caller may guess as to what type of oil, crude, or 

fuel was released. The database includes a latitude and longitude GPS (global positioning system) 

position for each spill, as well as a verbal description of location. The verbal description may not 

match the position. For example, the verbal description could be Mississippi Sound, but the GPS 

position is actually on the OCS. For this report, the GPS position was used, not the verbal 

description of the location.

BOEM pays special attention to spills related to exploration and production that occur on 

Federal leases in OCS waters, i.e., the submerged lands, subsoil, and seabed lying between the 

seaward extent of the State’s jurisdiction and the seaward extent of Federal jurisdiction. BOEM 

does not maintain comprehensive data on spills that have occurred in the State’s jurisdiction. 

Although BSEE has occasionally collected information on State pollution incidents, there is no 

database available that contains only past spills that have occurred in State offshore or coastal 

waters solely and directly as a result of OCS oil and gas development.

Therefore, coastal spill data from all potential spillage sources were searched using USCG’s

database for the most recent 13 years, January 2002-April 2015 (USDHS, CG, 2016) in order to 

obtain information on spills that have occurred in State offshore or coastal waters, most probably as 

a result of oil and gas development. In order to search the data, USCG’s data were examined using 

the latitude and longitude provided in the spill report, which resulted in some of the reported 

locations that fell inland or outside of the GOM being omitted. Some broad assumptions were made 

in the use of these data. State offshore waters and coastal waters are defined here as the portion of 

the GOM under State jurisdiction that begins at the coastline and ends at the Federal/State 

boundary 9 nmi (10.36 mi; 16.67 km) offshore Texas; 3 nmi (3.5 mi; 5.6 km) offshore Louisiana, 

Mississippi, and Alabama; and 9 nmi (10.36 mi; 16.67 km) offshore Florida. The number of GOM 

coastal spills from five sources associated with State or Federal offshore production and 

international importation was determined from the data (Table 3-13). Louisiana and Texas have 

extensive oil and gas activity occurring in their territorial seas, as well as in Federal waters on the 

OCS. The sources that were counted are fixed platforms, MODUs, OSVs, offshore pipelines, and 

tank ships or barges. Although counts for tank ships and barges are shown as sources, the amount 

of barged and tankered GOM oil production is limited; therefore, these numbers are conservatively 

high as they include all of the oil tankered or barged. BOEM shows that 96 percent of OCS oil- and 

gas-related activity spills are <1 bbl, with an average size of 0.05 bbl, and that 4 percent of OCS 

oil- and gas-related activity spills are < 999 bbl, with an average size of 77 bbl (Anderson et al., 

2012).
3-108 Gulf of Mexico Multisale EIS

Table 3-13. Historic Spill Source, Location, and Characteristics of a Maximum Spill for Coastal Waters1

(data extracted from USDHS, CG records, 2002-July 2015)

2

. 

Source

Number of Spills Maximum Volume of a Single Incident

Total 

Number of 

Spill Events

Number 

of Spills 

(<1,000 bbl)

Number 

of Spills 

(≥1,000 bbl)

Volume (bbl) of 

Maximum Spill 

from the Source 

Maximum Spill Amount 

Product/Year

Western Planning Area (WPA)2

Fixed Platform 147 147 0 7.62 Crude/2005

Pipeline 0 0 0 N/A N/A

MODU 2 2 0 4 Crude/2002

OSV 1 1 0 0.05 Crude/2014

Tank Ship or 

Barge 5 5 0 23.8 Crude/2009

Total 155 155 0 – –

Central Planning Area (CPA)2

Fixed Platform 2,398 2,398 0 300 Crude/2004

Pipeline 4 4 0 5 Crude/2002

MODU 28 27 1 4,928,100 Crude/2010

OSV 7 7 0 0.07 Crude 2014

Tank Ship or 

Barge 6 6 0 2 Crude/2013

Total 2,443 2,442 1 – –

Eastern Planning Area (EPA)2

Fixed Platform 0 0 0 N/A N/A

Pipeline 0 0 0 N/A N/A

MODU 0 0 0 N/A N/A

OSV 0 0 0 N/A N/A

Tank Ship or 

Barge 0 0 0 N/A N/A

Total 0 0 0 – –

Coastal Waters: Texas

Fixed Platform 67 67 0 20 Crude/2002

Pipeline 14 14 0 10 Crude/2005

MODU 5 5 0 0.48 Crude/2002

OSV 2 2 0 0.05 Crude/2003

Tank Ship or 

Barge 3 3 0 0.36 Crude/2009

Total 91 91 0 – –
Impact-Producing Factors and Scenario 3-109

Source

Number of Spills Maximum Volume of a Single Incident

Total 

Number of 

Spill Events

Number 

of Spills 

(<1,000 bbl)

Number 

of Spills 

(≥1,000 bbl)

Volume (bbl) of 

Maximum Spill 

from the Source 

Maximum Spill Amount 

Product/Year

Coastal Waters: Louisiana

Fixed Platform 2,022 2,021 1 1,200 Crude/2008

Pipeline 98 97 1 7,000 Crude/2008

MODU 4 4 0 0.24 Crude/ 2013

OSV 17 17 0 3 Crude/2013

Tank Ship or 

Barge 2 2 0 50 Crude/2002

Total 2,143 2,141 2 – –

Coastal Waters: Mississippi

Fixed Platform 1 1 0 0.001 Crude/2008

Pipeline 0 0 0 N/A NA

MODU 0 0 0 N/A N/A

OSV 0 0 0 N/A N/A

Tank Ship or 

Barge 1 1 0 0.05 Crude/2002

Total 2 2 0 – –

Coastal Waters: Alabama

Fixed Platform 2 2 0 0.024 Crude/2007

Pipeline 0 0 0 N/A N/A

MODU 0 0 0 N/A N/A 

OSV 0 0 0 N/A N/A

Tank Ship or 

Barge 0 0 0 N/A N/A

Total 2 2 0 – –

Coastal Waters: Florida

Fixed Platform 0 0 0 N/A N/A

Pipeline 0 0 0 N/A N/A

MODU 0 0 0 N/A N/A

OSV 0 0 0 N/A N/A

Tank Ship or 

Barge 0 0 0 N/A N/A

Total 0 0 0 – –
3-110 Gulf of Mexico Multisale EIS

Source

Number of Spills Maximum Volume of a Single Incident

Total 

Number of 

Spill Events

Number 

of Spills 

(<1,000 bbl)

Number 

of Spills 

(≥1,000 bbl)

Volume (bbl) of 

Maximum Spill 

from the Source 

Maximum Spill Amount 

Product/Year

bbl = barrel; MODU = mobile offshore drilling unit; N/A = not applicable; OSV = offshore support vessel.

Note: The reader should note that the spills are reported to USCG by responsible parties, other private 

parties, and government personnel. The USCG does not verify the source or volume of every 

report.

1

Coastal Waters – The portion of the Gulf of Mexico under State jurisdiction that begins at the coastline 

and ends at the Federal/State boundary 9 nmi (10.36 mi; 16.67 km) offshore Texas; 3 nmi (3.5 mi; 

5.6 km) offshore Louisiana, Mississippi, and Alabama; and 9 nmi (10.36 mi; 16.67 km) offshore Florida. 2

The data included represents spill events from January 2002 until July 2015.

3.2.1.1.3 Offshore Spills 

Petroleum spills from OCS oil- and gas- related activities include crude oil, condensate, and 

refined products such as diesel, hydraulic oil, lube oil and mineral oil. For spills of synthetic oil 

products, drilling muds, or chemicals, refer to Chapter 3.2.6. Spills from facilities include spills from 

drilling rigs, drillships, and storage, processing, or production platforms that occurred during OCS 

drilling, development, and production operations. Spills from pipeline operations are those that have 

occurred on the OCS and are directly attributable to the transportation of OCS oil. Oil-spill 

information comes from a variety of sources. The BSEE requires operators to report any spill ≥1 bbl 

occurring on the OCS and maintains a database for all reported incidents. Not included in BSEE’s 

data records are spills <1 bbl. Spills of any size and composition are required to be reported to 

USCG’s National Response Center and are further documented in USCG’s Marine Information for 

Safety and Law Enforcement (2001-present) database and its predecessors. Also not included in 

BSEE’s database are spills that have occurred in Federal waters from OCS barging operations and 

from other service vessels that support the OCS oil and gas industry. These data are included in 

USCG’s record of all spills; however, USCG’s database does not include the source of oil (OCS 

versus non-OCS) or in the case of spills from vessels, the type of vessel operations; such 

information is needed to determine if a particular spill occurred as a result of OCS operations. Spills 

from vessels are provided for tankers in worldwide waters and tankers and barges in U.S. coastal 

and offshore waters. The latter is a subset of the spills included in the worldwide tanker spill data. 

These data identify whether the spill occurred “at sea” or “in port’ as they can occur due to mishaps 

during loading, unloading, and taking on fuel oil, and from groundings, hull failures, and explosions. 

As mentioned previously, a recent report prepared by ABS Consulting, Inc. (2016) examined the 

occurrence rates for offshore oil spills gathering data from a variety of sources including BSEE, 

USCG, and DOT’s Pipeline and Hazardous Material Safety Administration. Tables 3-14 and 3-15

provide information on OCS spills ≥1,000 bbl that have occurred offshore in the GOM for the period 

from 1964 through July 2016. 
Impact-Producing Factors and Scenario 3-111

Table 3-14. Petroleum1 Spills ≥1,000 Barrels from United States OCS2 Platforms, 1964-July 2016.

Date

Leasing 

Area3 

and Block 

Number

Water 

Depth 

(ft)

Distance 

to Shore 

(mi)

Volume 

Spilled 

(bbl)

Operator Facility or Structure 

and Cause of Spill

4/08/1964 EI 208 94 48 2,559 Continental

Oil

Freighter struck Platform A: fire,

platform and freighter damaged

10/03/1964 Hurricane

Hilda

11,8694 Event Total 5 platforms destroyed during

Hurricane Hilda

EI 208 94 48 5,180 Continental

Oil

Platforms A, C, and D destroyed: 

blowouts (several days)

SS 149 55 33 5,100 Signal O & G Platform B destroyed: blowout

(17 days)

SS 199 102 44 1,589 Tenneco Oil Platform A destroyed: lost 

storage tank

7/19/1965 SS 29 15 7 1,6885 PanAmerican Well #7 drilling: blowout

(8 days), minimal damage

1/28/1969 6B 5165

Santa 

Barbara 

Channel, 

California

190 6 80,000 Union Oil Well A-21 drilling: blowout

(10 days), 50,000 bbl during

blowout phase, subsequent

seepage of 30,000 bbl (over

decades), 4,000 birds killed, 

considerable oil on beaches, 

platform destroyed

3/16/1969 SS 72 30 6 2,500 Mobil Oil Submersible rig Rimtide drilling in

heavy seas bumped by supply 

vessel

2/10/1970 MP 41 39 14 65,0006 Chevron Oil Platform C: rig shifted and

sheared wellhead, blowout

(3-4 days), fire of unknown origin,

blowout 12 wells (49 days), lost 

platform, minor amounts of oil on

beaches

12/1/1970 ST 26 60 8 53,000 Shell Oil Platform B: wireline work, gas

explosion, fire, blowout

(138 days), lost platform and

2 drilling rigs, 4 fatalities, 

36 injuries, minor amounts of oil

on beaches

1/09/1973 WD 79 110 17 9,935 Signal O & G Platform A: oil storage tank

structural failure

1/26/1973 PL 23 61 15 7,000 Chevron Oil Platform CA: storage barge sank

in heavy seas

11/23/1979 MP 151 280 10 1,5007 Texoma

Production

MODU Pacesetter III: diesel tank

holed, workboat contact in heavy 

seas
3-112 Gulf of Mexico Multisale EIS

Date

Leasing 

Area3 

and Block 

Number

Water 

Depth 

(ft)

Distance 

to Shore 

(mi)

Volume 

Spilled 

(bbl)

Operator Facility or Structure 

and Cause of Spill

11/14/1980 HI 206 60 27 1,456 Texaco Oil Platform A: storage tank

overflow during Hurricane

Jeanne evacuation

9/24/2005 Hurricane

Rita

5,0668 Event Total 1 platform and 2 rigs destroyed

by Hurricane Rita

EI 314 230 78 2,0005 Forest Oil Platform J: destroyed, lost oil on 

board and in riser

SM 146 238 78 1,4949 Hunt

Petroleum

Jack-up Rig Rowan Fort Worth: 

swept away, never found

SS 250 182 69 1,5729 Remington

O & G

Jack-up Rig Rowan Odessa: 

legs collapsed

04/20/2010 MC 252 4,992 53 4.9 

million10

BP E & P Deepwater Horizon Rig: gas

explosion, blowout (86 days to

cap well), fire, drilling rig sank, 

11 fatalities, multiple injuries, 

considerable oil on beaches, 

wildlife affected, temporary 

closure of area fisheries

Notes: barrel (bbl) = 42 gallons, billion = 109, MODU = mobile offshore drilling unit

Between 1964 and 2009, over 17.5 billion bbl of oil and 176.1 Mcf of natural gas were produced 

on the OCS.

1

Crude oil release unless otherwise noted; no spill contacts to land unless otherwise noted.

2

Outer Continental Shelf (OCS) – submerged lands, subsoil, and seabed administered by the U.S. 

Federal Government (http://www.boem.gov/Governing-Statutes/).

3

Gulf of Mexico leasing area unless otherwise noted (official protraction diagrams, 

http://www.boem.gov/Official-Protraction-Diagrams/l): EI = Eugene Island, HI = High Island, 

MC = Mississippi Canyon, MP = Main Pass, PL = South Pelto, SS = Ship Shoal, SM = South Marsh 

Island, ST = South Timbalier, and WD = West Delta.

4

Hurricane Hilda, 10/3/1964: platform spills ≥1,000 bbl at 3 facilities totaled 11,869 bbl; treated as 1 spill 

event.

5

Condensate – a liquid product of natural gas production.

6

Spill volume estimate between 30,000 and 65,000 bbl, previously reported as 30,000 bbl.

7

Diesel fuel.

8

Hurricane Rita, 9/24/2010: platform and 2 rig losses ≥1,000 bbl at 3 locations totaled to 5,066 bbl; 

treated as 1 spill event. The 5,066-bbl spill was a “passive” spill based on unrecovered pre-storm 

inventories from the platform and 2 rigs; no spill observed; no response required.

9

Diesel fuel and other refined petroleum products stored on rig.

10The Federal Interagency Solutions Group, 2010.

Sources: Anderson et al., 2012; ABS Consulting, Inc., 2016.
Impact-Producing Factors and Scenario 3-113

Table 3-15. Petroleum1 Spills ≥1,000 Barrels from United States OCS2 Pipelines, 1964-July 2016.

Date

Leasing 

Area3 

and Block 

Number

Water 

Depth 

(ft)

Distance 

to Shore 

(mi)

Volume 

Spilled 

(bbl)

Operator Pipeline Segment (pipeline authority4

) 

Cause/Consequences of Spill

10/15/1967 WD 73 168 22 160,638 Humble 

Pipeline

12" oil pipeline, Segment #7791 (DOT): 

anchor kinked, corrosion, leak 

3/12/1968 ST 131 160 28 6,000 Gulf Oil 18" oil pipeline, Segment #3573 (DOT): 

barge anchor damage

2/11/1969 MP 299 210 17 7,532 Chevron 

Oil

4" gas pipeline, Segment #3469 (DOT): 

anchor damage

5/12/1973 WD 73 168 22 5,000 Exxon 

Pipeline

16" gas & oil pipeline, Segment #807 (DOT): 

internal corrosion, leak

4/17/1974 EI 317 240 75 19,833 Pennzoil 14" oil Bonita pipeline, Segment #1128

(DOI): anchor damage

9/11/1974 MP 73 141 9 3,500 Shell Oil 8" oil pipeline, Segment #36 (DOI): 

Hurricane Carmen broke tie-in to 12"

pipeline, minor contacts to shoreline, brief

cleanup response in Chandeleur Area

12/18/1976 EI 297 210 17 4,000 Placid Oil 10" oil pipeline, Segment #1184 (DOI): 

trawl damage to tie-in to 14" pipeline

12/11/1981 SP 60 190 4 5,100 Atlantic 

Richfield

8" oil pipeline, Segment #4715 (DOT): 

workboat anchor damage

2/07/1988 GA A002 75 34 15,576 Amoco 

Pipeline

14" oil pipeline, Segment #4879 (DOT): 

damage from illegally anchored vessel

1/24/1990 SS 281 197 60 14,4235 Shell 

Offshore

4" condensate pipeline, Segment #8324

(DOI): anchor damage to subsea tie-in

5/06/1990 EI 314 230 78 4,569 Exxon 8" oil pipeline, Segment #4030 (DOI): trawl

damage

8/31/1992 PL 8 30 6 2,000 Texaco 20" oil pipeline, Segment #4006 (DOT): 

Hurricane Andrew, loose rig Treasure 75, 

anchor damage, minor contacts to 

shoreline, brief cleanup response 

11/16/1994 SS 281 197 60 4,5335 Shell 

Offshore

4" condensate pipeline, Segment #8324

(DOI): trawl damage to subsea tie-in

1/26/1998 EC 334 264 105 1,2115 Pennzoil E 

& P

16" gas & condensate pipeline, Segment

#11007 (DOT): anchor damage to tie-in to

30" pipeline, anchor dragged by vessel in

man-overboard response

9/29/1998 SP 38 108 6 8,212 Chevron 

Pipe Line

10" gas & oil pipeline, Segment #5625

(DOT): Hurricane Georges, mudslide 

damage, small amount of oil contacted

shoreline

7/23/1999 SS 241 133 50 3,200 Seashell 

Pipeline

12" oil pipeline, Segment #6462 & Segment

#6463 (DOT): “Loop Davis” jack-up rig, 

barge crushed pipeline when sat down on it

1/21/2000 SS 332 435 75 2,240 Equilon 

Pipeline

24" oil pipeline, Segment #10903 (DOT): 

anchor damage from MODU under tow
3-114 Gulf of Mexico Multisale EIS

Date

Leasing 

Area3 

and Block 

Number

Water 

Depth 

(ft)

Distance 

to Shore 

(mi)

Volume 

Spilled 

(bbl)

Operator Pipeline Segment (pipeline authority4

) 

Cause/Consequences of Spill

9/15/2004 MC 20 479 19 1,7206 Taylor 

Energy

6" oil pipeline, Segment #7296 (DOI): 

Hurricane Ivan, mudslide damage

9/13/2008 HI A264 150 73 1,3167 HI 

Offshore 

System

42" gas pipeline, Segment #7364 (DOT): 

Hurricane Ike, anchor damage parted line

7/25/2009 SS 142 60 30 1,500 Shell Pipe 

Line

20" oil pipeline, Segment #4006 (DOT): 

micro-fractures from chronic contacts at 

pipeline crossing caused failure (separators 

between pipelines missing)

5/11/20168 GC 248 3,500 97 2,100 Shell 

Offshore

6" oil pipeline, Segment #14371 (DOI): 

cracked collar on jumper line connecting 

well head to pipeline network

Notes: barrel (bbl) = 42 gallons, billion = 109, MODU = mobile offshore drilling unit.

Between 1964 and 2009, over 17.5 billion bbl of oil and 176.1 Mcf of natural gas were produced 

on the OCS.

1

Crude oil release unless otherwise noted; no spill contacts to land unless otherwise noted.

2

Outer Continental Shelf (OCS) – submerged lands, subsoil, and seabed administered by the U.S. 

Federal Government (http://www.boem.gov/Governing-Statutes/).

3

Gulf of Mexico leasing area unless otherwise noted (official protraction diagrams, 

http://www.boem.gov/Official-Protraction-Diagrams/l): EC = East Cameron, EI = Eugene Island, 

GA = Galveston, HI = High Island, MC = Mississippi Canyon, MP = Main Pass, PL = South Pelto, 

SS = Ship Shoal, SP = South Pass, ST = South Timbalier, and WD = West Delta.

4

Pipeline authority: DOI = Department of the Interior, Bureau of Ocean Energy Management, Regulation 

and Enforcement; DOT = Department of Transportation, Pipeline and Hazardous Materials Safety 

Administration. 5

Condensate – a liquid product of natural gas production.

6

The 1,720-bbl spill was a “passive” spill based on unrecovered pre-storm inventory trapped in the 

segment by a mudslide; no spill observed, no response required.

7

The 1,316-bbl spill was a “passive” spill based on unrecovered pre-storm inventory in the segment parted 

by storm; no spill observed, no response required.

8

This incident is still under investigation and the information provided here should be considered 

preliminary.

Sources: Anderson et al., 2012; ABS Consulting, Inc., 2016. 
Impact-Producing Factors and Scenario 3-115

Taylor Energy Oil Discharge at Mississippi Canyon Block 20 Site and Ongoing Response 

Efforts

The BSEE and BOEM have worked with USCG under a Unified Command to monitor and 

respond to discharges from Taylor Energy's Mississippi Canyon Block 20 (MC-20) site since the oil 

production platform and 25 of 28 connected wells were impacted and damaged during Hurricane

Ivan in 2004. The multi-agency effort has worked continuously to prevent and control the oil 

discharge, improve the effectiveness of containment around the source of the oil discharge, and 

mitigate environmental impacts.

The BSEE and USCG have also worked closely with representatives of Taylor Energy to 

mitigate the impacts of the discharge associated with the felled platform. Collaborative efforts have 

resulted in removal of the platform deck, removal of subsea debris, decommissioning of the oil 

pipeline, and efforts to plug 9 of the 25 impacted wells. Despite these efforts, there is an ongoing oil 

discharge from Taylor Energy's MC-20 site.

Based on data collected from nearly daily overflights since September 2014, oil sheens have 

been observed and reported by Taylor Energy to be as large as 1.5 mi (2.4 km) wide and 14 mi

(23 km) long, with an average of 1 mi (2 km) wide and 5.5 mi (8.9 km) long, covering an average 

area of 8 mi2 (21 km2

). Over this period, the daily volume of oil discharging from the MC-20 site has 

fluctuated between a low of ≤1 bbl to a high of 55 bbl (2,329 gallons). The average reported daily oil 

volume on the sea surface over a 7-month period was over 2 bbl; the volume over 75 days was 

>1 bbl, including 23 days of volume >3.8 bbl and 4 days >35 bbl. These spill size and volume 

estimates are based on reports submitted by Taylor Energy's contractors to the National Response 

Center. The BSEE's current estimate is that the oil discharge from the site, if left unchecked, could 

continue for 100 years or more.

The specific source(s) of discharge at the MC-20 site are not fully known. However, because 

the discharge volume is greater than can reasonably be accounted for by oil released from sediment 

only, oil is most likely emanating from one or more of the 25 wells (USDOI, BSEE, 2015). 

Taylor Energy had originally been ordered by MMS in October 2007 to permanently plug and 

abandon all of the wells by June 2008. In November 2007, MMS issued Taylor Energy an order to 

provide supplemental bonding to guarantee performance of Taylor Energy's decommissioning

obligations at the site. In December 2007, MMS ordered Taylor Energy to prevent any further 

hydrocarbon seepage from the MC-20 site. In February 2008, MMS sent Taylor Energy a Notice of 

Incident of Noncompliance for failure to provide the required supplemental bonding.

The DOI and Taylor Energy entered into a Trust Agreement in 2008 wherein Taylor Energy 

committed funds to fulfill obligations under the OCSLA regarding the MC-20 site. By entering into 

the Agreement, Taylor Energy fulfilled its supplemental bonding obligations and resolved the 

pending administrative citation with respect to those obligations. Decommissioning of the wells at 

the site, required under the regulations and the 2008 Trust Agreement, has not yet been completed. 
3-116 Gulf of Mexico Multisale EIS

For example, not all of the wells have been permanently plugged and abandoned. Future work to be 

performed under the Trust Agreement will be determined based on site conditions and the 

availability of applicable technology.

In addition to its obligations under the OCSLA, pursuant to the Oil Pollution Act (OPA) and 

BOEM regulations, Taylor Energy is required to provide evidence of financial responsibility (e.g., 

bond and insurance) demonstrating that it can fulfill its OPA obligations (e.g., removal and

compensation for damages) for oil spills from the MC-20 site.

Shell Offshore Pipeline Spill at Green Canyon Block 248

On May 12, 2016, USCG responded to an offshore oil spill that reportedly discharged from a 

Shell subsea well-head flow line, approximately 90 mi (145 km) south of Timbalier Island, Louisiana, 

at Green Canyon Block 248. The release came from the Glider subsea system, which ties back to 

the Brutus platform at Green Canyon Block 158. The volume of the release was estimated at 

2,100 bbl. Response efforts included on-water recovery vessels and skimming operations. There 

have been no reported impacts to wildlife or fisheries, and the sheen did not make contact with the 

shoreline. This information is preliminary and BSEE personnel are leading an investigation to 

determine the cause of the release and the effectiveness of the on-water response. Due to the 

timing of this event, this spill was not included in the ABS Consulting Inc.’s (2016) Update of 

Occurrence Rates for Offshore Oil Spills.

3.2.1.2 Characteristics of OCS Oil

Crude oils are a natural mixture of hundreds of different compounds, with liquid 

hydrocarbons accounting for up to 98 percent of the total composition. The chemical composition of 

crude oil can vary significantly from different producing areas; thus, the exact composition of oil 

being produced in OCS waters varies throughout the GOM. Extensive laboratory testing has been 

performed on various oils from the GOM to determine their physical and chemical characteristics. 

For example, numerous oils collected from the GOM (U.S. waters) are included in Environment 

Canada’s (2013) oil properties database. The database provides details of an oil’s chemical 

composition, including hydrocarbon groups (i.e., saturates, aromatics, resins, and asphaltenes), 

VOCs (such as benzene, toluene, ethylbenzene, and xylene), sulfur content, biomarkers, and 

metals. The database also includes API gravities, of which GOM oils are in the range of 15° to 60°. 

The American Petroleum Institute gravity is a common measure of the relative density of crude oil 

and is expressed in degrees (°API) with water having a value of 10° API. Crude oils with lower 

densities and viscosities usually contain higher levels of naphtha with predominantly volatile 

paraffinic hydrocarbons (Table 3-16). Light crude oils are easier to process, while heavy crude oils 

are more difficult. The sulfur content (sweet vs. sour) of crude oil also determines the amount of 

processing required. Light sweet crude oil is preferred by refineries because of its low sulfur content 

(typically less than 0.5%) (API, 2011).

Data have been collected from approximately 450 deepwater EPs and DOCDs that were 

submitted to BOEM/BSEE. These data are available through BOEM’s Exploration and Development 
Impact-Producing Factors and Scenario 3-117

Plans Online Query (USDOI, BOEM, 2014b). Statistics on these API gravities show a similar range 

of 16° to 58° as those reported in the Environment Canada database. The mean value for all oils 

examined was 36°.

Table 3-16. Properties and Persistence by Oil Component Group. 

Properties and 

Persistence Light Weight Medium Weight Heavy Weight

Hydrocarbon 

Compounds Up to 10 carbon atoms 10-22 carbon atoms >20 carbon atoms

API o >31.1o 31.1o-22.3o <22.3o

Evaporation 

Rate

Rapid (within 1 day) 

and complete

Up to several days; not 

complete at ambient 

temperatures

Negligible

Solubility in 

Water High Low (at most a few mg/L) Negligible

Acute Toxicity

High due to 

monoaromatic 

hydrocarbons (BTEX)

Moderate due to diaromatic 

hydrocarbons (naphthalenes 

– 2 ring PAHs)

Low, except due to smothering 

(i.e., heavier oils may sink)

Chronic Toxicity None, does not persist 

due to evaporation

PAH components (e.g., 

naphthalenes – 2 ring PAHs)

PAH components (e.g., 

phenanthrene, anthracene – 

3 ring PAHs)

Bioaccumulation 

Potential

None, does not persist 

due to evaporation Moderate Low, may bioaccumulate through sediment sorption

Compositional 

Majority

Alkanes and 

cycloalkanes

Alkanes that are readily 

degraded

Waxes, asphaltenes, and polar 

compounds (not significantly 

bioavailable or toxic)

Persistence Low due to evaporation

Alkanes readily degrade, but 

the diaromatic hydrocarbons 

are more persistent

High; very low degradation 

rates and can persist in 

sediments as tarballs or asphalt 

pavements

Notes: API = American Petroleum Institute; BTEX = benzene, toluene, ethylbenzene, and xylene; 

mg/L = milligram per liter; PAH = polycyclic aromatic hydrocarbons. 

Sources: Michel, 1992; Lee et al., 2015.

3.2.1.3 Transport and Fate of Offshore Spills 

The physical and chemical properties of oil greatly affect its transport and fate in the 

environment. Once spilled, oil is subject to a number of physical, chemical, and biological processes 

that alter its composition and can determine environmental impacts. Horizontal transport of oil is 

accomplished through spreading, advection, dispersion, and entrainment, whereas vertical transport 

involves dispersion, entrainment, Langmuir circulation (a series of shallow, slow, counter-rotating 

vortices at the ocean's surface aligned with the wind developed when wind blows steadily over the 

sea surface), sinking, overwashing, partitioning, and sedimentation. Following a spill, the 

composition of the released oil can change substantially due to weathering processes such as 

evaporation, emulsification, dissolution, and oxidation. The ultimate fate of oil in the environment 

and its impacts are influenced not only by the magnitude, spatial extent, and duration of the event 

but also by the response methods that may be employed (Chapter 3.2.8). More details on the 

properties and persistence of different types of oils are provided in Table 3-16.
3-118 Gulf of Mexico Multisale EIS

Spreading

It is expected that some portion of spilled oil would rise in the water column and/or remain on 

the sea surface, depending on the depth of the spill and whether a subsurface plume forms. Gulf of 

Mexico oils, having an average API gravity of 36o

, have a tendency to float. Once on the sea 

surface, oil rapidly spreads out, forming a slick that is initially a few millimeters (mm) in thickness in 

the center and much thinner around the edges. The rate of spreading depends upon the viscosity of 

the spilled oil, whether or not the oil is released at the water surface or subsurface, and whether the 

spill is instantaneous or continuous for some period. The spilled oil would continue to spread until its 

thickest part is about 0.1 mm. Once it spreads thinner than 0.1 mm, the slick would begin to break 

up into small patches, forming a number of elongated slicks, with an even thinner sheen trailing 

behind each patch of oil. Oil becomes diluted as it physically mixes with the surrounding water and 

moves into the water column, and the physical mixing zone of surface oil is generally limited to 

approximately 33 ft (20 m) (Lange, 1985; McAuliffe et al., 1975 and 1981a; Tkalich and Chan, 2002; 

Thompson et al., 1999; Schroeder, 2000). However, under turbulent mixing conditions oil can be 

transported deeper into the water column. In one extraordinary circumstance, a tropical storm 

forced a large volume of dispersant/oil mixture as deep as 246 ft (75 m) (Silva et al., 2015).

Weathering

Immediately upon being spilled, oil begins reacting with the environment. This process is 

called weathering. A number of processes alter the chemical and physical characteristics of the 

original hydrocarbon mixture, which reduces the oil mass over time. Weathering processes include 

evaporation of volatile hydrocarbons into the atmosphere, dissolution of soluble components, 

dispersion of oil droplets into the water column, emulsification and spreading of the slick on the 

surface of the water, chemo- or photo-oxidation of specific compounds (creating new components 

that are often more soluble), and biodegradation. Weathering and the existing meteorological and 

oceanographic conditions determine the time that the oil remains on the surface of the water, and 

the characteristics of the oil at the time of contact with a particular resource also influence the 

persistence time of an oil slick. Oil-spill cleanup timing and effectiveness would also be determining 

factors.

Chemical, physical, and biological processes operate on spilled oil to change its hydrocarbon 

compounds, reducing many of the components until the slick can no longer continue as a cohesive 

mass floating on the surface of the water. By spreading out, the oil’s more volatile components are 

exposed to the atmosphere and within a few days following a spill, light crude oils can lose up to 

75 percent of their initial volume and medium crude oils can lose up to 40 percent (NRC, 2003). 

Some crude oils mix with water to form an emulsion that is much thicker and stickier than the original 

oil (USDOC, NOAA, 2010a). Winds and waves continue to stretch and tear the oil patches into 

smaller pieces, or tarballs. Oil at a “light” API gravity would have few asphaltenes, would not 

emulsify, and would not form tarballs. Oil at a “heavy” API gravity, or enriched in heavy components 

after weathering, would more likely emulsify and form tarballs. While some tarballs may be as large 

as pancakes, most are coin-sized. Tarballs are very persistent in the marine environment and can 

travel hundreds of miles. It is expected that oil spilled as a result of an accident associated with a 
Impact-Producing Factors and Scenario 3-119

regionwide proposed action would be within the range of 30o

-35o API. BOEM used the SINTEF Oil 

Weathering Model to numerically model weathering processes to (1) estimate the likely amount of oil 

remaining on the ocean surface as a function of time and (2) predict the composition of any 

remaining oil (USDOI, MMS, 2007a). The results of BOEM’s weathering analyses were as follows. 

By 10 days after a spill event of 1,000 bbl, approximately 32-74 percent of the slick would have 

dissipated by natural weathering, with between 30 and 32 percent lost to the atmosphere via 

evaporation and between 2 and 42 percent lost into the water column via natural dispersion. The 

volume of the slick would be further reduced by spill-response efforts (Chapter 3.2.8). However, 

other fates would likely be appropriate to a catastrophic spill event, especially in deep waters. For 

example, Ryerson et al. (2011) estimated that the total hydrocarbon mass for the Deepwater Horizon

oil spill (including gas fraction) was partitioned among the following fates: ~36 percent to the deep 

subsurface plume; ~21 percent recovered by surface ships; ~10 percent to a surface slick; 

~6 percent flared at the surface; and ~4 percent evaporated at the surface, which leaves 

~23 percent unaccounted for based on available chemical data.

Persistence

The persistence of an offshore oil slick is strongly influenced by how rapidly it spreads and 

weathers and by the effectiveness of oil-spill response in removing the oil from the water surface. 

Hypothetical analyses were performed for a simulated pipeline break. Based on several scenarios 

implemented in the weathering model (e.g., variable season, oil type, and emulsification), BOEM 

estimated that the spill would dissipate from the water surface in approximately 2-10 days. Similarly, 

an OCS pipeline spill of 8,212 bbl on September 29, 1998, for which a panel investigation report was 

available, contained overflight information of the oil spill that showed the spill persisted for 5 days on 

the surface (USDOI, MMS, 1999).

Subsurface Release

The behavior of a spill depends on many factors, including the characteristics of the oil being 

spilled as well as oceanographic and meteorological conditions. Previously, an experiment in the 

North Sea indicated that the majority of oil released during a deepwater blowout would quickly rise to 

the surface and form a slick (Johansen et al., 2001). In such a case, impacts from a deepwater oil 

spill would occur at the surface where the oil is likely to be mixed into the water and dispersed by 

wind and waves. The oil would undergo natural physical, chemical, and biological degradation 

processes including weathering. However, data and observations from the Deepwater Horizon

explosion, oil spill, and response challenged the previously prevailing thought that most oil from a 

deepwater blowout would quickly rise to the surface. Due in part to the application of subsea 

dispersants, measurable amounts of hydrocarbons (dispersed or otherwise) were detected in the 

water column as subsurface plumes and on the seafloor in the vicinity of the release (e.g., Diercks 

et al., 2010; OSAT, 2010). Subsurface plume formation is based on numerous factors, including the 

level of subsea dispersant injection, the amount of natural dispersion related to blowout properties, 

and oceanographic conditions such as water column stratification and cross currents. After the Ixtoc

blowout in 1979, located 50 mi (80 km) offshore in the Bay of Campeche, Mexico, some subsurface 

oil also was observed dispersed within the water column (Boehm and Fiest, 1982); however, the 
3-120 Gulf of Mexico Multisale EIS

scientific investigations were limited (Reible, 2010). The water quality of marine waters would be 

affected by the dissolved components and oil droplets that are small enough that they do not rise to 

the surface or are mixed down by surface turbulence. In the case of subsurface oil plumes, it is 

important to remember that these plumes would be affected by subsurface currents and could be 

diluted over time. Even in the subsurface, oil would undergo natural physical, chemical, and 

biological degradation processes including weathering.

3.2.1.4 Analysis of Offshore Spills ≥1,000 bbl

3.2.1.4.1 Overview of Spill Risk Analysis

The BOEM conducts an oil-spill risk analysis prior to conducting lease sales in OCS areas

(refer to Figure 3-17). The analysis is conducted in three parts:

(1) the trajectories of oil spills from hypothetical spill locations, which are simulated 

using the Oil Spill Risk Analysis (OSRA) Model (Smith et al., 1982); 

(2) the probability of oil-spill occurrence, which is based on spill rates derived from 

historical data (Anderson et al., 2012) and on estimated volumes of oil produced 

and transported; and

(3) the combination of results of the first two to estimate the overall oil-spill risk if 

there is oil development.

In the GOM, the Cumulative OCS Oil and Gas Program scenario comprises all future 

operations that would occur over a 70-year time period (2017-2086) from proposed, existing, and 

future leases regionwide. The analysis uses data on past OCS production and spills, along with 

estimates of future activities, to evaluate the risk of future spills.
Impact-Producing Factors and Scenario 3-121

Figure 3-17. The Oil Spill Risk Analysis Model Process.

