Oil and Gas Technologies for the Arctic and

Deepwater

May 1985

NTIS order #PB86-119948
Recommended Citation:

Oil and Gas Technologies for the Arctic and Deepwater (Washington, DC: U.S. Congress,

Office of Technology Assessment, OTA-O-270, May 1985).

Library of Congress Catalog Card Number 85-600528

For sale by the Superintendent of Documents

U.S. Government Printing Office, Washington, DC 20402
Foreword

cent

Nearly 2 billion acres of offshore public domain is owned by the United States adjato Alaska and the lower 48 States. Much of the Nation’s future domestic petroleum

supply is expected to come from this area. Areas of highest potential apparently occur

in deeper water and in the Arctic where operating conditions are severe, development costs

high, and financial risks immense. As the pace of exploration increases in these ‘ ‘frontier’ regions, questions arise about the technologies needed to safely and efficiently explore and develop oil and gas in harsh environments.

The Office of Technology Assessment undertook this assessment at the joint request

of the House Committees on Interior and Insular Affairs and on Merchant Marine and

Fisheries. The study explores the range of technologies required for exploration and development of offshore energy resources and assesses associated economic factors and financial

risks. It also evaluates the environmental factors related to energy activities in frontier

regions and considers important government regulatory and service programs.

In March 1985, the Secretary of the Interior announced the Administration’s proposed new 5-year offshore leasing program that will determine the pace of oil and gas exploration in Federal offshore waters through 1991. The proposed leasing schedule will be

under review by the 99th Congress, with final approval slated for the Summer of 1986.

OTA’s report on Arctic and deepwater oil and gas is intended to provide a timely and

useful reference for the Congress as it reflects on the Department of the Interior’s proposed program.

OTA is grateful to the Offshore Technologies Advisory Panel and participants in OTA’s

workshops for their help in the assessment. Splendid cooperation was received from a number

of executive agencies during the course of the study, including the Minerals Management

Service, National Oceanic and Atmospheric Administration, and the U.S. Coast Guard.

Special thanks go to the Arctic Environmental Information and Data Center of the University of Alaska and its Director, David Hickok, for field assistance to OTA in Alaska.

JOHN H. GIBBONS

Director
Oil and Gas Technologies for the Arctic

and Deepwater Advisory Panel

Jacob Adams

President

Arctic Slope Regional Corp.

Larry N. Bell

Vice President

Arco Oil & Gas Co.

Dr. John H. Steele, Chairman

Director, Woods Hole Oceanographic Institute

Charles L. Blackburn

Executive Vice President

Exploration and Development

Shell Oil Co.

Sarah Chasis

Senior Staff Attorney

Natural Resources Defense Council

Clifton E. Curtis

Executive Vice President

The Oceanic Society

Gordon Duffy

Secretary, Environmental Affairs

State of California

Walter R. Eckelmann

Senior Vice President

Sohio Petroleum Corp.

William Fisher

State Geologist

State of Texas

Robert Grogan

Associate Director for Governmental

Coordination

Office of the Governor of Alaska

Frank J. Iarossi

President

Exxon Shipping

Don E. Kash

Director

c o .

Science and Public Policy Program

University of Oklahoma

Paul Kelly*

Vice President, Government Relations

Rowan Companies, Inc.

Dan R. Motyka

Vice President-Frontier

Gulf Canada Resources, Inc.

C. Robert Palmer

Board Chairman and President

Rowan Companies, Inc.

Sandford Sagalkin* *

Counsel for North Slope Burrough

Stanley Stiansen

Vice President

American Bureau

Wallace Tyner

Professor

Purdue University

Michael T. Welch

Vice President

Citibank, N.A.

of Shipping

● Represented C. Robert Palmer at panel meetings

● “Represented Clifton E Curtis at panel meetings.

iv
OTA Project Staff—Oil and Gas Technologies for the

Arctic and Deepwater

John Andelin, Assistant Director, OTA

Science, Information, and Natural Resources Division

Robert W. Niblock, Oceans and Environment Program Manager

Project Staff

James W. Curlin, Project Director

Peter Johnson, Senior Associate

Cheryl Dybas Nan Harllee Daniel Kevin

Candice Stevens William Westermeyer

Administrative Staff

Kathleen A. Beil Jacquelynne R. Mulder Kay Patteson

Contributing Staff

Richard Rowberg, Program Manager, Energy and Materials Program

Jenifer Robison, Energy and Materials Program

Dennis Dobbins, Health Program

Contractors/Consultants

Edward Horton, Deep Oil Technology

Virgil Keith, ECO

Francois Lampietti

Leslie Marcus

Peter Noble, Marine Technology Corp.

Denzil Pauli

Robert Schulze

Dr. James Smith, University of Houston

Robert Visser, Belmar Engineering
Other Contributors

Thomas Albert

North Slope Borough

Vera Alexander

Professor

University of Alaska

Alan A. Allen

Spiltec

Jean Audibert

Earth Technology Corp.

Robert G. Bea

Senior International Consultant

PMB Systems Engineering, Inc.

David Benton

Benton & Associates

Ken Blenkhern

Amoco Production Co.

Ted Bourgoyne

Professor

Louisiana State University

Katherine R. Boyd

American Petroleum Institute

Robert E. Bunney

National Oceanic and Atmospheric

Administration

Gus Cassity

Placid Oil Co.

Bruce Clardy

Sohio Petroleum Corp.

Gordon Cox

U.S. Army Cold Regions Research

and Engineering Lab

Charles Ehler

National Oceanic and Atmospheric

Administration

Mark Fraker

Sohio Alaska Petroleum Co.