3.2.1.4.2 Trajectory Modeling for Offshore Spills ≥1,000 bbl

The OSRA model simulates the trajectory of thousands of spills throughout the Gulf of 

Mexico OCS and calculates the probability of these spills being transported and contacting specified 

geographic areas and features. Using the OSRA model, BOEM estimates the likely trajectories of 

hypothetical offshore spills ≥1,000 bbl. Only spills ≥1,000 bbl are addressed because smaller spills 

may not persist long enough to be simulated by trajectory modeling. For this analysis, the OSRA 

model was run for Alternatives A, B, and C (Tables 3-2 and 3-4) and the Cumulative OCS Oil and 

Gas Program (2017-2086). 

The OSRA model uses hypothetical spill locations called launch points and simulates the 

trajectory of a spill’s movement on the surface of the water using modeled ocean currents and 

winds. The model can simulate a large number of hypothetical trajectories from each launch point. 

Spill trajectories are initiated once per day from each launch point and are time stepped every hour 

until a statistically valid number of simulations have been run to characterize the risk of contact. The 

simulated oil spills originate from approximately 6,000 points uniformly distributed 6-7 mi (10-11 km) 

apart within the Gulf of Mexico OCS. This spacing between launch points is sufficient to provide a 

resolution that creates a statistically valid characterization of the entire area (Price et al., 2001).

The model tabulates the number of times each trajectory moves across or touches a location 

(contact) occupied by polygons mapped on the gridded area. These polygons represent specified 

geographic areas and features. The OSRA model compiles the number of contacts to each feature 

that results from all of the modeled trajectory simulations from all of the launch points for a specific 

area. Contact occurs for offshore features if the trajectory simulation passes through the polygon. 
3-122 Gulf of Mexico Multisale EIS

Contact occurs for land-based features if the trajectory simulation touches the border of the feature. 

The simulation stops when the trajectory contacts the lines representing the land/water boundary or 

the borders of the domain. The probability of contact to a defined feature is calculated by dividing 

the number of contacts by the number of trajectories started at various launch locations in the 

gridded area.

The output from this component of the OSRA model provides information on the likely 

trajectory of a spill by wind and current transport, should one occur and persist for the time modeled 

in the simulations; the calculations for this EIS were modeled for 10 and 30 days. All contacts that 

occurred during these periods were tabulated for Alternatives A, B, and C (Table 3-17). 

Table 3-17. Probability (percent chance) of a Particular Number of Offshore Spills 

≥1,000 Barrels Occurring as a Result of Either Facility or Pipeline

Operations Related to Alternative A, B, or C. 

Facility Spills (%) Pipeline Spills (%) Total Spills (%)

Alternative A1

Number of Spills Low High Low High Low High

1 5 21 15 37 19 36

2 <0.5 3 1 18 2 23

3 <0.5 <0.5 <0.5 6 <0.5 10

4 <0.5 <0.5 <0.5 1 <0.5 3

5 <0.5 <0.5 <0.5 <0.5 <0.5 1

Alternative B2

Number of Spills Low High Low High Low High

1 4 19 14 36 17 37

2 <0.5 2 1 16 2 20

3 <0.5 <0.5 <0.5 4 <0.5 7

4 <0.5 <0.5 <0.5 1 <0.5 2

5 <0.5 <0.5 <0.5 <0.5 <0.5 <0.5

Alternative C3

Number of Spills Low High Low High Low High

1 1 4 2 11 3 14

2 <0.5 <0.5 <0.5 1 <0.5 1

3 <0.5 <0.5 <0.5 <0.5 <0.5 <0.5

4 <0.5 <0.5 <0.5 <0.5 <0.5 <0.5

5 <0.5 <0.5 <0.5 <0.5 <0.5 <0.5

Note: The columns under each spill category refer to the low and high resource 

estimates. Refer to Table 3-1 for more information on resource estimates.

1

Proposed regionwide lease sale.

2

Proposed regionwide lease sale excluding blocks in the WPA.

3

Proposed regionwide lease sale excluding blocks in the CPA/EPA.
Impact-Producing Factors and Scenario 3-123

3.2.1.4.3 Estimated Number of Offshore Spills ≥1,000 bbl and Probability of Occurrence

The mean number of spills ≥1,000 bbl estimated to occur as a result of each alternative is 

provided in Table 3-18. The range of the mean number of spills reflects the range of oil production 

volume estimated as a result of each alternative. The mean number of future spills ≥1,000 bbl is 

calculated by multiplying the spill rate (1.13 spills/BBO) by the volume of oil estimated to be 

produced as a result of each alternative. Spill rates were calculated based on the assumption that 

spills occur in direct proportion to the volume of oil handled and are expressed as number of spills 

per billion barrels of oil handled (spills/BBO).

Table 3-18. Mean Number and Sizes of Spills Estimated to Occur in OCS Offshore Waters from an 

Accident Related to Rig/Platform and Pipeline Activities Supporting Each Alternative Over a 

50-Year Time Period. 

Spill Size Group Spill Rate

(spills/BBO)1

Number of Spills Estimated Estimated

Median Spill 

Size 

(bbl)1 Alternative A Alternative B Alternative C

0-1.0 bbl 2,020 424-2,258 374-1,959 51-290 <1

1.1-9.9 bbl 57.4 12-64 11-56 2-9 3 10.0-49.9 bbl 17.4 4-20 3-17 1-3

50.0-499.9 bbl 11.3 2-13 2-11 <1-2 126 500.0-999.9 bbl 1.63 <1-2 <1-2 <1

Platforms

>1,000-9,999 bbl 0.25 <1 <1 <1 5,066

>10,000 bbl 0.13 <1 <1 <1 –2

Pipelines

>1,000-9,999 bbl 0.88 <1-1 <1 <1 1,720

>10,000 bbl 0.18 <1 <1 <1 –2

Notes: The number of spills estimated is derived by application of the historical rate of spills 

(1996-2010) per volume of crude oil handled based on the projected production for each 

alternative (Table 3-2). The actual number of spills that may occur in the future could vary 

from the estimated number.

1

The spill rates presented are a sum of rates for United States OCS platforms/rigs and pipelines. The 

average (vs. the median) spill sizes for a larger number of spill size categories can also be found in the 

original source (Anderson et al., 2012).

2

During the last 15 years, the only ≥10,000-bbl spill was the Deepwater Horizon. However, this spill is 

considered to be a low-probability catastrophic event, which is not reasonably foreseeable and is 

therefore not included.

The probabilities for oil spill occurrence resulting from each alternative (2017-2066) and the 

Cumulative OCS Oil and Gas Program (2017-2086) for offshore spills ≥1,000 bbl can be found in 

Table 3-19 and for spills ≥10,000 bbl in Table 3-20. The OSRA model estimates the chance of oil 

spills occurring during the production and transportation of a specific volume of oil over the lifetime of 

the scenario being analyzed. The estimation process uses a spill rate constant, based on historical 

accidental spills ≥1,000 bbl, expressed as a mean number of spills per billion barrels of oil handled. 

For this analysis, the low estimate and high estimate of projected oil production for a single proposed 

lease sale for each alternative and for the Cumulative OCS Oil and Gas Program (2017-2086) are 
3-124 Gulf of Mexico Multisale EIS

used. For more information on OCS spill-rate methodologies and trends, refer to Anderson et al. 

(2012). A discussion of how the range of resource estimates was developed is provided in 

Chapter 3.1.1 and Table 3-1.

Table 3-19. Oil-Spill Occurrence Probability Estimates for Offshore Spills ≥1,000 Barrels Resulting from 

Each Alternative (2017-2066) and the Cumulative OCS Oil and Gas Program (2017-2086). 

Forecasted Oil 

Production 

(Bbbl)1

Mean Number of Spills Estimated to Occur Estimates of Probability (% chance)

of One or More Spills

Platforms Pipelines Tankers Total Platforms Pipelines Tankers Total

Single Proposed Lease Sale Alternatives

Alternative A2 0.210 0.05 0.19 0 0.24 5 17 <0.5 21

1.118 0.28 0.98 0.01 1.27 24 63 <0.5 72

Alternative B3 0.185 0.05 0.16 0 0.21 5 15 <0.5 19

0.970 0.24 0.85 0 1.10 22 57 <0.5 67

Alternative C4 0.026 0.01 0.02 0 0.03 1 2 <0.5 3

0.148 0.04 0.13 0 0.17 4 12 <0.5 15

Cumulative OCS Oil and Gas Program

Regionwide 15.482 3.87 13.62 0.08 17.57 98 >99.5 7 >99.5

25.806 6.45 22.71 0.13 29.29 >99.5 >99.5 12 >99.5

CPA/EPA 13.590 3.40 11.96 0.07 15.42 97 >99.5 7 >99.5

22.381 5.60 19.70 0.11 25.40 >99.5 >99.5 11 >99.5

WPA 1.892 0.47 1.66 0 2.14 38 81 <0.5 88

3.425 0.86 3.01 0 3.87 58 95 <0.5 98

Notes: Bbbl = billion barrels.

“Platforms” refers to facilities used in exploration, development, or production. 1

Values represent the low and high resource estimates. Refer to Table 3-1 for more information on resource estimates. 2

Proposed regionwide lease sale. 3

Proposed regionwide lease sale excluding blocks in the WPA.

4

Proposed regionwide lease sale excluding blocks in the CPA/EPA.

Source: Ji, official communication, 2015. 

Table 3-20. Oil-Spill Occurrence Probability Estimates for Offshore Spills ≥10,000 Barrels Resulting from 

Each Alternative (2017-2066) and the Cumulative OCS Oil and Gas Program (2017-2086). 

Forecasted Oil 

Production 

(Bbbl)1

Mean Number of Spills Estimated to Occur Estimates of Probability (% chance)

of One or More Spills

Platforms Pipelines Tankers Total Platforms Pipelines Tankers Total

Single Sale Alternatives

Alternative A2 0.210 0.03 0.04 0 0.07 3 4 <0.5 6

1.118 0.15 0.20 0 0.35 14 18 <0.5 29

Alternative B3 0.185 0.02 0.03 0 0.06 2 3 <0.5 6

0.970 0.13 0.17 0 0.30 12 13 <0.5 26

Alternative C4 0.026 0 0 0 0.01 <0.5 <0.5 <0.5 1

0.148 0.02 0.03 0 0.05 2 3 <0.5 4
Impact-Producing Factors and Scenario 3-125

Forecasted Oil 

Production 

(Bbbl)1

Mean Number of Spills Estimated to Occur Estimates of Probability (% chance)

of One or More Spills

Platforms Pipelines Tankers Total Platforms Pipelines Tankers Total

Cumulative OCS Oil and Gas Program

Regionwide 15.482 2.01 2.79 0.02 4.82 87 94 2 99

25.806 3.35 4.65 0.04 8.04 97 99 4 >99.5

CPA/EPA 13.590 1.77 2.45 0.02 4.23 83 91 2 99

22.381 2.91 4.03 0.04 6.97 95 98 4 >99.5

WPA 1.892 0.25 0.34 0 0.59 22 29 <0.5 44

3.425 0.45 0.62 0 1.06 36 46 <0.5 65

Notes: Bbbl = billion barrels.

“Platforms” refers to facilities used in exploration, development, or production. 1

Values represent the low and high resource estimates. Refer to Table 3-1 for more information on resource estimates. 2

Proposed regionwide lease sale. 

3

Proposed regionwide lease sale excluding blocks in the WPA. 

4

Proposed regionwide lease sale excluding blocks in the CPA/EPA. 

Source: Ji, official communication, 2015. 

3.2.1.4.4 Most Likely Source of Offshore Spills ≥1,000 bbl

Table 3-17 indicates the probabilities of one or more spills ≥1,000 bbl occurring from OCS 

facility or pipeline operations related to each alternative. The most likely cause of a spill ≥1,000 bbl 

is a pipeline break at the seafloor (Anderson et al., 2012). The various circumstances responsible 

for pipeline breaks included during the 1996-2010 analysis period were damage by an anchor, 

mudslide damage during a hurricane, a jack-up rig barge crushing the pipeline when it sat down on 

it, and microfractures from chronic contacts at a pipeline crossing where separators between the 

pipelines were missing.

3.2.1.4.5 Most Likely Size of an Offshore Spill ≥1,000 bbl

The estimated size of an offshore spill utilizes the median spill size from the trend analysis 

found in Anderson et al. (2012) for accidents occurring from drilling rig, platform, or pipeline

activities. Extreme events such as the Deepwater Horizon oil spill skew the average and, as such, 

does not provide a useful statistical measure. The median size of spills ≥1,000 bbl that occurred 

during 1996-2010 is 2,240 bbl. This size was calculated based on the nine spills (both platforms/rigs 

and pipelines) that occurred during this timeframe and included the Deepwater Horizon oil spill. For 

information on the mean number and size of spills estimated to occur for each alternative, refer to

Table 3-18. 

3.2.1.4.6 Length of Coastline Affected by Offshore Spills ≥1,000 bbl

The BOEM has previously estimated the length of shoreline that could be contacted if a spill 

≥1,000 bbl occurred as a result of an accident associated with each alternative (USDOI, MMS, 

2007a). The length of shoreline contacted is dependent upon the original spill size and the volume 

of oil removed by natural weathering and offshore cleanup operations prior to the slick making 

shoreline contact. The shoreline length contacted is a simple arithmetic calculation based on the 

area of the remaining slick. The calculation assumes that the slick will be carried 30 m (98 ft) 
3-126 Gulf of Mexico Multisale EIS

inshore of the shoreline, either onto the beachfront up from the water’s edge or into the bays and 

estuaries, and will be spread out at uniform thickness of 1 mm; this assumes that no oil-spill boom is 

used. The maximum length of shoreline affected by a spill of 4,600 bbl was estimated to be 

30-50 km (19-31 mi) of shoreline, assuming such a spill were to reach land within 12 hours. Some 

redistribution of the oil due to longshore currents and further smearing of the slick from its original 

landfall could also occur.

3.2.1.4.7 Risk Analysis by Resource

The BOEM analyzes risk to resources from oil spills and oil slicks that could occur as a result 

of each alternative. The results are based on BOEM’s estimates of likely spill locations, sources, 

sizes, frequency of occurrence, the physical fate of different types of oil slicks, and the probable 

transport that are described in more detail in the preceding spill scenarios. For offshore spills, 

combined probabilities were calculated using the OSRA model, which includes both the likelihood of 

a spill from each alternative occurring and the likelihood of the oil slick reaching areas where known 

resources exist.

The environmental, social and economic resources utilizing the OSRA modeling results were 

selected by BOEM analysts. Details on the individual resource categories, as well as a detailed 

analysis of the impacts to each resource from oil spills, are provided under each resource category 

in Chapter 4. 

3.2.1.4.8 Likelihood of an Offshore Spill ≥1,000 bbl Occurring and Contacting Coastal and 

Offshore Areas

A more complete measure of spill risk was calculated by multiplying the probability of contact 

generated by the OSRA model by the probability of occurrence of one or more spills 1,000 bbl as a 

result of each alternative. This provides a risk factor that represents the probability of a spill 

occurring as a result of each alternative and contacting a specified geographic area or feature. 

These are referred to as “combined probabilities” because they combine the risk of occurrence of a 

spill from OCS sources and the risk of such a spill contacting areas of sensitive environmental, 

social and economic resources. The combined probabilities for an offshore spill ≥1,000 bbl 

occurring and contacting coastal and offshore areas for each for each alternative can be found in the 

figures in Appendix E. 

To better reflect the geologic distribution of oil and gas resources and natural variances of 

meteorological and oceanographic conditions in the computation of combined probabilities, BOEM 

also generated combined probabilities for smaller areas within the GOM. A cluster analysis was 

used to analyze the contact probabilities generated for each of the 6,000 launch points. For this 

analysis, similar trajectories and contact to 10-mi (16-km) shoreline segments were tabulated to 

identify offshore cluster areas. The estimated oil production from each alternative was proportionally 

distributed to the cluster areas and the likelihood of spill occurrence was calculated for each cluster 

area. The probability of spill occurrence was combined with probabilities of contact from the 

trajectory modeling to estimate the combined risk of spills occurring and contacting specific areas 
Impact-Producing Factors and Scenario 3-127

from spills in each cluster area. To account for the risk of spills occurring from the transportation of 

oil to shore, generalized pipeline corridors originating within each of the offshore cluster areas and 

terminating at major oil pipeline landfall areas were developed. The oil volume estimated to be 

produced as a result of each alternative within each cluster area was proportioned among the 

pipeline corridors. The mean number of spills and the probability of contact of spills from each 

pipeline corridor were then calculated and combined with the risk of spills occurring and contacting 

resources from OCS facility development and production operations to complete the analysis.

3.2.1.5 Analysis of Offshore Spills <1,000 bbl

3.2.1.5.1 Estimated Number of Offshore Spills <1,000 bbl and Total Volume of Oil Spilled

The number of spills <1,000 bbl estimated to occur over the next 50 years as a result of each 

alternative is provided in Table 3-18. The number of spills is estimated by multiplying the oil-spill 

rate for each of the different spill size groups by the projected oil production as a result of each 

alternative (Tables 3-2 and 3-4). As spill size increases, the occurrence rate decreases and so the 

number of spills estimated to occur decreases.

3.2.1.5.2 Most Likely Source and Type of Offshore Spills <1,000 bbl

Most spills <1,000 bbl on the OCS would likely occur from a mishap on a production facility, 

most likely related to a failure related to the storage of oil. From 1995 to 2009, there were 

14,191 spills <1,000 bbl on platforms, rigs, or vessels and 1,139 spills from pipelines (Anderson 

et al., 2012). Spills on platforms and rigs could be crude or refined (diesel, hydraulic) oil. Reported 

pipeline spills are likely to be crude oil, and vessel spills are likely to be refined oil. For spills 

<1,000 bbl, a total of 19,050 bbl were released to OCS waters from platforms, rigs, or vessels, and 

8,002 bbl were released from pipelines.

3.2.1.5.3 Most Likely Size of Offshore Spills <1,000 bbl

Table 3-12 provides the most likely volume of oil estimated to be spilled for each of the spillsize groups. As stated previously, the estimated size of an offshore spill utilizes the median spill size 

from the trend analysis in Anderson et al. (2012) for all spill-size classes During the 50-year analysis 

period, 96 percent of all spills estimated to occur as a result of each alternative would be small spills 

<1 bbl (Anderson et al., 2012).

3.2.1.5.4 Likelihood of an Offshore Spill <1,000 bbl Occurring and Contacting Coastal and 

Offshore Areas

Because spills <1,000 bbl are not expected to persist as a slick on the surface of the water 

beyond a few days and because spills on the OCS would occur at least 3-10 nmi (3.5-11.5 mi; 

5.6-18.5 km) from shore, it is unlikely that any spills would make landfall prior to breaking up. For an 

offshore spill <1,000 bbl to make landfall, the spill would have to occur proximate to State waters 

(defined as 3-12 mi [5‐19 km] from shore). If a spill were to occur proximate to State waters, only a 

spill >50 bbl would be expected to have a chance of persisting long enough to reach land. Spills 
3-128 Gulf of Mexico Multisale EIS

>50 and <1,000 bbl are infrequent. Should such a spill occur, the volume that would make landfall 

would be expected to be extremely small (a few barrels).

3.2.1.6 Analysis of Coastal Spills 

Coastal spills occur in coastal waters, which are defined here as State offshore waters and 

spills in navigation channels, rivers, and bays from barges and pipelines carrying OCS-produced oil. 

These spills occur at shoreline storage, processing, and transport facilities supporting the OCS oil 

and gas industry. BOEM projects that most (>90%) oil produced as a result of a proposed action 

under Alternative A would be brought ashore via pipelines to oil pipeline shore bases, stored at 

these facilities, and eventually transferred via pipeline or barge to GOM coastal refineries. Because 

oil is commingled at shore bases and cannot be directly attributed to a particular lease sale, this 

analysis of coastal spills addresses spills that could occur prior to the oil arriving at the initial 

shoreline facility. It is also possible that non-OCS oil may be commingled with OCS oil at these 

facilities or during subsequent secondary transport.

3.2.1.6.1 Estimated Number and Most Likely Sizes of Coastal Spills 

According to USCG’s database for the most recent 13 years, January 2002-July 2015, 

(USDHS, CG, 2016) (Table 3-13), in the waters 0-9 nmi (0-10.36 mi; 16.67 km) off the Texas coast, 

there were a total of 91 spills reported from 2002 to 2015 or about 7 spills <1,000 bbl/yr. In the 

waters 0-3 nmi (0-3.45 mi; 5.56 km) off the Louisiana coast, there were a total of more than 

2,143 spills reported from 2002-2015, or about 165 spills <1,000 bbl/yr. In the waters 0-3 mi 

(0-5 km) off the Mississippi coast, there were a total of 2 spills reported from all sources, or about 

0.2 spills <1,000 bbl/yr. In the waters 0-3 nmi (0-3.45 mi; 5.56 km) off the Alabama coast, there 

were a total 2 spills reported from all sources from 2002-2015, or about 0.2 spills <1,000 bbl/yr. In 

the waters 0-9 nmi (0-10.36 mi; 16.67 km) off the Florida coast, there were a total 0 spills reported 

from all sources from 2002-2015,. When limited to just oil- and gas-related spill sources such as 

platforms, pipelines, MODU’s, and support vessels, the number and most likely spill sizes to occur in 

coastal waters in the future are expected to resemble the patterns that have occurred in the past as 

long as the level of energy-related commercial and recreational activities remain the same. The 

coastal waters of Louisiana, Texas, Mississippi, Alabama, and Florida have had a total of 165, 7, 

0.2, 0.2, and 0 spills <1,000 bbl/yr, respectively. Assuming future trends would reflect past historical 

records, it is also predicted that Louisiana will be the state most likely to have a spill ≥1,000 bbl 

occur in water 0-3 mi (0-5 km) offshore.

3.2.1.6.2 Likelihood of Coastal Spill Contact

Estimates of future coastal spills are based on historical spills reported to USCG. Based 

upon historical data, offshore Louisiana is the most likely location for the occurrence of a coastal 

spill. A spill that occurs in Federal waters could also be transported to State waters.
Impact-Producing Factors and Scenario 3-129

3.2.2 Losses of Well Control

All losses of well control are required to be reported to BSEE. In 2006, BOEM and BSEE’s 

predecessor (the Minerals Management Service), revised the regulations for loss of well control 

incident reporting, which were further clarified in NTL 2010-N05, “Increased Safety Measures for 

Energy Development on the OCS.” Operators are required to document any loss of well control 

event, even if temporary, and the cause of the event by mail or email to the addressee indicated in 

the NTL. The operator does not have to include kicks that were controlled but should include the 

release of fluids through a flow diverter (a conduit used to direct fluid flowing from a well away from 

the drilling rig). The current definition for loss of well control is as follows:

• uncontrolled flow of formation or other fluids (the flow may be to an exposed 

formation [an underground blowout] or at the surface [a surface blowout]);

• uncontrolled flow through a diverter; and/or

• uncontrolled flow resulting from a failure of surface equipment or procedures.

Not all loss of well control events would result in a blowout as defined above, but it is most 

commonly thought of as a release to the human environment. A loss of well control can occur during 

any phase of development, i.e., exploratory drilling, development drilling, well completion, 

production, or workover operations. A loss of well control can occur when improperly balanced well 

pressure results in sudden, uncontrolled releases of fluids from a wellhead or wellbore (PCCI Marine 

and Environmental Engineering, 1999; Neal Adams Firefighters, Inc., 1991).

Of the 48 loss of well control events reported in the GOM from 2007 to 2015, 26 (54%) 

resulted in loss of fluids at the surface or underground (USDOI, BSEE, 2016a).

The BSEE reports that they have had 288 unique loss of well control incidents captured in 

their database from 1956 to 2010 (Herbst, 2014), with an additional 22 incidents documented from 

2010 through August 2015. A synopsis conducted by BSEE of the 288 well incidents that occurred 

from 1956 through 2010 shows the following:

• 69 of the 288 incidents had duration greater than or equal to 5 days (24%); 

• 55 of the 69 incidents occurred in water depths <300 ft (91 m) (80%);

• 42 of the 69 incidents occurred within 50 mi (80 km) of shore (61%);

• a total of 31 fatalities occurred in 5 of the 69 incidents;

• a total of 84 injuries occurred in 7 of the 69 incidents; and

• 8 of the 69 incidents were oil blowouts (12%).

In contrast, the Deepwater Horizon oil spill continued uncontained for 87 days, between 

April 20 and July 15, 2010. The Deepwater Horizon blowout in Mississippi Canyon Block 252 
3-130 Gulf of Mexico Multisale EIS

resulted in the release of 4.9 MMbbl of oil and large quantities of gas (McNutt et al., 2011). For 

purposes of calculating the maximum possible civil penalty under the CWA, a January 2015 

judgement used a quantity of 4.0 MMbbl of oil for total discharged and 3.19 MMbbl of oil as the 

actual amount that was released into environment (Barbier and Shushan, 2015). As shown by the 

Deepwater Horizon explosion and oil spill, the loss of well control in deep water presents obstacles 

and challenges that differ from a loss of well control in shallow waters. Although many of the same 

techniques used for wild well control efforts in shallow water were used to attempt to control the 

Macondo well, these well control efforts were hindered by water depth, which required reliance 

solely upon the use of ROVs for all well intervention efforts. This is a concern in deep water 

because the inability to quickly regain control of a well increases the size of a spill.

There are several options that can be attempted to control a well blowout. Common kill 

techniques include (1) bridging, (2) capping/shut-in, (3) capping/diverting, (4) surface stinger, 

(5) vertical intervention, (6) offset kill, and (7) relief wells (Neal Adams Firefighters, Inc. 1991). 

Although much has been learned about well control as a result of the Deepwater Horizon explosion, 

oil spill, and response, if a deepwater subsea blowout occurs in the future, it is still likely that an 

operator would be required to immediately begin to drill one or more relief wells to gain control of the 

well. This may be required whether or not this is the first choice for well control because a relief well 

is typically considered the ultimate final solution for regaining well control in such circumstances. 

Although it can take months, the actual amount of time required to drill the relief well depends upon 

the following: (1) the depth of the formation below the mudline; (2) the complexity of the 

intervention; (3) the location of a suitable rig; (4) the type of operation that must be terminated in 

order to release the rig (e.g., may need to complete a casing program before releasing the rig); and 

(5) any problems mobilizing personnel and equipment to the location.

The major difference between a blowout during the drilling phase versus the completion or 

workover phases is the tendency for a drilling well to “bridge off.” Bridging is a phenomenon that 

occurs when severe pressure differentials are imposed at the well/reservoir interface and the 

formation around the wellbore collapses and seals the well. Deepwater reservoirs are susceptible to 

collapse under “high draw down” conditions. However, a completed well may not have the same 

tendency to passively bridge off as would a drilling well involving an uncased hole. Bridging would 

have a beneficial effect for spill control by slowing or stopping the flow of oil from the well (PCCI 

Marine and Environmental Engineering, 1999). There is a difference of opinion among blowout 

specialists regarding the likelihood of deepwater wells bridging naturally in a short period of time. 

Completed wells, or those in production, have more severe consequences in the event of a blowout 

due to the hole being fully cased down to the producing formation, which lowers the probability of 

bridging (PCCI Marine and Environmental Engineering, 1999). Therefore, the potential for a well to 

bridge is greatly influenced by the phase of a well. Refer to Chapter 3.2.8 for a discussion of 

planned well-source containment options that were designed to address an ongoing loss of well 

control event.
Impact-Producing Factors and Scenario 3-131

Blowout Preventers

A blowout preventer (BOP) is a device with a complex of choke lines and hydraulic rams 

mounted atop a wellhead designed to close the wellbore with a sharp horizontal motion that can cut 

through or pinch shut well casing and sever tool strings. The BOPs were invented in the early 

1920’s and have been instrumental in ending dangerous, costly, and environmentally damaging oil 

gushers on land and in water. The BOPs have been required for OCS oil and gas operations from 

the time offshore drilling began in the late 1940’s.

The BOPs are actuated as a last resort upon imminent threat to the integrity of the well or the 

surface rig. For cased wells, in a normal situation, the hydraulic ram may be closed if oil or gas from 

an underground zone enters the wellbore and destabilizes it. By closing a BOP, usually by 

redundant surface-operated and hydraulic actuators, the drilling crew can prevent explosive 

pressure release and allow control of the well to be regained by balancing the pressure exerted by a 

column of drilling mud with formation fluids or gases from below.

Because BOPs are important for the safety of the drilling crew, as well as the rig and the 

wellbore itself, BOPs are regularly inspected, tested, and refurbished. The post-Deepwater Horizon

explosion, oil spill, and response regulations and inspection program required for BOPs is discussed 

in Appendix A.5. 

Finalization of the Well Control Rule on April 29, 2016, resulted in reforms that establish 

(phased in over time) the following items: (1) incorporation of the latest industry standards that 

establish minimum baseline requirements for the design, manufacture, repair, and maintenance of 

blowout preventers; (2) additional controls over the maintenance and repair of BOPs; (3) use of dual 

shear rams in deepwater BOPs (API Standard 53); (4) requirement that BOP systems include a 

technology that allows the drill pipe to be centered during shearing operations; (5) more rigorous 

third-party certification of the shearing capability of BOPs; (6) expanded accumulator capacity and 

operational capabilities for increased functionality; (7) real-time monitoring capability for deepwater 

and high-temperature/high- pressure drilling activities; (8) establishment by regulation of criteria for 

the testing and inspection of subsea well containment equipment; (9) increased reporting of BOP 

failure data to BSEE and the Original Equipment Manufacturers (OEMs); (10) expectations set for

what constitutes a safe drilling margin and allows for alternative safe drilling margins when justified, 

(11) requirement for the use of accepted engineering principles and establishment of general 

performance criteria for drilling and completion equipment; (12) establishment of additional 

requirements for using remotely operated vehicles (ROVs) to function certain components on the 

BOP stack; (13) requirement for adequate centralization of the casing during cementing; and 

(14) makes the testing frequency of BOPs used on workover and decommissioning operations the 

same as drilling operations. Additonal information regarding the Well Control Rule can be found on 

BSEE‘s website at https://www.bsee.gov/guidance-and-regulations/regulations/well-control-rule. 

In addition, the Technology Assessment Program, a research element within BOEM’s 

regulatory program, supports research associated with operational safety and pollution prevention. 
3-132 Gulf of Mexico Multisale EIS

Since the Deepwater Horizon explosion, oil spill, and response, several well control-related studies 

have been funded through this program and the details of this research can be found on BSEE’s 

website at http://www.bsee.gov/Technology-and-Research/Technology-Assessment-Programs/

index/.

3.2.3 Accidental Air Emissions

Accidental events associated with offshore oil and gas activities can result in the emission of 

air pollutants. These OCS oil- and gas-related accidental events could include the release of oil, 

condensate, or natural gas; chemicals used offshore; pollutants from the burning of these products; 

fire; or H2S release. The air pollutants could include NAAQS criteria pollutants, volatile and semivolatile organic compounds, hydrogen sulfide, and methane. Emissions sources related to accidents 

from OCS operations can include well blowouts, oil spills, pipeline breaks, tanker accidents, and 

tanker explosions.

If a fire was associated with an accidental event, it could produce a broad array of pollutants 

including VOCs, NAAQS primary pollutants, and greenhouse gases. Although temporary in nature, 

response activities could impact air quality. These response activities could include in-situ burning, 

the use of flares to burn gas and oil, and the use of dispersants applied from aircraft. In-situ burning 

could impact air quality due to the possible release of toxic gases, and dispersants could impact air 

quality by possibly releasing toxic aromatics into the atmosphere. Atmospheric pollutants emitted 

from the Deepwater Horizon oil spill included plumes of organic aerosol particles and VOCs. In 

these plumes, the highly volatile species evaporated on time scales of <10 hours, while intermediate 

volatility evaporated between 10 and 1,000 hours. After the highly volatile species surfaced, they 

spread to a larger area due to surface currents and contributed to a wide spectrum of vapors 

(Bahreini et al., 2012). Additionally, in the presence of evaporating hydrocarbons from the oil spill, 

NOx emissions from the recovery and cleanup activities produced ozone (Middlebrook et al., 2012).

The presence of H2S within formation fluids occurs sporadically in the Gulf of Mexico OCS 

and may be released during an accident. Accidents involving the release of H2S could result in 

irritation, injury, and lethality from leaks; exposure to sulfur oxides produced by flaring; equipment 

and pipeline corrosion; and outgassing and volatilization from spilled oil. Regulations and NTLs 

include safeguards and protective measures, which are in place to protect workers from H2S 

releases.

3.2.3.1 Hydrogen Sulfide and Sulfurous Petroleum

Sulfur may be present in oil as elemental sulfur, within gas as H2S, or within organic 

molecules, all three of which vary in concentration independently. Safety and infrastructure

concerns include the following: irritation, injury, and even lethality to workers who are exposed to 

H2S from leaks; exposure to sulfur oxides produced by flaring; equipment and pipeline corrosion; 

and outgassing and volatilization from spilled oil.
Impact-Producing Factors and Scenario 3-133

Sour oil and gas occur sporadically throughout the Gulf of Mexico OCS, primarily off the 

Louisiana, Mississippi, and Alabama coasts. Sour hydrocarbon tends to originate in carbonate 

source or reservoir rocks that may not have abundant clay minerals that serve as a binder for 

elemental sulfur. If not bound in clay minerals, it remains free and can become a part of any 

hydrocarbon produced or sourced from that rock.

Deep gas reservoirs on the GOM continental shelf are likely to have high corrosive content, 

including H2S. There is some evidence that petroleum from deepwater areas may be sulfurous, but 

exploration wells have not identified deepwater areas that are extraordinarily high in H2S 

concentration.

BOEM reviews all exploration and development plans in the Gulf of Mexico OCS for the 

possible presence of H2S in the area(s) identified for exploration and development activities. 

Activities determined to be associated with a presence of H2S are subjected to further review and 

requirements. Federal regulations at 30 CFR § 250.490(c) require all lessees, prior to beginning 

exploration or development operations, to request a classification of the potential for encountering 

H2S. The classification is based on previous drilling and production experience in the areas 

surrounding the proposed operations, as well as other factors.

According to BSEE’s regulations at 30 CFR § 250.490(f), all operators on the OCS involved 

in production of sour gas or oil (i.e., >20 ppm) are also required to file an H2S Contingency Plan. 

This plan lays out procedures to ensure the safety of the workers on the production facility. In 

addition, all operators are required under 30 CFR § 250.107 to adhere to the National Association of 

Corrosion Engineers’ (NACE) Standard Material Requirements—Methods for Sulfide Stress 

Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments (NACE MR0175-

2003) (NACE, 2003) as best available and safest technology. The NACE standards that relate to an 

H2S partial pressure of 0.05 pounds per square inch absolute primarily address stress cracking and 

stress corrosion resistance, while BSEE’s definition of “H2S present” addresses human safety and 

protecting the environment for H2S concentrations equal to or exceeding 20 ppm. The BSEE is 

concerned if either threshold is crossed (NTL 2009-G31). These engineering standards preserve 

the integrity of infrastructure through specifying equipment to be constructed of materials with 

metallurgical properties that resist or prevent sulfide stress cracking and stress corrosion cracking in 

the presence of sour gas. The BSEE issued a final rule (30 CFR § 250.490; Federal Register, 1997) 

governing requirements for preventing H2S releases, detecting and monitoring H2S and sulfur 

dioxide, protecting personnel, providing warning systems and signage, and establishing 

requirements for H2S flaring and venting. The NTL 2009-G31 establishes Standard Material 

Requirements, Materials for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in 

Sour Oilfield Environments (NACE Standard MR0175-2003) as best available and safest technology, 

provides further guidance on classifying an area for the presence of H2S, includes guidance on H2S 

detection, updates regulatory citations, and includes a guidance document statement. Hydrogen 

sulfide contingency plans are discussed in Appendix A.8. 
3-134 Gulf of Mexico Multisale EIS

3.2.4 Pipeline Failures

Significant sources of damages to OCS pipeline infrastructure can be caused by corrosion 

(Chapters 3.1.3.3.1 and 3.1.6.1), physical pipeline stress due to location, mass sediment 

movements and mudslides that can exhume or push the pipelines into another location, and 

accidents due to weather or impacts from anchor drops or boat collisions. 

Long unsupported pipelines subjected to strong bottom currents will experience vortexinduced vibrations, which significantly increase pipeline fatigue. Two potential causes for pipeline 

failure are regional-scale hydrodynamic forces and vortex-induced vibrations. Hydrodynamic forces 

are of most concern to pipelines with multiple unsupported spans. In conjunction with strong 

episodic events, these pipelines may experience lateral instability and movement. Although the 

effects of hydrodynamic forces warrant attention, vortex-induced vibrations are perhaps of greatest 

concern.

Following the 2004, 2005, and 2008 hurricane seasons, BOEM commissioned studies to 

examine the failure mechanisms of offshore pipelines (Atkins et al., 2006 and 2007; Energo 

Engineering, 2010). Numerous pipelines were damaged after the 2004-2008 hurricanes passing 

through the CPA and WPA. Much of the reported damage was riser or platform-associated damage, 

which typically occurs when a platform is toppled or otherwise damaged. While many pipelines were 

damaged, few resulted in a spill >50 bbl. The total pipeline damage reports and number of spills are 

listed by hurricane below.

Hurricane Total Pipeline

Damage Reports

Number of Spills 

>50 bbl

Ivan 168 8

Katrina 299 5

Rita 243 5

Gustav and Ike 314 6

The largest spills are typically due to pipeline movements, mudslides, anchor drops, and 

collisions of one type or another. Most pipeline damage occurs in shallow water (<200 ft; 61 m) 

because of the potential for increasing impacts of the storm on the seabed in shallow water, the 

relative density of pipelines, or the age and design standards of the pipeline or the platforms to 

which the pipelines are connected. The future impact of hurricanes on damage to pipelines is 

uncertain. As oil production shifts from shallow to deeper water, there may be a consolidation of 

pipeline utilization.

The uncertain location of pipelines (both active and abandoned in place) is an ongoing safety 

and environmental hazard. On October 23, 1996, in Tiger Pass, a channel through the Mississippi 

River Delta into the Gulf of Mexico near Venice, Louisiana, the crew of the Bean Horizon 

Corporation dredge Dave Blackburn dropped a stern spud (a large steel shaft that is dropped into 

the river bottom to serve as an anchor and a pivot during dredging operations) into the bottom of the 

channel in preparation for continued dredging operations. The spud struck and ruptured a 12-in 
Impact-Producing Factors and Scenario 3-135

(30-cm) diameter, submerged natural gas steel pipeline. Within seconds of reaching the surface, the 

natural gas ignited, destroying the dredge and the tug (USDOT, National Transportation Safety 

Board, 1998). Lack of awareness of the precise location of the pipeline was a major contributing 

factor to this accident (USDOT, National Transportation Safety Board, 1998). On December 5, 

2003, this Agency received an incident report that a cutterhead dredge barge ruptured a 20-in 

(51-cm) diameter condensate pipeline in Eugene Island Block 39. Lack of awareness of the precise 

location of the pipeline was the major contributing factor to this accident as well. An OCS-related 

spill ≥1,000 bbl would likely be from a pipeline accident; the median spill size is estimated to be 

2,200 bbl for rig/platform and pipeline activities supporting each alternative (Tables 3-14 and 3-15). 

For Alternative A, B, or C, up to one spill of this size is estimated to occur.

3.2.5 Vessel and Helicopter Collisions

BOEM’s data show that, from 2007 to 2014, there were 137 OCS oil- and gas-related vessel 

collisions (USDOI, BSEE, 2015c). Most collision mishaps are the result of service vessels colliding 

with platforms or vessel collisions with pipeline risers. Fires resulted from hydrocarbon releases in 

several of the collision incidents. Diesel fuel is the product most frequently spilled, while oil, natural 

gas, corrosion inhibitor, hydraulic fluid, and lube oil have also been released as the result of a vessel 

collision. Approximately 10 percent of vessel collisions with platforms in the OCS caused diesel 

spills. To date, the largest diesel spill associated with a collision occurred in 1979 when an anchorhandling boat collided with a drilling platform in the Main Pass leasing area, spilling approximately 

1,500 bbl. Human error accounts for approximately half of all reported vessel collisions from 2006 to 

2010. Safety fairways, traffic separation schemes, and anchorages are the most effective means of 

preventing vessel collisions with OCS structures. In 2014, an approximated 3,571 bbl of bunker fuel 

spilled into the Houston Ship Channel after a collision between a barge and a ship.

In general, fixed structures such as platforms and drilling rigs are prohibited in fairways. 

Temporary underwater obstacles, such as anchors and attendant cables or chains attached to 

floating or semisubmersible drilling rigs, may be placed in a fairway under certain conditions. A 

limited number of fixed structures may be placed at designated anchorages. The USCG’s 

requirements for indicating the location of fixed structures on nautical charts and for lights, soundproducing devices, and radar reflectors to mark fixed structures and moored objects also help 

minimize the risk of collisions. To prevent any further incidents in regard to collisions with 

submerged or destroyed platforms following Hurricanes Katrina and Rita, in December 2005, the 

Bureau of Ocean Energy Management, Regulation and Enforcement published a safety alert that 

provided the location of all facilities that were destroyed during the storms. In addition, USCG’s

8th District’s Local Notice to Mariners (monthly editions and weekly supplements) informs GOM 

users about the addition or removal of drilling rigs and platforms, locations of aids to navigation, and 

defense operations involving temporary moorings. Marked platforms often become aids to 

navigation for vessels (particularly fishing boats and vessels supporting offshore oil and gas

operations) that operate in areas with high densities of fixed structures.
3-136 Gulf of Mexico Multisale EIS

The National Offshore Safety Advisory Committee (NOSAC, 1999) examined collision

avoidance measures between a generic deepwater structure and marine vessels in the GOM. The 

NOSAC offered three sets of recommendations: (1) voluntary initiatives for offshore operators; 

(2) joint government/industry cooperation or study; and (3) new or continued USCG action. The 

NOSAC (1999) proposes that oil and gas facilities be used as aids-to-navigation because of their 

proximity to fairways, fixed nature, well-lighted decks, and inclusion on navigational charts. Mariners 

intentionally set and maintain course toward these facilities, essentially maintaining a collision 

course. Unfortunately, most deepwater facilities do not install collision avoidance radar systems to 

alert offshore facility personnel of a potentially dangerous situation. The NOSAC estimates that 

7,300 large vessels (tankers, freight ships, passenger ships, and military vessels) pass within 35 mi 

(56 km) of a typical deepwater facility each year. This estimate resulted in approximately 20 transits 

per day for the 13 deepwater production structures existing in 1999. The NOSAC found the total 

collision frequency to be approximately one collision per 250 facility-years (3.6 x 10-3 per year). The 

NOSAC estimated that, if the number of deepwater facilities increases to 25, the estimated total 

collision frequency would increase to one collision in 10 years. A cost-benefit analysis within the 

report did not support the use of a dedicated standby vessel for the generic facility; however, the 

analysis did support the use of a radar system on deepwater facilities if the annual costs of the 

system were less than or equal to $124,500.

The OCS oil- and gas-related vessels could strike marine mammals, sea turtles, and other 

marine animals during transit. To limit or prevent such strikes, NMFS provides all boat operators 

with whale-watching guidelines, which is derived from the Marine Mammal Protection Act. These 

guidelines suggest safe navigational practices based on speed and distance limitations when 

encountering marine mammals. The frequency of vessel strikes with marine mammals, sea turtles, 

or other marine animals probably varies as a function of spatial and temporal distribution patterns of 

the living resources, as the pathways of maritime traffic (coastal traffic is more predictable than 

offshore traffic), and as a function of vessel speed, the number of vessel trips, and the navigational 

visibility.

The average number of helicopter accidents per year in the GOM since 1984 has been 

7.9 per year, with the last 10 years averaging 4.7 per year and with only two in 2014. The 2014 

GOM oil industry helicopter accident rate per 100,000 flight hours was 0.68, with a total of two 

accidents compared with a 31-year annual average accident rate of 1.74. The fatal accident rate per 

100,000 flight hours during 2014 was 0.34 compared with a 31-year average of 0.44 (Heliport Safety 

Advisory Conference, 2015).

Since 1999, there have been 23 accidents of which only 5 were fatal; this resulted in 

13 fatalities and 15 injuries. The leading causes, not all inclusive, of the accidents since 1999 were 

engine related, loss of control or improper procedures, helideck obstacle strikes, controlled flight into 

terrain, and other technical failures (Helicopter Safety Advisory Conference, 2015).
Impact-Producing Factors and Scenario 3-137

3.2.6 Chemical and Drilling-Fluid Spills

Chemicals and synthetic-based drilling fluids are used in offshore oil and gas drilling and 

production activities, and may be spilled to the environment due to equipment failure, weather (i.e., 

wind, waves, and lightning), accidental collision, and human error.

Chemicals are stored and used to condition drill muds during production and in well 

completions, stimulation, and workover procedures. The relative quantity of their use is reflected in 

the largest volumes spilled. Well completion, workover, and treatment fluids, including calcium 

chloride brine and zinc bromide, are the largest quantity used and are typically the largest accidental 

releases. Zinc bromide is of particular concern because it is persistent (nondegradable) and is 

comparatively toxic. A study of chemical spills from OCS oil- and gas-related activities determined 

that only two chemicals could potentially impact the marine environment—zinc bromide and 

ammonium chloride (Boehm et al., 2001). Other common chemicals spilled include methanol and 

ethylene glycol, which are used in deepwater operations where gas hydrates tend to form due to 

cold temperatures. These alcohol-based chemicals are nonpersistent (degradable) and exhibit 

comparatively low toxicity.

The SBF has typically been used since the mid-1990s for the deeper well sections because 

SBF has superior performance properties. The synthetic oil used in SBF is relatively nontoxic to the 

marine environment and has the potential to biodegrade. However, SBF is considered more toxic 

than water-based fluid, and spills of SBF are categorized separately from water-based fluid releases. 

Accidental riser disconnections result in the release of large quantities of drilling fluid.

Refer to Table 3-21 for information on spill statistics for chemicals and SBFs for 2007-2012 

(USDOI, BSEE, 2015c). The BSEE reports spills in categories of 10-49 bbl (small spills) and >50 bbl

(large spills). Table 3-21 shows the total annual spill volumes in barrels of product lost for SBFs and 

chemicals in both spill size categories. The number of spill incidents per year are listed with the 

average spill volume in barrels for a given year.

Table 3-21. Number and Volume of Chemical and Synthetic-Based Fluid Spills for 

10-49 Barrels and >50 Barrels in the Gulf of Mexico from 2007 through 2014. 

Year

Product Lost 

(bbl) Number of Spills Average Spill Volume (bbl)

SBF Chemical SBF Chemical SBF Chemical

A. Spills 10-49 bbl

2007 110 17 6 1 18 17

2008 73 102 2 6 37 17

2009 38 24 1 2 38 12

2010 54 51 3 3 18 17

2011 73 0 2 0 37 0

2012 88 12 4 1 22 12

2013 51 20 2 1 26 20
3-138 Gulf of Mexico Multisale EIS

Year

Product Lost 

(bbl) Number of Spills Average Spill Volume (bbl)

SBF Chemical SBF Chemical SBF Chemical

A. Spills 10-49 bbl

2014 0 0 0 0 0 0 

Average 

Value 61 28 3 2 24 12

B. Spills Greater Than 50 bbl

Year Product Lost (bbl) Number of Spills Average Spill Volume 

(bbl)

SBF Chemical SBF Chemical SBF Chemical

2007 1,518 550 2 1 759 550

2008 1,849 3,229 2 16 925 202

2009 602 500 4 3 151 167

2010 131 123 2 1 66 123

2011 252 0 2 0 126 0 

2012 158 1,595 3 5 53 319

2013 0 0 0 0 0 0 

2014 323 66 3 1 108 66

Average 

Value 604 758 2 3 273 178

SBF = synthetic-based fluid.

During the period of 2007 to 2014, small SBF spills occurred at an average annual volume of 

61 bbl, while large spills occurred at an annual average volume of 601 bbl. During the same period, 

small chemical spills occurred at an average annual volume of 28 bbl, while large chemical spills 

occurred at an average annual volume of 758 bbl. Small SBF spills averaged 24 bbl per spill, while 

large SBF spills averaged 178 bbl per spill. A spike in the volume of large chemical spills in 2008 is 

attributed to Hurricane Ike, which occurred on September 13, 2008.

3.2.7 Trash and Debris

The discharge of marine debris by the offshore oil and gas industry and supporting activities 

is subject to a number of laws and treaties. These include the Marine Debris Research, Prevention, 

and Reduction Act; the Marine Plastic Pollution Research and Control Act; and the MARPOL-Annex 

V treaty. Regulation and enforcement of these laws is conducted by a number of agencies such as 

USEPA, NOAA, and USCG. The BSEE policy regarding marine debris prevention is outlined in NTL 

2015-BSEE-G03, “Marine Trash and Debris Awareness and Elimination.” This NTL instructs OCS 

operators to post informational placards that outline the legal consequences and potential ecological 

harms of discharging marine debris. This NTL also states that OCS workers should complete 

annual marine debris prevention training; operators are also instructed to develop a certification 

process for the completion of this training by their workers. These various laws, regulations, and 

NTL would likely minimize the discharge of marine debris from OCS operations.
Impact-Producing Factors and Scenario 3-139

Occasionally during construction or operation, equipment may be dropped to the seafloor. If 

this happens within the planned construction site, the bottom-disturburbing impacts are 

conservatively considered as part of the routine impacts; however, accidental drops may occur 

during transport.

3.2.8 Spill Response

3.2.8.1 BSEE Spill-Response Requirements and Initiatives

3.2.8.1.1 Spill-Response Requirements

As a result of the Oil Pollution Act of 1990 and the reorganization of the Bureau of Ocean 

Energy Management, Regulation and Enforcement into BOEM and BSEE, BSEE was tasked with a 

number of oil-spill response duties and planning requirements. Within BSEE, the Oil Spill

Preparedness Division addresses all aspects of offshore oil-spill planning, preparedness, and 

response. Additional information about the Oil Spill Preparedness Division can be found on BSEE’s 

website at http://www.bsee.gov/About-BSEE/Divisions/OSPD/index/. 

The BSEE implements the following regulations according to 30 CFR parts 250 and 254:

• requires immediate notification for spills >1 bbl—all spills require notification to 

USCG, and BSEE receives notification from USCG of all spills ≥1 bbl;

• conducts investigations to determine the cause of a spill;

• assesses civil and criminal penalties, if needed;

• oversees spill source control and abatement operations by industry;

• sets requirements and reviews and approves OSRPs for offshore facilities (More 

information on oil-spill response plan regulations and processes can be found in 

Appendix A.5.);

• conducts unannounced drills to ensure compliance with OSRPs;

• requires operators to ensure that their spill-response operating and management 

teams receive appropriate spill-response training;

• conducts inspections of oil-spill response equipment;

• requires industry to show financial responsibility to respond to possible spills; and

• provides research leadership to improve the capabilities for detecting and 

responding to an oil spill in the marine environment.

BOEM receives and reviews the worst-case discharge information submitted for EPs, DPPs, 

and DOCDs on the OCS. BOEM also has regulatory requirements addressing site-specific OSRPs 

and spill-response information. As required by BOEM at 30 CFR §§ 550.219 and 550.250, 

operators are required to provide BOEM with an OSRP that is prepared in accordance with 30 CFR 
3-140 Gulf of Mexico Multisale EIS

part 254 subpart B with their proposed exploration, development, or production plan for the facilities 

that they will use to conduct their activities; or to alternatively reference their approved regional 

OSRP by providing the following information:

• a discussion of the approved regional OSRP;

• the location of the primary oil-spill equipment base and staging area;

• the name of the oil-spill equipment removal organization(s) for both equipment 

and personnel;

• the calculated volume of the worst-case discharge in accordance with 30 CFR § 

254.26(a) and a comparison of the worst-case discharge in the approved 

regional OSRP with the worst-case discharge calculated for the proposed 

activities; and

• a description of the worst-case discharge response scenario to include the 

trajectory information, potentially impacted resources, and a detailed discussion 

of the spill response proposed to the worst-case discharge in accordance with 

30 CFR §§ 254(b)-(e).

All OSRPs are reviewed and approved by BSEE, whether submitted with a BOEMassociated plan or directly to BSEE in accordance with 30 CFR part 254. Hence, BOEM relies 

heavily upon BSEE’s expertise to ensure that the OSRP complies with all pertinent laws and 

regulations, and demonstrates the ability of an operator to respond to a worst-case discharge. 

BOEM’s regulations require that an operator must have an approved OSRP prior to BOEM’s 

approval of an operator-submitted exploration, development, or production plan.

The operator is also required to carry out the training, equipment testing, and periodic drills 

described in the OSRP. In addition, since 1989, BSEE has conducted government-initiated 

unannounced exercises. In any given year, BSEE will hold both table-top, unannounced exercises 

and a limited number of response equipment deployment unannounced exercises. Equipment 

deployment exercises are held when BSEE elects to conduct an exercise of an operator’s 

procurement, loading, and deployment of certain pieces of oil-spill response equipment that are cited 

within an operator’s OSRP. The BSEE equipment deployment exercises are designed most often to 

take place in open water in waterways adjacent to where the equipment is stored in order to test the 

equipment that is proposed to be utilized offshore during the response, but the exercise may be 

moved to an alternate location if BSEE’s exercise parameters require it. In addition, BSEE can also 

require that the nearshore and onshore equipment be deployed if a BSEE-developed drill scenario 

requires it. Drills testing the nearshore and onshore equipment would typically take place in an 

onshore or nearshore environment within the vicinity of a staging or storage area.

Any dispersant application included as part of the drill scenario always simulates the actual 

application of dispersant during BSEE’s drills. No actual dispersants are ever utilized during the 

drills. Likewise, the oil spill itself is only simulated during any of BSEE’s unannounced drills. Typical 
Impact-Producing Factors and Scenario 3-141

BSEE unannounced deployment exercises last only a few hours and rarely take longer than a day. 

Multi-day scenarios only occur when a more complicated drill scenario is developed by BSEE to test 

an operator’s ability to adequately respond. Several NTLs and guidance documents have been 

issued by BOEM and BSEE that clarify oil-spill requirements since the occurrence of the Deepwater

Horizon explosion, oil spill, and response. More information on these NTLs and guidance 

documents can be found in Appendix A.5. 

3.2.8.1.2 Spill-Response Initiatives

For more than 25 years, BSEE and its predecessors have maintained a comprehensive longterm research program to improve oil-spill response knowledge and technologies. The major focus 

of the program is to improve the methods and technologies used for oil-spill detection, containment, 

treatment, recovery, and cleanup. The BSEE Oil Spill Response Research program is a cooperative 

effort bringing together funding and expertise from research partners in State and Federal 

government agencies, industry, academia, and the international community. The funded projects 

cover numerous spill-response-related issues such as chemical treating agents; in-situ burning of oil; 

research conducted at BSEE’s Oil Spill Response Test Facility (Ohmsett) located in Leonardo, New 

Jersey; behavior of oil; decisionmaking support tools; mechanical containment; and remote sensing.

The BSEE’s recently awarded research contracts that highlight the varied types of research 

projects can be found on BSEE’s website at http://www.bsee.gov/Technology-and-Research/OilSpill-Response-Research/index/. 

3.2.8.2 Offshore Response, Containment, and Cleanup Technology

In the event of a spill, particularly a loss of well control, there is no single method of 

containment and removal that would be 100 percent effective. Spill cleanup is a complex and 

evolving technology. There are many situations and environmental conditions that necessitate 

different approaches. New technologies constantly evolve, but they provide only incremental 

benefits. Each new tool then becomes part of the spill-response tool kit. Each spill-response 

technique/tool has its specific uses and benefits (Fingas, 1995). Offshore removal and spillcontainment efforts to respond to an ongoing spill offshore would likely require multiple technologies, 

including source containment, mechanical spill containment and cleanup, in-situ burning of the slick, 

and the use of chemical dispersants. Even with the deployment of all of these spill-response 

technologies, it is likely that, with the operating limitations of today’s spill-response technology, not 

all of the oil can be contained and removed offshore.

Because no single spill-response method is 100 percent effective, it is likely that larger spills 

under the right conditions would require the simultaneous use of all available cleanup methods (i.e., 

source containment, mechanical spill containment and cleanup, dispersant application, and in-situ

burning). Accordingly, the response to the Deepwater Horizon explosion, oil spill, and response

employed all of these options simultaneously. The cleanup technique chosen for a spill response 

would vary depending upon the unique aspects of each situation. The selected mix of 

countermeasures would depend upon the shoreline and natural resources that may be impacted; the 
3-142 Gulf of Mexico Multisale EIS

size, location, and type of oil spilled; weather; and other variables. The overall objective of on-water 

recovery is to minimize the risk of impact by preventing the spread of free-floating oil. The physical 

and chemical properties of crude oil can greatly affect the effectiveness of containment and recovery 

equipment, dispersant application, and in-situ burning. It is expected that oil found in the majority of 

the proposed lease sale area could range from medium weight oil to condensate. The variety of 

standard cleanup protocols that were used for removing Deepwater Horizon oil from beaches, 

shorelines, and offshore water are identified in Table 3-22. 

Table 3-22. Primary Cleanup Options Used during the Deepwater Horizon Response. 

Fresh Oil Sheens Mousse Tarballs Burn Residue

On-Water 

Response

Disperse, skim, 

burn

Light sheens very 

difficult to recover, 

heavier sheens 

picked up with 

sorbent boom or 

sorbent pads

Skim Snare boom Manual removal

On-Land 

Response

Sorbent pads, 

manual recovery, 

flushing with water, 

possible use of 

chemical shoreline 

cleaning agents

Light sheens very 

difficult to recover, 

heavier sheens 

picked up with 

sorbent boom or 

sorbent pads

Sorbent 

pads, manual 

recovery

Snare boom, 

manual 

removal, beach 

cleaning 

machinery

Manual removal

Source: USDOC, NOAA, 2010a.

Most oil-spill response strategies and equipment are based upon the simple principle that oil 

floats. However, as evident during the Deepwater Horizon explosion, oil spill, and response, this is 

not always true. Sometimes it floats and sometimes it suspends within the water column or sinks to 

the seafloor (refer to Chapter 3.2.1.3). Oil suspended in the water column and moving with the 

currents is difficult to track and recover using standard visual survey methods (Coastal Response 

Research Center, 2007).

Source Containment

The NTL 2010-N10 states that offshore operators address containment system expectations 

to be able to rapidly contain a spill as a result of a loss of well control from a subsea well. This 

resulted in the development of rapid response containment systems that are available through either 

the Marine Well Containment Company (MWCC) or Helix Well Ops in the Gulf of Mexico. In 

addition, industry has a multitude of vendors available within the GOM region that can provide the 

services and supplies necessary for debris removal capability, dispersant injection capability, and 

top-hat deployment capability. Many of these vendors are already cited for use by MWCC and Helix 

Well Ops. The BSEE does not allow an operator to begin drilling operations until adequate subsea 

containment and collection equipment, as well as subsea dispersant capability, is determined by 

BSEE to be available to the operator and is sufficient for use in response to a potential incident from 

the proposed well(s).
Impact-Producing Factors and Scenario 3-143

Marine Well Containment Company

The Marine Well Containment Company’s (MWCC’s) Containment System includes two 

modular capture vessels (MCVs); enhanced subsea umbilical, risers, and flowlines (SURF) 

equipment; three capping stacks; and additional ancillary equipment. The capping stack is uniquely 

designed to shut off the flow of fluid from the well or by providing a conduit to safely flow well fluids 

to the two MCVs. The processing equipment on the MCVs can separate sand and process liquids 

and gases flowed from a damaged subsea well. The MWCC Containment System is built for use in 

the deepwater Gulf of Mexico, defined as water depths from 500 to 10,000 ft (1,524-3,048 m), in 

temperatures up to 350 °F (177 °C), and under pressure up to 15,000 psi. The MWCC’s suite of 

containment equipment enables the company to mobilize and deploy the most appropriate well 

containment technology based upon the unique well control incident and equipment requirements. 

The system has the capacity to contain up to 100,000 bbl of liquid per day (4.2 million gallons/day) 

and handle up to 200 million standard cubic feet of gas per day. It is envisioned that this system 

could be fully operational within days to weeks after a spill event occurs (Marine Spill Response 

Corporation, 2015a).

The Marine Well Containment Company’s SURF equipment, which is used to flow fluid from 

the capping stack to the MCVs as well as to provide dispersant and hydrate mitigation injection, is 

staged in Theodore, Alabama. The MWCC houses, stores, and tests the processing equipment for 

the two MCVs as well as its capping stacks in Ingleside, Texas. The companies that originated this 

system have formed a nonprofit organization, the Marine Well Containment Company, to operate 

and maintain the system (Marine Spill Response Corporation, 2015a). The MWCC would provide 

fully trained crews to operate the system, ensure the equipment is operational and ready for rapid 

response, and conduct research on new containment technologies (Marine Spill Response 

Corporation, 2015a).

In the summer of 2012, a full-scale deployment of MWCC’s critical well-control equipment to 

exercise the oil and gas industry’s response to a potential subsea blowout in the deep water of the 

Gulf of Mexico was conducted by BSEE. The MWCC’s 15,000-psi capping stack system, a 30-ft 

(9-m) tall, 100-ton piece of equipment similar to the one that stopped the flow of oil from the 

Macondo well following the Deepwater Horizon explosion in 2010, was successfully tested during 

this deployment drill. During this exercise, the capping stack was deployed from its storage location 

in Ingleside, Texas, to an area in the Gulf of Mexico nearly 200 mi (322 km) from shore. Once on 

site, the system was lowered to a simulated wellhead (a pre-set parking pile) on the ocean floor in 

nearly 7,000 ft (2,134 m) of water, connected to the wellhead, and then pressurized to 10,000 psi. 

Helix Well Ops

Another option for source control and containment in the Gulf of Mexico is through Helix Well 

Ops. Helix Well Ops contracted the equipment that it found useful in the Deepwater Horizon

explosion, oil spill, and response and offered it to oil and gas producers for use beginning January 1, 

2011. This system focused on the utilization of the Helix Producer I and the Q4000 vessels. Each 

of these vessels played a role in the Deepwater Horizon explosion, oil spill, and response explosion, 
3-144 Gulf of Mexico Multisale EIS

oil spill, and was continually working in the Gulf of Mexico. Helix Well Ops’ system, which is referred 

to as the Helix Fast Response System today, has the ability to fully operate in up to 10,000 ft 

(3,048 m) of water and has intervention equipment to cap and contain a well with the mechanical 

integrity to be shut-in. The Helix Fast Response System also has the ability to capture and process 

57,000 bbl of oil per day, 72,000 bbl of liquid per day, and 120 million standard cubic feet per day at 

10,000 psi (Helix Well Containment Group, 2015).

In April-May 2013, a full-scale deployment of Helix Well Ops’ critical well-control equipment 

to exercise the oil and gas industry’s response to a potential subsea blowout in the deep water of the 

Gulf of Mexico was conducted by BSEE. Helix Well Ops’ capping stack system is a 20-ft (6-m) tall, 

146,000-pound piece of equipment similar to the one that stopped the flow of oil from the Macondo

well following the Deepwater Horizon explosion in 2010. It was successfully tested during this 

unannounced deployment drill. The capping stack was deployed from its storage location and once 

onsite, the system was lowered to a simulated wellhead (a pre-set parking pile) on the ocean floor in 

nearly 5,000 ft (1,524 m) of water, connected to the wellhead, and then pressurized to 8,400 psi. 

3.2.8.2.1 Mechanical Cleanup

Generally, mechanical containment and recovery is the primary oil-spill response method 

used (33 CFR § 153.305(a)). Mechanical recovery is the process of using booms and skimmers to 

remove oil from the water surface. Booms are used to enclose oil and prevent it from spreading; to 

protect harbors, bays, and biologically sensitive areas; to divert oil to areas where it can be 

recovered or treated; and to concentrate oil and maintain an even thickness so that skimmers can be 

used; or other cleanup techniques, such as in-situ burning, can be applied. Sorbent booms are 

specialized containment and recovery devices made of porous sorbent material such as woven or 

fabric polypropylene, which absorbs oil while it is being contained. Sorbent booms are used when 

the oil slick is relatively thin for final polishing of an oil spill, to remove small traces of oil or sheen, or 

as a backup to other booms. Skimmers are mechanical devices designed to remove oil from the 

water surface. Skimmers are classified according to their basic operating principles: oleophilic 

surface skimmers; weir skimmers; suction skimmers or vacuum devices; elevating skimmers; and 

submersion skimmers (Fingas, 2013).

It is expected that the oil-spill response equipment needed to respond to an offshore spill in 

the proposed sale area could be called out from one or more of the following oil-spill equipment base 

locations: New Iberia, Belle Chasse, Baton Rouge, Sulphur, Morgan City, Port Fourchon, Harvey, 

Houma, Galliano, New Iberia, Leeville, Fort Jackson, Venice, Grand Isle, or Lake Charles, Louisiana; 

Corpus Christi, Port Arthur, Aransas Pass, Ingleside, Galveston, or Houston, Texas; Pascagoula or 

Kiln, Mississippi; Mobile or Bayou La Batre, Alabama; and/or Panama City, Pensacola, Tampa, 

and/or Miami, Florida (Clean Gulf Associates, 2015; Marine Spill Response Corporation, 2015b; 

National Response Corporation, 2015). Response times for any of this equipment would vary, 

depending on the location of the equipment, the staging area, and the spill site; and on the transport 

requirements for the type of equipment procured. It is anticipated that equipment would be procured 

from the closest available oil-spill staging areas. 
Impact-Producing Factors and Scenario 3-145

As indicated in Chapter 3.2.8.1 and Appendix A.5, BSEE oversees a research program to 

improve the capabilities for detecting and responding to an oil spill in the marine environment. One 

of BSEE’s recently completed research projects suggested an alternative to improve the present 

regulatory requirements at 30 CFR § 254.44 for determining the effective daily recovery capacity of 

spill-response skimming equipment. This suggested alternative would consider the encounter rate 

of a skimming system with spilled oil instead of the presently used de-rated pump capacity of a 

skimmer. This project was undertaken because the Deepwater Horizon oil-spill response highlighted 

that the existing regulation may not be an effective or accurate planning standard and predictor of 

oil-spill response equipment recovery capacity. The project was completed in 2012 and the National 

Academy of Sciences completed a peer review in 2013. The USCG has indicated that the guidance 

generated by this research is applicable for offshore use but that a separate standard would still 

need to be developed for nearshore response capability determinations.

If an oil spill occurs during a storm, spill response from shore may be delayed to after the 

storm. Spill response would not be possible while storm conditions continued, given the sea-state 

limitations for skimming vessels and containment boom deployment. However, oil released onto the 

ocean surface during a storm event would be subject to accelerated rates of weathering and 

dissolution (i.e., oil and water would be agitated, forcing oil into smaller droplets and facilitating 

dissolution of the high end aromatic compounds present). 

In rough seas, a large spill of low viscosity oil, such as a light or medium crude oil, can be 

scattered over many square kilometers within just a few hours. Oil recovery systems typically have 

swath widths of only a few meters and move at slow speeds while recovering oil. Therefore, even if 

this equipment can become operational within a few hours, it would not be feasible for them to 

encounter more than a fraction of a widely spread slick (International Tanker Owners Pollution 

Federation Limited, 2010). For this reason, it is assumed that a maximum of 10-30 percent of an oil 

spill in an offshore environment can be mechanically removed from the water prior to the spill 

making landfall (U.S. Congress, Office of Technology Assessment, 1990). Some newer oil 

skimming equipment procured internationally displayed faster recovery speed during the response to 

the Deepwater Horizon oil spill, and some changes were also made in the logistics of how skimmers 

and booms were positioned offshore during this response that increased the equipment’s swath 

width. However, for the Deepwater Horizon response, it was estimated that only 3 percent of the 

total oil spilled was picked up by mechanical equipment offshore (Lubchenco et al., 2010).

A common difficulty when deploying booms and skimmers to recover oil is coordinating 

vessel activities to work the thickest areas of oil (International Tanker Owners Pollution Federation 

Limited, 2010). It is a rule of thumb that 90 percent of the oil is in 10 percent of the area. The 

10 percent of the oil that makes up 90 percent of a slick is typically sheen. For this reason, 

containment and recovery operations on water require extensive logistical support to direct the 

response effort. Additionally, the limitations that poor weather and rough seas impose on spillresponse operations offshore are seldom fully appreciated. Handling wet, oily, slippery equipment 

on vessels that are pitching and rolling is difficult and can raise safety considerations. Winds, wave 

action, and currents can drastically reduce the ability of a boom to contain and a skimmer to recover 
3-146 Gulf of Mexico Multisale EIS

oil. It is important to select equipment for a response that is suitable for the type of oil and the 

prevailing weather and sea conditions for a region. Efforts should generally be made to target the 

heaviest oil concentrations and areas where collection and removal of the oil would reduce the 

likelihood of oil reaching sensitive resources and shorelines. As oil weathers and increases in 

viscosity, cleanup techniques and equipment should be reevaluated and modified (International 

Tanker Owners Pollution Federation Limited, 2010).

Practical limitations of strength, water drag, and weight mean that generally only relatively 

short lengths of boom (tens to a few hundred meters) can be deployed and maintained in a working 

configuration. Towing booms at sea (e.g., in U or J configurations, which increase a skimmer’s 

swath width) is a difficult task requiring specialized vessels and trained personnel (International 

Tanker Owners Pollution Federation Limited, 2010). Additional boom limitations are discussed in 

Chapter 3.2.8.3. Because skimmers float on the water surface, they experience many of the 

operational difficulties that apply to booms, particularly those posed by wind, waves, and currents 

(International Tanker Owners Pollution Federation Limited, 2010). The effectiveness of any skimmer 

depends upon a number of factors, in addition to the ambient weather and sea conditions, including 

the type of oil, the thickness of the oil, the presence of debris in the oil or in the water, the extent of 

weathering and emulsification of the oil, and the location of the spill (Fingas, 2013). Even moderate 

wave motion can greatly reduce the effectiveness of most skimmer designs (International Tanker 

Owners Pollution Federation Limited, 2010). In high sea-state conditions, many skimmers, 

especially weir and suction skimmers, take up more water than oil (Fingas, 2013). Because of the 

various constraints placed upon skimmers in the field, their design capacities are rarely realized. 

Experience from numerous spills has consistently shown that skimmer recovery rates reported under 

test conditions cannot be sustained during a spill response (International Tanker Owners Pollution 

Federation Limited, 2010). The availability of sufficient oil-storage facilities is necessary to ensure 

continuous oil-spill recovery. This storage needs to be easy to handle and easy to empty once full 

so that it can be used repeatedly with the least interruption in recovery activity (International Tanker 

Owners Pollution Federation Limited, 2010).

There are no proven methods for the containment of submerged oil, and methods for 

recovery of submerged oils have limited effectiveness. Efforts to mechanically contain and/or 

recover suspended oil have focused on different types of nets, either the ad hoc use of fishing nets 

or specially designed trawl nets. There has been some research conducted on the design of trawl 

nets for the recovery of emulsified fuels. However, the overall effectiveness for large spills is 

expected to be very low. The suspended oil can occur as liquid droplets or semisolid masses in 

sizes ranging from millimeters to meters in diameter (Coastal Response Research Center, 2007). At 

spills where oil has been suspended in the water column, responders have devised low technology 

methods for tracking the presence and spread of oil over space and time. For suspended oil, these 

methods include stationary systems such as snare sentinels, which can consist of any combination 

of the following: a single length of white absorbent pom-poms (snare) on a rope attached to a float 

and an anchor; one or more crab traps on the bottom that are stuffed with snare; and minnow or 

other type of traps that are stuffed with snare and deployed at various water depths. The 

configuration would depend upon the water depth where the oil is located within the water column. 
Impact-Producing Factors and Scenario 3-147

At present, it is not possible to determine the particle size, number of particles, or percent oil cover in 

the water column based upon the visual observations of oil on these systems (Coastal Response 

Research Center, 2007).

Spills involving submerged oil trigger the need for real-time data on current profiles (surface 

to bottom), wave energy, suspended sediment concentrations, detailed bathymetry, seafloor 

sediment characteristics, and sediment transport patterns and rates. These data are needed to 

validate or calibrate models (both computer and conceptual), direct sampling efforts, and predict the 

behavior and fate of the submerged oil. This information might be obtained through the use of 

acoustic Doppler current profilers, dye tracer studies, rapid seafloor mapping systems, and 

underwater camera or video systems that can record episodic events (Coastal Response Research 

Center, 2007). During the Deepwater Horizon response, fluorimeters were used successfully to 

detect the presence of submerged oil.

3.2.8.2.2 Spill Treating Agents

Treating oil with specially prepared chemicals is another option for responding to oil spills. 

An assortment of chemical spill treating agents is available to assist in cleaning up oil. However, 

approval must be obtained in accordance with the provisions of the National Oil and Hazardous 

Substances Pollution Contingency Plan (NCP) before these chemical agents can be used.

The USEPA has recently issued a proposed rule to amend the requirements in Subpart J of 

the NCP that governs the use of dispersants, other chemical and biological agents, and other spill 

mitigating substances when responding to oil discharges into waters of the United States. The 

proposed rule addresses the efficacy, toxicity, environmental monitoring of dispersants, and other 

chemical and biological agents, as well as public, State, local and Federal officials’ concerns 

regarding their use (Federal Register, 2015c). The USEPA also updated the NCP product schedule 

in 2014. The 2014 NCP Product Schedule lists the following types of products that are authorized 

for use on oil discharges:

• dispersants; 

• surface washing agents;

• surface collecting agents;

• bioremediation agents; and

• miscellaneous oil-spill control agents.