John Norton Garrett

International Petroleum Consultant

Ronald L. Geer

Senior Mechanical Engineering

Consultant

Shell Oil Co.

John Gregory

Minerals Management Service

Richard Griffiths

U.S. Environmental Protection Agency

John Haeber

Vetco Offshore, Inc.

Dillard Hammett

Sedco, Inc.

Jim Hecker

Terris and Sunderland

R. P. Hermann

Sonat Offshore Drilling, Inc.

David Hickok

Professor

University of Alaska

Sharon Hillman

Sohio Alaska Petroleum Co.

W. E. Holland

Exxon, U.S.A.

Baxter D. Honeycutt

Arco Oil and Gas Co.

Jerry Imm

Minerals Management Service

James K. Jackson

American Petroleum Institute

Leland A. Johnson

President

Arctic Slope Consulting Engineers

Graham King

Arco Oil and Gas Co.

Joseph H. Kravitz

National Oceanic and Atmospheric

Administration

vi
Jack Lewis

Minerals Management Service

Gary Lore

Minerals Management Service

Bonnie A. McGregor

U.S. Geological Survey

D. B. McLean

Gulf Canada Resources, Inc.

Jim Mielke

Congressional Research Service

David Norton

Professor

University of Alaska

Paul O’Brien

Alaska Department of Environmental

Conservation

John Oktollik

Alaska Eskimo Whaling Commission

Raj Phansalkar

Conoco, Inc.

Richard Pomfret

Exxon International Co.

Jim Ray

Shell Oil Co.

Joe Riva

Congressional Research

William M. Sackinger

Professor

University of Alaska

Service

John Shanz

Congressional Research Service

William H. Silcox

Standard Oil of California

Walt Spring

Mobil Research and Development Corp.

Tim Sullivan

Minerals Management Service

Rod Swope

Alaskan Governor’s Office

Pete Tebeau

Lieutenant Commander

U.S. Coast Guard

Ed Tennyson

Minerals Management Service

J. Kim Vandiver

Professor

Massachusetts Institute of Technology

R. H. Weaver

Exxon Corp.

Robert Wilson

U.S. General Accounting Office

Doug Wolfe

National Oceanic and Atmospheric

Administration

John Wolfe, Jr.

Conoco Oil Co.

vii
Contents

Chapter

1. Summary, Issues, and Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2. The Role of Offshore Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3. Technologies for Arctic and Deepwater Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4. Federal Services and Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

5. Economic Factors.

6. Federal Leasing Pol

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

icies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7. Environmental Considerations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

3

21

47

89

117

131

163

Appendix A. Offshore Leasing Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 205

Appendix B. Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223
Chapter 1

Summary, Issues, and Options
Contents

Page

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

Offshore Resources and Future Energy Needs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Technologies for Arctic and Deepwater Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Arctic Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Deepwater Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Federal Offshore Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Economic Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........

Federal Leasing Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....

Environmental Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...

Issues and Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....

Energy Planning and Offshore Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Area-Wide Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Military Use Conflicts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Disputed International Boundaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lease Terms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Alternative Bidding Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Alaskan Oil Export Ban . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

oil spills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...

U.S. Coast Guard Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ice Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , , . . . . . .

Government Information Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Chapter 1

Summary, Issues, and Options

INTRODUCTION

This assessment addresses the technologies, the

economics, and the operational and environmental

factors affecting the exploration and development

of energy resources in the deepwater and Arctic regions of the U.S. Outer Continental Shelf (OCS)

and the 200-mile Exclusive Economic Zone (EEZ)

established in March 1983. For the purposes of this

study, OTA defined ‘‘deepwater’ as those offshore

areas where water depths exceed 400 meters or

1,320 feet. The ‘ ‘Arctic’ is defined as the Beaufort,

Chukchi, and Bering Seas north of the Aleutian

Islands.

Leasing submerged coastal lands for oil and gas

development began with State programs in California, Louisiana, and Texas years before there was

a Federal offshore leasing program. Leasing in Federal offshore lands began in 1954 after the Outer

Continental Shelf Lands Act of 1953 provided the

Secretary of the Interior guidance and authority for

such activity. The industry leased, explored, and

developed OCS oil and gas under the provisions

of the 1953 Act for 25 years. Most of the offshore

activity during that period was in the Gulf of Mexico and the Pacific Ocean off southern California.

Then, in 1978, an emerging national awareness of

the environment coupled with the Arab oil embargo

and increased concern about energy supplies led

to enactment of the OCS Lands Act Amendments.

Congress included in the 1978 amendments a directive that the Secretary of the Interior seek a balance in the OCS leasing program that would accommodate ‘‘expeditious’ development while

protecting the environment and the interests of the

coastal States. The amendments established procedures for considering environmental and State

concerns in leasing decisions, required the orderly

formulation of future leasing schedules, and ordered

experimentation with a variety of alternative bidding systems. In seeking to balance energy development and other values, the offshore leasing program has been the target of criticism from coastal

States, environmentalists, and the industry. These

criticisms have sharpened in the 1980s as offshore

activities have expanded into the deepwater and

Arctic frontier areas.

The revised leasing system mandated by the 1978

amendments has been in place slightly more than

6 years. During this period, two Presidents and four

Secretaries at the Department of the Interior left

their mark on the implementation of the offshore

leasing program, In addition, Secretary James Watt

initiated a major departmental reorganization

which brought together components of the Bureau

of Land Management, the U.S. Geological Survey, and the OCS policy office in the Office of the

Assistant Secretary for Policy, Budget, and Administration. These were placed in a newly formed

Minerals Management Service (MMS). Responsibility for Secretarial oversight of MMS was shifted

from what was once the Assistant Secretary for

Energy and Minerals to a new secretarial directorate in the Office of the Assistant Secretary for

Land and Minerals Management.

The changes in leadership and the reorganizations, the shift in leasing from nearshore areas to

offshore frontier regions, and the short period of

time since the passage of the 1978 amendments

have all affected the offshore oil and gas leasing program. In spite of the fact that it has proven to be

one of the government’s most controversial natural resource programs, the offshore leasing program

has generally performed well in achieving the objectives set by Congress. It is unlikely that any statutory framework devised to expand and expedite

exploration for oil and gas on Federal lands, while

giving equal weight to protecting the environment

and honoring the sovereign goals of the States, can

be anything but adversarial and contentious. Despite the conflicts which have arisen, leasing of offshore oil and gas has worked more smoothly and

efficiently than other Federal energy leasing

programs.

3
4 ● Oil and Gas Technologies for the Arctic and Deepwater

The existing OCS Lands Act appears to provide OCS Lands Act allows the administrative flexiCongress and the executive branch sufficient lat- bility needed to adjust leasing terms and condiitude to guide the leasing program in any direc- tions to deepwater and Arctic frontier areas.

tion that public policy may dictate. In general, the

OFFSHORE RESOURCES AND FUTURE

ENERGY NEEDS

Energy supply and demand projections to the end

of the century indicate that demand for oil and gas

in the United States will increase and domestic supplies will not. Falling oil and gas prices have reduced incentives to conserve energy and to substitute alternative fuels for petroleum products. At the

same time, domestic oil production is likely to decline and the country is unable to maintain its reserves. Oil imports, which have declined in recent

years, are expected to gradually increase and may

again reach the high levels of the 1970s.

Forecasts by the Department of Energy and the

Gas Research Institute indicate domestic energy

shortfalls may necessitate oil imports over 7 million barrels per day and natural gas imports of

about 3 trillion cubic feet per day by the end of the

century. Projections by OTA and the Congressional Research Service anticipate higher oil import rates in the 1990s, perhaps again reaching the

historic 1977 high of 9.3 million barrels per day.

Predictions of declining real oil prices in the short

term, which would reduce incentives for exploration and production of domestic resources, make

even these forecasts optimistic. Oil imports of the

magnitude expected in the 1990s would make the

country more vulnerable to supply interruptions

and would increase the trade deficit.

Where might new domestic oil and gas resources

be found to assist in meeting future U.S. energy

needs? The onshore areas of the lower 48 States

are the most densely explored and developed oil

provinces in the world. But—with the exception of

Prudhoe Bay, the largest field in North America—

few sizable onshore discoveries have come on line

during the past decade. Domestic reserves continue

to dwindle. It is unlikely—but not impossible—

that a giant field similar to Prudhoe Bay will be

found onshore in the lower 48 States.

Most of the undiscovered oil and gas in the

United States is expected to be in offshore areas

or onshore Alaska. But resource estimates of undiscovered oil and gas, while useful as indicators

of relative potential, are little more than educated

guesses. Experts agree that prospects for oil and

gas offshore are good, but they also admit there is

a chance that only an insignificant amount of economically recoverable oil and gas may be found.

In fact, only one major offshore field of a size

needed to significantly increase reserves-the Point

Arguello Field off southern California—has been

discovered since offshore exploration was accelerated in the 1970s.

Exploration in the offshore frontier regions during the last 5 years has yielded some information—

most of it negative—about potential oil and gas resources. The U.S. Geological Survey estimated that

between 26 and 41 percent of the future oil and between 25 and 30 percent of the future natural gas

is offshore. The most promising prospects are believed to be in the deepwater and Arctic frontiers.

However, MMS recently lowered the estimates of

undiscovered recoverable offshore oil by half and

of natural gas by 44 percent as a result of unsuccessful exploration efforts in Alaska and the

Atlantic.

Much of the 1.9 billion acres within the offshore

jurisdiction of the United States is still unexplored.

Only actual exploratory drilling can determine the

presence of hydrocarbons. The offshore oil and gas

industry will drill the most promising geological

structures as exploration expands in the Arctic and

deepwater frontiers. If significant reserves are not

discovered in the first round of drilling, the government may need to consider a ‘‘second-round’

leasing strategy to induce the industry to drill

second-level prospective structures.
Ch. 1—Summary, Issues, and Options ● 5

If Congress wishes to pursue the objectives of tial of frontier areas. A “second-round” leasing

the OCS Lands Act, it is important that the oil and strategy may also be needed to assess the extent

gas industry have access to Federal offshore lands of smaller offshore reservoirs that could cumulato more accurately determine the resource poten- tively contribute to the Nation’s energy security.

TECHNOLOGIES FOR ARCTIC AND

DEEPWATER AREAS

Developing oil and gas in the deepwater and Arctic frontiers will be a major technological challenge.

The severe environments and remote locations will

require the design and construction of innovative

and costly exploration and production systems. The

key to safe, efficient, and economical development

of offshore resources in these frontiers will be the

technology used for exploring, producing, and

transporting oil and gas under some extreme environmental conditions.

Offshore technology has generally developed—

and will probably continue to develop—in an evolutionary fashion. Once wholly landbased, the oil and

gas industry has moved its onshore technology offshore, first onto piers, then onto seabed-bound platforms, and finally onto floating vessels as it ventured into deeper water.

Exploration systems have been operating in

many deepwater and Arctic areas for several years.

But production systems have not yet been installed

in frontier areas. Several production systems have

been designed, however, and some have been tested

in prototype. In addition, many of the individual

components that make up total production systems

are in service elsewhere in the world. The systems

finally adapted for use in the deepwater and Arctic frontiers probably will be a combination of previously tested subsystems and new components

designed to withstand specific and often severe conditions.