In February 2014, the USEPA also published an NCP Product Schedule Notebook that 

presents manufacturers’ summary information that describes (1) the conditions under which each of 

the products is recommended for use, (2) handling and worker precautions, (3) storage information, 

(4) recommended application procedures, (5) physical properties, (6) toxicity information, and 

(7) effectiveness information (USEPA, 2014b).
3-148 Gulf of Mexico Multisale EIS

Dispersants

When dispersants are applied to spilled crude oil, the surface tension of the oil is reduced, 

allowing wind and wave action to break the oil into tiny droplets that are dispersed into the upper 

portion of the water column. Oil that is chemically dispersed at the surface move into the top 20 ft 

(6 m) of the water column where it mixes with surrounding waters and begins to biodegrade (U.S. 

Congress, Office of Technology Assessment, 1990). Dispersant use, in combination with natural 

processes, breaks up oil into smaller components that allows them to dissipate into the water and 

degrade more rapidly (Nalco, 2010). Dispersant use must be in accordance with a Regional 

Response Team’s (RRT) Preapproved Dispersant Use Manual and with any conditions outlined 

within a RRT’s site-specific, dispersant approval given after a spill event. Consequently, dispersant 

use must be in accordance with the restrictions for specific water depths, distances from shore, and 

monitoring requirements. At this time, neither the Region IV nor the Region VI RRT dispersant use 

manuals, which cover the GOM region, give preapproval for the application of dispersant use 

subsea. However, the USEPA is presently revisiting these RRT preapprovals in light of the 

dispersant issues, such as subsea application, that arose during the Deepwater Horizon response. 

The USEPA issued a letter dated December 2, 2010, that provided interim guidance on the use of 

dispersants for major spills that are continuous and uncontrollable for periods greater than 7 days 

and for expedited approval of subsurface applications. This letter outlined the following exceptions 

to the current preapprovals until they are updated:

• dispersants may not be applied to major spills that are continuous in nature and 

uncontrollable for a period greater than 7 days;

• additional dispersant monitoring protocols and sampling plans may be developed 

that meet the unique needs of the incident; and

• subsurface dispersants may be approved on an incident-specific basis as 

requested by USCG’s On-Scene Coordinator.

In addition, this letter indicated that more robust documentation may be required. This 

documentation would include daily reports that contain the products used, specific time and locations 

of application, equipment used for each application, spotter aircraft reports, photographs, vessel 

data, and analytical data.

Additionally, in light of the dispersant issues that arose during the Deepwater Horizon

response, the State of Florida’s Department of Environmental Protection submitted a letter dated 

May 5, 2011, to the USEPA Region IV RRT in which the State of Florida withdrew all State waters 

(9 nmi [10.36 mi; 16.67 km] off the coast of Florida in the Gulf of Mexico) from the Green Zone (or 

approved area) for dispersant preapproval as outlined within the Use of Dispersants in Region IV 

document (USEPA, Region IV Regional Response Team, 1996). The State indicated in the letter 

that this change was requested due to the enormous changes that have occurred in communication 

and response technologies since the preapproval was first agreed to in 1996. The State indicated 

that they felt that the Use of Dispersants in Region IV document needed to be updated to reflect 
Impact-Producing Factors and Scenario 3-149

technological advances and lessons learned during the response to the Deepwater Horizon oil spill

(State of Florida, Dept. of Environmental Protection, 2011).

For a deepwater (>1,000-ft [305-m] water depth) spill ≥1,000 bbl, dispersant application may 

be a preferred response in the open-water environment to prevent oil from reaching a coastal area, 

in addition to mechanical response. However, the window of opportunity for successful dispersant 

application may be somewhat narrower for some deepwater locations that are dependent upon the 

physical and chemical properties of oil, which tend to be somewhat heavier than those found closer 

to shore. A significant reduction in the window of opportunity for dispersant application may render 

this response option ineffective.

Due to the unprecedented volume of dispersants applied for an extended period of time in 

situations not previously envisioned or incorporated in existing dispersant use plans (i.e., during the 

Deepwater Horizon oil-spill response), the National Response Team has developed guidance for 

monitoring atypical dispersant operations. The guidance document, which was approved on 

May 30, 2013, is titled Environmental Monitoring for Atypical Dispersant Operations: Including 

Guidance for Subsea Application and Prolonged Surface Application. The subsea guidance 

generally applies to the subsurface ocean environment and focuses on operations in water depths 

below 300 m (984 ft) and below the pycnocline or in the interface between an upper mixed density 

gradients and a lower stable density gradient. The surface application guidance supplements and 

complements the existing protocols as outlined within the existing Special Monitoring of Applied 

Response Technologies monitoring program where the duration of the application of dispersants on 

discharged oil extends beyond 96 hours from the time of the first application (U.S. National 

Response Team, 2013). This guidance is provided to the Regional Response Teams by the 

National Response Team to enhance existing Special Monitoring of Applied Response Technologies

protocols and to ensure that their planning and response activities are consistent with national 

policy.

The most popular application method for dispersants in the offshore GOM is from small and 

large fixed-wing aircraft. Based on the present location of dispersant stockpiles and dispersant 

application equipment available to the Oil Spill Removal Organizations used by offshore operators in 

the GOM, it is expected that the dispersant application aircraft called out for an oil-spill response to 

an offshore spill in the proposed lease sale area would come from Houma, Louisiana; Kiln, 

Mississippi; Mesa, Arizona; Concord, California; and/or Salisbury, Maryland. Stockpiles of 

dispersants are located at each of the designated staging airports. Response times for this 

equipment would vary, depending on the spill site and on the transport time for additional supplies of 

dispersants to arrive at a staging location. Based on historic information, this Multisale EIS assumes 

that dispersant application applied to the water surface would be effective on 20-50 percent 

(S.L. Ross Environmental Research Ltd., 2000) of the treated oil.

If an oil spill occurs during a storm, the dispersant application would occur following the 

storm. Aerial and vessel dispersant application would not be possible while storm conditions

continued. However, oil released onto the ocean surface during a storm event would be subject to 
3-150 Gulf of Mexico Multisale EIS

accelerated rates of weathering and dissolution (i.e., oil and water would be agitated, forcing oil into 

smaller droplets and facilitating dissolution of the high-end aromatic compounds present).

Other Spill Treating Agents

Surface washing agents, emulsion breakers and inhibitors, recovery enhancers, solidifiers, 

and sinking agents are other types of chemical treatment agents that are available, if approval is

obtained, for treating oil spills. The use of these chemical products is subject to approval in the 

same manner as dispersants. The use of bioremediation agents also requires approval in the same 

manner as dispersants. The U.S. Environmental Protection Agency’s NCP Product Schedule 

Notebook presents manufacturers’ summary information that describes (1) the conditions under 

which each of the products is recommended for use, (2) handling and worker precautions, 

(3) storage information, (4) recommended application procedures, (5) physical properties, (6) toxicity 

information, and (7) effectiveness information (USEPA, 2014b).

3.2.8.2.3 In-situ Burning

In-situ burning is an oil-spill cleanup technique that involves the controlled burning of the oil 

at or near a spill site. The use of this spill-response technique can provide the potential for the 

removal of large amounts of oil over an extensive area in less time than other techniques. In ideal 

circumstances, in-situ burning requires less equipment and much less labor than other cleanup 

techniques (Fingas, 2013). In-situ burning involves the same oil collection process used in 

mechanical recovery, except instead of going into a skimmer, the oil is funneled into a fire boom, 

which is a specialized boom that has been constructed to withstand the high temperatures from 

burning oil. While in-situ burning is another method for disposing of oil that has been collected in a 

boom, this method is typically more effective than skimmers when the oil is highly concentrated. 

There were 411 in-situ burn operations conducted during the course of the Deepwater Horizon oilspill response, successfully eliminating between 220,000 and 300,000 bbl of oil from the water 

surface (Allen, 2010), approximately 5 percent of the Macondo oil spilled (Lubchenco et al., 2010).

Because of the successful use of this technology during the Deepwater Horizon oil-spill 

response, the Gulf of Mexico’s Oil Spill Removal Organizations have procured fire boom, which they 

have strategically stockpiled throughout the GOM region. Response times for bringing a fireresistant boom onsite would vary, depending on the location of the equipment, the staging area, and 

the spill site. If an oil spill occurs during a storm, in-situ burning would occur following the storm. 

In-situ burning would not be possible while storm conditions continued.

3.2.8.2.4 Natural Dispersion

Depending upon environmental conditions and spill size, the best response to a spill may be 

to allow the natural dispersion of a slick to occur. Natural dispersion may be a preferred option for 

smaller spills of lighter nonpersistent oils and condensates that form slicks that are too thin to be 

removed by conventional methods and that are expected to dissipate rapidly, particularly if there are 

no identified potential impacts to offshore resources and a potential for shoreline impact is not 
Impact-Producing Factors and Scenario 3-151

indicated. In addition, natural dispersion may also be a preferred option in some nearshore 

environments, such as a marsh habitat, when the potential damage caused by a cleanup effort could 

cause more damage than the spill itself. For more information on the transport and fate of oil spills, 

refer to Chapter 3.2.1.3. 

3.2.8.3 Onshore Response and Cleanup

Offshore response and cleanup is preferable to shoreline cleanup; however, if an oil slick 

reaches the coastline, it is expected that the specific shoreline cleanup countermeasures identified 

and prioritized in the appropriate Area Contingency Plans (ACPs) for various habitat types would be 

used. The sensitivity of the contaminated shoreline is the most important factor in the development 

of cleanup recommendations. Shorelines of low productivity and biomass can withstand more 

intrusive cleanup methods such as pressure washing. Shorelines of high productivity and biomass 

are very sensitive to intrusive cleanup methods and, in many cases, the cleanup is more damaging 

than allowing natural recovery.

Oil-spill response planning in the U.S. is accomplished through a mandated set of 

interrelated plans. The ACPs cover subregional geographic areas and represent the third tier of the 

National Response Planning System mandated by the Oil Pollution Act of 1990. The ACPs are a 

focal point of response planning, providing detailed information on response procedures, priorities, 

and appropriate countermeasures. The USCG has worked diligently to improve coastal oil-spill 

response since the Deepwater Horizon oil spill by improving the ACPs for each coastal USCG 

sector. The GOM coastal area that falls within USCG’s 8th District is covered by ACPs for areas 

covered by USCG Sector Corpus Christi, Sector Houston/Galveston, Sector Port Arthur, Sector 

Morgan City, Sector New Orleans, and Sector Mobile. The ACPs from USCG’s 7th District cover the 

remaining GOM coastal area. The Gulf of Mexico OCS Region’s ACPs also include separate 

Geographic Response Plans (GRP), which are developed jointly with local, State, and other Federal 

entities to better focus spill-response tactics and priorities. These GRPs contain the resources 

initially identified for protection during a spill, response priorities, procedures, and appropriate spillresponse countermeasures. The ACPs are written and maintained by Area Committees assembled 

from Federal, State, and local government agencies that have pollution-response authority; 

nongovernmental participants may attend meetings and provide input. The coastal Area 

Committees are chaired by respective Federal On-Scene Coordinators from the appropriate USCG 

Office and are comprised of members from local or area-specific jurisdictions. Response 

procedures identified within an ACP or its GRP(s) reflect the priorities and procedures agreed to by 

members of the Area Committees.

If an oil slick reaches the coastline, the responsible party should be prepared to deploy any 

of the shoreline cleanup countermeasures that were specified for the protection of the prioritized 

sensitive areas that are identified within the appropriate GRPs that cover these areas. The single, 

most-frequently recommended, spill-response strategy for the areas identified for protection in all of 

the applicable ACPs or its GRPs is the use of a shoreline boom to deflect oil away from coastal 

resources such as seagrass beds, marinas, resting areas for migratory birds, bird and turtle nesting 
3-152 Gulf of Mexico Multisale EIS

areas, etc. Since oil spilled at sea tends to move and spread rapidly into very thin layers, boom is 

deployed to corral the oil on the water to enhance recovery effectiveness of skimmers and other 

response technologies. Boom is also used to protect shoreline areas and to minimize the 

consequences of an oil spill reaching shore. There are tradeoffs in deciding where and when to 

place boom because, once deployed, boom is time consuming to tend and to relocate. For example, 

booming operations are sensitive to wind, wave, and currents and need to be tethered and secured 

to keep the boom from moving. Rough seas can tear, capsize, or shred boom. Currents over 

1.5 knots (1.7 miles per hour) or even a wake from a boat can send oil over or under a boom. 

Untended boom can become a barricade to wildlife and ship traffic. Boom anchors can damage 

some habitats (Gulf Coast Incident Management Team, 2011). During the Deepwater Horizon

response, it was discovered that hard boom often did more damage in the marsh it was intended to 

protect than anticipated after weather conditions ended up stranding the boom back into the marsh.

If a shoreline is oiled, the selection of the type of shoreline remediation to be used would 

depend on the following: (1) the type and amount of oil on the shore; (2) the nature of the affected 

coastline; (3) the depth of oil penetration into the sediments; (4) the accessibility and the ability of 

vehicles to travel along the shoreline; (5) the possible ecological damage of the treatment to the 

shoreline environment; (6) weather conditions; (7) the current state of the oil; and (8) jurisdictional 

considerations. To determine which cleanup method is most appropriate during a spill response, 

decision-makers must assess the severity and nature of the injury using Shoreline Cleanup and 

Assessment Team (SCAT) survey observations. These onsite decisionmakers must also estimate 

the time it would take for an area to recover in the absence of cleanup (typically considering short 

term to be 1-3 years, medium term to be 3-5 years, and long term greater than 5 years) (U.S. 

National Response Team, 2010). The variety of standard cleanup protocols that were used for 

removing Macondo oil from beaches, shorelines, and offshore water are identified in Table 3-22. 

During the Deepwater Horizon shoreline response, oiling conditions generally included 

surface and buried oil layers, surface and buried oil/sand balls, stained sand, and sunken oil in the 

adjacent subtidal waters. Since waste minimization was a core principle considered when cleaning 

sand beaches, efforts were made to remove as little sediment as practical from the shore zone 

during cleaning operations. Treatment methods for sand beaches comprised manual and 

mechanical removal, an on-site treatment plant, and sediment relocation. Mechanical removal 

involved a range of commercial self-propelled or towed machines designed primarily to sieve debris 

and litter on recreational beaches. Field trials were conducted to evaluate which specific 

mechanisms were more appropriate for the different oiling conditions. The beach cleaners were 

used as scrapers on the more heavily oiled beaches in Louisiana, whereas the sieving function was 

more appropriate to recover oil particles on the beaches of Mississippi, Alabama, and Florida. Oiled 

wetlands included Spartina salt marshes and Phragmites (“roseau cane”) brackish-freshwater 

wetlands in the Mississippi Delta. Because previous spills in this region provided an understanding 

of the recovery potential for the oiled wetlands, natural recovery was the preferred strategy in most 

cases based on the generally light oiling conditions. Natural attenuation was relatively rapid if an 

area was only lightly oiled, as the Macondo well oil type had an API gravity of 35 ̊. A guiding 

principle for wetland treatment was to minimize physical intrusion and work from floating platforms, 
Impact-Producing Factors and Scenario 3-153

skiffs, or shallow-draft barges, whenever possible. Floating mechanical flushing machines, using 

concrete pump arms, were used on a limited scale to reach into oiled fringe wetlands to wash and 

recover mobile oil. Oiled rip rap, breakwaters, and groins and jetties were treated through manual 

removal of bulk oil and were washed using a range of temperatures and pressures depending on the 

character of the oil (Owens et al., 2011).

Shoreline Cleanup Countermeasures

When spilled oil contaminates shoreline habitats, responders should survey the affected 

areas to determine appropriate response. Although general approvals or decision tools for using 

shoreline cleanup methods can be developed during pre-spill planning stages, responders’ specific 

treatment recommendations should integrate gathered, filed, and documented data on shoreline 

habitats, oil type, the degree of shoreline contamination, spill-specific physical processes, and 

ecological and cultural resource issues. Cleanup endpoints should be established early so that 

appropriate cleanup methods can be selected to meet the cleanup objectives. Shoreline surveys, as 

part of the SCAT program, should be conducted systematically because they are imperative to the 

cleanup decisions. Also, repeated surveys are needed to monitor the effectiveness of the ongoing 

treatment methods so that the need for changes in methodology, additional treatment, or constraints 

can be evaluated (USDOC, NOAA, 2013a).

The following assumptions and guidance regarding the cleanup of spills that contact coastal 

resources are identified in NOAA’s Characteristic Coastal Habitats: Choosing Spill Response 

Alternatives job aid, which provides general guidance adopted in the Gulf of Mexico OCS Region’s

ACPs (USDOC, NOAA, 2010b). The ACPs applicable to the GOM coastal region encompass a vast 

geographical area. The differences in the response priorities and procedures among the various 

ACPs or the GRPs reflect the differences in the identified resources needing spill protection. 

Sand Beaches

Predicted Oil Behavior

Light oil accumulations would be deposited as oily swashes or bands along the upper 

intertidal zone of sand beaches. Heavy oil accumulations would cover the entire beach surface. Oil 

would be lifted off of the lower beach with the rising tide. The maximum penetration of oil into fineto-medium-grained sand is about 10-15 cm (4-6 in) and up to 25 cm (10 in) in coarse-grained sand. 

Burial of oiled layers by clean sand can be rapid (within 1 day), and burial to depths as much as 1 m 

(3 ft) is possible if the oil comes ashore at the beginning of a depositional period. Organisms living 

in the beach sediment may be killed by smothering or lethal oil concentrations in the interstitial 

water. Biological impacts include temporary declines in infauna, which can affect important 

shorebird foraging areas.

Response Considerations

Sand beaches are one of the easiest shoreline types to clean. Cleanup would concentrate 

on removing oil and oily debris from the upper swash zone once most of the oil has come ashore. 
3-154 Gulf of Mexico Multisale EIS

Manual cleanup, rather than road graders and front end loaders, is advised to minimize the volume 

of sand removed from the shore and requiring disposal. All efforts should focus on preventing 

vehicular and foot traffic from mixing oil deeper into the sediments. Mechanical reworking of lightly 

oiled sediments from the high-tide line to the middle intertidal zone can be effective along exposed 

beaches.

Salt to Brackish Marshes

Predicted Oil Behavior

Oil adheres readily to intertidal vegetation in salt and brackish marshes. The band of coating 

would vary widely depending upon the water level at the time of oiling. Large slicks would persist 

through multiple tidal cycles and will coat the entire stem from the high-tide line to the base. Heavy 

oil coating would be restricted to the outer fringe of thick vegetation, although lighter oils can 

penetrate deeper, to the limit of tidal influence. Medium to heavy oils do not readily adhere to or 

penetrate the fine sediments but can pool on the surface or in animal burrows and root cavities. 

Light oils can penetrate the top few centimeters of sediment and, under some circumstances, oil can 

penetrate burrows and cracks up to 1 m (3 ft).

Response Considerations

Under light oiling, the best practice is to let the area recover naturally. Natural removal 

processes and rates should be evaluated before conducting cleanup. Heavily pooled oil can be 

removed by vacuum, sorbents, or low-pressure flushing. During flushing, care should be taken to 

prevent transporting oil to sensitive areas down slope or along shore. Cleanup activities should be 

carefully supervised to avoid damaging vegetation. Any cleanup activity should not mix the oil 

deeper into the sediments, trampling of the plants and disturbance of soft sediments should be 

minimized. Lastly, aggressive cleanup methods should only be considered when other resources 

(e.g., migratory birds and endangered species) are at greater risk from oiled vegetation left in place. 

Under heavy oiling that requires more aggressive cleanup, replanting can reduce further shoreline 

erosion and accelerate vegetation recovery (Zengel et al., 2015)

Sand and Gravel Beaches

Predicted Oil Behavior

During small spills, oil could be deposited along and above the high-tide swash on sand and 

gravel beaches. Large spills would likely spread across the entire intertidal area. Oil penetration 

into the beach sediments may be up to 50 cm (20 in); however, the sand fraction can be quite mobile 

and oil behavior is much like on a sand beach if the sand fraction exceeded about 40 percent. The 

burial of oil may be deep at and above the high-tide line where oil tends to persist, particularly where 

beaches are only intermittently exposed to waves. In sheltered pockets on the beach, pavements of 

asphalted sediments can form if oil accumulations are not removed because most of the oil remains 

on the surface.
Impact-Producing Factors and Scenario 3-155

Response Considerations

First, heavy accumulations of pooled oil from the upper beach face should be removed. All 

oiled debris should be removed, but sediment removal should be limited as much as possible. 

Low-pressure flushing can be used to float oil away from the sediments for recovery by skimmers or 

sorbents. High-pressure spraying should be avoided because of the potential for transporting 

contaminated finer sediments (sand) to the lower intertidal or subtidal zones; mechanical reworking 

of oiled sediments from the high-tide zone to the middle intertidal zone can be effective in areas 

regularly exposed to wave activity; however, oiled sediments should not be relocated below the 

mid-tide zone. Lastly, in-place tilling may be used to reach deeply buried oil layers in the mid-tide 

zone on exposed beaches.

Exposed or Sheltered Tidal Flats

Predicted Oil Behavior

Oil does not usually adhere to the surface of sheltered or exposed tidal flats but instead 

moves across the flat and accumulates at the high-tide line. Deposition of oil on the sheltered or 

exposed flat may occur on a falling tide if concentrations are heavy. Oil would not penetrate watersaturated sediments but could penetrate burrows and desecration cracks or other crevices in muddy 

sediments in sheltered flats or coarse-grained sand in exposed flats. In areas of high suspendedsediment concentrations, the oil and sediments could mix, resulting in the deposition of 

contaminated sediments on the flats. Biological impacts could be severe.

Response Considerations

Sheltered tidal flats are high-priority areas for protection since cleanup options are limited. 

Cleanup of the sheltered tidal flat surface would be very difficult because of the soft substrate, and 

many methods may be restricted. Low-pressure flushing, vacuuming, and deployment of sorbents 

from shallow-water draft boats may be used on sheltered tidal flats. Currents and waves on 

exposed tidal flats can be effective in the natural removal of oil. Cleanup can only be done during 

low tide on exposed flats, thereby providing a narrow window of opportunity for response. The use 

of heavy machinery should be restricted on exposed tidal flats to prevent oil mixing into the 

sediments. Manual methods are preferred on exposed tidal flats.

Exposed, Solid Manmade Structures Such as Seawall/Piers

Predicted Oil Behavior

Oil is held offshore by waves reflecting off of the steep hard surfaces of exposed, solid 

manmade structures such as seawall/piers. Oil would readily adhere to the dry rough surfaces but it 

would not adhere to wet substrates. The most resistant oil would remain as a patchy band at or 

above the high-tide line.
3-156 Gulf of Mexico Multisale EIS

Response Considerations

Cleanup is usually not required, and high-pressure water spraying may be conducted to 

remove risks of contamination of people or vessels or to improve aesthetics.

Mangroves

Predicted Oil Behavior

Oil can wash through mangroves if oil comes ashore at high tide. If a berm or shoreline is 

present, oil tends to concentrate and penetrate into the berm sediments or accumulated wrack/litter. 

Heavy and emulsified oil can be trapped in thickets of red mangrove prop roots or dense young 

trees. Oil readily adheres to prop roots and tree trunks. Re-oiling from resuspended or released oil 

residues may cause additional injury over time. Oiled trees start to show evidence of effects (leaf 

yellowing) weeks after oiling, and tree mortality may take months, especially for heavy oils.

Response Considerations

Oiled wrack can be removed once the threat of oiling has passed as wrack can actually 

protect the trees from direct oil contact. Sorbent boom can be placed in front of oiled forests to 

recover oil released naturally and, in most cases, no other cleanup activities are recommended. 

Where thick oil accumulations are not being naturally removed, low-pressure flushing or vacuum 

may be attempted at the outer fringe. No attempt should be made to clean interior mangroves

except where access to the oil is possible from terrestrial areas, and it is extremely important that 

cleanup activities be conducted by boat so that disturbance of the substrate by foot traffic be 

prevented.

Seagrasses

Predicted Oil Behavior

Oil would usually pass over subtidal seagrass beds, with no direct contamination. Floating 

oil stranded on adjacent beaches can pick up sediment and then get eroded and deposited in 

adjacent seagrass beds.

Response Considerations

Care should be taken when deploying and anchoring booms to prevent physical damage to 

seagrass beds and to prevent sediment suspension and mixing with the oil and disturbance of roots 

and vegetation by foot traffic and boat activity. Seagrasses should not be cut unless species like 

sea turtles, manatees, or waterfowl are at substantial risk of contacting or ingesting oil. Also, 

dispersant use directly over subtidal seagrass beds may impact the highly sensitive communities. 

However, the use of booms or dispersants in offshore areas can reduce impacts to highly sensitive 

intertidal environments, as well as prevent shoreline stranding in mangroves that can be a chronic 

source of re-oiling of adjacent seagrass beds. Lastly, in-situ burning should only be considered 

outside the immediate vicinity of seagrass beds to protect sensitive intertidal environments because 
Impact-Producing Factors and Scenario 3-157

burn residues can sink and the potential effects of the residue would depend on the composition and 

amount of the oil to be burned and the location where it would sink.

Bays and Estuaries

Predicted Oil Behavior

Oil can impact bottom habitats (benthic organisms) when water is shallow. Stranded oil on 

nearby shorelines can become a prolonged source for oil re-released to the water column, and tides 

and freshwater can substantially influence spilled oil movement.

Response Considerations

Reducing impacts to organisms that live on or in the sea surface is often a high priority, 

reducing the extent of impacts to sensitive nearshore subtidal or intertidal habitats should be 

considered. Spill response is not conducted from a shoreline but from water-based vessels or 

aircraft. The use of certain response options is seasonally limited to protect species with sensitive 

life histories. Lastly, adverse effects to birds would be greatest during migration and overwintering 

when birds form large flocks.

3.3 CUMULATIVE IMPACTS

3.3.1 Cumulative OCS Oil and Gas Program Scenario

The Cumulative OCS Oil and Gas Program scenario includes all 

activities (i.e., routine activities projected to occur and accidental events that 

could occur) from past, proposed, and future lease sales. This includes 

projected activity from (1) past lease sales, including lease sales still 

scheduled for the 2012-2017 Five-Year Program but for which exploration or development has either 

not yet begun or is continuing; (2) lease sales that would be held in this Five-Year Program; and 

(3) future lease sales that would be held as a result of future Five-Year Programs (four additional 

programs are included in this cumulative analysis). Activities that take place beyond the analysis 

timeframe as a result of future lease sales are not included in this analysis. Tables 3-23 and 3-25

present projections of the major activities and impact-producing factors related to future Cumulative 

OCS Oil and Gas Program activities. Table 3-25 can be found in Chapter 3.3.1.7 below.
3-158 Gulf of Mexico Multisale EIS

Table 3-23. Future Activity Projections Associated with the Cumulative OCS Oil and Gas Program 

(2017-2086), Including All Future Activities that are Projected to Occur from Past, Proposed, 

and Future Lease Sales. 

Activity Planning 

Area

Offshore Subareas (m)1

Totals2

0-60 60-200 200-800 800-

1,600

1,600-

2,400 >2,400

Exploration 

and 

Delineation 

Wells

GOM 939-2,562 253-1,166 110-170 153-240 97-278 119-301 1,671-4,717

CPA/EPA 775-1,999 202-1,007 83-142 88-184 70-142 99-211 1,317-3,685

WPA 164-563 51-159 27-28 65-56 27-136 20-90 354-1,032

Development 

and 

Production 

Wells3

G

O

M

Total 4,050-9,225 1,570-4,324 912-2,034 617-1,127 446-723 633-985 8,238-18,418

Oil 438-987 164-453 446-993 280-487 230-372 310-482 1,868-3,774

Gas 2,440-5,566 894-2,457 186-415 149-288 79-126 126-194 3,874-9,046

C

P

A/

E

P

A

Total 3,170-6,634 1,139-3,558 676-1,557 490-779 405-623 595-899 6,475-14,050

Oil 354-740 122-379 326-750 240-385 207-319 289-437 1,538-3,010

Gas 1,898-3,972 645-2,015 142-327 95-152 72-110 119-179 2,971-6,755

W

P

A

Total 880-2,591 431-766 236-477 137-348 41-100 38-86 1,763-4,368

Oil 84-247 42-74 120-243 40-102 23-53 21-45 330-764

Gas 542-1,594 249-442 44-88 54-136 7-16 7-15 903-2,291

Installed 

Production 

Structures 

GOM 2,168-5,121 558-1,638 36-71 26-38 16-38 23-42 2,827-6,948

CPA/EPA 1,760-3,682 432-1,347 23-54 17-26 14-21 20-30 2,266-5,160

WPA 408-1,439 126-291 13-17 9-12 2-17 3-12 561-1,788

Production 

Structures 

Removed 

Using 

Explosives

GOM 2,435-4,388 568-1,310 0 0 0 0 3,003-5,698

CPA/EPA 2,051-3,315 440-1,065 0-0 0-0 0-0 0-0 2,491-4,380

WPA 384-1,073 128-245 0-0 0-0 0-0 0-0 512-1,318

Total 

Production 

Structures 

Removed

GOM 3,381-6,148 784-1,796 39-69 36-44 20-33 21-31 4,281-8,121

CPA/EPA 2,847-4,639 608-1,459 26-54 25-31 17-22 18-24 3,541-6,229

WPA 534-1,509 176-337 13-15 11-13 3-11 3-7 740-1,892

Length of 

Installed 

Pipelines

(km)4

GOM 2,181-15,822 1,432-

10,511 1,078-8,037 1,268-8,265 700-7,001 704-7,359 7,363-56,995

CPA/EPA 586-11,799 388-8,355 328-6,390 385-6,381 364-6,168 405-6,750 2,456-45,843

WPA 1,595-4,023 1,044-2,156 750-1,647 883-1,884 336-833 299-609 4,907-11,152

ServiceVessel Trips 

(1,000’s 

round trips)

GOM 2,443-6,998 645-2,300 284-942 213-556 134-498 187-577 3,909-11,873

CPA/EPA 1,978-5,037 496-1,892 186-722 140-389 115-306 163-440 3,079-8,788

WPA 465-1,960 150-408 98-221 72-167 19-192 23-137 830-3,085

Helicopter 

Operations 

(1,000’s 

round trips)

GOM 11,714-55,063 4,511-25,155 270-1,162 183-651 139-422 183-546 17,000-83,000

CPA/EPA 9,614-40,734 3,544-21,159 191-898 148-440 121-352 165-475 13,786-64,059

WPA 2,098-14,329 966-3,996 78-264 34-211 17-70 17-70 3,214-18,941

1

Refer to Table 3-2. 2

Subareas totals may not add up to the planning area total because of rounding.

3

Development and Production Wells includes some exploration wells that were re-entered and completed. These wells 

were removed from the Exploration and Delineation well count.

4

Projected length of pipelines does not include length in State waters.
Impact-Producing Factors and Scenario 3-159

It is reasonably foreseeable to assume that lease sales would continue to be proposed for 

many years to come in the Gulf of Mexico region, based on resource availability, existing 

infrastructure, and projected time lapses required for any other major energy sources to come 

online. However, the level of activities (exploration wells, production wells, and pipelines) becomes 

more speculative as time is projected into the future. The causes for this are uncertainty in oil 

prices, resource potential, cost of development, and drill rig availability, versus the amount of 

acreage leased from a lease sale. 

Therefore, these scenarios do not predict future OCS oil- and gas-related activities with 

absolute certainty, even though they were formulated using historical information and current trends 

in the oil and gas industry. Indeed, these scenarios are only approximate since future factors such 

as the contemporary economic marketplace, the availability of support facilities, and pipeline

capacities are all unknowns. Notwithstanding these unpredictable factors, the scenarios used in this 

Multisale EIS represent the best assumptions and estimates of a set of future conditions that are 

considered reasonably foreseeable and suitable for presale impact analyses. The development 

scenarios do not represent a BOEM recommendation, preference, or endorsement of any level of 

leasing or offshore operations, or of the types, numbers, and/or locations of any onshore operations 

or facilities. Methodologies for the Cumulative OCS Oil and Gas Program scenario are similar to 

those for a regionwide or individual planning area typical lease sale scenario analysis and are 

described in detail in Chapter 3 above.

3.3.1.1 Cumulative OCS Oil and Gas Program Projected Production

As of 2014, 19.02 BBO of oil and 185.2Tcf of gas had been produced in the GOM (USDOI, 

BOEM, 2013; USDOI, BSEE, 2015d). While offshore oil production has remained fairly constant 

over the last 10 years, gas production rates offshore have declined due to availability from onshore 

production (Figure 3-18). Projected future reserve/resource production estimates for the Cumulative 

OCS Oil and Gas Program scenario regionwide are 15.482-25.806 BBO and 57.875-108.513 Tcf of 

gas. These estimates represent all anticipated production from lands currently under lease plus all 

anticipated production from future lease sales over the 70-year analysis period (Table 3-1). Table 

3-23 presents all anticipated activity associated with production from lands currently under lease in 

regionwide plus all anticipated activity associated with production from future total OCS Program 

(WPA, CPA, and EPA) lease sales over the 70-year analysis period. 
3-160 Gulf of Mexico Multisale EIS

Figure 3-18. OCS Oil and Gas Production Between 2004 and 2015 (USDOI, BSEE, 2016b).

Projected future reserve/resource production estimates for the Cumulative OCS Oil and Gas 

Program scenario in the CPA and EPA are 13.707-22.152 BBO and 46.328-84.009 Tcf of gas. 

These estimates represent all anticipated production from lands currently under lease in the CPA 

and EPA plus all anticipated production from future leased lands in the CPA and EPA over the 

70-year analysis period (Table 3-1). Projected production estimates in the CPA and EPA represents 

approximately 88.5-85.8 percent of the oil and 80-77.4 percent of the gas of the cumulative OCS Oil 

and Gas Program regionwide. Table 3-23 presents all anticipated activity associated with 

production from lands currently under lease in the CPA and EPA plus all anticipated activity 

associated with production from future leased lands in the CPA and EPA over the 70-year analysis 

period.

Projected future reserve/resource production estimates for the Cumulative OCS Oil and Gas 

Program scenario in the WPA are 1.775-6.654 BBO and 11.547-24.504 Tcf of gas. These estimates 

represent all anticipated production from lands currently under lease in the WPA plus all anticipated 

production from future leased lands in the WPA over the 70-year analysis period (Table 3-1). 

Projected production estimates in the WPA represent approximately 11.5-14.2 percent of the oil and 

20-22.5 percent of the gas of the cumulative OCS Oil and Gas Program regionwide. Table 3-23

presents all anticipated activity associated with production from lands currently under lease in the 

WPA plus all anticipated activity associated with production from future leased lands in the WPA 

over the 70-year analysis period.

3.3.1.2 Cumulative Geological and Geophysical Surveys

Chapter 3.1.2.1 discusses OCS oil- and gas- related G&G survey activities. In order to 

forecast future programs as required in the cumulative case analysis, the baseline projection was 

scaled relative to the forecast of exploration wells drilled as defined by the cumulative case 
Impact-Producing Factors and Scenario 3-161

scenarios to obtain a longer term outlook. Cumulatively, G&G surveys are projected to follow the 

same trend as cumulative exploration drilling activities, which would peak in 2030-2040 and decline 

until 2060, and remain relatively low throughout the last quarter of the 70-year analysis period. It is 

important to note that the cycling of G&G data acquisition is not driven by the 50-year life cycle of a 

single productive lease but instead would tend to respond to new production or potential new 

production driven by new technology. Consequently, some areas would be resurveyed in 2-year 

cycles, while other areas, considered nonproductive, may not be surveyed for 20 years or more. 

Conservatively, BOEM assumes that, as a result of the Cumulative OCS Oil and Gas Program, one 

HRG survey would occur for every block leased (estimated by the number of platforms predicted), 

one HRG survey would occur for every 5 km (3 mi) of pipeline laid (the average length of a pipeline 

permit), and one VSP survey would be conducted on 15 percent of all exploration and development 

wells drilled. Table 3-24 below reflects a reasonable level of cumulative G&G surveying activities 

that could be expected to occur in the Gulf of Mexico (2017-2086).

Table 3-24. Cumulative G&G Surveying Activities Expected in the Gulf of Mexico (2017-2086).

3.3.1.3 Cumulative Exploration and Delineation Plans and Drilling

Chapter 3.1.2.2 describes in detail exploration and delineation activities. Since the 1950’s, 

approximately 18,954 exploratory wells have been drilled, of which 12,516 have been permanently 

abandoned (Marine Cadastre, 2015). The future projected exploration and delineation well estimate 

for the Cumulative OCS Oil and Gas Program scenario regionwide during the 70-year analysis 

period is 1,671-4,717 exploration and delineation wells drilled. Of these, 1,317-3,685 wells would be 

in the CPA/EPA and 354-1,032 wells would be in the WPA. Table 3-23 shows the estimated range 

of exploration and delineation wells by water-depth range for the Cumulative OCS Oil and Gas 

Program scenario for each planning area of the GOM. Of the wells projected under the Cumulative 

OCS Oil and Gas Program Scenario, 71-79 percent are expected to be on the continental shelf 

(0-200 m [0-656 ft] water depth) and 29-21 percent are expected in water-depth ranges >200 m 

(656 ft).