The industry may be characterized as cautiously

conservative in its approach to designing and deploying new technology. Yet, in general, it appears

that development of offshore technology is progressing at a pace compatible with government

leasing schedules and projected exploration and

development timeframes.

Arctic Technologies

The severity of the Arctic environment generally dictates a rigorous approach to design and construction of all primary and support systems. The

cold temperatures, ice, harsh weather, and remoteness of many Arctic regions will force the use of

costly equipment to achieve required reliability.

Technology for meeting the challenges of the

Arctic will have to develop concurrently with exploration for oil and gas. Because of the immense

costs of development in this hostile environment,

there is a tremendous incentive for industry to design and build using advanced technologies and

materials that will ensure reliability and cost effectiveness. This is particularly true for production systems which, unlike exploration equipment, must

withstand the severe, exposed, and corrosive conditions for the life of the field-usually 20 years or

more.

In order to assess the technology needed to explore, develop, and produce oil and gas in the Arctic, OTA studied hypothetical sites at Harrison Bay

in the Beaufort Sea, the Norton Basin in the Bering Sea, and the Navarin Basin in the Bering Sea.

Each of the three Arctic scenarios was based on different assumptions of environmental conditions,

water depths, oil field sizes, and production rates,

which consequently call for different technologies.

Study of the OTA scenarios and review of available industry and government Arctic research and

development programs indicate that priority should

be given to additional research related to ice properties, ice movements and forces, oceanographic

and meteorological processes, and seismicity.

Sea ice is considered to be the most important

design factor for engineering in the Beaufort, Chuk-
6 ● Oil and Gas Technologies for the Arctic and Deepwater

chi, and northern reaches of the Bering Seas. Additional research is needed to obtain basic data on

ice strength, ice forces due to movements, and ice

properties under the range of conditions likely to

be encountered. Better surveillance of ice movements from satellites and aircraft could provide

more accurate and up-to-date information. Additional research and development may be warranted

on more rapid and effective trenching techniques

to bury subsea pipelines below ice-gouge depths.

The construction of ice-breaking tankers that are

capable of working year round in the Beaufort and

Chukchi Seas will require better design data. For

the St. George and North Aleutian Basins, more

information is needed on seismic activities associated with the subduction of the Pacific plate beneath

the North American plate.

Deepwater Technologies

Deepwater technologies must be developed to

withstand such environmental factors as water currents, seafloor instability, mud slides, and hurricane-force winds and waves. In the United States

OCS, there has been a natural progression of offshore technology from shallow water into everincreasing depths. As the severity of the operating

environment has increased, incremental modifications have been made to basic designs to deal with

these changing factors. In general, as depths have

increased, structures have become larger, more substantial, and consequently, more expensive. To

assist in understanding the technology needed to

explore, develop, and produce oil in the deepwater

frontiers, OTA studied a hypothetical site off the

central California coast in water depths of up to

4,100 feet.

Exploratory drilling in very deep water is limited

by extreme ocean waves and currents and subsea

formation conditions which make drilling slow and

difficult. To date, the deepest offshore exploration

well was drilled in 6,952 feet of water in the Atlantic offshore region in 1984. The Department of the

Interior is now offering leases in 7,500 feet in the

Atlantic and up to 10,000 feet in the Pacific.

The deepest water from which oil is currently being produced is 1,025 feet in the Gulf of Mexico.

Discoveries have been made in 1,640 feet of water

in the Gulf of Mexico, but production systems are

only now being developed. In the Mediterranean

Sea, development wells have been drilled in 2,500

feet of water, but production has not yet begun.

Nearly all offshore fields discovered thus far have

been developed using fixed-leg production platforms. This trend has been an extension of scaledup shallow-water technology. Technically, fixedleg platforms can probably be designed for water

depths of 1,575 feet or more. However, the immense amounts of steel required, coupled with the

cost of fabrication and installation, may limit the

economic application of fixed-leg platforms to water

depths of about 1,480 feet

It is reasonable to expect that in a few years, several types of production systems will be designed

and built for water depths of 1,640 to 2,500 feet.

Advanced conceptual design and some component

testing are underway for compliant and floating

platforms, subsea wellheads, and submerged production systems for these water depths. However,

there has been limited effort to develop site-specific

engineered solutions for use in deeper waters because of the lack of commercial discoveries.

Industry experts generally agree that current

technology may be extended to about 8,000 feet

without the need for major breakthroughs. Existing

technologies which are particularly promising for

deepwater include buoyant towers, tension leg platforms, and subsea production units. All but the

subsea production units are generically referred to

as ‘‘compliant structures, which flex and give way

under wind, wave, and current forces.

A number of technologies related to the production system are critical to deepwater development.

These include unique structures design, materials

development, and ocean floor foundation engineering. Innovative installation, maintenance, and repair techniques are important for structures, risers,

and deepwater pipelines. Drilling, well control, and

well completion are also important to deepwater

development. Human diving capability is currently

limited to about 1,640 feet, although there have

been experimental dives to 2,300 feet. Both oneatmosphere manned vehicles and remote-controlled

unmanned vehicles will be increasingly used for

construction, maintenance, monitoring, and repair

of equipment. Deepwater pipeline systems will involve adaptation of conventional pipelaying techniques and new approaches to overcome problems
Ch. 1—Summary, Issues, and Options ● 7

of buckling caused by long unsupported span

lengths, higher strain levels, and severe sea states.

Offshore Safety

Special safety risks are present in oil and gas development in offshore frontier regions because of

the harsh environments and remote locations. In

general, the safety record of offshore operations appears equal to or better than the record of comparable onshore industries. Still, there may be a need

for new approaches to preventing work-related injuries and fatalities in coping with new hazards

in the hostile Arctic and deepwater frontiers. The

oil and gas industry has the primary responsibility

for ensuring the safety of offshore operations and

is governed by a complex system of regulations.

Both the Coast Guard and MMS enforce regulations controlling aspects of workplace safety.

The possibility of catastrophic rig accidents is the

greatest concern in offshore frontier areas. Such incidents have occurred in the past because of storms,

structural failures, and capsizings. Other fatalities

have been caused by well blowouts, explosions, and

fires. Currently, there is no regulatory requirement

for the submission of integrated safety plans which

address technical, managerial, and other aspects

of the safety of offshore operations. In addition, insufficient funding by the Federal Government may

result in inadequate rig safety inspections and monitoring efforts. Comprehensive safety plans, increased regularity of government monitoring efforts, and improved inspection techniques to match

the increasing complexity and sophistication of offshore facilities may be needed.

Environmental conditions in frontier regions also

present unique problems in evacuating personnel

from rigs and platforms. Conventional lifeboats and

rafts cannot be used on ice or in remote locations.

Free-falling boats, air-cushioned vehicles, special

aircraft or helicopters, and icebreaking ships may

be needed to evacuate personnel from rigs. It has

been proposed that appropriate standby vessels be

required by law to be stationed near offshore facilities. The adequacy of evacuation measures could

be assured by evacuation performance requirements, regular inspections, and evaluation of evacuation drills.

Since offshore accidents are most frequently

caused by human errors rather than by equipment

failures, there are limits to safety improvements

possible through purely technical means. To

achieve some improvement in human performance,

responsibility for safety could be delineated more

clearly and better defined chains of command could

be established. More extensive and improved work

force training also may be necessary for operations

in hostile frontier regions.

There is currently no single comprehensive

source of statistics on offshore injury and fatality

rates. The lack of integrated data makes it difficult to evaluate the level of safety achieved by the

offshore oil and gas industry or to assess the effects

of safety regulations and equipment on the industry’s safety performance. Improved population and

injury data collection systems, greater consistency

among data sources, and centralization of data collection and analysis in a single government agency

could aid in evaluating the effectiveness of safety

measures. Offshore safety data systems could be

improved to include comprehensive event and exposure data; to relate events to specific employers,

locations, operations, and equipment; to calculate

frequency and severity rates and analyze trends;

and to permit monitoring of the relative safety performance of owners and employers, locations, and

activities.

Federal Offshore Services

The Federal Government provides a variety of

services and information that bear on the development and protection of offshore resources. Government services most useful to the offshore oil and

gas industry are those that support maritime operations, including research and development, weather information, navigation services, and icebreaking. The adequacy of these services for large-scale

oil and gas development in offshore frontier areas,

particularly the Arctic, is in question. There is also

debate regarding the appropriate division of costs

and responsibilities between the government and

the private sector in the provision of offshore

services.

The most significant government research and

development program is the MMS Technology As-
8 ● Oil and Gas Technologies for the Arctic and Deepwater

sessment and Research Program, which focuses on

the evaluation of offshore technologies with regard

to safe operation and pollution avoidance. This program, which has almost been eliminated in past

budget cuts, is the primary research activity supporting Federal regulatory efforts and deserves

continued support. In 1984, Congress enacted the

Arctic Research and Policy Act to facilitate the coordination of Arctic research. However, this Act

does not contain authority for the appropriation of

additional funds, and budget support for Arctic research must come from existing programs.

Federal programs providing weather and ice information and navigational services are generally

considered marginal for increased industry activities in offshore frontier regions, but at the same time

are targeted for budget cuts. The Administration

has proposed shifting the responsibility for weather

satellite services and coastal and bathymetric charting to the private sector. In addition, there are plans

to phase out existing radionavigation systems and

replace them with a single satellite system—the

Global Positioning System (GPS). Despite the dependence of the oil and gas industry on accurate

ice information, there are limitations on sensing

equipment and significant voids in satellite coverage for a major part of the Arctic.

The proper role of the government in the provision of icebreaking services is also in question. Icebreaking will be essential to maintaining shipping

lanes and drillship sites, protecting drilling operations from drifting ice, and aiding supply and logistics operations, oil spill response, and search and

rescue. However, the U.S. Coast Guard, which

would normally provide these services, has no plans

for an Arctic facility. The closest Coast Guard facility to Point Barrow, Alaska, is now 400 miles

to the south. While the Coast Guard will continue

to meet its overall icebreaking obligations to the extent allowed by the budget, additional capacity may

not be available to serve the expanding needs of

the offshore petroleum industry.

ECONOMIC FACTORS

Exploration and development of oil and gas resources in Arctic and deepwater frontiers will result only if the promise of economic returns outweighs the associated high risks and costs. In

general, higher costs and longer lead-times to production lower the profit margins of resource development in offshore frontier areas. As a result, the

sensitivity of project economics to changes in various economic factors—e.g., costs, prices, and government payments—is higher in frontier areas than

in mature producing regions such as the shallow

areas of the Gulf of Mexico. The leasing and payment provisions of the OCS Lands Act Amendments of 1978 were based largely on experience

gained from oil and gas leasing in State submerged

lands and the Federal areas of the Gulf of Mexico

and California.

OTA used a computer simulation model to analyze the economic attractiveness of oil and gas development under deepwater and Arctic conditions

and to assess the implications of government policies. Cash flow profiles were developed for the four

technology scenarios in the Navarin Basin, Harrison Bay, Norton Basin, and California deepwater,

as well as for a more conventional project in the

Gulf of Mexico.