3.3.1.4 Cumulative Development and Production Drilling

Chapter 3.1.3.1 describes in detail development and production activities. Since the 1950s, 

approximately 35,029 development wells have been drilled, of which, 13,941 have been permanently 

abandoned (Marine Cadastre, 2015). The future projected development and production well

estimate for the Cumulative OCS Oil and Gas Program Scenario regionwide is

Survey Area

2D 

Surveys

(mi)

2D 

Permits

3D Lease 

Blocks 

3D 

Permits

Ancillary 

Permits

HRG 

Surveys

VSP 

Surveys

Regionwide 365,800-

1,036,700 183-506 126,800-358,400 90-235 2,261-5,559 4,300-18,347 1,486-3,470

CPA/EPA 362,000-

1,026,100 171-482 104,100-292,100 69-186 1,813-4,128 2,757-14,329 1,168-2,660

WPA 3,700-

10,600 12-23 22,700-66,300 21-48 449-1,430 1,542-4,019 317-810
3-162 Gulf of Mexico Multisale EIS

8,238-18,418 development and production wells drilled. Of these, 6,475-14,050 wells would be in 

the CPA/EPA and 1,763-4,368 wells would be in the WPA. Table 3-23 shows the estimated range 

of development and production wells by water-depth range for the Cumulative OCS Oil and Gas 

Program scenario for each planning area of the GOM. Of the wells projected under the Cumulative 

OCS Oil and Gas Program scenario, 68-73.5 percent are expected to be on the continental shelf 

(0-200 m [0-656 ft] water depth) and 32-26.5 percent are expected in water-depth ranges >200 m 

(656 ft).

3.3.1.5 Infrastructure Emplacement/Structure Installation and Decommissioning Activities

As of 2013, 7,020 platforms had been installed regionwide in the OCS; however, active 

platforms were estimated at only approximately 2,634 (USDOI, BSEE, 2015e; Figure 3-19). 

Chapter 3.1.3.2 describes in detail infrastructure emplacement and structure installation and 

commissioning activities. The projected estimate of additional production structures expected to be 

installed for the Cumulative OCS Oil and Gas Program scenario in the WPA, CPA, and EPA during 

the 70-year analysis period is 2,827-6,948 production structures. Of these, 2,266-5,160 structures 

would be in the CPA/EPA and 561-1,788 structures would be in the WPA. Table 3-23 shows the 

estimated range of production structure installation range by water-depth range for the Cumulative 

OCS Oil and Gas Program scenario for each planning area of the GOM. Of the platforms projected 

under the Cumulative OCS Oil and Gas Program scenario, about 97 percent are expected to be on 

the continental shelf (0-200 m [0-656 ft] water depth) and 3 percent are expected in water-depth 

ranges >200 m (656 ft).

Figure 3-19. Number of Production Structures Installed and Decommissioned in Past 

Programs and the Range of Future Projections that May Occur as a Result of All 

Past, Present, and Future Actions (USDOI, BSEE, 2015e).
Impact-Producing Factors and Scenario 3-163

Pipelines: Chapter 3.1.3.3.1 describes in detail activities associated with oil and gas 

transportation via pipelines. BOEM estimates 10,789-35,415 mi (7,363-56,995 km) of pipeline would 

be installed regionwide as a result of the activities associated with the Cumulative OCS Oil and Gas 

Program scenario (Tables 3-23 and 3-25). About 30-27 percent of the new pipeline length would be 

in water depths <60 m (197 ft) and would require burial. As of 2015, 144 pipeline landfalls currently 

exist in coastal areas of the OCS (Smith, official communication, 2015).

Bottom-Area Disturbance: Chapter 3.1.3.3.2 describes in detail infrastructure emplacement 

and structure installation and commissioning activities. Bottom area disturbance is calculated as a 

relationship between the structures projected (i.e., platforms, wells, subsea structures, and pipeline

miles installed) and the associated disturbance of each. For the Cumulative OCS Oil and Gas 

Program scenario, between 294,821 and 605,178 ha (728,518-1,495,427 ac) of sea bottom is 

projected to be disturbed. Future activity is expected to disturb >1 percent of the seafloor 

regionwide. Of this, 241,116-460,238 ha (595,810-1,137,272 ac) of the disturbance is expected in 

the CPA/EPA and 53,705-144,939 ha (132,707-358,152 ac) of the disturbance is expected in the 

WPA. 

Navigation Channels: BOEM conservatively estimates that there are approximately 

4,850 km (3,013 mi) of Federal navigation channels, bayous, and rivers potentially exposed to OCS 

traffic regionwide (Table 3-7 and Figure 3-9). No new navigation canals are expected to be 

created; however, erosion of existing channels may occur. Chapter 3.1.3.3.4 describes in detail 

activities associated with navigation channels. Using the estimated proportion of vessel traffic 

associated with the Cumulative OCS Oil and Gas Program scenario as a measurement of erosion, 

BOEM conservatively estimates the OCS Oil and Gas Program’s contribution to bank erosion over 

the 70-year cumulative scenario to be 3,135-9,524 ac (1,269-3,854 ha). This number is considered 

conservative because open waterways were included in the total length of Federal navigation 

channels, bank armoring rates may increase, vessel size was not taken into consideration, and there 

are sources of erosion to navigation canals other than vessel traffic alone.

3.3.1.6 Infrastructure Presence

Chapter 3.1.3.4 describes in detail activities associated with infrastructure presence. The 

maximum number of production structures operating simultaneously in the Cumulative OCS Oil and 

Gas Program scenario in the WPA, CPA, and EPA is 1,367 structures, including all depth ranges. 

Therefore, a maximum of 8,202 ha (20,268 ac) or approximately 6 ha (15 ac) of surface area would 

be temporarily unavailable to other activities in the OCS. To put this in perspective, <1 percent of 

the surface area of the GOM would be temporarily lost to the Cumulative OCS Oil and Gas Program. 

Additional impact-producing factors associated with offshore oil and gas infrastructure are oil spills

and trash and debris. These are the factors most widely recognized as major threats to the 

aesthetics of coastal lands, especially recreational beaches. These factors, individually or 

collectively, may adversely affect the fishing industry, resort use, and the number and value of 

recreational beach visits. 
3-164 Gulf of Mexico Multisale EIS

3.3.1.7 Transport

Barging: Chapter 3.1.4.1 describes in detail activities associated with barging. Barging is 

projected to continue to account for <1 percent of the oil transported (Table 3-25).

Table 3-25. Future Oil Transportation Projections Associated with the Cumulative OCS Oil and Gas 

Program (2017-2086), Including All Future Transportation that is Projected to Occur from 

Past, Proposed, and Future Lease Sales. 

Activity Region

Offshore Subareas (m)1

Totals2

0-60 60-200 200-800 800-

1,600

1,600-

2,400 >2,400

Percent 

Oil Piped3

GOM 94-95% 100% 100% 100% 89.6-87.4% 87.4-85.7% 91.6-90.6%

CPA/EPA 94-95% 100% 100% 100% 97.8-96.3% 94.9-95.3% 90.8-91.0%

WPA 100% 100% 100% 100% 100-89% 100-86.4% 100-95.1%

Percent 

Oil Barged

GOM 6-5% 0% 0% 0% 0% 0% 0.2%

CPA/EPA 6-5% 0% 0% 0% 0% 0% 0.2%

WPA 0% 0% 0% 0% 0% 0% 0%

Percent 

Tankered4

GOM 0% 0% 0% 0% 10.4-12.6% 12.6-14.3% 8-9%

CPA/EPA 0% 0% 0% 0% 12.2-13.7% 5.1-4.7% 9-8.75%

WPA 0% 0% 0% 0% 0-11% 0-13.6% 0-4.85% 1

Refer to Figure 3-2. Ranges are reported from the low production scenario to the high production scenario. 2

Subareas totals may not add up to the planning area total because of rounding.

3

100% of gas is assumed to be piped.

4

Tankering is forecasted to occur only in water depths >1,600 m (5,249 ft). 

Tankering: The OCS oil- and gas-related tankering began in 2012. Since 2012, tankering 

has increased to account for about 2 percent of the yearly production of oil. Chapter 3.1.4.2

describes in detail activities associated with tankering. BOEM estimates that 5-14 FPSO systems 

could be installed regionwide (a maximum of 2 per decade) as a result of the Cumulative OCS Oil 

and Gas Program scenario. Zero to five systems are projected within the WPA and 5-9 systems are 

projected within the CPA/EPA. As a result of these additional systems, up to 9 percent of the oil 

during any given year may be tankered to a processing facility (Table 3-25).

Service Vessels: Chapter 3.1.4.3 describes in detail activities associated with service 

vessels. The Cumulative OCS Oil and Gas Program scenario estimates that 3,909,000-11,873,000 

service-vessel trips would occur regionwide over the 70-year analysis period (Table 3-23) or 

55,842-169,614 trips annually. Table 3-7 indicates 875,000 vessel trips occurred on Federal 

navigation channels, ports, and OCS oil- and gas-related waterways in 2012. Annual OCS oil- and 

gas-related vessel traffic due to cumulative OCS oil- and gas-related activity represents between 

6 and 19 percent of the total traffic in the GOM.

Helicopters: Chapter 3.1.4.4 describes in detail activities associated with helicopters. The 

Cumulative OCS Oil and Gas Program scenario estimates that 17-83 million helicopter trips would 
Impact-Producing Factors and Scenario 3-165

occur regionwide over the 70-year analysis period (Table 3-23). This equates to an average rate of 

240,000-1,190,000 operations annually.

3.3.1.8 Discharges and Wastes 

Detailed descriptions of discharges and wastes associated with the OCS Oil and Gas 

Program activity can be found in Chapter 3.1.5. Various laws, regulations, and NTLs would likely 

minimize the discharges and wastes from OCS oil- and gas-related activities in association with the 

Cumulative OCS Oil and Gas Program scenario. Cumulative effects of discharges and wastes are 

discussed in Chapter 4.2. 

3.3.1.9 Decommissioning and Removal Operations

As of 2013, approximately 62.5 percent of structures had been decommissioned and 

removed (USDOI, BSEE, 2015e; Figure 3-19. Chapter 3.1.6 describes in detail decommissioning 

and removal operations. Table 3-23 shows the forecasted platform removals by water-depth range 

for the Cumulative OCS Oil and Gas Program scenario for each planning area of the GOM. Of the 

4,281-8121 production structures estimated to be removed from the GOM in the Cumulative Oil and 

Gas Program scenario, 3,003-5,698 production structures (installed landward of the 800-m [2,625-ft] 

isobath) would likely to be removed using explosives.

3.3.1.10 Coastal Infrastructure

Refer to Table 3-5 for information on existing coastal infrastructure that services the OCS Oil 

and Gas Program. Chapter 3.1.7 describes coastal infrastructure in detail. The Cumulative OCS Oil 

and Gas Program scenario estimates no additional: service bases, heliports, platform fabrication 

yards, shipyards, or pipe-coating facilities and yards.

Expectations for new gas processing facilities being built (as a direct result of the Cumulative 

OCS Oil and Gas Program) are dependent on long-term market trends that are not easily predicable 

over the next 70 years. Existing facilities would likely experience equipment switch-outs or upgrades 

during this time. BOEM projects that expansions at existing LNG facilities and the construction of 

new facilities would not occur as a direct result of the cumulative OCS Oil and Gas Program. New 

refineries may be built, but there has been a trend toward constructing simple refineries instead of 

complex refineries.

3.3.1.11 Air Emissions

Chapter 3.1.8 describes in detail activities associated with the production of air emissions. 

BOEM is responsible for determining if air pollutant emissions from offshore oil and gas activities in 

the Gulf of Mexico influence the NAAQS’ compliance status of Texas, Louisiana, Mississippi, 

Alabama, and Florida. As such, BOEM would continue to inventory emissions and model emissions 

whenever the USEPA updates the NAAQS. Effects to air quality from the Cumulative OCS Oil and 

Gas Program are discussed in Chapter 4.1. 
3-166 Gulf of Mexico Multisale EIS

3.3.2 Non-OCS Oil- and Gas-Related Impact-Producing Factors

The impact-producing factors considered in this chapter are defined as other past, present, 

and reasonably foreseeable future activities occurring within the same geographic range and within 

the same timeframes as the aforementioned projected routine activities and potential accidental 

events, but they are not related to the Cumulative OCS Oil and Gas Program. This chapter

describes other impact-producing factors that could potentially affect an environmental or 

socioeconomic resource in addition to OCS oil- and gas-related activity.

While the scenario developed for the Cumulative OCS Oil and Gas Program scenario

forecasts 70 years of activities, the scenarios developed as part of this chapter vary in the length of 

time projected depending on what would be considered reasonably foreseeable by impact-producing 

factors based on the data available and the ability to predict future actions without being speculative. 

3.3.2.1 State Oil and Gas Activity

All of the five Gulf Coast States have had some historical oil and gas exploration activity and, 

with the exception of Florida and Mississippi, all currently produce oil and gas in State waters. The 

coastal infrastructure that supports the OCS Program also supports State oil and gas activities.

State oil and gas infrastructure consists of the wells that extract hydrocarbon resources, 

facilities that produce and treat the raw product, pipelines that transport the product to refineries and 

gas plants for further processing, and additional pipelines that transport finished product to points of 

storage and final consumption. The type and size of infrastructure that supports production depends 

upon the size, type, and location of the producing field, the time of development, and the life cycle 

stage of operations.

Texas

According to the Railroad Commission of Texas, since June 2015 cumulative total State 

offshore production of oil was reported at over 42 million bbl and offshore gas production totals were 

reported at over 4.1 billion Mcf (Railroad Commission of Texas, 2015). Texas was the leading 

crude-oil producing state in the Nation in 2013 and exceeded production levels even from the 

Federal offshore areas (USDOE, Energy Information Administration, 2014a).

The Lands and Minerals Division of the Texas General Land Office holds lease sales for oil 

and gas on State lands, and the Texas General Land Office manages Texas State resources for the 

benefit of public education. The Texas General Land Office generally holds lease sales every 4 

months in January, April, July, and October. The Texas General Land Office’s Mineral Leasing 

Division uses a sealed bid process for the leasing of State lands. BOEM expects that Texas would 

conduct regular oil and gas lease sales in State waters during the next 70 years, although the lease 

sales’ regularity could differ from current practices.
Impact-Producing Factors and Scenario 3-167

Louisiana

Louisiana has been the second most important oil- and gas-producing state after Alaska. Oil 

production in Louisiana began in 1902, with the first oil production in the coastal zone in 1926. 

Southern Louisiana produces mostly oil and northern Louisiana produces mostly gas. Over the last 

60 years, Louisiana averaged around 27 MMbbl of oil and 12 Tcf of gas per year (State of Louisiana, 

Dept. of Natural Resources, 2015a and 2015b). 

Louisiana’s leasing procedure is carried out by the Petroleum Lands Division of the Office of 

Mineral Resources within the Louisiana Department of Natural Resources (State of Louisiana, Dept. 

of Natural Resources, 2015c). BOEM expects that Louisiana would conduct regular oil and gas 

lease sales in State waters during the next 70 years. 

Mississippi

At present, Mississippi only has an onshore oil and gas leasing program; however, it is 

expected that the State would start issuing leases for offshore activity in State waters in the near 

future. In 2004, the Mississippi Legislature limited offshore natural oil and gas exploration to areas 

located predominantly south of the barrier islands. On December 19, 2011, the Mississippi 

Development Authority published draft regulations; the public comment period closed on January 20, 

2012 (Mississippi Development Authority, 2011). However, recent efforts to open Mississippi State 

waters for G&G and leasing activities have been challenged in court (Davis, 2014).

Development of an offshore oil and gas leasing program in Mississippi State waters during 

the next 70 years is reasonably foreseeable. 

Alabama

The State Oil and Gas Board of Alabama is the regulatory agency of the State of Alabama 

with statutory charge of oil and gas development. From 1989 to 2014, a total of 8,278,884 MMcf of 

gas has been produced in State waters, averaging approximately 331,155 MMcf of gas production 

per year. From 1989 to 2012, a total of 293,730,516 bbl of oil were produced, averaging 

approximately 12,770,892 bbl/yr (State of Alabama, Oil and Gas Board, 2015). 

Alabama has no established schedule of lease sales. The limited number of tracts in State 

waters has resulted in the State not holding regularly scheduled lease sales. The last lease sale 

was held in 1997. BOEM does not expect Alabama to institute a lease sale program in the near 

future, although there is at least a possibility of a lease sale in State waters during the next 70 years. 

Florida

The Florida Department of Environmental Protection’s Mining Mitigation and Delineation 

Program is the permitting authority for the exploration and production of oil and gas in Florida.
3-168 Gulf of Mexico Multisale EIS

A total of 19 wells were drilled in Florida State waters from 1947 to 1983 (State of Florida, 

Dept. of Natural Resources, 1991). Offshore exploratory drilling in Federal waters of the EPA 

included six wells completed in 1988 and 1989; one of these was the discovery in the Destin Dome 

Area and was classified by the Federal Government as a producible field (State of Florida, Dept. of 

Natural Resources, 1991). In July 1990, all offshore drilling activity in Florida State waters was 

prohibited and the State’s policy on offshore oil and gas drilling changed. Since 1989, the Florida 

State Congress has prohibited new leasing off Florida in the EPA.

With current State policy and regulations prohibiting oil and gas exploration and development 

in State waters, BOEM does not expect Florida to institute a lease sale program in the near future. If 

State policy and regulations change and the moratorium is allowed to expire, the potential for a lease 

sale in State waters could be a possibility during the next 70 years. 

3.3.2.1.1 State Pipeline Infrastructure

The existing pipeline network in the Gulf Coast States is the most extensive in the world and 

has unused capacity (Cranswick, 2001). The network carries oil and gas onshore and inland to 

refineries and terminals, and a network of pipelines distributes finished products such as diesel fuel 

or gasoline to and between refineries and processing facilities onshore (Peele et al., 2002, Figure 

4.1). Expansion of this network is projected to be primarily small-diameter pipelines to increase the 

interconnectivity of the existing network and a few major interstate pipeline expansions. However, 

as discussed in Chapter 3.1.3.3.1, there is spare capacity in the existing pipeline infrastructure to 

move oil and gas to market, and deepwater ports can serve onshore facilities, including intrastate as 

well as interstate pipelines. Refer to Table 3-6 for a list of current pipeline landfalls.

3.3.2.1.2 Artificial Reefs

Use of artificial reefs to enhance fisheries along the U.S. coastline was documented as early 

as the mid-19th century (Stone, 1974; McGurrin et al., 1989; Christian et al., 1998). For nearly 

200 years, purpose-built structures (e.g., wooden huts, cinder block reefs, and concrete pyramids) 

and obsolete materials (e.g., decommissioned vessels and damaged concrete pipe) have been 

intentionally deposited in estuarine and marine environments to add bottom relief, attract fishes, and 

improve angler access and success. As a result of research into the potential benefits and adverse 

impacts resulting from specific artificial reef designs, materials, and siting, the National Artificial Reef 

Plan and subsequent revision in 2007 were developed to provide guidance to artificial reef 

coordinators, fisheries managers, and other parties on recommended siting, construction, 

management, and monitoring of artificial reefs. The Secretary of the Army, through the COE, is 

responsible for the artificial reef permitting process and for coordination of the appropriate State and 

Federal agencies (USDOC, NOAA, 2007). The Wallop-Breaux Amendment provided increased 

Federal funding to State agencies for sport fish restoration, contributing to the National Fisheries 

Enhancement Act’s objectives through support of habitat enhancement projects, research, and 

monitoring (Christian et al., 1998).
Impact-Producing Factors and Scenario 3-169

Offshore oil and gas platforms have been contributing hard substrate to the GOM since the 

1930’s, and fishermen quickly found fishing success was enhanced in the vicinity of OCS oil- and 

gas-related structures (State of Louisiana, Dept. of Wildlife and Fisheries, 1987). By the late-1970’s 

some artificial reef advocates and recreational fishermen had begun viewing the decommissioning

and removal of OCS oil- and gas-related structures as a lost opportunity. The increased interest and 

participation in fishing at offshore oil and gas platforms and national support for effective artificial 

reef development coincided with research and fisheries management efforts, which led to passage 

of the National Fishing Enhancement Act of 1984 and the development of the first National Artificial 

Reef Plan. In 1987, Louisiana published a State artificial reef plan that specifically addressed the 

need to support public interest through development of artificial reef planning areas and the addition 

of decommissioned OCS platforms as artificial reef substrate (State of Louisiana, Dept. of Wildlife 

and Fisheries, 1987). Texas’ Artificial Reef Act of 1989 explicitly identified decommissioned 

platforms as the preferred substrate for the construction of artificial reefs (State of Texas, Parks and 

Wildlife Dept., 1990). Currently, all five Gulf Coast States have active artificial reef programs, which 

develop and manage artificial reefs on the Federal OCS.

The OCSLA and implementing regulations establish decommissioning obligations for 

lessees, including the removal of platforms. The Rigs-to-Reefs Policy provides a means by which 

lessees may request a waiver to the removal requirement. For additional information, refer to 

Chapter 3.1.6.2. Since the first Rigs-to-Reefs conversion, approximately 11 percent of the platforms 

decommissioned from the Gulf of Mexico OCS have been redeployed within designated State 

artificial reefs. Scientific and public interest in the ecology of offshore structures and the potential 

benefits of contributing hard substrate to a predominantly soft bottom environment have led to 

increased emphasis on the development of artificial reefs. The current paradigm posits oil and gas 

structures act as both fish-attracting and production-enhancing devices, depending upon the species 

(Carr and Hixon, 1997; Gallaway et al., 2009; Shipp and Bortone, 2009; and Dance et al., 2011). 

However, determination of specific and cumulative impacts resulting from construction of artificial 

reefs within permitted areas is very difficult. As recommended by the National Artificial Reef Plan 

(USDOC, NOAA, 2007), well-defined objectives, clear management strategies, and long-term 

monitoring are critical elements of an artificial reef program and are necessary if managers intend to 

use artificial reefs as a fisheries management tool.

3.3.2.2 Marine Vessel Activity

Under current conditions, freight and cruise ship passenger marine transportation within the 

analysis area should continue to grow at a modest rate or remain relatively unchanged based on 

historical freight and cruise traffic statistics. In 2013, the Sabine-Neches Waterway had the highest 

vessel capacity, followed by the Port of New Orleans in terms of tonnage handled. The Port of 

Houston was the third largest port in the United States (USDOT, MARAD, 2015a). Tankers carrying 

mostly petrochemicals account for about 60 percent of the vessel calls in the Gulf of Mexico. Drybulk vessels, including bulk vessels, bulk containerships, cement carriers, ore carriers, and woodchip carriers, account for another 17 percent of the vessel calls. The GOM also supports a popular 

cruise industry. In 2011, there were 149 cruise ship departures from Galveston, 139 cruise ship 
3-170 Gulf of Mexico Multisale EIS

departures from New Orleans, and 199 cruise ship departures from Tampa (USDOT, MARAD, 

2012).

Total port calls, or vessel stops at a port, in the U.S. is increasing as a whole, and total port 

calls within the GOM is also increasing. Gulf of Mexico port calls represent approximately 

33 percent of total U.S. port calls. Trends for GOM port calls relative to total U.S. port calls shows 

an approximate 3 percent average increase of GOM port calls between 2003 and 2012, from 

18,034 to 24,730 port calls (USDOT, MARAD, 2015a) (Table 3-26). 

Table 3-26. Number of Vessel Calls at U.S. Gulf Ports Between 2002 and 20111. 

Vessel Type 2003 2004 2005 2006 2007 2008 2009 2010 2011 201211

TankerProduct2,3 5,143 5,764 6,171 6,594 6,784 6,597 6,451 7,000 8,413

15,032

Tanker-Crude2,4 4,227 4,361 4,303 4,343 4,614 4,574 4,502 5,150 5,626

Container5 1,263 1,284 1,378 1,354 1,306 1,372 1,641 1,934 2,338 2,047

Dry Bulk6 4,837 4,959 4,575 5,289 4,988 4,563 4,021 3,475 3,917 4,888

RO-RO (Roll-on 

Roll-off)7 398 370 337 423 386 374 491 549 566 547

Gas8 624 548 558 622 628 462 441 500 604 612

Combo9 375 258 201 155 135 116 102 94 66 NA

General10 1,167 1,141 1,160 1,246 1,362 1,363 1,300 1,387 1,459 1,604

All Types 18,034 18,685 18,683 20,026 20,203 19,421 18,949 20,089 22,989 24,730

1

The data in this report are only for oceangoing self-propelled vessels of 10,000 deadweight (DWT) capacity 

or greater. In 2005, these vessels accounted for 98 percent of the capacity calling at U.S. ports.

2

Petroleum tankers and chemical tankers.

3

10,000-69,999 DWT. 4

>70,000 DWT.

5

Container carriers, refrigerated container carriers.

6

Bulk vessels, bulk containerships, cement carriers, ore carriers, wood-chip carriers. 7

RO/RO vessels, RO/RO containerships, vehicle carriers.

8

Liquefied natural gas carriers, liquefied natural gas/liquefied petroleum gas carriers, liquefied petroleum 

carriers.

9

Ore/bulk/oil carriers, bulk/oil carriers.

10General cargo carriers, partial containerships, refrigerated ships, barge carriers, livestock carriers.

11In 2012, product and crude tankers were not distinguished.

Source: USDOT, MARAD, 2015a.

It is expected that the usage of GOM ports would continue to increase by approximately 

3 percent annually over the next 50 years. As such, it is anticipated that port calls by all ship types 

would be bounded annually by a lower limit of current use and an upper limit of approximately 

99,417 vessel port calls per year.

Non-OCS oil- and gas-related tankering includes ships carrying crude or ships carrying 

product. Overall, tankering (including U.S. ships and foreign ships) in the U.S. increased by 
Impact-Producing Factors and Scenario 3-171

28 percent between 2003 and 2011 (USDOT, MARAD, 2013). While U.S. tankering port of calls 

declined between 2003 and 2011, foreign ship tankering port of calls increased, as listed below.

Ship Origin 2003 2011

U.S. Tankers 3,759 2,956

Foreign Tankers 14,744 20,722

Source: USDOT, MARAD, 2013.

Due to the double-hulled ships’ ability to reduce or prevent oil spills, double-hulled ships 

have replaced almost all single-hulled ships. In 2003, 60-70 percent of all tankers were double 

hulled, but by 2011, 97-100 percent of all tankers were double hulled.

Non-OCS oil- and gas-related vessels other than those listed above utilize the GOM. These 

ships include research vessels, recreational vessels and commercial vessels. Commercial and 

recreational fishing in the Gulf of Mexico are regulated by NMFS. For more information on 

recreational fishing vessels, refer to Chapter 4.11. For more information on commercial fishing 

vessels, refer to Chapter 4.10. Research activities, including surveys, genetic research, capture, 

relocation, or telemetric monitoring, may affect organisms or ecosystems in the GOM. If any of 

these activities could involve the take of an endangered species, the activity is required to obtain a 

permit through NMFS. Vessels involved in the photography of marine mammals may also require a 

permit through NMFS. 

Any of the non-OCS oil- and gas-related vessels could affect marine and archaeological 

resources by anchoring. Effects would be similar to those discussed in the OCS oil- and gas-related 

anchoring Chapter 3.1.3.4.1. 

3.3.2.3 Non-OCS Oil- and Gas-Related Wastes and Discharges

Current and historic marine activities, unrelated to the OCS oil and gas program, are

considered in the cumulative scenario for water quality in the GOM. These include regulated 

effluents from State oil and gas activities and the discharge of bilge, ballast water, and sanitary 

wastes from commercial shipping, similar to OCS oil- and gas-related service vessels (Chapter 

3.1.5). Other non-OCS oil- and gas-related wastes are associated with dredged material disposal, 

potentially polluting shipwrecks, military activities, disposal of military chemical weapons and 

industrial wastes, land-based discharges, and non-OCS oil- and gas-related sources of trash and 

debris.

3.3.2.3.1 Potentially Polluting Shipwrecks

There are thousands of shipwrecks in U.S. waters. Some of the vessels involved in those 

wrecks are likely to contain oil, as fuel and possibly cargo, and may eventually result in pollution to 

the marine environment. Warships and cargo vessels sunk in wartime may also contain munitions, 

including explosives and chemical warfare agents, which may pose a continued threat because of 

their chemical composition. The NOAA maintains a large database of shipwrecks, dumpsites, 
3-172 Gulf of Mexico Multisale EIS

navigational obstructions, underwater archaeological sites, and other underwater cultural resources 

(USDOC, NOAA, 2013b). This internal database, Resources and Undersea Threats, includes 

approximately 20,000 shipwrecks in U.S. waters. Shipwrecks in the Resources and Undersea 

Threats database were ranked to identify the most ecologically and economically significant, 

potentially polluting wrecks in U.S. waters for inclusion in the Remediation of Underwater Legacy 

Environmental Threats Program. Under this Program, wrecks are ranked based on age, size, hull 

material, type, location, historical information on the vessel, engineering analysis, archaeological site 

formation, whether they are currently leaking, and modeling of the trajectory, fate, and 

consequences of an oil release from a shipwreck. The NOAA identified 87 priority wrecks on the 

2012 Remediation of Underwater Legacy Environmental Threats Program (those with the highest 

probability of discharge). Of these, 53 sank during an act of war and 34 sank as a result of collision, 

fire, grounding, storms, or other causes. Priority wrecks located in the Gulf of Mexico include 

R.W. Gallagher, which contains 80,855 bbl of Bunker C fuel oil, located about 40 mi (64 km) south of 

Terrebonne Parish, Louisiana, and Joseph M. Cudahy, which contains 77,444 bbl of crude and 

lubricating oil, located about 65 mi (105 km) northwest of Key West, Florida. The NOAA Wreck Oil 

Removal Program provides for the removal of oil from priority wrecks, where feasible.

Another shipwreck of note is Tank Barge DBL 152, which, on November 11, 2005, struck the 

submerged remains of a pipeline service platform in West Cameron Block 229 (about 50 mi [80 km]

southeast of Sabine Pass, Texas). The platform had previously collapsed during Hurricane Rita. 

The barge was carrying a cargo of approximately 119,793 bbl of a blended mixture of low-API 

gravity oil (i.e., heavy oil, likely to sink). A portion of the oil was released at the point of impact, 

which sank to the seafloor. The barge was towed toward shallow water to facilitate salvage; 

however, it grounded and capsized approximately 12 mi (19 km) to the west-northwest, releasing 

additional oil to the seafloor. An estimated 45,846 bbl of oil were released during the incident, of 

which about 2,355 bbl were recovered by divers. In January 2006, recovery of additional oil was 

deemed infeasible and cleanup operations were discontinued, leaving approximately 43,491 bbl of 

oil unrecovered on the seafloor (USDOC, NOAA, 2013c).

3.3.2.3.2 Discharges Associated with Military Activities

A full description of military activities is discussed in Chapter 3.3.2.6.1 below. Military 

operations within military warning areas (MWAs) and Eglin Water Test Areas (EWTAs) vary in types 

of missions performed and their frequency of use. Such missions may include carrier maneuvers, 

missile testing, rocket firing, pilot training, air-to-air gunnery, air-to-surface gunnery, minesweeping 

operations, submarine operations, air combat maneuvers, aerobatic training, and instrument training. 

To eliminate potential impacts from multiple-use conflicts related to the warning and test areas, a 

standard Military Areas Stipulation is routinely applied to all GOM leases (example in 

Appendix D.3).

Between the years of 1995 through 1999, Eglin Air Force Base in Florida conducted nearly 

39,000 training sorties per year in the eastern Gulf. Potential impacts from these activities are 

discussed in the Eglin Gulf Test and Training Range, Final Programmatic Environmental 
Impact-Producing Factors and Scenario 3-173

Assessment (Air Force Air Armament Center, 2002). These military activities may result in marine 

impacts from chaff, fuel releases, flares, chemical materials, and debris.

Chaff, which is composed of short aluminum fibers similar in appearance to human hair, 

metalized glass fiber, or plastic, is dispensed by military aircraft as a countermeasure to distract 

radar-guided missiles from their targets. The Air Force Air Armament Center identified a remote 

potential that chaff could be mistaken as a food source and be ingested by aquatic organisms; 

however, the quantity of chaff used was not stated (Air Force Air Armament Center, 2002, 

page 4-18).

During in-flight emergencies, fuel may be released in the air or a fuel tank may be jettisoned 

and impact the surface. Drones may also be shot down and release fuel upon surface impact. The 

type of fuel used, JP-8, is very volatile and, when released at altitude, evaporates quickly. The Air 

Force Air Armament Center concluded that temporary localized effects to air and water quality may 

result from fuel releases; however, the frequency of fuel releases is extremely low (Air Force Air 

Armament Center, 2002, pages ES-1 and ES-2).

Flares may be ejected from aircraft to confuse and divert enemy heat-seeking or heatsensitive missiles, and may also be used to illuminate surface areas during nighttime operations. 

Flares are composed primarily of aluminum, magnesium, and TeflonTM. Upon burning, the 

magnesium (as magnesium oxide) in the flare may be deposited on the water surface. The Air 

Force Air Armament Center characterizes the impact to water from flares to be less than the natural 

concentrations of magnesium found in the Gulf (Air Force Air Armament Center, 2002, pages 4-20 

and 4-21).

The Air Force Air Armament Center stated that chemical materials are introduced into the 

marine environment through drones, gun ammunition, missiles, chaff, flares, smokes and 

obscurants. The Air Force Armament Center concluded that potential chemical contamination 

concentrations were extremely low and not likely to impact marine species.

Debris may be released into the GOM as a result of military activities, including ordnance 

and shrapnel deposits from bombs and missiles, drones, chaff and flare cartridges, and intact inert 

bombs. This debris generally falls into the major categories of aluminum, steel, plastic, concrete, 

and other components (i.e., copper and lead) and originates largely from inert bombs, missiles, and 

downed drones (Air Force Armament Center, 2002, page 2-21).

3.3.2.3.3 Historical Chemical Weapon Disposal Areas

After World War I, chemical weapons were routinely disposed of in the world’s oceans, 

including the GOM. In some instances, conventional explosives and radiological wastes were 

dumped along with chemical weapons. Army records document several instances of mustard and 

phosgene bombs being disposed of in the Gulf of Mexico, originating from New Orleans, Louisiana, 

and Mobile, Alabama. Chemical weapons disposed of in other locations, and potentially in the Gulf 
3-174 Gulf of Mexico Multisale EIS

of Mexico, contained hydrogen cyanide, arsenic trichloride, cyanogen chloride, lewisite, tabun, sarin, 

and VX, as reported in a Report to Congress (Bearden, 2007).

Six former explosives dumping areas are noted on NOAA’s chart of the Gulf of Mexico 

(USDOC, NOAA, 2015a) and likely contain disposed chemical weapons. These include two areas 

offshore Texas (about 65 nmi [75 mi; 120 km] southeast of Aransas Pass and about 100 nmi 

[115 mi;185 km] south of Galveston); two areas offshore Louisiana (both about 35-40 nmi 

[42-46 mi;65-74 km] south of the mouth of the Mississippi River); one area offshore Alabama (about 

70 nmi [81 mi; 130 km] southeast of Mobile Bay); and one offshore Florida (about 130 nmi [150 mi; 

241 km] west of Tampa Bay).

The Marine Protection, Research, and Sanctuaries Act of 1972, also known as the Ocean 

Dumping Act, was promulgated to regulate ocean dumping and to set aside certain areas as national 

marine sanctuaries. Section 101 of the Act (33 U.S.C. § 1411) prohibits ocean dumping, except as 

authorized by permit issued by the USEPA pursuant to Section 102 (33 U.S.C. § 1412). Section 102 

specifically states that radiological, chemical, and biological warfare agents, high-level radioactive 

waste, and medical waste would not be permitted for ocean disposal after 1972.

3.3.2.3.4 Historical Industrial Waste Dumping Areas

Between 1940 and 1970, certain offshore locations of the United States were used for the 

disposal of various industrial wastes and low-level radioactive wastes, these activities being large, 

unrecorded, and unregulated (USDOC, NOAA, 2015b).

Section 102 of the Ocean Dumping Act (33 U.S.C. § 1412) authorizes the issuance of 

permits for ocean disposal of certain waste streams and requires that the USEPA determine that 

such dumping will not unreasonably degrade or endanger human health, welfare, or amenities, or 

the marine environment, ecological systems, or economic potentialities.

In 1973, the USEPA permitted two interim industrial waste disposal sites in the Gulf of 

Mexico pursuant to Section 102 of the Marine Protection, Research, and Sanctuaries Act, the 

charting of which has been maintained by NOAA. Disposal Site A, located within the WPA, is 

situated on the upper part of the Texas-Louisiana continental shelf, about 125 nmi (144 mi; 232 km) 

south of Galveston, Texas. Disposal Site B is located in the CPA off the western side of the 

Mississippi Delta about 60 nmi (75 mi; 120 km) south of the mouth of the Mississippi River. The

National Academy of Sciences’ report, Assessing Potential Ocean Pollutants (National Academy of 

Sciences, 1975), provides additional information about these sites. 

3.3.2.3.5 Dredged Material Disposal

Dredged material is described in 33 CFR part 324 as any material excavated or dredged 

from navigable waters of the United States. Materials from maintenance dredging are primarily 

disposed of offshore on existing dredged-material disposal areas and in ocean dredged-material 

disposal sites (ODMDSs). Additional dredged-material disposal areas for maintenance or new-
Impact-Producing Factors and Scenario 3-175

project dredging are developed as needed and must be evaluated and permitted by COE and 

relevant State agencies prior to construction. The ODMDSs are regulated by the USEPA under the 

Clean Water Act and the Marine Protection, Research, and Sanctuaries Act.