Extremely large oil and gas discoveries are

needed to offset the high costs and long timeframes

of development in offshore frontier areas. While

a 40- to 50-million barrel field may be highly profitable in the shallow-water areas of the Gulf of

Mexico, some economic projects in the Alaskan offshore may depend on finding 1 to 2 billion barrels

or more of recoverable reserves. Fields of this magnitude are called ‘ ‘elephants’ by the industry and

are extremely limited.

The OTA computer simulation indicated that

government lease and tax payments affect the profitability of offshore fields differently in frontier areas

than in other leasing areas. Fixed royalties tend to

overtax small fields and remove the economic incentive for the development of resources. Bidding

systems based on alternative types of lease payments
Ch. 1—Summary, Issues, and Options Ž 9

may reduce the financial risks associated with fron- prices. In the Alaskan region, the availability of ecotier-area fields and provide greater incentive to the nomic market outlets for oil and gas—from the exdevelopment of marginal resources. port of Alaskan oil and the development of procIn general, the profitability of oil and gas devel- essing and transportation systems for Alaskan

opment in deepwater and Arctic regions will be af- natural gas—could improve the economic profile

fected by increases or decreases in real oil and gas of offshore fields.

FEDERAL LEASING POLICIES

In the 1980s, the Department of the Interior accelerated the rate and extent of offshore leasing as

a means of hastening exploration and development

of energy resources. Secretary Watt initiated a system of ‘ ‘area-wide leasing, which expanded the

offshore acreage considered for each lease sale. The

number of lease sales to be held each year was increased, and the focus was on leasing in deepwater

and Arctic frontier areas. However, the actual pace

of offshore leasing in this period was constrained

by opposition and conflicts. Resolution of the issues

surrounding area-wide leasing could allow the new

5-year leasing program (1986-91) to proceed more

smoothly.

Challenges to the area-wide leasing approach

have been based on the adequacy of environmental

information to support lease sale decisions. Other

litigation stemmed from disagreements between

Coastal States and the Federal Government over

requirements that Federal offshore actions be consistent with State coastal zone management programs. Congress imposed moratoria on leasing in

some areas, largely as a result of Federal-State

disputes on the division of escrow money from jointly owned tracts, the failure to devise a mutually acceptable revenue-sharing formula, and coastal zone

management issues. Because of these delays, only

7 of the 21 lease sales scheduled through the end

of 1984 were held on the originally scheduled date.

The extent of offshore acreage offered for lease

has also been constrained by military deferrals of

areas for fleet operations, submarine transit lanes,

missile flights, aircraft testing, underwater listening posts, and other uses. As offshore oil and gas

activities have expanded into frontier regions, the

possible incompatibility between military and energy

development uses in some areas of the ocean has

become more obvious. Continuing deferrals may

result in permanent withdrawals of OCS lands for

military reservations. Such reservations could

remove a significant amount of potentially productive acreage from oil and gas development. Currently, there is some confusion as to who has final

authority for withdrawing acreage from oil and gas

development— the Department of the Interior, Department of Defense, or Congress. If uncertainty

in the frontier-area leasing process is to be reduced,

this issue as well as questions regarding U.S. international boundaries in several frontier regions

and the exact delimitation of the U.S. Outer Continental Shelf eventually should be resolved.

In order to provide the necessary incentives for

exploration and development in offshore frontier

areas, it may be desirable to implement new leasing approaches or modify lease terms and conditions. There is general agreement on the need for

longer lease terms for offshore deepwater and Arctic

areas in view of the much longer period of time

needed to explore and develop resources under hostile operating conditions. As leasing in offshore

frontier areas has increased, more tracts have been

offered and leased with 10-year rather than 5-year

lease terms. However, specific criteria may be

needed for extending lease terms. In addition, there

should probably be a requirement for submission

of exploration plans within a specified timeframe.

There is less agreement on the type of bidding

systems appropriate to offshore frontier areas. The

Department of the Interior prefers the traditional

cash bonus bid with a fixed royalty system that has

gained general acceptance from industry and is easy

to administer. However, bidding variables other
10 . Oil and Gas Technologies for the Arctic and Deepwater

than the cash bonus and lease payments other than discovery of oil or gas, government payments may

fixed royalties may be more suited to the econom- be based on profits, on productivity of the tracts,

ics and risks of frontier areas. Other countries leas- or other variables that take into account the costs

ing in frontier areas generally have used a more and risks of development. More analysis and testing

flexible work commitment system in conjunction are needed before any attempts at implementation

with larger lease areas and longer lease terms. After of these systems on a broad basis.

ENVIRONMENTAL CONSIDERATIONS

The development of offshore oil and gas resources

and protection of the environment are potentially

conflicting objectives and the subject of continuing debate. Nevertheless, the OCS Lands Act

Amendments of 1978 require that energy and environmental policy goals be balanced in offshore development. Other Federal laws provide additional

environmental safeguards. Major environmental

considerations related to the development of Arctic and deepwater areas include trends in the Department of the Interior’s Environmental Studies

Program, the status of the endangered bowhead

whale and other marine mammals, and the adequacy of oil spill containment and cleanup techniques.

The OCS Lands Act directs the Department of

the Interior to systematically study the environmental components that may be affected by offshore

development. The MMS Environmental Studies

Program includes research on the distribution and

population dynamics of marine species, the fate and

effect of oil spills, and general ecosystem processes.