If funds are available, the COE uses dredge materials beneficially for restoring and creating 

habitat, for beach nourishment projects, and for industrial and commercial development (Chapter 

3.3.2.8.3). The applicant would need funds to cover the excess cost over the least cost 

environmentally acceptable alternative (the Federal Standard). The material must also be suitable 

for the particular beneficial use. Virtually all ocean dumping that occurs today is maintenance 

dredging of sediments from the bottom of channels and bodies of water in order to maintain 

adequate channel depth for navigation and berthing. There are four authorized open-water disposal 

areas in Louisiana and Mississippi along stretches of the main Gulf Intracoastal Waterway (GIWW) 

between Louisiana and Mississippi: in Louisiana, Disposal Area 66 (1,593 ac; 645 ha); and in 

Mississippi, Disposal Area 65A (1,962 ac; 794 ha), Disposal Area 65B (815 ac; 330 ha), and 

Disposal Area 65C (176 ac; 71 ha) (U.S. Dept. of the Army, COE, 2008, Table 1). Dredged 

materials from the GIWW are disposed of at these locations. The ODMDSs utilized by the COE are 

located in the cumulative activities area and can be found on the Ocean Disposal Database website

(U.S. Dept. of the Army, COE, 2015a). 

There are two primary Federal environmental statutes governing dredge material disposal. 

The Marine Protection, Research, and Sanctuaries Act (also called the Ocean Dumping Act) govern

transportation for the purpose of disposal into ocean waters. Section 404 of the Clean Water Act 

governs the discharge of dredged or fill material into U.S. coastal and inland waters. The USEPA 

and COE are jointly responsible for the management and monitoring of ocean disposal sites. The 

responsibilities are divided as follows: (1) the COE issues permits under the Clean Water Act and 

the Marine Protection, Research, and Sanctuaries Act; (2) the USEPA has lead for establishing 

environmental guidelines/criteria that must be met to receive a permit under either statute; 

(3) permits for ODMDS disposal are subject to USEPA review and concurrence; and (4) the USEPA 

is responsible for designating ODMDSs.

The COE’s Ocean Disposal Database reports the amount of dredged material disposed in 

ODMDSs by district (U.S. Dept. of the Army, COE, 2015a). Table 3-27 shows the quantities of 

dredged materials disposed of in ODMDSs between 2004 and 2013 by the Galveston, New Orleans, 

and Mobile Districts.
3-176 Gulf of Mexico Multisale EIS

Table 3-27. Quantities of Dredged Materials Disposed of in Ocean Dredged-Material Disposal Sites 

Between 2004 and 2013. 

Year

New Orleans District Galveston District Mobile District

yd3 m3 yd3 m3 yd3 m3

2004 21,156,300 16,175,160 4,078,900 3,118,544 9,902,000 7,570,626

2005 21,403,200 16,363,928 1,250,900 956,382 3,796,900 2,902,940

2006 13,493,400 10,316,449 9,182,200 7,020,299 3,219,100 2,461,180

2007 17,550,700 13,418,479 6,361,200 4,863,489 1,952,800 1,493,023

2008 16,800,900 12,845,216 5,664,800 4,331,052 3,725,093 2,848,039

2009 7,618,900 5,825,070 16,295,000 12,458,427 10,351,223 7,914,082

2010 15,386,100 11,763,523 6,226,300 4,760,350 4,361,670 3,334,738

2011 15,613,143 11,937,110 3,502,600 2,677,931 3,749,570 2,866,753

2012 14,680,727 11,224,226 10,875,772 8,315,128 1,592,204 1,217,328

2013 3,669,836 2,805,792 4,452,299 3,404,028 3,473,019 2,655,315

Average 14,737,321 11,267,495 6,788,997 5,190,563 4,612,358 3,526,402

Source: U.S. Dept. of the Army, COE, 2015a. 

The New Orleans District dredges an average annual 14.7 million yd3 (11.3 million m3). 

Current figures estimate that approximately 38 percent of that average is available for the beneficial 

use of dredge materials program (U.S. Dept. of the Army, COE, 2013). The remaining 62 percent of 

the total material dredged yearly by the COE’s New Orleans District is disposed of at placement 

areas regulated under Section 404 of the Clean Water Act, at ODMDSs, or is stored in temporary 

staging areas located inland (e.g., the Pass a Loutre Hopper Dredge Disposal Site at the head of the 

Mississippi River’s main “birdfoot” distributary channel system).

Evaluation of dredged material for ocean disposal under the Marine Protection, Research, 

and Sanctuaries Act relies largely on biological (bioassay) tests. The ocean testing manual, 

commonly referred to as the Green Book (USEPA, 1991), provides national guidance for 

determining the suitability of dredged material for ocean disposal. Benthic and water-column 

impacts of dredged material disposal are evaluated prior to disposal through analysis of 

representative samples of the material to be disposed, unless the sand source is previously 

characterized. Sample evaluation may include physical analysis (i.e., grain size, total solids, and 

specific gravity) and chemical analysis for priority pollutants (i.e., metals, semivolatile and volatile 

organic compounds, PCBs, and pesticides).

BOEM anticipates that, over the next 70 years, the amount of dredged material disposed of 

at ODMDSs would fluctuate generally within the trends established by the COE district offices. 

Between 2004 and 2013, the New Orleans District has averaged about 14.7 million yd3

(11.2 million m3

) of material dredged per year disposed of at ODMDSs, while the Mobile District is 

about one-quarter of that quantity, or 4.6 million yd3 (3.5 million m3

). Quantities disposed of at 

ODMDSs may decrease as more beneficial uses of dredged material onshore are identified and 

evaluated.
Impact-Producing Factors and Scenario 3-177

3.3.2.3.6 Land-Based Discharges

As authorized by the Clean Water Act, the NPDES permit program controls water pollution 

by regulating point sources on land that discharge pollutants into waters of the United States. Point 

sources are discrete conveyances (outfalls) such as pipes or manmade ditches that may contain 

process water flows and/or precipitation from impervious surfaces. Industrial, municipal, and other 

facilities must obtain permits if their discharges go directly to surface waters. In most cases, the 

NPDES permit program is administered by authorized states (USEPA, 2015a).

The NPDES program includes periodic characterization of outfall flow to limit pollutants 

entering surface water. The Mississippi River basin drains 41 percent of the 48 contiguous states of 

the United States. The basin covers more than 1,245,000 mi2 (3,224,535 km2

) and includes all or 

parts of 31 states and two Canadian provinces (U.S. Dept. of the Army, COE, 2015b). Nonpointsource contributions to the Mississippi River from erosion, uncontained runoff, and groundwater 

discharge are primary sources of freshwater, sediment, suspended solids, organic matter, and 

pollutants (including nutrients, heavy metals, pesticides, oil and grease, and pathogens). As a 

result, water quality in coastal waters of the northern GOM is highly influenced by seasonal variation 

in river flow. The Mississippi River introduces approximately 3,680,938 bbl of oil and grease per 

year from land-based sources (NRC, 2003, Table I-9, page 242; Chapter 3.3.2.4) into the waters of 

the Gulf. Nutrients carried in waters of the Louisiana and Texas rivers contribute to seasonal 

formation of hypoxic zones (1Chapter 3.3.2.12) on the Louisiana and Texas shelf. Additional 

information regarding water quality in the northern GOM can be found in Chapter 4.2. 

3.3.2.3.7 Trash and Debris 

Marine debris originates from both land-based and ocean-based sources. Forty-nine percent 

of marine debris originates from land-based sources, 18 percent originates from ocean-based 

sources, and 33 percent originates from general sources (sources that are a combination of landbased and sea-based activities) (USEPA, 2009a). Some of the sources of land-based marine debris 

are beachgoers, storm-water runoff, landfills, solid waste, rivers, floating structures, and illmaintained garbage bins. Marine debris also comes from combined sewer overflows and typically 

includes medical waste, street litter, and sewage. Ocean-based sources of marine debris include 

galley waste and other trash from ships, recreational boaters, fishermen, and offshore oil and gas 

exploration and production facilities. Commercial and recreational fishers produce trash and debris 

by discarding plastics (e.g., ropes, buoys, fishing line and nets, strapping bands, and sheeting), 

wood, and metal traps. Some trash items, such as glass, pieces of steel, and drums with chemical 

or chemical residues, can be a health threat to local water supplies and as a result to biological, 

physical, and socioeconomic resources, to beachfront residents, and to users of recreational 

beaches. To compound this problem, there is population influx along the coastal shorelines. These 

factors, combined with the growing demand for manufactured and packaged goods, have led to an 

increase in nonbiodegradable solid wastes in our waterways.
3-178 Gulf of Mexico Multisale EIS

3.3.2.4 Non-OCS Oil- and Gas-Related Spills

The NRC (2003) computed petroleum hydrocarbon inputs into North American marine 

waters for several major categories. The results show that three activities – extraction, 

transportation, and consumption – are the main sources of anthropogenic petroleum hydrocarbon 

pollution in the sea.

Non-OCS oil- and gas-related spills include the loss of petroleum products as a result of the 

extraction-, transportation-, and refinery-related activities from State oil and gas leases offshore 

Louisiana and Texas. The major sources of petroleum hydrocarbon discharges into the marine 

waters by transportation activities, including non-OCS oil- and gas-related sources, are tank vessel 

spills, operational discharges from cargo washings, coastal facilities spills, and gross atmospheric 

deposition of VOC releases from tankers. Non-OCS oil- and gas-related offshore spills are possible 

during the extensive maritime barging and tankering operations that occur in offshore waters of the 

GOM. Spills from transportation activities include a wide variety of petroleum products (not just 

crude oil), each of which behaves differently in the environment and may contain different 

concentrations of toxic compounds.

Consumption-related sources of petroleum releases to the marine environment include landbased sources (i.e., river discharge and runoff), two-stroke vessel discharge, non-tank vessel spills, 

operational discharges, gross atmospheric deposition, and aircraft dumping. Releases that occur 

during the consumption of petroleum, whether by individual car and boat owners, non-tank vessels, 

or run-off from increasingly paved urban areas, contribute the vast majority of petroleum introduced 

to the environment through human activity. Nearly 85 percent of the 29 million gallons of petroleum 

that enter North American ocean waters each year as a result of human activities comes from landbased runoff, polluted rivers, and aircraft. Land runoff and two-stroke engines account for nearly 

three quarters of the petroleum introduced to North American waters from activities associated with 

petroleum consumption, activities almost exclusively restricted to coastal waters. Unlike other 

sources, inputs from consumption occur almost exclusively as slow chronic releases. The estimates 

for land-based sources of petroleum are the most poorly documented and the uncertainty associated 

with the estimates range over several orders of magnitude. On occasion, aircraft carry more fuel 

than they can safely land with so fuel is jettisoned into offshore marine waters. The amount of 

1,120 bbl (160 tonnes) of jettisoned fuel per year was estimated for the GOM.

Tables 3-28 and 3-29 provide the NRC (2003) estimates of hydrocarbon inputs into marine 

waters. In general, response activities to non-OCS oil- and gas-related spills would be similar to 

those described for an OCS oil- and gas-related spill (Chapter 3.2.8).
Impact-Producing Factors and Scenario 3-179

Table 3-28. Average Annual Inputs of Petroleum Hydrocarbons to Coastal Waters of the Gulf of 

Mexico, 1990-1999. 

Inputs Western Gulf of Mexico Eastern Gulf of Mexico

(tonnes) (bbl) (tonnes) (bbl)

Extraction of Petroleum

Platforms Spills 90 630 trace1 trace

Atmospheric Releases (VOCs) trace trace trace trace

Permitted Produced-Water Discharges 590 4,130 trace trace

Sum of Extraction Inputs 680 4,760 trace trace

Transportation of Petroleum

Pipeline Spills 890 6,230 trace trace

Tank Vessel Spills 770 5,390 140 980

Coastal Facilities Spills2 740 5,180 10 70

Atmospheric Releases (VOCs)3 trace trace trace trace

Sum of Transportation Inputs4 2,400 16,800 160 1,120

Consumption of Petroleum

Land-Based Sources5 11,000 77,000 1,600 11,200

Recreational Vessels 770 5,390 770 5,390

Vessel >100 GT (spills) 100 700 30 210

Vessel >100 GT (operational discharges) trace trace trace trace

Vessel <100 GT (operational discharges) trace trace trace trace

Deposition of Atmospheric Releases 

(VOCs)

90 630 60 420

Aircraft Jettison of Fuel N/A N/A N/A N/A

Sum of Consumption 12,000 84,000 2,500 17,500

1

Trace indicates <70 bbl (10 tonnes).

2

Coastal facility spills do not include spills in coastal waters related to exploration and production 

spills or spills from vessels. The category “Coastal Facilities” includes aircraft, airport, refined 

product in coastal pipeline, industrial facilities, marinas, marine terminals, military facilities, 

municipal facilities, reception facilities, refineries, shipyards, and storage tanks. 3

Volatization of light hydrocarbons during tank vessel loading, washing, and voyage.

4

Sums may not match. 5

Inputs from land-based sources during consumption of petroleum are the sum of diverse sources. 

Three categories of wastewater discharge are summed: municipal; industrial (not related to 

petroleum refining); and petroleum refinery wastewater. Urban runoff is included. It results from 

oil droplets from vehicles washing into waterways from parking lots and roads, and the improper 

disposal of oil containing consumer products.

GT = gross tons.

N/A = not available.

VOCs = volatile organic compounds.

Source: NRC, 2003.
3-180 Gulf of Mexico Multisale EIS

Table 3-29. Average Annual Inputs of Petroleum Hydrocarbons to Offshore Waters of the Gulf of 

Mexico, 1990-1999. 

Inputs

Western Gulf of Mexico Eastern Gulf of Mexico

(tonnes) (bbl) (tonnes) (bbl)

Natural Sources

Seeps 70,000 490,000 70,000 490,000

Extraction of Petroleum

Platform Spills 50 350 trace1 trace

Atmospheric Releases (VOCs) 60 420 trace trace

Permitted Produced-Water Discharges 1,700 11,900 trace trace

Sum of Extraction 1,800 12,600 trace trace

Transportation of Petroleum

Pipelines Spills 60 420 trace trace

Tank Vessels Spills 1,500 10,500 10 70

Atmospheric Releases (VOCs) trace trace trace trace

Sum of Transportation 1,600 11,200 10 70

Consumption of Petroleum

Land-Based Consumption2 N/A N/A N/A N/A

Recreational Vessel Consumption3 N/A N/A N/A N/A

Vessel >100 GT (spill) 120 840 70 490

Vessel >100 GT (operational discharges) 25 175 trace trace

Vessel <100 GT (operational discharges) trace trace trace trace

Deposition of Atmospheric Releases 

(VOCs) 1,200 8,400 1,600 11,200

Aircraft Jettison of Fuel 80 560 80 560

Sum of Consumption4 1,400 9,800 1,800 12,600

1

Trace indicates <70 bbl (10 tonnes). 2

Limited to coastal zone.

3

Limited to within 3 mi (5 km) of the coast.

4

Sums may not match.

GT = gross tons.

N/A = not available.

VOCs = volatile organic compounds.

Source: NRC, 2003.
Impact-Producing Factors and Scenario 3-181

3.3.2.5 Non-OCS Oil- and Gas- Related Air Emissions

There are many air emissions sources related to non-OCS oil- and gas-related activities. Air 

emissions are caused by non-OCS onshore oil and gas activities and offshore State oil and gas 

activities, including combustion sources from power and heat generation, and the use of 

compressors, pumps, and reciprocating engines (i.e., boilers, turbines, and other engines); 

emissions resulting from flaring and venting of gas; and fugitive emissions. For instance, at the 

northern border between Texas and Louisiana (Haynesville Shale), there is a very large reserve of 

recoverable natural gas with recent extensive leasing and exploration activities. The economic 

impact is important in the region; however, it also generates significant amounts of ozone precursors 

as revealed by air quality modeling scenarios ranging from limited, moderate, and aggressive 

development reported in Kemball-Cook et al. (2010). Such precursors, nitrogen oxides and VOCs, 

are emitted during drilling, subsequent rock fracturing, venting, well completion, dehydration of 

natural gas, and fugitive emissions from compressor engines, wells, and pipeline components. The 

principal pollutants from these air emissions could also include NOx, SOx, CO, PM10, PM2.5, H2S, 

VOC, benzene, ethylbenzene, toluene, xylene, glycols, and polycyclic aromatic hydrocarbons 

(PAHs).

Non-OCS oil- and gas-related activities can also include emissions from commercial and 

home heating, naturally occurring forest fires, motor vehicles, industrial activities in territorial seas 

and coastal waters, and industrial and transportation activities onshore. These activities can range 

from large, highly regulated industrialized sources such as electric utilities that burn fuel down to 

individual human sources such as outdoor grilling, jet skis, or using gasoline-powered equipment. In 

addition, sand borrowing and transportation in State territorial waters also generate emissions that 

can affect air quality. The principal pollutants from these air emissions sources include NOx, SOx, 

CO, PM10, PM2.5, and VOC. For more information on sources of air quality issues, refer to Chapter 

4.1.2. 

3.3.2.6 Other Non-OCS Oil- and Gas-Related Activities

3.3.2.6.1 Military Warning and Water Test Areas

The Gulf of Mexico (GOMEX) Range Complex contains four separate operating areas: 

Panama City and Pensacola, Florida; New Orleans, Louisiana, and Corpus Christi, Texas. The 

operating areas within the GOMEX Range Complex are not contiguous but are scattered throughout 

the GOM. The GOMEX Range Complex includes special-use airspace with associated warning 

areas and restricted airspace, and surface and subsurface sea space of the four operating areas. 

The air space over the GOM is used by the DOD for conducting various military operations. Twelve 

MWAs and six EWTAs are located within the GOM (Figure 3-8). These MWAs and EWTAs are 

multiple-use areas where military operations and oil and gas development have coexisted without 

conflict for many years. Several military stipulations are planned for leases issued within identified 

military areas.
3-182 Gulf of Mexico Multisale EIS

To eliminate potential impacts from multiple-use conflicts on the aforementioned area and on 

blocks that the Navy has identified as needed for testing equipment and for training mine warfare 

personnel, a standard Military Areas Stipulation is routinely applied to all GOM leases

(Appendix D.3). 

In addition, BOEM’s Gulf of Mexico OCS Region issued NTL 2014-BOEM-G04, which 

provides links to the addresses and telephone numbers of the individual command headquarters for 

the military warning and water test areas in the GOM. The NTL 2014-BOEM-G04 can be found on 

BOEM’s website at http://www.boem.gov/Notices-to-Lessees-and-Operators/. 

BOEM anticipates that, over the next 50 years, the military use areas currently designated 

regionwide would remain the same and that none of them would be released for nonmilitary use. 

Over the cumulative activities scenario, BOEM expects to continue to require military coordination 

stipulations in these areas. The intensity of the military’s use of these areas, or the type of activities 

conducted in them, is anticipated to fluctuate with military mission needs.

3.3.2.6.2 Offshore Deepwater Ports and Nearshore Liquefied Natural Gas Terminals

Deepwater ports are designed to provide access for tankers and LNG carriers to offshore 

offloading facilities for hydrocarbon products, i.e., crude oil and natural gas. Crude oil passing 

through an offshore port may be temporarily stored and then transported to shore via pipeline. The 

term “deepwater port” includes all associated components and equipment, including pipelines, 

pumping stations, service platforms, mooring buoys, and similar features or equipment to the extent 

that they are located seaward of the high water mark (USDOT, MARAD, 2015b).

The Deepwater Port Act of 1974, as amended by the Maritime Transportation Security Act of 

2002, establishes a licensing system for ownership, construction, operation and decommissioning of 

deepwater port structures located beyond the U.S. territorial sea. The Deepwater Port Act sets out 

conditions that deepwater port license applicants must meet, including the minimization of adverse 

impacts on the marine environment and submission of detailed plans for construction, operation, and 

decommissioning of deepwater ports. The Deepwater Port Act also sets out detailed procedures for 

the issuance of licenses by the Secretary of Transportation and prohibits the issuance of a license 

without the approval of the Governors of the adjacent coastal states (USDOT, MARAD, 2015b). 

Since early 2015, 20 deepwater port license applications have been filed with the Maritime 

Administration (MARAD) for approval (18 applications for licenses to import LNG and 2 applications 

filed for licenses to import oil).

Gulf of Mexico Offshore Deepwater Ports

Currently in the U.S., there is one offshore deepwater port in operation in the GOM, i.e., the 

Louisiana Offshore Oil Port (LOOP). The LOOP has received and transferred over 11 Bbbl of crude 

oil since its inception (LOOP, LLC, 2015).The offloaded crude oil is transported to shore via 48-in 

(123-cm) diameter pipeline. The LOOP receives and temporarily stores crude oil supplies from three 

sources, including the following:
Impact-Producing Factors and Scenario 3-183

• tankers carrying foreign (imported oil from Arabian Gulf, Russia, West Africa, 

North Sea, Mexico, and South America) and domestic crude oil from FPSOs; 

• domestic crude oil produced in the Gulf of Mexico (Mars and Thunder Horse 

platforms); and 

• movement of domestic crude oil via the Houston to Houma (Ho-Ho) pipeline. 

Another LNG deepwater port (Port Dolphin) has been proposed in the Gulf of Mexico, and it

has been approved by MARAD and USCG. Port Dolphin is in development and is obtaining the 

necessary permits for construction; in addition, Höegh LNG is currently evaluating the market 

potential that may affect the status of the project (Castro, official communication, 2015). Port 

Dolphin has approval from the Federal Energy Regulatory Commission (FERC) and MARAD for 

completion of construction of the deepwater port and pipeline until December 2018. Gulf Gateway 

Energy Bridge was an LNG deepwater port in the Gulf of Mexico, and it was decommissioned in 

2013. Additional information on the licenses and applications of deepwater ports and LNG facilities 

specific to the Gulf of Mexico can be found on MARAD’s website (USDOT, MARAD, 2015b).

In 2015, Delfin LNG proposed an offshore floating LNG project in the U.S. which would be

located approximately 45 mi (72 km) offshore of Cameron, Louisiana (Federal Register, 2015d). 

The proposed project schedule is to receive Federal approvals and the Deepwater Port Act license 

in 2016, to have offshore and onshore construction in 2017 to 2018, and to commence operations in 

2019.

Gulf Gateway Energy Bridge, LLC (Gulf Gateway) operated in the Gulf of Mexico off the 

coast of Louisiana from 2005 to 2012. The decision to decommission the facility was due to 

irreparable hurricane damage to pipelines (Hurricane Ike in 2008) interconnecting with the 

deepwater port and a changing natural gas market, which impacted the operator’s ability to receive 

consistent shipments (USDOT, MARAD, 2015b).

Nearshore Liquefied Natural Gas (LNG)

The FERC is responsible for authorizing the siting and construction of onshore and 

nearshore (State waters) LNG import or export facilities under Section 3 of the Natural Gas Act. The 

FERC, under Section 7 of the Natural Gas Act, also issues certificates of public convenience and 

necessity for LNG facilities engaged in interstate natural gas transportation by pipeline. There are 

more than 110 LNG facilities operating in the U.S. performing a variety of services. The LNG 

terminal means all natural gas facilities located onshore or nearshore (in State waters) that are used 

to receive, unload, load, store, transport, gasify, liquefy, or process natural gas that is 

• imported to the U.S. from a foreign country, 

• exported to a foreign country from the U.S., or 

• transported in interstate commerce by a waterborne vessel.
3-184 Gulf of Mexico Multisale EIS

Some facilities export natural gas from the U.S., some provide natural gas supply to the 

interstate pipeline system or local distribution companies, while others are used to store natural gas 

for periods of peak demand. There are also facilities that produce LNG for vehicle fuel or for 

industrial use. Depending on location and use, an LNG facility may be regulated by several Federal 

agencies and by State utility regulatory agencies. Projects that are approved and built are subject to 

FERC’s oversight for as long as the facility is in operation. The FERC currently regulates 

24 operational LNG facilities (USDOE, FERC, 2015b). In the Gulf of Mexico State waters 

(nearshore), there are currently five LNG terminals, of which all five are currently in operation and 

planned for expansion of the facilities to export of natural gas to foreign markets:

• Freeport LNG Import/Export Terminal (Freeport, Texas); 

• Golden Pass LNG Import/Export Terminal (Sabine Pass, Texas); 

• Sabine Pass LNG Import/Export Terminal (Sabine Pass, Texas); 

• Cameron LNG Import/Export Terminal (Formerly Hackberry LNG) (Cameron, 

Louisiana); and

• Lake Charles LNG Import/Export Terminal (Lake Charles, Louisiana). 

The Corpus Christi LNG import/export terminal (Corpus Christi, Texas) was recently 

reviewed and approved by FERC and DOE, and they subsequently began construction in May 2015

(Cheniere Energy, 2015). 

While interest in deepwater port development peaked in the 2000-2010 period, economic 

conditions for LNG have changed since 2010. BOEM notes that interest in LNG offshore terminal 

projects is expected to diminish over at least the next decade, with potential and subsequent 

stabilization in the LNG market. It is possible that LNG facilities in the Gulf of Mexico, or elsewhere, 

presently in the permitting process or in early construction phases could be withdrawn from 

consideration, cancelled, or deferred until LNG economics improve or until facilities under 

construction for importing LNG could be modified for exporting LNG. BOEM anticipates that, over 

the next 50 years, two additional LNG facilities in the CPA would be licensed and operating. It is 

unclear as to whether these LNG facilities will occur during the period of a proposed action, although 

trends evident in the submittal, approval, and withdrawal of recent applications suggest that such 

development is unlikely. Additional information on LNG terminal applications, application review 

determinations, and operational status for the Gulf of Mexico offshore LNG facilities can be found on

MARAD’s website at http://www.marad.dot.gov/ports/.

3.3.2.6.3 Development of Gas Hydrates

Methane hydrates (or gas hydrates) are cage-like lattices of water molecules containing 

methane, the chief constituent of natural gas found under arctic permafrost, as well as beneath the 

ocean floor. These may represent one of the world's largest reservoirs of carbon-based fuel. 

However, with abundant availability of natural gas from conventional and shale resources, there is 
Impact-Producing Factors and Scenario 3-185

no economic incentive to develop gas hydrate resources, and no commercial-scale technologies to 

exploit them have been demonstrated (USDOE, Energy Information Administration, 2012).

In the Gulf of Mexico, a Joint Industry Project was formed to carry out an assessment of gas 

hydrates in deep water of the GOM and to better understand the impact of hydrates on safety and 

seafloor stability, climate change, and assessment of the feasibility of marine hydrate as a potential 

future energy source. The findings of the 13-year (2001-2014) study concluded that hydrates are a 

readily managed, shallow drilling hazard and that hazard mitigation can be accomplished using 

existing protocols; field data indicate the occurrence of high-saturation hydrate accumulations in the 

GOM; methods employed to locate and predict hydrates were effective and accurate; and 

development of prototype tools and methods to collect hydrate pressure cores were developed.

BOEM released the results of a systematic geological and statistical assessment of gas 

hydrates resources in the GOM (USDOI, MMS, 2008a). This assessment incorporates the latest 

science with regard to the geological and geochemical controls on gas hydrate occurrence. It 

indicated that a mean volume of 607 trillion m3 (21,444 Tcf) of methane was in-place in hydrate form. 

The assessment has determined that a mean of 190 trillion m3 (6,710 Tcf) of this resource occurs as 

relatively high-concentration accumulations within sand reservoirs that may someday be produced. 

The remainder occurs within clay-dominated sediments from which methane probably would never 

be economically or technically recoverable.

BOEM anticipates that, over the next 40 years, the Joint Industry Project would complete the 

third leg of its characterization project for GOM gas hydrates in the cumulative impacts area. Within 

40 years, it is likely that the first U.S. domestic production from hydrates may occur in Alaska, where 

gas obtained from onshore hydrates would either support local oil and gas field operations or be 

available for commercial sale if and when a gas pipeline is constructed to the lower 48 states. 

However, it is not possible to discount the possibility that first U.S. domestic production of gas 

hydrates could occur in the GOM (Moridis et al., 2008). Despite the substantially increased 

complexity and cost of offshore operations, there is a mature network of available pipeline capacity 

and easier access to markets in the GOM.

3.3.2.6.4 Renewable Energy and Alternative Use

On August 8, 2005, President George W. Bush signed the Energy Policy Act of 2005 into 

law. Section 388 (a) of the Energy Policy Act amended Section 8 of the OCSLA (43 U.S.C. § 1337) 

to authorize DOI to grant leases, easements, or rights-of-way on the OCS for the development and 

support of energy resources other than oil and gas and to allow for alternate uses of existing 

structures on OCS lands.

A final programmatic EIS for the OCS renewable energy program was published by this 

Agency in October 2007 (USDOI, MMS, 2007b) and a Record of Decision was published in the 

Federal Register on January 10, 2008 (Federal Register, 2008a). The Act authorized this Agency to 

develop a comprehensive program and regulations to implement the new authority. Final rules for 
3-186 Gulf of Mexico Multisale EIS

BOEM’s renewable energy program were published on April 29, 2009, as 30 CFR part 285 (Federal 

Register, 2009).

The two primary categories of renewable energy that have the potential for development in 

the coastal and OCS waters of the U.S. are wind turbines and marine hydrokinetic systems. The 

first and most technologically mature renewable energy is wind energy, a popular source of clean 

and renewable energy that has been in use for centuries. The DOE released a strategic plan for 

creating an offshore wind industry in the U.S. (USDOE, 2011). In this plan, DOE determined that 

offshore wind energy can help the Nation reduce its greenhouse gas emissions, diversify its energy 

supply, provide cost-competitive electricity to key coastal regions, and stimulate economic 

revitalization of key sectors of the economy. However, if the Nation is to realize these benefits, key 

barriers to the development and deployment of offshore wind technology must be overcome, 

including the relatively high cost of energy, technical challenges surrounding installation and grid 

interconnection, and the permitting processes governing deployment in both Federal and State 

waters. There are two critical objectives to realize the strategic plan’s goals: (1) reduce the cost of 

offshore wind energy; and (2) reduce the timeline for deploying offshore wind energy (USDOE, 2011, 

page 2). Since April 29, 2009, when the regulations governing renewable energy on the OCS were 

publicized, no wind park developments have been proposed in OCS waters of the GOM; however, 

there have been proposals in Texas coastal waters.

In Fiscal Year 2010, the DOE instituted the Offshore Wind Innovation and Demonstration 

initiative to consolidate and expand its efforts to promote and accelerate responsible commercial 

offshore wind development in the United States. In 2012, the DOE’s Wind Program announced 

Federal funding nationwide in three major categories: technology development; market acceleration; 

and advanced technology demonstration. The Wind Program is working with BOEM to advance a 

national strategy for offshore wind research and development (Navigant Consulting, Inc., 2013). 

According to the Navigant Consulting, Inc. report, there is a potential of 594 gigawatts of potential 

wind energy available in the GOM. Offshore wind could create approximately 20.7 direct jobs per 

annual megawatt (or 20,700 jobs per annual gigawatt) installed in U.S. waters. Baryonyx Rio 

Grande Wind Farms received $4 million to produce three demonstration turbines in State waters 

(refer to “Renewable Energy Projects in Texas State Waters” below).

The second category of potential offshore renewable energy technologies is marine 

hydrokinetic systems, which are in a more developmental stage relative to wind turbines. The 

marine hydrokinetic systems consist of devices capable of capturing energy from ocean waves and 

currents. There has been no interest expressed in wave or current technologies in the GOM 

because the conditions necessary for their deployment are not suitable to the Gulf of Mexico. The 

marine hydrokinetic current technologies are actively being considered for the east coast of Florida 

where the Gulf Stream would provide a strong and continuous source of energy to turn underwater 

turbines.

The Energy Policy Act clarifies the Secretary’s authority to allow the existing oil and gas 

structures on OCS lands to remain in place after production activities have ceased and to transfer 
Impact-Producing Factors and Scenario 3-187

liability and extend the life of these facilities for non-oil and gas purposes, such as research, 

renewable energy production, aquaculture, etc., before being removed. With many bottom-founded 

platform structures located along the nearshore border of OCS waters, the GOM would seem to 

have some potential for the reuse of these facilities.

BOEM expects that, over the next 40 years, a limited number of alternative use projects 

would be proposed in the WPA. It is also likely that these alternative use projects would consist of 

wind energy projects based on the current development of that technology. BOEM’s expectation is 

based on the fact that known projects are being proposed in Texas State waters. Likewise, the 

potential alternative use projects could consist of a combination of integrated existing GOM 

infrastructure with new-built facilities.

Renewable Energy Projects in Texas State Waters

On October 24, 2005, the Texas General Land Office announced authorization for the first 

offshore wind energy project in the United States to be built in State waters off the Texas coast. An 

11,355-ac (4,595-ha) lease was awarded to Galveston-Offshore Wind, L.L.C., a subsidiary of 

Louisiana-based Wind Energy Systems Technologies (now Coastal Point Energy LLC), where 

50 wind turbines would be placed for the 150-megawatt development. The lease area is located 

approximately 7 mi (11 km) southeast of Galveston Island. Wind Energy Systems Technologies 

(now Coastal Point Energy LLC) was awarded the rights for additional leases south of the 

Galveston-Offshore Wind, L.L.C. project area, which would be developed after the Galveston 

project. The target completetion date is 2018. The Texas General Land Office leased acreage to 

Baryonyx Corporation to build additional offshore wind projects; however, while Baryonyx 

Corporation received money during the first phase of the Offshore Wind and Innovation 

Demonstration initiative, which was led by the U.S. Department of Energy, they did not receive 

funding to continue into the second phase (USDOE, Office of Energy Efficiency and Renewable 

Energy, 2015). Baryonyx Corporation ultimately abandonded the project.

3.3.2.6.5 Aquaculture

Offshore aquaculture is the rearing of aquatic animals in controlled environments (e.g., 

cages or net pens) in Federal waters. The NOAA has published the rule to implement a Fishery 

Management Plan for regulating offshore aquaculture in the Gulf of Mexico (Federal Register, 

2016c). The rule establishes a comprehensive regulatory program for managing the development of 

an aquaculture industry in Federal waters of the Gulf of Mexico. An interagency group has been 

established and is working on the permitting process for future proposed aquaculture activities. This 

group consists of the three permitting agencies, i.e., NOAA, USEPA, and USACE, and other 

agencies with an interest or expertise on the OCS, including USCG, FWS, BOEM, and BSEE. This 

group will continue to coordinate the permitting process.
3-188 Gulf of Mexico Multisale EIS

3.3.2.6.6 OCS Sand Borrowing

If OCS sand is desired for coastal restoration or beach nourishment, BOEM uses the 

following two types of lease conveyances: a noncompetitive negotiated agreement (NNA) that can 

only be used for obtaining sand and gravel for public works projects funded in part or whole by a 

Federal, State, or local government agency; and a competitive lease sale in which any qualified 

person may submit a bid. BOEM has issued 51 noncompetitive negotiated agreements but has 

never had a competitive lease sale for OCS sand and gravel resources. BOEM’s Marine Minerals 

Program continues to focus on identifying sand resources for coastal restoration, investigating the 

environmental implications of using those resources, and processing noncompetitive use requests.

Since 2003, BOEM has participated in the multiagency Louisiana Sand Management 

Working Group to identify, prioritize, and define a pathway for accessing sand resources in the nearoffshore OCS of Louisiana, an area where competitive space use mainly involves OCS oil- and gasrelated infrastructure such as wells, platforms, and pipelines. Table 3-30 shows the projected 

approximate volume of OCS sand uses for coastal restoration projects over the next 5 years. 

Approximately 76 million yd3 (58 million m3

) are expected to be needed for coastal restoration 

projects, as reported by the Gulf of Mexico OCS Region’s Marine Minerals Program. To visualize 

such a dimension, this volume of sand could fill the Louisiana Superdome stadium 16.5 times.

In 2005, BOEM began to conduct offshore sand studies to investigate available sources of 

OCS sand for restoring coastal areas in Louisiana, Texas, Alabama, and Mississippi that were 

damaged by Hurricanes Katrina and Rita. Sand sources identified through BOEM’s cooperative 

effort with Louisiana would likely serve as the major source of material for the restoration of the 

barrier islands planned as part of the Louisiana Coastal Area ecosystem restoration study (U.S. 

Dept. of the Army, COE, 2004) and for projects identified in the Louisiana 2012 and 2017 Master 

Plans (State of Louisiana, Coastal Protection and Restoration Authority, 2012 and 2015), projects 

developed under the Deepwater Horizon Natural Resource Damage Assessment (NRDA); Coastal 

Wetlands Planning, Protection and Restoration Act; Coastal Impact Assessment Program; National 

Fish and Wildlife Foundation’s Gulf Environmental Benefit Fund; and the 2012 Resources and 

Ecosystems Sustainability, Tourist Opportunities and Revived Economies of the Gulf Coast States 

Act (RESTORE Act) barrier island restoration efforts.
Impact-Producing Factors and Scenario 3-189

Table 3-30. Projected OCS Sand Resource Needs for Planned Restoration Projects.