Overall funding for the Environmental Studies Program has been decreasing at a nearly constant rate

since 1978. The MMS maintains that a great deal

has been learned about the offshore environment

in the past 10 years of the program, and that substantial additional research may not now be warranted. However, OTA believes that the projected

pace of leasing in the relatively unknown deepwater

and Arctic regions and the need to monitor and regulate post-lease exploration and development activities may require more rather than less study of

environmental effects.

Although many species of fish, marine mammals,

and birds may be affected by oil and gas development, bowhead whales have received the most attention in recent years. Controversies surrounding

the bowhead whale demonstrate the complexity of

managing and protecting marine animals. Bowhead

whales, which are classified as an endangered species, could be adversely affected by offshore oil and

gas operations in the Arctic. Bowhead whales hold

special meaning for the native Alaskan Inuit and

Yupik people, and they serve as a supplementary

food source for native people throughout much of

the Arctic region. In addition, whales are involved

in the politics of the international conservation

movement and come under the scrutiny of the International Whaling Commission.

In comparison to funds spent on studying other

endangered species, a large proportion of available

funds has been spent on bowhead whale research.

Despite this, most scientists are reluctant to make

unqualified statements concerning population, reproduction, or the effects of oil and noise on the

animals. Four major areas are targeted for more

research: 1 ) bowhead whale population estimates;

2) the effects of noise on whales; 3) the long-term

cumulative effects of industrial activities on whales;

and 4) identification of critical habitats for bowheads.

Although the risk of catastrophic oil spills from

offshore operations is believed to be low, effective

containment and cleanup measures are essential in

light of the potential harmful effects of any such

spill. The offshore oil and gas industry is genuinely

concerned and has diligently prepared for dealing

with the eventuality of oil spills. Industry has invested large amounts of funds and effort in engineering technology to prevent blowouts and other

catastrophic rig accidents. Considerable costs for

cleanup and damage claims could be associated with

a large spill. Some claim, however, that there is
Ch. 1—Summary, Issues, and Options • 11

little market incentive for developing oil spill

countermeasures compared to spill avoidance.

For the most part, oil spill containment and

cleanup technology has been developed for spills

in nearshore and temperate regions. It may not be

suitable for use under the extreme conditions of

deepwater and the Arctic. Arctic oil spill countermeasures may be complicated by extremely cold

temperatures, the presence of ice, long periods of

darkness, intense storms, and lack of transportation and storage facilities in most areas. In deepwater areas, high sea-states may be encountered,

and greater distances from shore may create logistical problems for oil spill cleanup. To date, it has

not been demonstrated in a real situation that industry will be able to use effectively the existing oil

spill equipment and countermeasure strategies in

hostile environments.

ISSUES AND OPTIONS

Little is known about the actual resource potential of the offshore lands of the United States. Experts believe that major new oil and gas supplies

may be located in the Arctic and deepwater frontiers. The country will need this oil and gas to fill

energy requirements at the end of the century—a

mere 15 years away. The history of petroleum exploration suggests that large fields are generally discovered early in the exploration cycle. Even if major resource discoveries are made by the end of the

next 5-year leasing program in 1991, the Nation

will still have serious decisions to make about its

energy future. The offshore oil and gas industry

may need incentives to reenter the frontier areas

for a ‘ ‘second-round’ of exploration of the promising but smaller oil and gas prospects.

OTA has identified policy options for expediting

exploration and development of oil and gas in deepwater and Arctic offshore regions and for providing additional incentives to the industry. OTA has

also outlined options for protecting environmental

values and increasing offshore safety in conjunction with exploration and development activities.

These issues and options should be considered by

Congress in the review of the next 5-year leasing

program ( 1986-91), which will place emphasis on

leasing in offshore frontier areas.

Energy Planning and

Offshore Resources

The goal of the offshore leasing program is to

increase the Nations energy supply, thereby reducing dependence on oil imports. The offshore

frontier areas are believed to have the greatest potential for major new domestic oil and gas discoveries, In the next few years, most of the remaining

prospective areas of the offshore frontier regions

will be considered for leasing. Substantial exploration has already occurred in some offshore frontier areas, such as the Gulf of Alaska and Atlantic

regions, However, except in the Gulf of Mexico

and California nearshore areas, exploration thus

far has added very little to proven reserves. Accurate knowledge of the resource potential of the

Nation’s offshore areas is critical to overall energy

planning and to making decisions about the offshore

leasing program and alternative energy programs.

In order to effectively plan for future energy needs,

the Nation may need to reevaluate the role and resource potential of offshore areas when the findings of additional exploratory drilling in offshore

frontiers are available.

Congressional Options

Option 1: Reassess available information about

the resources of the OCS with regard to the potential of offshore oil and gas in supplementing the

Nation’s future energy supplies in the context of

National Energy Planning.

Action: Establish a Congressional Commission

or request an existing body (e. g., National Research Council, National Petroleum Council) to

reassess the role of offshore oil and gas in the Nation energy future at some point in the next 5-

year leasing schedule.
12 . Oil and Gas Technologies for the Arctic and Deepwater

Area- Wide Leasing

Exploration and development of oil and gas resources in offshore frontier areas can be encouraged

by more rapid and efficient leasing of offshore acreage. The system of area-wide leasing initiated by

the Department of the Interior in 1983 has increased the pace of leasing with the hope of early

identification of resources. Area-wide leasing permits the industry to select from among the full range

of available tracts in deepwater and Arctic regions

and to explore those of greatest resource potential.

However, the greater size and faster pace of lease

offerings under the area-wide system may reduce

the detailed consideration of environmental concerns, competing land uses, and State and local

views in the leasing process. A return to the previous tract nomination system could allow for greater

outside input into the leasing process, but may slow

determination of the resource potential of offshore

frontier areas.