Restoration Project Maximum Sand 

(yd3) 

OCS Lease Area and Block Number

(if known)

NRDA Breton Island ~6,000,000 Breton Sound 42-44; Main Pass 42-44 and 53-55

NRDA Caillou Lake Headlands 

(Whiskey) 13,400,000 Ship Shoal 88

Mississippi Coastal Improvement 

Program (MsCIP) 23,000,000 Mobile 817-819 and 861-864

Southwest Louisiana ~15,000,000 N/A

Raccoon Island ~1,100,000 Ship Shoal 88 and 89; South Pelto 12-14

Trinity and East Islands ~16,260,000 Ship Shoal 88 and 89; South Pelto 12-14

Timbalier Island ~10,700,000 Ship Shoal 88 and 89; South Pelto 12-14

East Timbalier Island Restoration ~11,230,000 South Pelto 12-14

Caminada Headland (I and II) ~11,300,000 South Pelto 12-14

Total ~108,490,000

N/A = not available.

~ = approximately.

Since the dredging of OCS sand and the associated activities of oceangoing dredge vessels 

could present some use conflicts on blocks also leased for oil and gas extraction, BOEM initiated a 

regional offshore sand management program in Louisiana in 2003, which, over the course of 

10 years and several meetings, has developed options and recommendations for an orderly process 

to manage the competing use of OCS sand resources in areas of existing OCS infrastructure. With 

input from the Sand Management Working Group, BOEM has developed guidelines for sand 

resource allocations, maintaining a master schedule of potential sand dredging projects, developing 

procedures for accessing sand under emergency conditions, and establishing environmental 

requirements for the use of offshore borrow areas.

Noncompetitive negotiated agreements have been issued in the following locations. No 

sand noncompetitive negotiated agreements have ever been issued for OCS sand in the WPA. The 

EPA has three noncompetitive negotiated agreements:

• Pinellas County, Florida; 

• Longboat Key, Town of Longboat Key, Florida; and 

• Collier County, Florida.

The following 11 noncompetitive negotiated agreements for OCS sand have been issued in 

the CPA:
3-190 Gulf of Mexico Multisale EIS

• Holly Beach, Cameron Parish, Louisiana; 

• South Pelto test area, Terrebonne Parish, Louisiana; 

• Pelican Island shoreline restoration, Plaquemines Parish, Louisiana; 

• Raccoon Island marsh creation, Terrebonne Parish, Louisiana; 

• St. Bernard Shoals, St. Bernard and Plaquemines Parishes, Louisiana; 

• Ship Shoal in South Pelto Area for Caminada Headland restoration, Lafourche 

and Jefferson Parishes, Louisiana; 

• Sabine Bank, Cameron Parish, Louisiana; 

• Caminada II, Lafourche and Jefferson Parishes, Louisiana; 

• NRDA Whiskey Island, Terrebonne Parish, Louisiana; 

• North Breton Island, Breton Island National Wildlife Refuge, Louisiana; and

• Mississippi Coastal Improvements Program, Gulf Island National Seashore, 

Mississippi.

In 2013, BOEM began working with the U.S. Dept. of the Interior, Geological Survey (USGS) 

and FWS on a North Breton Island Restoration Project work plan, which is included in the NRDA

early restoration plan, Phase III (USDOC, NOAA, 2015c). The North Breton Island Restoration 

Project (Louisiana) would use sand from the Breton Sound Area to restore shorebird and brown 

pelican nesting habitat in the Breton National Wildlife Refuge. It is anticipated that the 

noncompetitive negotiated agreement would be signed in 2017, with dredging for the North Breton 

Island Restoration Project beginning in late 2017. BOEM issued two noncompetitive negotiated 

agreements in Louisiana in 2015: the first was for the Deepwater Horizon NRDA Whiskey Island 

Restoration Project in Terrebonne Parish using sand from Ship Shoal Block 88; and the second was 

for Phase Two of the Caminada Headland Restoration Project in Lafourche and Jefferson Parishes 

using sand from South Pelto Blocks 13 and 14. Dredging for Caminada II began in 2015 and is 

anticipated to be complete in 2017. Whiskey island is anticipated to begin construction in Winter 

2016/2017 with completion in 2018. Another project site, East Timbalier Island, has been severely 

degraded due to the impacts of several strong storms, subsidence, and other factors. Historically, 

the island served to define the seaward boundary of the eastern Terrebonne Basin estuary, reducing 

the transmission of GOM waves into Terrebonne Bay. The noncompetitive negotiated agreement is 

expected to be signed in 2017 using proposed borrow areas from Ship Shoal in South Pelto Blocks 

12, 13, and 14. BOEM is also working with the COE’s Mobile District and the National Park Service 

on the Mississippi Coastal Improvements Program, which would use OCS sand from the Mobile 

Area for barrier island restoration projects along East and West Ship Islands in the Gulf Islands 

National Seashore. The noncompetitive negotiated agreement Record of Decision was signed in 

2016 and will utilize OCS sand from Mobile Blocks 817-819 and 861-864. Dredging associated with 

the Mississippi Coastal Improvements Program is expected to begin in 2017 and is expected to 

continue until 2019. 
Impact-Producing Factors and Scenario 3-191

BOEM is authorized by 30 CFR § 550.101 to ensure that operations conform to sound 

conservation practice to preserve, protect, and develop mineral resources of the OCS and to 

minimize or eliminate conflicts between the exploration, development, and production of oil and 

natural gas and the recovery of other resources. BOEM’s responsibility as steward of significant 

sand resources on the OCS is outlined in NTL 2009-G04. This NTL provides guidance for the 

avoidance and protection of significant OCS sediment resources essential to coastal restoration 

initiatives in BOEM’s Gulf of Mexico OCS Region. The use of OCS sediment resources is 

authorized by BOEM through its Marine Minerals Program. Additional measures have been 

implemented and continue to be developed to help safeguard the most significant OCS sediment 

resources, reduce multiple use conflicts, and minimize interference with oil and gas operations under 

existing leases or pipeline rights-of-way. Mitigating measures ensure activities (including surface or 

near-surface emplacement of platforms, wells, drilling rigs, pipelines, umbilicals, and cables) avoid or 

are removed from, to the maximum extent practicable, significant OCS sediment resources.

Over the next 50 years, increased use of OCS sand for restoration projects in states that fall 

within the CPA are likely. Currently, no WPA restoration projects have been specifically identified. 

The boundary between the OCS and Texas State waters (9 nmi [10 mi; 16 km]) allows that some 

offshore sand is within the jurisdiction of the State; however, the easternmost portion of the shelf in 

Texas State waters is relatively devoid of beach-quality sand deposits. The Texas General Land 

Office, in cooperation with BOEM and the Texas Bureau of Economic Geology, has investigated the 

potential for use of Heald and Sabine Banks and confirmed substantial reserves of restoration 

quality sand. However, the State of Texas has yet to identify specific projects. The COE has 

intermittently used OCS sand reserves, and it is expected that this trend would continue. With 

respect to Louisiana, some uncertainty exists as to the amount of offshore OCS sand that would 

eventually be sought for coastal restoration projects. The Louisiana Coastal Area Ecosystem 

Restoration Plan potentially may use up to 60 million yd3 (46 million m3

) (U.S. Dept. of the Army, 

COE, 2009a). Recently, there has been an increase in requests from Louisiana for State-funded 

OCS sand resources projects. BOEM anticipates that this growing trend of State-led projects would 

continue into the future as restoration funding is made available directly to the State through the 

Coastal Impact Assistance Program, the Gulf of Mexico RESTORE Act, Coastal Wetlands Planning, 

Protection and Restoration Act, National Fish and Wildlife Foundation: Gulf Environmental Benefit 

Fund, the Deepwater Horizon NRDA restoration, and GOMESA. These programs are outlined in 

more detail in Chapter 3.3.2.8.3. 

3.3.2.7 Noise from Non-OCS Oil- and Gas-Related Sources

Other noise sources in the GOM are from non-OCS oil- and gas-related activities: vessel 

propeller cavitation from commercial shipping vessels, research vessels, tourism vessels, and 

commercial and recreational fishing vessels; sources from other equipment used on vessels (e.g., 

pingers used in fisheries to prevent animals getting caught in nets); State drilling operations; aircraft; 

military operations; coastal infrastructure construction (e.g., pile driving); underwater explosions; and 

natural phenomena such as wind, large storms, or lightning strikes. It is not under BOEM’s authority 

to regulate any of these non-OCS oil- and gas-related noise sources, although some do occur on the
3-192 Gulf of Mexico Multisale EIS

OCS. Refer to Chapter 3.1.9 for general information on OCS oil- and gas-related sources of noise 

in the GOM.

Non-OCS Oil- and Gas-Related Geological and Geophysical Surveys

The G&G surveys are conducted to (1) obtain data for hydrocarbon and mineral exploration 

and production in Federal or State waters; (2) aid in siting renewable energy structures and facilities, 

and pipelines; (3) locate and monitor the use of potential sand and gravel resources for 

development; (4) identify possible seafloor or shallow-depth geologic hazards; and (5) locate 

potential archaeological resources and benthic habitats that should be avoided (Chapters 4.4 and 

4.13, Deepwater Benthic Communities and Archaeological Resources, respectively).

Detailed descriptions of G&G activities are provided in more detail in the Atlantic G&G 

Activities Programmatic EIS (USDOI, BOEM, 2014a). A Programmatic EIS is currently being 

developed for the GOM (refer to Chapter 1.7). The selection of a specific technique or suite of 

techniques is driven by data needs and the target of interest. These activities include the following:

• various types of deep-penetration seismic airgun surveys used for State oil and 

gas exploration and development;

• other types of surveys and sampling activities used only in support of State oil 

and gas exploration and development, including electromagnetic surveys, deep 

stratigraphic and shallow test drilling, and various remote-sensing methods;

• HRG surveys used in all three program areas to detect shallow geohazards and 

marine minerals, archaeological resources, and certain types of benthic 

communities; and

• geological and geotechnical bottom sampling used in all three program areas to 

assess the suitability of seafloor sediments for supporting structures (e.g., 

platforms, pipelines, cables, renewable energy facilities such as wind turbines) or 

to evaluate the quantity and quality of marine minerals and sand for beach 

nourishment or other potential marine mineral extraction projects.

Deep-penetration seismic surveys, in which survey vessels tow an airgun or an array of 

airguns that emit acoustic energy pulses through the overlying water then into the seafloor over long 

durations and over large areas, are the most extensive G&G activities that would be conducted. 

These surveys would occur almost exclusively in support of oil and gas exploration and development 

and could be conducted in State waters. The G&G activities in support of renewable energy

development would consist mainly of HRG and geotechnical surveys in Federal and State waters 

less than 40 m (131 ft) deep (USDOI, MMS, 2007b); this area represents approximately 25.9 percent 

of the GOM. The G&G activities in support of marine mineral uses (e.g., sand and gravel mining) 

would consist mainly of HRG and geotechnical surveys in Federal and State waters greater than 

30 m (98 ft) deep; this area represents approximately 19.5 percent of the GOM. The G&G activities 

beyond the outer boundary of the planning areas have not been determined but could include 
Impact-Producing Factors and Scenario 3-193

Although absolute sea-level rise is a 

contributor to the total amount of sea-level 

rise along the Gulf Coast, subsidence is 

the most important contributor to the total.

geophysical surveys in support of the U.S. Extended Continental Shelf Project, which aims to 

establish the full extent of the continental shelf of the U.S., consistent with international law. 

3.3.2.8 Coastal Environments

3.3.2.8.1 Sea-Level Rise and Subsidence

As part of the Mississippi River’s delta system, both the Delta Plain and the Chenier Plain of 

the Louisiana Coastal Area (LCA) are experiencing relatively high rates of subsidence. All 

coastlines of the world have been experiencing a gradual absolute rise of sea level that is based on 

measurements across the globe and that extends across the influence of a single sedimentary 

basin. There are two aspects of sea-level rise during the past 10,000 years (Holocene Epoch): 

absolute sea-level rise and relative sea-level rise. Absolute sea-level rise refers to a net increase in 

the volume of water in the world’s oceans. Relative sea-level rise refers to the appearance of sealevel rise, a circumstance where subsidence of the land is taking place at the same time that an 

absolute sea-level change may be occurring. Geologists tend to consider all sea-level rises as 

relative because the influence of one or the other is difficult to separate over geologic timeframes.

An absolute sea-level rise would be caused by the following two main contributors to the 

volume of ocean water on the Earth’s surface: (1) change in the volume of ocean water based on 

temperature; and (2) change in the amount of ice locked in glaciers, mountain ice caps, and the 

polar ice sheets. For the period 1961-2003, thermal expansion of the oceans accounts for only 

23 ± 9 percent of the observed rate of sea-level rise (Bindoff et al., 2007); the remainder is water 

added to the oceans by melting glaciers, ice caps, and the polar ice sheets. The measurement of 

sea-level rise over the last century is based on tidal gauges and, more recently, satellite 

observations, which are not model dependent. Projections for future sea-level rise are dependent on 

temperature. As determined by an analysis of air bubbles trapped in Antarctic ice cores, today’s 

atmospheric concentration of CO2 is the highest it has ever been over the last 2.1 million years (Karl 

et al., 2009; Luthi et al., 2008; Hönisch et al., 2009). Although the measured data for atmospheric 

CO2 concentration or temperatures measurements since the Industrial Revolution are generally not 

in dispute, proxy data for climates of the geologic past are a source of debate, and the models 

constructed to make projections for how climate may change remain controversial. Climate models 

are very sophisticated, but they may not account for all variables that are important or may not 

assign variables the weight of their true influence.

The Intergovernmental Panel on Climate 

Change (IPCC) reported that, since 1961, global 

average sea level (mean sea level) has risen at an 

average rate of 1.8 millimeter/year (mm/yr) 

(0.07 in/yr) and, since 1993, at 3.1 mm/yr 

(0.12 in/yr) (Bindoff et al., 2007). With updated 

satellite data to 2010, Church and White (2011) show that satellite-measured sea levels continue to 

rise at a rate close to that of the upper range of the IPCC projections (IPCC, 2012). It is unclear 

whether the faster rate for 1993-2010 reflects decadal variability or an increase in the longer-term 
3-194 Gulf of Mexico Multisale EIS

trend. In the structured context used by the IPCC, there is high confidence that the observed 

sea-level rise rate increased from the 19th to the 20th century. Over the period 1901 to 2010, global 

mean sea level rose by 0.19 m (0.62 ft) (with a range of 0.17-0.21 m [56-69 ft]). The rate of 

sea-level rise since the mid-19th century has been larger than the mean rate during the previous two 

millennia (IPCC, 2014). The U.S. Global Change Research Program reported that, over the last 

50 years, sea level has risen up to 8 in (203 mm) along parts of the Atlantic and Gulf Coasts, which 

included Louisiana and Texas (Karl et al., 2009), and that global sea level is currently rising at an 

increasing rate.

In comparison to other areas along the Gulf Coast, Louisiana’s Mississippi Delta and Chenier 

Plains are built of young sediments deposited over the last 7,000 years. These deltaic sediments 

have been undergoing compaction and subsidence since they were deposited. The land is sinking 

at the same time that sea level is rising, contributing to high rates of relative sea-level rise along the 

Louisiana coast. Blum and Roberts (2009) posited four scenarios for subsidence and sea-level rise, 

and they concluded sediment starvation alone would cause approximately 2,286 mi2 (592,071 ha) of 

the modern delta plain to submerge by 2100, without any other impacting factors (including sea-level 

rise) contributing to land loss.

A general value of approximately 6 mm/yr (0.23 in/yr) of subsidence from sediment 

compaction, dewatering, and oxidation of organic matter (Meckel et al., 2006; Dokka, 2006) is a 

reasonable rate to attribute to the Louisiana coastal area, with the understanding that subsidence 

rates along the Louisiana coast are spatially variable and influenced by subsurface structure and the 

timing and manner that the delta was deposited. 

Stephens (2009 and 2010) reported that the influence of subsurface structure has not been 

taken into account in subsidence assessments in the LCA and along the Gulf Coast (Stephens, 

2009, page 747). Most workers studying the effects of subsidence along the LCA have focused on 

surficial or near-surface geologic data sources and have made no attempt to integrate basin analysis 

into planning for coastal restoration or flood control project planning.

Results from the National Assessment of Coastal Vulnerability to Sea Level Rise estimate 

the rate of sea-level rise in the GOM, in particular the areas around Eugene Island, Louisiana, to be 

the highest (9.65 mm/yr; 3.17 ft/century) in the United States (USDOC, NOAA, 2015d). This 

classification is based upon variables such as coastal geomorphology, regional coastal slope, rate of 

sea-level rise, wave and tide characteristics, and historical shoreline change rates. As much as 

88 percent of the northern GOM falls within the high vulnerability category. Areas ranked as the very 

low vulnerability category still have some sea-level rise. The lowest rate of rise is found in Panama 

City, Florida, with a rate of 1.6 mm/yr or 0.53 ft/century. Given this range, BOEM anticipates that, 

over the next 50 years, the northern GOM would likely experience a minimum relative sea-level rise 

of 80.7 mm (3.18 in) and a maximum relative sea-level rise of 482.6 mm (19.0 in). Sea-level rise 

and subsidence together have the potential to affect many important areas, including the OCS oil 

and gas industry, waterborne commerce, commercial fishery landings, and important habitat for 

biological resources (State of Louisiana, Coastal Protection and Restoration Authority, 2012). Oil 
Impact-Producing Factors and Scenario 3-195

and gas infrastructure located within 15 in (381 mm) of the highest high tide in coastal areas along 

the Gulf of Mexico could potentially be affected by sea-level rise during this program. Programmatic 

aspects of climate change relative to the environmental baseline for the GOM are discussed in 

Chapter 4.2.1 of the Five-Year Program EIS. 

Formation Extraction and Subsidence

Extracting fluids and gas from geologic formations can lead to localized subsidence at the 

surface. The Texas coast is experiencing high (5-11 mm/yr) (0.19-0.43 in) rates of relative sea-level 

rise that are the sum of subsidence and eustatic sea-level rise (Sharp and Hill, 1995). Even higher 

rates are associated with areas of groundwater pumping from confined aquifers. Berman (2005, 

Figure 3) reported that 2 m (6 ft) of subsidence had occurred in the vicinity of the Houston Ship 

Channel by the mid-1970’s as a result of groundwater withdrawal.

Morton et al. (2005) examined localized areas or “hot spots” corresponding to fields in the 

LCA where oil, gas, and brine were extracted at known rates. Morton et al. (2005, Figure 26) shows 

measured subsidence along transects across these fields that range from 18 to 4 mm/yr (0.7 to 

0.15 in), with the greatest rates tending to coincide with the surface footprints of oil or gas fields. 

Mallman and Zoback (2007) interpreted downhole pressure data in several Louisiana oil fields in 

Terrebonne Parish and found localized subsidence over the fields; however, they could not link 

these localized rates to the subsidence measured and observed on a regional scale.

Down-to-the-basin faulting, also called listric or growth faulting, is a long recognized fault 

style along deltaic coastlines, and the Mississippi Delta is no exception (Dokka, 2006; Gagliano, 

2005a). There is currently disagreement in the literature regarding the primary cause of modern 

fault movement in the Mississippi Delta region, and the degree to which it is driven by fluid 

withdrawal or sediment compaction resulting from the sedimentary pile pressing down on soft, 

unconsolidated sediments that causes downward and toward the basin movement along surfaces of 

detachment in the shallow and deep subsurface. Berman (2005) discussed the conclusions of 

Morton et al. (2005) and believed that they failed to make the case that hydrocarbon extraction 

caused substantial subsidence over the broader area of coastal Louisiana, a conclusion also 

reached by Gagliano (2005b).

Oil production on the LCA peaked at 513 MMbbl in 1970 and gas production peaked at 

7.8 MMcf in 1969 (Ko and Day, 2004). Between 2003 and 2012, oil production from Federal Gulf of 

Mexico waters has continued to decline (USDOE, Energy Information Administration, 2014b). From 

the peak, the level of production activity is slowly decreasing. The magnitude of subsidence caused 

by formation extraction is a function of how pervasive the activity is across the LCA. The oil and gas 

field maps in Turner and Cahoon (1987, Figure 4) and Ko and Day (2004, Figure 1) seem an 

adequate basis to estimate the LCA’s oil- and gas-field footprint at ~20 percent of the land area. The 

amount of subsidence from formation extraction is also occurring on a delta platform that is 

experiencing natural subsidence and sea-level rise. Fluid and gas extraction may lead to high local 
3-196 Gulf of Mexico Multisale EIS

subsidence on the scale of individual oil and gas fields but not as a pervasive contributor to regional 

subsidence across the LCA.

3.3.2.8.2 Erosion

BOEM conservatively estimates that there are approximately 4,850 km (3,013 mi) of Federal 

navigation channels, bayous, and rivers potentially exposed to OCS traffic regionwide (Table 3-7) 

and that the average canal is widening at a rate of 0.99 m/year (3.25 ft/year). Regionwide, this 

results in a total annual land loss of approximately 480 ac/yr (1,186 ha/yr).

In the Louisiana Coastal Master Plan (State of Louisiana, Coastal Protection and Restoration 

Authority, 2012), it is estimated that up to 1,750 mi2 (4,500 km2

) of land would be lost in the next 

50 years. Using BOEM’s conservative estimate of approximately 4,850 km (3,014 mi) of Federal 

navigation channels, bayous, and rivers potentially exposed to OCS traffic in the LCA (Table 3-7) 

and the average canal widening rate of -0.99 m/yr (-3.25 ft/yr) (Thatcher et al., 2011), a total land

loss of approximately 83,053 ac (33,611 ha) in navigation canals may be estimated over the next 

70 years. Using this estimate and comparing it with the total expected land loss in coastal Louisiana 

over the next 50 years, BOEM estimates that approximately 2 percent of the total land loss in 

Louisiana would occur due to salt intrusion, hurricanes, and vessel traffic (OCS Program-related and 

non-OCS Program-related) in navigation canals. Because OCS Program-related vessel traffic 

constitutes such a small percentage (<1%) of the contributing factor to erosion in navigation canals, 

greater than 99 percent of the land loss in coastal Louisiana in the next 70 years can be attributed to 

non-OCS sources. 

Net landloss due to navigation canals alone can be calculated by comparing erosion rates 

with beneficial activities such as land gained through the use of dredged sands. BOEM anticipates 

that, over the next 40 years, if current trends in the beneficial use of dredged sand and sediment are 

simply projected based on past land additions (U.S. Dept. of the Army, COE, 2009b), approximately 

50,000 ac (20,234 ha) may be created or protected in the LCA through dredged materials programs. 

3.3.2.8.3 Coastal Restoration Programs

The Mississippi Delta sits atop a pile of Mesozoic and Tertiary-aged sediments up to 7.5 mi 

(12.2 km) thick at the coast and it may be as much as 60,000 ft (18,288 m) or 11.4 mi (18.3 km) thick 

offshore (Gagliano, 1999). Five major lobes are generally recognized within about the uppermost 

50 m (164 ft) of sediments (Britsch and Dunbar, 1993; Frazier, 1967, Figure 1). The oldest lobe 

contains peat deposits dated as 7,240 years old (Frazier, 1967). The youngest delta lobe of the 

Mississippi Delta is the Plaquemines-Balize lobe that has been active since the St. Bernard lobe was 

abandoned about 1,000 years ago. The lower Mississippi River has shifted its course to the Gulf of 

Mexico every thousand years or so, seeking the most direct path to the sea while building a new 

deltaic lobe. Older lobes were abandoned to erosion and subsidence as the sediment supply was 

shut off. Because of the dynamics of delta building and abandonment, the Louisiana coastal area 

(U.S. Dept. of the Army, COE, 2004) experiences relatively high rates of subsidence relative to more 

stable coastal areas eastward and westward. Coastal Louisiana wetlands make up the seventh 
Impact-Producing Factors and Scenario 3-197

largest delta on Earth and undergo about 90 percent of the total coastal wetland loss in the 

continental United States. In fact, from 1932 to 2010, coastal Louisiana has undergone a net 

change in land area of about 1.2 million ac (0.48 million ha). Trend analyses conducted from 1985 

to 2010 show that the coastal Louisiana wetland loss rate is 16.57 mi2 (42.92 km2) per year. If this 

loss were to occur at a constant rate, it would equate to Louisiana losing an area the size of one 

football field per hour (Couvillion et al., 2011).

In recognition of these ongoing impacts, several programs have been for the conservation, 

protection, and preservation of coastal areas, including wetlands along the Gulf Coast. In recent 

years, Louisiana has received over $1 billion in offshore 8(g) revenues, over half a billion dollars in 

Coastal Impact Assistance Program funds, and stands to receive many more billions in offshore 

revenue shares in coming years. These programs are described below.

Coastal Wetlands Planning, Protection and Restoration Act

The first systematic program authorized for coastal restoration in the LCA was the Federal 

1990 Coastal Wetlands Planning, Protection and Restoration Act (CWPPRA), otherwise known as 

the “Breaux Act.” Individual CWPPRA projects are designed to protect and restore between 10 and 

10,000 ac (4 and 4,047 ha), require an average of 5 years to transition from approval to construction, 

and are funded to operate for 20 years (U.S. Government Accountability Office, 2007), which is a 

typical expectation for project effectiveness (Campbell et al., 2005).

The 1990 CWPPRA introduced an ongoing program of relatively small projects to partially 

restore the coastal ecosystem. As the magnitude of Louisiana’s coastal land losses and ecosystem 

degradation became more apparent, it was identified that a more systematic approach to integrate 

smaller projects with larger projects to restore natural geomorphic structures and processes was 

needed. Projects have ranged from small demonstration projects to projects that cost over 

$50 million. The Coast 2050 report (State of Louisiana, Dept. of Natural Resources, 1998) 

combined previous restoration planning efforts with new initiatives from private citizens, local 

governments, State and Federal agency personnel, and the scientific community to converge on a 

shared vision to sustain the coastal ecosystem. The LCA Ecosystem Restoration Study (U.S. Dept. 

of the Army, COE, 2004) built upon the Coast 2050 Report. The LCA’s restoration strategies 

generally fell into one of the following categories: (1) freshwater diversion; (2) marsh management; 

(3) hydrologic restoration; (4) sediment diversion; (5) vegetative planting; (6) beneficial use of dredge 

material; (7) barrier island restoration; (8) sediment/nutrient trapping; and (9) shoreline protection, as 

well as other types of projects (Louisiana Coastal Wetlands Conservation and Restoration Task 

Force, 2006, Table 1).

As of August 2016, 210 authorized CWPPRA projects were approved, 103 of which have 

been constructed. Over 83,000 “anticipated total acres” have been projected from completed 

projects, and 102 projects that were not yet completed as of mid-2016 are reported to result in 

greater than 54,000 anticipated total acres (LaCoast.gov, 2016). Of the 103 completed projects 

listed on LaCoast.gov (2016), more than half were one of three categories types: shoreline 
3-198 Gulf of Mexico Multisale EIS

protection projects (30 projects); hydrologic restoration projects (24 projects); and marsh creation 

projects (22 projects).

Following Hurricanes Katrina and Rita in 2005, an earlier emphasis on coastal or ecosystem 

restoration of the LCA was reordered to add an equal emphasis on hurricane flood protection. The 

Department of Defense Appropriations Act of 2006 required Louisiana to create a State organization 

to sponsor the hurricane protection and restoration projects that resulted. The State legislature 

established the Coastal Protection and Restoration Authority (CPRA) and charged it with 

coordinating the efforts of local, State, and Federal agencies to achieve long-term, integrated flood 

control and wetland restoration. The CPRA has since produced comprehensive master plans for a 

sustainable coast (State of Louisiana, Coastal Protection and Restoration Authority, 2007 and 2012) 

as their vision of an integrated program that identified 109 high-performing projects that could 

substantially increase flood protection for communities and create a sustainable coast (State of 

Louisiana, Coastal Protection and Restoration Authority, 2012).

Anticipating which projects are undertaken for COE’s comprehensive range of flood control, 

coastal restoration, and hurricane protection measures for the LCA would feed into the CPRA’s 

Annual Plan for authorization and which ones would ultimately be completed is challenging. Past 

completed projects have the potential of protecting up to 100,000 ac (40,469 ha) of Louisiana’s 

wetlands (State of Louisiana, Coastal Protection and Restoration Authority, 2014). Because 

CWPPRA projects compete for annual Federal appropriations, there is no simple way to establish 

projections for land added or preserved over the cumulative activities scenario period (2017-2086) 

and the potential protection those projects would provide. Nor is there a way to anticipate which 

projects under the protection of the State’s CPRA are admitted to its Annual Plan and completed.

Louisiana Coastal Master Plan

Since 2007, the CPRA has built or improved 159 mi (256 km) of levees, benefited 19,405 ac 

(7,853 ha) of coastal habitat, secured $17 billion in State and Federal funding, moved over 

150 projects into design and construction, and constructed 32 mi (51 km) of barrier islands/berms 

(State of Louisiana, Coastal Protection and Restoration Authority, 2012). The projects included in 

the Louisiana Coastal Master Plan have the potential to build between 580 and 800 mi2 (1,502 and 

2,072 km2

) of land over the next 50 years, depending on future coastal conditions.

In 2012, Louisiana’s CPRA released a Final Coastal Master Plan, which expanded upon the 

2007 Master Plan. The objectives of the 2012 Master Plan focused on: flood protection, harnessing 

natural processes, supporting coastal habitats, sustaining cultural heritage, and promoting a working 

coast (State of Louisiana, Coastal Protection and Restoration Authority, 2012). The 2012 Louisiana 

Coastal Master Plan was based on a $50 billion budget and targeted use of these funds allows for 

improved protection for communities and could (with additional funding and depending how future 

coastal conditions change) turn the tide of land loss in Louisiana for the first time in a century. The 

$50 billion budget was determined by an estimate of money that Louisiana could receive in the next 

50 years for coastal protection and restoration from sources such as the Gulf of Mexico Energy 
Impact-Producing Factors and Scenario 3-199

Security Act, Energy and Water Act, Coastal Wetlands Planning and Restoration Act, Deepwater

Horizon Natural Resources Damage Assessment, Deepwater Horizon Clean Water Act penalties, 

carbon and nutrient credits, future State funding, and Louisiana’s Coastal Protection and Restoration 

Fund.

The CPRA is actively working on the 2017 Coastal Master Plan, which would carry the 2007 

and 2012 Master Plans forward while improving methods, ensuring that projects are completed 

efficiently and effectively while maintaining the vision of the future and adapting to future conditions 

(State of Louisiana, Coastal Protection and Restoration Authority, 2015). In order to develop the list 

of candidate projects for inclusion, the CPRA solicited proposals for new projects to be evaluated. 

Two solicitation periods occurred, one closing on August 21, 2014, and the second closing on 

October 31, 2014. A variety of project ideas were submitted, including bank stabilization, diversions, 

hydrologic restoration, marsh creation, oyster barrier reef restoration, ridge restoration, shoreline 

protection, and structural protection. Project sponsors included agencies, parishes, elected officials, 

nongovernment organizations, and private landowners.

As funding becomes available, the CPRA’s Annual Plan is the vehicle for outlining how 

projects are prioritized and implemented. Each Annual Plan would provide project and funding 

details for the current year as well as 2 years into the future. The Annual Plan would provide an 

easy way for citizens and legislators to track progress of the 2012 and 2017 Coastal Master Plans.

Coastal Impact Assistance Program

The Energy Policy Act of 2005 was signed into law by President George W. Bush on 

August 8, 2005. Section 384 of Energy Policy Act amended Section 31 of the OCSLA (43 U.S.C. § 

1356(a)) to establish the Coastal Impact Assistance Program (CIAP). The authority and 

responsibility for the management of CIAP is vested in the Secretary of the Interior; the Secretary 

delegated this authority and responsibility to BOEM until September 30, 2011. Under Section 384, 

Congress directed the Secretary to disburse $250 million for each of the fiscal years 2007 through 

2010 to eligible OCS oil- and gas-producing States and coastal political subdivisions.

On October 1, 2011, FWS took over administration of CIAP as directed by the Secretary 

because the program aligned with FWS’s conservation mission and similar grant programs run by 

FWS. The eligibility requirements for States, coastal political subdivisions, and fundable projects 

remained largely the same after the transfer.

The CIAP provides Federal grant funds derived from Federal offshore lease revenues to oilproducing states for conservation, protection, or restoration of coastal areas. The funds can be 

directed to a number of different projects, including restoration of wetlands; mitigation of damage to 

fish, wildlife, or natural resources; planning assistance and payment of the administrative costs of 

complying with these objectives; implementation of a federally approved marine, coastal, or 

comprehensive conservation management plan; and mitigation of the impacts of OCS oil- and 

gas-related activities through the funding of onshore infrastructure projects and public service needs.
3-200 Gulf of Mexico Multisale EIS

Eligible CIAP States Eligible CIAP Coastal Political Subdivisions

Alabama Baldwin and Mobile Counties

Alaska 

Municipality of Anchorage and Bristol Bay, Kenai Peninsula, Kodiak Island, 

Lake and Peninsula, Matanuska-Susitna, North Slope, and Northwest Arctic 

Boroughs

California

Alameda, Contra Costa, Los Angeles, Marin, Monterey, Napa, Orange, San 

Diego, San Francisco, San Luis Obispo, San Mateo, Santa Barbara, Santa 

Clara, Santa Cruz, Solano, Sonoma, and Ventura Counties

Louisiana

Assumption, Calcasieu, Cameron, Iberia, Jefferson, Lafourche, Livingston, 

Orleans, Plaquemines, St. Bernard, St. Charles, St. James, St. John the 

Baptist, St. Martin, St. Mary, St. Tammany, Tangipahoa, Terrebonne, and 

Vermilion Parishes

Mississippi Hancock, Harrison, and Jackson Counties

Texas

Aransas, Brazoria, Calhoun, Cameron, Chambers, Galveston, Harris, 

Jackson, Jefferson, Kennedy, Kleberg, Matagorda, Nueces, Orange, Refugio, 

San Patricio, Victoria, and Willacy Counties

CIAP = Coastal Impact Assistance Program.

Natural Resource Damage Assessment

The Oil Pollution Act of 1990, as provided in 33 U.S.C. § 2706, allowed the designation of 

the Natural Resource Damage Assessment Trustee Council (Trustee Council), which included 

certain Federal agencies, States, and federally recognized Indian Tribes. Executive Order 13554, 

which was signed on October 5, 2010, recognized the role of the Trustee Council under the Oil 

Pollution Act and “designated trustees as provided in 33 U.S.C. 2706, with trusteeship over those 

natural resources injured, lost, or destroyed as a result of the Deepwater Horizon oil spill.” 

Specifically, Executive Order 13554 recognized the importance of carefully coordinating the work of 

the Gulf Coast Ecosystem Task Force with the Trustee Council, “whose members have statutory 

responsibility to assess natural resource damages from the Deepwater Horizon oil spill, to restore 

trust resources, and seek compensation for lost use of those trust resources” (The White House, 

2012). The Task Force, on the other hand, was charged with creating a plan to improve the overall 

health of the Gulf of Mexico area and has focused on a number of stressors to the Gulf Coast 

ecosystem beyond those caused by the Deepwater Horizon explosion, oil spill, and response. While 

the work of the Task Force has been independent from the work of the Trustees, the valuable 

information gathered by the Task Force will be useful to the Trustees in their restoration planning 

efforts (USDOC, NOAA, 2015e).

The NRDA activities for the BP oil spill have been divided into the categories below and 

focus on specific species, habitats, or uses (USDOC, NOAA, 2015f):

• marine mammals and sea turtles; 

• fish and shellfish;

• birds;

• deepwater habitat (e.g., deepwater coral);
Impact-Producing Factors and Scenario 3-201

• nearshore habitats (including seagrasses, mud flats, and coral reefs);

• shoreline habitats (including salt marsh, beaches, and mangroves);

• land-based wildlife and habitat; and

• public uses of natural resources (including recreational fishing, boating, beach 

closures).

The Trustee Council is currently in Phase III of early restoration, and the data collection, 

analysis, and restoration are ongoing (Deepwater Horizon Natural Resource Damage Assessment 

Trustees, 2016). The final Phase III plan proposes $627 million for 44 new early restoration projects 

across the Gulf Coast States. It also includes plans to prepare a programmatic EIS and 

programmatic restoration plan for early restoration (USDOC, NOAA, 2015g).

Resources and Ecosystems Sustainability, Tourist Opportunities, and Revived Economies of 

the Gulf Coast States Act

In July 2012, in response to the Deepwater Horizon explosion, oil spill, and response and 

other environmental challenges in the Gulf Coast region, Congress passed the Resources and 

Ecosystems Sustainability, Tourist Opportunities, and Revived Economies of the Gulf Coast States 

Act or the RESTORE Act, (Gulf Coast Ecosystem Restoration Council, 2015). In September 2012, 

an Executive Order was released affirming the Federal Government’s Gulf Coast ecosystem 

restoration efforts in light of the recent passage of the RESTORE Act, which created a Gulf Coast 

Restoration Trust Fund (Trust Fund), outlined a structure for allocating the Trust Fund, and 

established the Gulf Coast Ecosystem Restoration Council (Council) (The White House, 2012). The 

Council is comprised of governors from the five affected Gulf Coast States, the Secretaries from the 

U.S. Departments of the Interior, Commerce, Agriculture, and Homeland Security, as well as the 

Secretary of the Army and the Administrator of the U.S. Environmental Protection Agency. The Gulf 

Coast States recommended and President Obama appointed the Secretary of Commerce as the 

Council’s Chair. As an independent entity, the Council has responsibilities with respect to 

60 percent of the funds made available from a Gulf Coast Restoration Trust Fund and is charged 

with developing a comprehensive plan for ecosystem restoration on the Gulf Coast (Comprehensive 

Plan), as well as any future revisions to the Comprehensive Plan (Gulf Coast Ecosystem Restoration 

Council, 2014).

The Initial Comprehensive Plan, approved in August 2013, establishes the Council’s goals 

defined as: (1) restore and conserve habitat; (2) restore water quality; (3) replenish and protect 

living coastal and marine resources; (4) enhance community resilience; and (5) restore and revitalize 

the GOM economy (The White House, 2012). In July 2014, the Council approved a proposal 

submission and evaluation process to select projects for inclusion on the draft Funded Priorities List, 

which will be included as an addendum to the Initial Comprehensive Plan. This first Funded 

Priorities List addendum would contain projects and programs that will be funded with available 

Transocean Deepwater Inc. funds. Future amendments to this Funded Priorities List and the 

process by which projects are selected for inclusion would evolve over time as new information 
3-202 Gulf of Mexico Multisale EIS

becomes available, adaptive management activities occur, and as funding uncertainties are resolved 

(Gulf Coast Ecosystem Restoration Council, 2014). As a result of the settlement of Clean Water Act 

civil claims against Transocean Deepwater Inc. and related entities, a total of approximately 

$800 million, plus interest, was deposited in the Trust Fund between 2013 and 2015. Thus, based 

upon the RESTORE Act and the payment schedule agreed to by the court for the Transocean 

settlement, by February 20, 2015, 30 percent of that total amount (i.e., $240 million plus interest) 

was deposited in the Trust Fund for allocation by the Council under the Council-Selected Restoration 

Component (Gulf Coast Ecosystem Restoration Council, 2013).

Among its other duties, the Council is tasked with establishing additional advisory 

committees as may be necessary to assist the Council, including a scientific advisory committee and 

a committee to advise the Council on public policy issues; gathering information relevant to Gulf 

Coast restoration, including thorough research, modeling, and monitoring; and providing an annual 

report to Congress on implementation progress (The White House, 2012).

As outlined in the RESTORE Act, the Council submitted a 2014 Annual Report to Congress 

on the implementation progress (Gulf Coast Ecosystem Restoration Council, 2014). In 2015, the 

Council proposed regulation that would establish the formula allocating funds made available from 

the Gulf Coast Restoration Trust Fund among the Gulf Coast States of Alabama, Florida, Louisiana, 

Mississippi and Texas (Federal Register, 2015e). The Council also released a draft initial-funded 

priorities list (Gulf Coast Ecosystem Restoration Council, 2015).

National Fish and Wildlife Foundation: Gulf Environmental Benefit Fund

In early 2013, a U.S. District Court approved two plea agreements resolving certain criminal 

cases against BP and Transocean, cases which arose from the 2010 Deepwater Horizon explosion, 

oil spill, and response. The agreements direct a total of $2.544 billion to the National Fish and 

Wildlife Foundation to fund projects benefiting the natural resources of the Gulf Coast that were 

impacted by the spill.

Between 2013 and 2018, the National Fish and Wildlife Foundation’s newly established Gulf 

Environmental Benefit Fund will receive a total of $1.272 billion for barrier island and river diversion 

projects in Louisiana; $356 million each for natural resource projects in Alabama, Florida, and 

Mississippi; and $203 million for similar projects in Texas. Funding priorities include projects that

• restore and maintain the ecological functions of landscape-scale coastal habitats, 

including barrier islands, beaches, and coastal marshes, and ensure their viability 

and resilience against existing and future threats, such as sea-level rise;

• restore and maintain the ecological integrity of priority coastal bays and 

estuaries; and
Impact-Producing Factors and Scenario 3-203

• replenish and protect living resources including oysters, red snapper and other 

reef fish, Gulf Coast bird populations, sea turtles, and marine mammals (National 

Fish and Wildlife Foundation, 2015).

As of 2016, the Gulf Environmental Benefit Fund has supported 75 projects worth nearly 

$500 million. In making the awards, the National Fish and Wildlife Foundation has worked closely 

with key State and Federal resource agencies to select projects that remedy harm and eliminate or 

reduce the risk of future harm to Gulf Coast natural resources. For example, funding was awarded 

from the Gulf Environmental Benefit Fund for engineering and construction of both Caminada Beach 

and Dune Increment II and East Timbalier Island, both involving the use of OCS sediment resources 

(National Fish and Wildlife Foundation, 2016).

3.3.2.8.4 Saltwater Intrusion

Saltwater intrusion is one of many factors that impact coastal environments, contributing to 

coastal land loss. Such impacts can be natural, as when storm surge brings GOM water inland, or 

anthropogenic, as when navigation or pipeline canals allow tides to introduce high salinity water to 

interior marshes. In addition, produced water from oil wells in the coastal zones can be a source of 

water of extreme high salinity, well over 100 parts per thousand. Produced water, which is 

regulated, often contains pollutants such as heavy metals and hydrocarbons, as well.

Marsh plants are exposed to salinity stress when higher salinity GOM waters reach interior 

marshes, exposing plants to salinities above their tolerance levels. This can result in decreased 

plant growth and/or mortality depending on the tolerance of the plant species and the amount, rate, 

and duration of salinity increase (Mendelssohn and McKee, 1987). Plant dieback can be followed by 

subsequent erosion of the marsh substrate and eventual land loss (Ko and Day, 2004; Boesch et al., 

1994).

The freshwater-adapted habitats (i.e., fresh or intermediate marsh and forested wetlands) 

are more sensitive to saltwater intrusion than the other more salt-tolerant habitats, such as brackish 

and saline marsh. Saltwater intrusion can result in conversion of freshwater to saline habitats or can 

simply kill fresh or intermediate marshes, thus converting them to open water (Johnston et al., 2009).

The leveeing of the Mississippi River and the construction of numerous water control 

structures are generally thought to have accelerated coastal land loss by isolating coastal wetlands

from the freshwater, sediment, and nutrients of the Mississippi River, which previously served to 

nourish and sustain these wetlands. Among other impacts, this isolation effect results in the loss or 

reduction in freshwater flow, and thus a greater marine influence on the coastal wetlands, which in 

turn results in saltwater intrusion (Johnston et al., 2009).

Saltwater intrusion into coastal environments can also impact estuarine species distribution, 

shifting patterns of habitat usage. Marine species penetrate farther inland when salinities are within 
3-204 Gulf of Mexico Multisale EIS

their tolerance, and less salt-tolerant species are restricted to the fresher areas. This can also lead 

to a shift in the pattern of availability of preferred fish species to fishermen.

3.3.2.8.5 Maintenance Dredging and Federal Channels

Along the Texas Coast there are eight federally maintained navigation channels in addition to 

the GIWW. Most of the dredged materials from the Texas channels have high concentrations of silt 

and clay. Beneficial uses of dredged material include beach nourishment for the more sandy 

materials and storm reduction projects or ocean disposal for much of the finer-gained material. 

Ocean disposal locations along the Texas coast are situated so that materials are placed on the 

down drift side of the channel (U.S. Dept. of the Army, COE, 1992,).

There are 10 Federal navigation channels in the LCA, ranging in depth from 4 to 14 m (12 to 

45 ft) and in width from 38 to 300 m (125 to 1,000 ft), that were constructed as public works projects 

beginning in the 1800’s (Good et al., 1995, Table 1). The combined length of the Federal channels 

in Good et al. was reported as 2,575 mi (1,600 km), with three canals considered deep-draft and 

seven considered shallow (Good et al., 1995, page 9). The Federal navigation channels in 

Louisiana identified by Good et al. (1995, Table 1) are as follows: (1) GIWW East of Mississippi 

River; (2) Mississippi River Gulf Outlet; (3) GIWW between the Atchafalaya and Mississippi Rivers; 

(4) GIWW West of Atchafalaya River; (5) Barataria Bay Waterway; (6) Bayou Lafourche; (7) Houma 

Navigation Canal; (8) Mermentau Navigation Channel; (9) Freshwater Bayou; and (10) Calcasieu 

River Ship Channel. The Mississippi River Gulf Outlet has been decommissioned and sealed with a 

rock barrier as of July 2009 (Shaffer et al., 2009, page 218).

The GIWW is a Federal, shallow-draft navigation channel constructed to provide a domestic 

connection between GOM ports after the discovery of oil in East Texas in the early 1900’s, as well 

as to provide a pathway to support the growing need for interstate transport of steel and other 

manufacturing materials in the early 20th century. It extends approximately 1,400 mi (2,253 km) 

along the Gulf Coast from St. Marks in northwestern Florida to Brownsville, Texas, with the 

Louisiana part reported to be 994 mi (1,600 km) in length (Good et al., 1995). With the exception of 

the east-west GIWW in Louisiana, Federal channels are approximately north-south in orientation, 

making them vulnerable to saltwater intrusion during storms (refer to Chapter 3.3.2.8.3 above). 

Cumulative impacts include the displacement of wetlands by original channel excavation and 

disposal of the dredged material. Turner and Cahoon (1987, Table 4-5) estimated that immediate 

impacts from the construction of navigation channels were between 58,000 and 96,000 ac 

(23,472 and 38,850 ha). Indirect cumulative land losses resulted from hydrologic modifications, 

saltwater intrusion, or bank erosion from vessel wakes (Wang, 1988). Once cut, navigation canals 

tend to widen as banks erode and subside, depending on the amount of traffic using the channel. 

Good et al. (1995, Table 1) estimated indirect impacts on wetland loss from bank erosion at 

35,000 ac (14,164 ha).
Impact-Producing Factors and Scenario 3-205

The COE reported that the New Orleans District has the largest channel maintenance 

dredging program in the U.S., with an annual average of 70 million yd3 (53.5 million m3

) of material 

dredged (U.S. Dept. of the Army, COE, 2009a). Maintenance dredging activity from 2004 through 

2013 for Federal channels by COE’s Galveston District, New Orleans District, and Mobile District are 

reported in COE’s Ocean Disposal Database (U.S. Dept. of the Army, COE, 2015a) (Table 3-27). 

The average amount of material disposed of in the 10-year period is highest for the New Orleans 

District (14,737,321 yd3 [11,267,495 m3

]), followed by the Galveston District (6,788,997 yd3

[5,190,563 m3

]) and the Mobile District (4,612,358 yd3 [3,526,402 m3]). Federal channels and canals 

are maintained throughout the onshore cumulative impact area by the COE, State, county, 

commercial, and private interests. Proposals for new and maintenance dredging projects are 

reviewed by Federal, State, and local agencies as well as by private and commercial interests to 

identify and mitigate adverse impacts upon social, economic, and environmental resources.

Maintenance dredging is performed on an as-needed basis. Typically, the COE schedules 

surveys every 2 years on each navigation channel under its responsibility to determine the need for 

maintenance dredging. Dredging cycles may be from 1 to as many as 11 years from channel to 

channel and from channel segment to channel segment. The COE is charged with maintaining all 

larger navigation channels in the cumulative activities area. The COE dredges millions of cubic 

meters of material per year in the cumulative activities area, most of which is under the responsibility 

of the New Orleans District. Some shallower port-access channels may be deepened over the next 

10 years to accommodate deeper draft vessels. Vessels that support deepwater OCS oil- and 

gas-related activities may include those with drafts to about 7 m (23 ft).

Construction and maintenance dredging of rivers and navigation channels can furnish 

sediment for a beneficial purpose, a practice the COE calls beneficial use of dredge materials 

program. Drilling, production activity, and maintenance at most coastal well sites in Louisiana 

require service access canals that undergo some degree of aperiodic maintenance dredging to 

maintain channel depth, although oil and gas production on State lands peaked in 1969-1970 

(Ko and Day, 2004, page 398). In recent years, dredged materials have been sidecast to form new 

wetlands using the beneficial use of dredge materials program. Potential areas suited for beneficial 

use of dredged material are considered most feasible within a 10-mi (16-km) boundary around 

authorized navigation channels in the New Orleans District, but the potential for future long-distance 

pipelines for disposal of dredged material could increase the potential area available for the 

beneficial use of dredge materials program considerably (U.S. Dept. of the Army, COE, 2009a, 

page 27).

As discussed in Chapter 3.3.2.8.5, the New Orleans District dredges an average annual 

14.7 million yd3 (11.3 million m3

) of material. Current figures estimate that approximately 38 percent 

of that average is available for the beneficial use of the dredge materials program (U.S. Dept. of the 

Army, COE, 2013). The COE reported that, over the last 20 years, approximately 12,545 ha 

(31,000 ac) of wetlands have been created with dredged materials, most of which are located on the 

LCA delta plain (U.S. Dept. of the Army, COE, 2013).
3-206 Gulf of Mexico Multisale EIS

3.3.2.9 Natural Events and Processes

3.3.2.9.1 Physical Oceanography

Physical oceanographic processes in the GOM include the Loop Current, Loop Current

eddies, and whirlpool-like features that appear underneath the Loop Current and Loop Current

eddies that interact with the bottom. Infrequently observed processes include a limited number of

high-speed current events, at times approaching 100 cm/s (39 in/s). These events were observed at

depths exceeding 1,500 m (4,921 ft) in the northern GOM (Hamilton and Lugo-Fernandez, 2001;

Hamilton et al., 2003) and as very high-speed currents in the upper portions of the water column

observed in deep water by several oil and gas operators.

Caribbean Sea waters colliding with the Yucatan Peninsula turn northward and enter the

Yucatan Channel as a strong flow called the Yucatan Current. This current exhibits two basic

arrangements inside the Gulf of Mexico. First, the Yucatan Current enters the GOM and turns

immediately eastward, exiting the GOM towards the Atlantic Ocean via the Florida Straits to become

the Gulf Stream. The second arrangement consists of a northward penetration of the Yucatan

Current into the Gulf of Mexico reaching to 26o-28o N. latitudes, then curls clockwise turning south,

and exiting via the Florida Straits into the Atlantic Ocean to become, again, the Gulf Stream. This

circulation inside the GOM is called the Loop Current. The Loop Current transports warm and salty

water year round into the GOM at a rate of 25-30 million cubic meters per second, and it is the main

energy source for oceanographic processes inside the Gulf of Mexico. At its climatic northern

position, the Loop Current becomes unstable, breaks, and sheds a large (200- to 400-km diameter

[124- to 248-mi diameter]) clockwise whirlpool that travels southwestwards at speeds of 4-8 km/day

(2-5 mi/day). The southwest trip of Loop Current eddies continues until colliding with the Texas and

Mexico continental slope in the western GOM, where they disintegrate. This sequence connects the

eastern with the western Gulf, which otherwise appear disconnected.

Mean seasonal circulation patterns of inner-shelf and outer-shelf currents on the LouisianaTexas continental shelf, the northeastern GOM shelf, and the West Florida shelf are primarily wind

driven and are also influenced by riverine outflow. Cold water from deeper off-shelf regions moves

onto and off the continental shelf by cross-shelf flow associated with upwelling and downwelling

processes in some locations (Collard and Lugo-Fernandez, 1999). There are also a number of

secondary whirlpools with smaller diameters (50-100 km; 31-62 mi) that affect the exchange

between the shelf and deepwater, and these smaller whirlpools interact with the larger Loop Current

eddies (Donohue et al., 2008). Additionally, wind events such as tropical cyclones (especially

hurricanes), extratropical cyclones, and cold-air outbreaks can result in extreme waves and cause

currents with speeds of 100-150 cm/s (39-59 in/s) over continental shelves.

Deepwater currents of the GOM can be approximated as a two-layer system with an upper

layer about 800-1,000 m (2,625-3,281 ft) deep that is dominated by the Loop Current and associated

clockwise whirlpools and a lower layer below ~1,000 m (3,281 ft) that has near uniform currents (Cox

et al., 2010; Welsh et al., 2009; Inoue et al., 2008). The coupling between these two layers is

generally absent, but it appears that motions at the layer interface are needed to transmit the energy
Impact-Producing Factors and Scenario 3-207

from the Loop Current and eddies downward (Cox et al., 2010; Welsh et al., 2009; Inoue et al., 2008,

Donohue et al., 2008). Mean deep flow around the edges of the GOM circulates in a 

counterclockwise direction, as observed at ~2,000 m (6,562 ft) (Sturges et al., 2004) and at ~900 m 

(2,953 ft) (Weatherly, 2004), with current speeds generally decreasing with depth.

3.3.2.9.2 Natural Seeps

“Natural seeps” is used here to mean the naturally occurring seepage of crude oil and tar into 

the GOM. These seeps are geographically common and have likely been active throughout history. 

Natural seeps account for approximately 47 percent of the crude oil entering the marine environment 

(Kvenvolden and Cooper, 2003). Mitchell et al. (1999) estimated a range of 280,000-700,000 bbl 

per year (40,000-100,000 tonnes per year), with an average of 490,000 bbl (70,000 tonnes) for the 

northern GOM, excluding the Bay of Campeche. Using this estimate and assuming seep scales are 

proportional to surface area, the NRC (2003) estimated annual seepage for the entire GOM at 

~980,000 bbl (140,000 tonnes) per year, or about 3 times the estimated amount of oil spilled by the 

1989 Exxon Valdez event (~270,000 bbl) (Steyn, 2010) or a quarter of the amount released into the 

environment by the Deepwater Horizon explosion and oil spill (4.1 MMbbl of oil) (Lubchenco et al., 

2010). As seepage is a natural occurrence, the rate of ~980,000 bbl (140,000 tonnes) per year is 

expected to remain unchanged throughout the cumulative analysis period. Refer to Chapter 4.4 for 

more information on natural seeps.

3.3.2.9.3 Hurricanes

Climatic cycles in tropical latitudes typically last 20-30 years or even longer (USDOC, NOAA, 

2005). As a result, the North Atlantic experiences alternating periods of above-normal or 

below-normal hurricane seasons. There is a two- to three-fold increase in hurricane activity during 

eras of above-normal activity. The hurricane activity from 1995 to 2007 is representative of an era of 

above-normal hurricane activity (Elsner et al., 2008, page 1,210).

Twenty-one hurricanes made landfall in the WPA, CPA and EPA during the 1995-2015 

hurricane seasons, disrupting OCS oil- and gas-related activity in the GOM (Table 3-31). Half of 

these hurricanes reached a maximum strength of Category 1 or 2 while in the CPA or WPA, while 

the other half were powerful hurricanes reaching maximum strengths of Category 4 or 5. The 

current era of heightened Atlantic hurricane activity began in 1995; therefore, the Gulf of Mexico 

could expect below average hurricanes in the GOM in the near term due to a strong El Nino. 

Increased hurricanes may occur if El Nino wanes during the first half of the 50-year analysis period 

and levels return to below-normal activity during the remaining half to three-quarters of the 50-year 

analysis period.
3-208 Gulf of Mexico Multisale EIS

Table 3-31. Hurricane Landfalls in the Northern Gulf of Mexico from 1995 through 2016. 

Event Year Affected State Storm Name Intensity at Landfall

1 1995 AL, FL Opal Hurricane Category 3

2 1995 FL Erin Hurricane Category 2

3 1997 LA, AL Danny Hurricane Category 1

4 1998 FL Earl Hurricane Category 1

5 1998 MS, AL Georges Hurricane Category 2

6 1999 TX Bret Hurricane Category 3

7 2002 LA Lili Hurricane Category 1

8 2003 TX Claudette Hurricane Category 1

9 2004 FL Charley Hurricane Category 4

10 2004 FL Frances Hurricane Category 2

11 2004 MS, AL Ivan Hurricane Category 3

12 2005 LA, MS Cindy Hurricane Category 1

13 2005 FL, AL Dennis Hurricane Category 3

14 2005 LA, MS Katrina Hurricane Category 5

15 2005 TX, LA Rita Hurricane Category 3

16 2005 FL Wilma Hurricane Category 3

17 2007 TX, LA Humberto Hurricane Category 1

18 2008 LA Gustav Hurricane Category 2

19 2008 TX, LA Ike Hurricane Category 4

20 2008 TX Dolly Hurricane Category 1

21 2012 LA Isaac Hurricane Category 1

Note: There were no hurricane landfalls in the northern Gulf of Mexico in 2009-2011 and 

2013-2016. 

Source: USDOC, NOAA, 2016a. 

Hurricanes Ivan, Katrina, Rita, Gustav, and Ike entered the GOM and destroyed 

181 structures and 1,673 wells on the OCS (Kaiser, 2015a). In general, they caused extensive 

damage to OCS platforms, topside facilities, and pipeline systems (Table 3-32). During Hurricanes 

Ivan, Katrina, and Rita, 9 jack-up rigs and 19 moored rigs were either toppled or torn from their 

mooring systems. Sixty platforms were destroyed as a result of Hurricanes Gustav and Ike in 2008, 

31 platforms had extensive damage, and 93 platforms had moderate damage (USDOI, MMS, 

2008b). The number of destroyed platforms by Hurricanes Gustav and Ike exceeds the number 

destroyed by Hurricane Katrina. Hurricane Isaac made landfall near the mouth of the Mississippi 

River on August 28, 2012, as a Category 1 hurricane, which only caused very minor damage to the 

offshore oil or gas infrastructure in the GOM. However, after Hurricane Isaac, tarballs and tar mat 

fragments were found along Alabama’s shoreline (Auburn University, Samuel Ginn College of 

Engineering, 2012). It was also observed that Hurricane Isaac resulted in the suspension of small 

amounts of tarballs and some oil from sediments (Mulagabal et al., 2013). Refer to Chapters 

3.2.1.1.1 and 3.2.4 for additional details for pipeline failures caused by hurricanes.
Impact-Producing Factors and Scenario 3-209

Table 3-32. Oil Spilled from Pipelines on the Federal OCS, 2002-2009. 

Regulator Area Total Oil Spilled 

(bbl)

Oil Spilled due to 

Hurricanes 

(bbl)

Proportion of Total Oil Spilled

due to Hurricanes 

(%)

BOEM Federal OCS 5,522 5,179 94

DOT Federal OCS 5,667 3,272 58

DOT State Waters 9,903 9,622 97

Source: USDOI, BOEMRE, 2011c.

3.3.2.9.4 Climate Change

Issues related to climate change, including global warming, sea-level rise, and programmatic 

aspects of climate change relative to the environmental baseline for the GOM are discussed in 

Chapter 4.2.1 of the Five-Year Program EIS.

3.3.2.10 Mississippi River Hydromodification

The Mississippi River has been anchored in place by engineered structures built in the 

20th century and has been hydrologically isolated from the delta it built. The natural processes that 

allowed the river to flood and distribute alluvial sediments across the delta platform and channels to 

meander have been shut down. Hydromodifying interventions include construction of (1) levees 

along the river and distributary channel systems, (2) upstream dams and flood control structures that 

impound sediment and meter the river flow rate, and (3) channelized channels with earthen or 

armored banks. Once the natural processes that act to add sediment to the delta platform to keep it 

emergent are shut down, subsidence begins to outpace deposition of sediment.

Of total upstream-to-downstream flow, the Old River Control Structure (built 1963) diverts 

70 percent of flow down the levee-confined channels of the Mississippi River and 30 percent down 

the unconfined Atchafalaya River, which has been actively aggrading its delta plain since 1973 

(LaCoast.gov, 2011). Blum and Roberts reported that the time-averaged sediment load carried by 

the Mississippi and Atchafalaya Rivers before installation of the Old River Control Structure was 

~400-500 million tons per year and that the average suspended load available to either river after 

construction of the Old River Control Structure was ~205 million tons per year (Blum and Roberts, 

2009, Figure 2). Modern sediment loads are, therefore, less than half that is required to build and 

maintain the modern delta plain, a figure largely in agreement with previous work reporting 

decreases in suspended sediment load of nearly 60 percent since the 1950’s (Turner and Cahoon, 

1987; Tuttle and Combe, 1981).

Blum and Roberts (2009, Figure 3b) posited three scenarios for subsidence and sea-level 

rise, and concluded that sediment starvation alone would cause ~2,286 mi2 (592,071 ha) of the 

modern delta plain to submerge by 2050 without any other impacting factors contributing to land

loss. The use of sediment budget modeling, a relatively new tool for land loss assessment, appears 

to indicate that hydrographic modification of the Mississippi River has been the most profound 
3-210 Gulf of Mexico Multisale EIS

man-caused influence on land loss in the LCA. Sediment starvation of the deltaic system is allowing 

rising sea level and subsidence to outpace the constructive processes building and maintaining the 

delta.

BOEM anticipates that, over the next 50 years, there might be minor sediment additions 

resulting from new and continuing freshwater diversion projects managed by the COE. Refer to

Chapter 3.3.2.8.3 for more information on coastal restoration.

3.3.2.11 Mississippi River Eutrophication

The Mississippi River Basin drains 41 percent of the contiguous United States. The basin 

covers more than 1,245,000 mi2 (3,224,535 km2

) and includes all or parts of 31 states and 

2 Canadian provinces (U.S. Dept. of the Army, COE, 2015b). Dissolved pollutants, including 

nutrients, enter surface water within the Mississippi River Basin via uncontained runoff and 

groundwater discharge (nonpoint sources).

The sources of nutrients in surface waters can be broadly divided as natural and 

anthropogenic. Natural sources are generally ubiquitous; however, their contribution is usually low 

because, over the course of time, natural systems have established balances between the 

production and consumption of nutrients. Anthropogenic sources arise from many activities. In the 

agricultural setting of the Mississippi River drainage basin, farmers increase the productivity and 

yield of their crops by use of chemical fertilizers. If more fertilizers are applied than are used by the 

crops, they can move into ground and surface waters and become a major source of nutrients in 

rivers. Additionally, fertilizer that is bound to soil or “loose” fertilizer may be subject to erosion by 

wind or water and affect surface waters. Information regarding nutrient management can be found 

on the U.S. Department of Agriculture’s Natural Resources Conservation Service website (USDA, 

NRCS, 2015). Other major sources of nutrients in surface waters are domestic and animal wastes. 

Although municipal wastewater is treated, only a fraction of the nutrients is removed. In addition to 

the nutrients derived from human sewage, municipal wastewater also contains nutrients from such 

things as lawn fertilizers, household cleaners, and detergents. Other anthropogenic sources of 

nutrients are industrial, either from the manufacture of fertilizers or as by-products of other 

manufacturing processes (Antweiler et al., 1995).

The most significant inorganic forms of two elements, nitrogen and phosphorus, include four 

nutrient compounds: nitrate (NO3

-

); nitrite (NO2

-

); ammonium (NH4

+

); and orthophosphate (PO4

-3). 

Of these four major nutrient compounds, only nitrate is found in concentrations approaching the 

USEPA’s maximum contaminant level of 10 mg/L. Orthophosphate usually is present in low 

concentrations, and concentrations of ammonium and nitrite usually are insignificant (USDOI, GS, 

1995).

Nutrient enrichment results in eutrophication, causing growth of algae (algal bloom) and 

other aquatic plants. A second effect of eutrophication is the increased uptake of dissolved oxygen 

by bacteria in response to higher concentrations of organic matter. If oxygen is taken up by 
Impact-Producing Factors and Scenario 3-211

decaying organic matter faster than it is imported from the atmosphere or produced by 

photosynthesis, it becomes depleted, and the aquatic species that require it are adversely affected. 

Furthermore, oxygen depletion causes basic changes in the chemical environment (i.e., a reduced 

environment) that allow materials (including many metals) that were formerly associated with the 

solid phase sediments (e.g., sorbed) to become soluble and, therefore, more mobile in the aqueous 

phase (USDOI, GS, 1995).

On October 21, 2014, the U.S. Department of the Interior and the U.S. Department of 

Agriculture announced a new partnership to strengthen the effectiveness of State and Federal 

nutrient-reduction strategies (USDOI, GS, 2014). As a result of this and other efforts, states are 

beginning to impose Best Management Practices on growers within the Mississippi River Basin to 

develop nutrient management plans, including fertilizer applicator certification programs, and 

monitoring to minimize excess nutrients from washing into waterways.

3.3.2.12 Hypoxia

The Gulf of Mexico hypoxic zone is a band of oxygen-stratified water that stretches along the 

Texas-Louisiana shelf each summer where the dissolved oxygen concentrations are less than 

2 mg/L (USEPA, 2015d). Other small hypoxic areas infrequently form at the discharge of smaller 

rivers along the Gulf Coast; however, in the Gulf of Mexico, the hypoxic zone resulting from the 

Mississippi and Atchafalaya Rivers is by far the predominant feature. The hypoxic zone is the result 

of excess nutrients, primarily nitrogen, carried downstream by rivers to discharge to coastal waters. 

Density stratification results where the less dense, nutrient-rich freshwater spreads on top of the 

denser seawater and prevents oxygen from replenishing the bottom waters. The excess nutrients 

cause phytoplankton blooms that eventually die and sink to the bottom, where bacterial 

decomposition consumes dissolved oxygen. The oxygen-depleted bottom waters occur seasonally 

and are affected by the timing of the Mississippi and Atchafalaya Rivers’ discharges carrying 

nutrients and freshwater to shelf surface waters. Hypoxic zones are sometimes called “dead zones” 

because of the absence of commercial quantities of shrimp and fish in the bottom layer.

The hypoxic zone on the Louisiana-Texas shelf is the largest such zone in the United States 

and the entire western Atlantic Ocean (Turner et al., 2005). The Louisiana Universities Marine 

Consortium generally forecasts the seasonal maximum size of the Louisiana-Texas hypoxic zone 

based on nitrogen loading in the Mississippi River (as measured in May of each year), and the actual 

size reported is based on cruise data collected by the Louisiana Universities Marine Consortium in 

July of each year. Recent estimates of the area of low oxygen by NOAA (USDOC, NOAA, 2015h) 

as of August 3, 2015, measured 6,474 mi2 (16,700 km2

) (Figure 3-20), an increase from the size 

measured in 2014 (5,052 mi2

) and larger than the estimated size (5,838 mi2) forecast by the 

Louisiana Universities Marine Consortium (2015) in June 2015 and three times larger than the 

Action Plan Goal of 5,000 km2 or 1,991 mi2 (Louisiana Universities Marine Consortium, 2014). The 

hypoxic zone extends up to 60-70 km (37-43 mi) from the shoreline, well into OCS waters.
3-212 Gulf of Mexico Multisale EIS

Figure 3-20. 2015 Gulf of Mexico Hypoxic Zone (USDOC, NOAA, 2015h).

Rabalais (2005) and Bierman et al. (2008) evaluated the potential contributions of carbon 

and nitrogen in discharged produced waters on the hypoxic zone. Both studies found that the 

effects due to produced water were minimal compared with those of the Mississippi River. As such, 

the Louisiana-Texas hypoxic zone is considered to be unrelated to OCS oil- and gas-related

activities but is discussed here as a potential cumulative effect.

3.3.2.13 Sedimentation

The lower Mississippi River, from Cairo, Illinois, to the Gulf of Mexico, transported an 

average of 150 million tons (with a range of 70-230 million tons) of sediment annually between 1963 

and 2005. Historically, the quantity of sediment derived from catchment erosion has been affected 

by changes in land use and river management, increasing in the 19th and early 20th centuries before 

decreasing due to soil conservation and improved land management. Seasonal analysis shows that, 

in the spring, the median load is approximately four times the median total load in the fall. The 

median sediment size is mostly silt, but it coarsens during the winter and spring when 10 percent of 

the sediment load is coarser than fine sand (U.S. Dept. of the Army, European Research Office, 

2008).

Suspended sediment and bed load enter the GOM from the outlets of the Mississippi and 

Atchafalaya Rivers. Suspended sediment is circulated along the Louisiana-Texas continental shelf 

where it settles out and may later become resuspended during storms. Bed-load sediment 

discharge builds the Mississippi and Atchafalaya River deltas and may be redistributed on the 

continental shelf by currents and wave action. Sediment on the continental shelf may ultimately be 

intercepted by the Mississippi Canyon where it is transported downslope to the Mississippi Fan in 

deep water. 
Impact-Producing Factors and Scenario 3-213

Since the marine environment is a dynamic system, sediment quality and water quality can 

affect each other. For example, a contaminant may react with the mineral particles in the sediment 

and be removed from the water column (e.g., adsorption). Thus, under appropriate conditions, 

sediments can serve as sinks for contaminants such as metals, nutrients, or organic compounds. 

However, if sediments are resuspended (e.g., due to dredging or a storm event), the resuspension 

can lead to a temporary redox flux, including a localized and temporal release of any formally sorbed 

metals as well as nutrient recycling. Resuspension events are less likely in deepwater environments 

(Caetano et al., 2003; Fanning et al., 1982).

Several studies have addressed offshore water and sediment quality in deep waters. Water 

at depths >1,400 m (4,593 ft) is relatively homogeneous with respect to temperature, salinity, and 

oxygen (Nowlin,1972; Pequegnat, 1983; Gallaway et al., 1988; Jochens et al., 2005). Limited 

analyses of trace metals and hydrocarbons for the water column and sediments exist (Trefry, 1981; 

Gallaway et al., 1988). Continental Shelf Associates, Inc. completed an Agency-funded field study 

of four drilling sites located in water depths of 1,033-1,125 m (3,389-3,691 ft) (CSA, 2006). The 

sampling design called for before and after exploratory or development drilling and captured the 

drilling-related changes that occur in sediments and sediment pore water. Chemical impacts of 

drilling were detected at all four sites. Impacts noted within the near-field zone included elevated 

barium, synthetic-based fluids, total organic carbon concentrations, and low sediment oxygen levels. 

One of the study locations was Viosca Knoll Block 916, which was considered to be relatively 

pristine prior to drilling. No drilling had ever been performed at Viosca Knoll Block 916, and the 

closest drilling activity had occurred 1.4 mi (2.3 km) north-northwest 2 years prior to the study. The 

site was located at a water depth of 1,125 m (3,691 ft) and 70 mi (120 km) from the mouth of the 

Mississippi River. At this relatively pristine location, mean concentrations of sediment barium 

increased by approximately 30-fold at near-field stations following exploratory drilling (from 0.108% 

to 3.32%). As well, mean concentrations of sediment mercury and total PAHs increased in the 

near-field. At this site, sediment cadmium concentrations did not change substantially following 

exploratory drilling.

Several studies have assessed the occurrence and distribution of hydrocarbons in sediments 

since the Deepwater Horizon explosion, oil spill, and spill response in 2010 from Mississippi Canyon 

Block 252. Montagna et al. (2013) reported results of monitoring cruises conducted in the fall of 

2010 to measure potential impacts on two soft bottom benthic invertebrate groups, i.e., macrofauna 

and meiofauna. The most severe relative reduction of faunal abundance and diversity extended to 

3 km (2 mi) from the wellhead in all directions, covering an area of 24 km2 (9 mi2

). Moderate impacts 

were observed up to 17 km (11 mi) toward the southwest and 8.5 km (5.3 mi) toward the northeast 

of the wellhead, covering an area of 148 km2

 (57 mi2). Benthic effects were correlated to 

hydrocarbon concentrations and distance from the wellhead but not distance to natural hydrocarbon 

seeps.

A study by Valentine et al. (2014) used the concentration of the marker compound hopane in 

more than 3,000 sediment samples from 534 locations to evaluate the extent of oil on the seafloor. 

The pattern of contamination was described as similar to a “bathtub ring” formed from an oil-rich 
3-214 Gulf of Mexico Multisale EIS

layer of water impinging laterally on the continental slope at a depth of about 900-1,300 m

(2,953-4,265 ft). A secondary “fallout plume” from the oil-rich layer was reported to impact a zone of 

sediments at a depth of about 1,300-1,700 m (4,265-5,577 ft). The combined areas of impact were 

estimated to span 3,200 km2 (1,236 mi2

). Based on the horizontal and vertical distribution of hopane 

in the sediments, the authors concluded that the contamination was consistent with the recent 

Deepwater Horizon explosion and oil spill as the source and not natural ongoing seeps. 

Calculations presented in the study indicate that oil in the “bathtub ring” represents 4-31 percent of 

the approximately 2 MMbbl of oil estimated to be sequestered in the oil-rich layer of water at depths 

of 1,000-1,300 m (3,287-4,265 ft). 

Sammarco et al. (2013) conducted a regional study using approximately 70 sediment 

samples in coastal waters from Galveston, Texas, to the Florida Keys. Sediment total petroleum 

hydrocarbon and total PAH concentrations peaked in samples near Pensacola, Florida, and 

Galveston, Texas.

The Department of the Interior Mission

The Department of the Interior protects and manages the Nation’s natural 

resources and cultural heritage; provides scientific and other information 

about those resources; and honors the Nation’s trust responsibilities or 

special commitments to American Indians, Alaska Natives, and affiliated 

island communities.

The Bureau of Ocean Energy Management Mission

The Bureau of Ocean Energy Management (BOEM) is responsible for 

managing development of U.S. Outer Continental Shelf energy and mineral 

resources in an environmentally and economically responsible way.