Congressional Options

Option 1: Allow the Secretary of the Interior to

determine the size of lease offerings in offshore

frontier areas.

Action: No action required by Congress.

Option 2: Direct the Secretary of the Interior

to use a “tract nomination system” for lease offerings in offshore frontier areas.

Action: Amendment to OCS Lands Act or congressional directive through the appropriations

process.

Military Use Conflicts

As exploration and development have expanded

to offshore frontier regions, there has been increasing conflict between oil and gas activities and military uses of offshore areas. An estimated 40 to 55

million acres of offshore land are restricted from

oil and gas development for military and national

security purposes, and as much as 75 million additional acres are affected by restrictions on the density of oil and gas operations. Deferrals and exclusions of lease tracts for military reasons are now

negotiated by the Department of the Interior and

the Department of Defense. Past disagreements on

offshore land uses have prompted a review of this

procedure and have led to a new memorandum of

understanding between the agencies. While the

OCS Lands Act gives authority for withdrawal of

offshore acreage for national defense purposes to

the Secretary of Defense, the Withdrawal of Lands

for Defense Purposes Act reserves this authority for

Congress. Continuing confusion over who has final authority to withdraw offshore acreage adds uncertainty to the leasing process and may delay exploration in offshore frontier areas. A procedure

is needed which resolves the conflicting authorities

and adequately balances energy and military uses

of offshore lands.

Congressional Options

Option 1: Allow Secretary of the Interior and

Secretary of Defense to continue negotiating military withdrawals of OCS acreage.

Action: No action required by Congress.

Option 2: Delegate authority for military withdrawal of OCS acreage to one department.

Action: Amendment to OCS Lands Act and/or

amendment to Withdrawal of Lands for Defense

Purposes Act.

Option 3: Reserve authority for military withdrawal of OCS acreage to Congress.

Action: Amendment to OCS Lands Act.

Disputed International Boundaries

Contested international boundaries eventually

may contribute to delays in oil and gas exploration.

There are unresolved disputes between the United

States and other countries in several offshore frontier regions, including those with the Soviet Union

in the Bering Sea and with Canada in the Beaufort

Sea. A dispute between the United States and Canada over Georges Bank was recently arbitrated by

the International Court of Justice, but important

bilateral management issues are yet to be worked

out. In addition, the outer boundary of the extensive U.S. continental shelf has not been delimited,

and uncertain jurisdiction in the central Gulf of

Mexico may eventually cause tension between the

United States, Mexico, and possibly Cuba. Although there is no immediate need to resolve con-
Ch. 1—Summary, Issues, and Options ● 13

tested boundaries, such disputes could be settled

through bilateral negotiation, arbitration, or mediation. Arrangements could be made for joint exploration and/or development of contested areas by the

parties to the dispute. Contested offshore areas

could also be withdrawn from oil and gas development pending settlement of disputes. Resolution

of offshore boundary questions would help reduce

international tensions and allow exploration and development of frontier areas to proceed in an orderly

manner.

Congressional Options

Option 1: Allow arbitration by the International

Court of Justice to resolve boundary disputes.

Action: Congressional directive to Department

of State to negotiate arbitration agreements with

other countries.

Option 2: Establish an interim arrangement for

exploration and/or development of disputed offshore areas.

Action: Congressional directive to Department

of State to negotiate appropriate agreements.

Option 3: Create buffer zones in disputed areas

where no oil or gas development would take place.

Action: Congressional directive to Department

of State to negotiate appropriate agreements.

Lease Terms1

Longer lease terms may be needed in offshore

frontier areas to allow sufficient time for exploration and identification of resources. The standard

5-year lease term for offshore tracts has been increased to 10 years for many tracts in deepwater

and Arctic areas under the authority provided to

the Secretary of the Interior in the OCS Lands Act.

However, the lack of specific criteria for 10-year

lease terms adds uncertainty to the offshore leasing process in Arctic and deepwater frontier areas.

In addition, 10-year lease terms in deepwater now

are provided only for tracts in water deeper than

1MMS has extended lease terms for deepwater tracts (Federal Register, Apr. 3, 1985). Tracts in water depths between 400 and 900 meters

will have 8-year terms, and tracts in waters deeper than 900 meters

will have 10-year terms. To ensure exploration diligence, exploration

drilling is required during the first 5 years.

900 meters or 2,950 feet. An established policy on

10-year lease terms and a more realistic deepwater

threshold may be needed. The Department of the

Interior has proposed automatic 10-year lease terms

for all tracts in water deeper than 400 meters or

1,320 feet. Currently, companies with 10-year

leases have no set deadline for the submission of

exploration plans and may hold a lease for 8 or 9

years before filing a statement of intention to explore. In conjunction with a longer lease term policy, the Department of the Interior may need to

ensure diligent exploration in frontier areas by requiring submission of exploration plans at a specific time in the lease term (e. g., fifth or sixth year).

Congressional Options

Option 1: Establish automatic 10-year lease

terms for tracts in water depths greater than 400

meters or 1,320 feet and for selected Arctic regions.

Action: Congressional directive to Department

of the Interior through the appropriations process.

Option 2: Establish automatic 10-year lease

terms for selected offshore frontier areas and include provisions for submission of exploration

plans within a specific time period.

Action: Congressional directive to Department

of the Interior through the appropriations process.

Alternative Bidding Systems

The United States has traditionally allocated offshore tracts on the basis of the highest cash bonus

bid with a fixed royalty payment, The OCS Lands

Act Amendments of 1978 mandated testing of several alternative bidding systems. However, after

testing, the Department of the Interior prefers the

traditional system. This bidding system is easy to

administer, has promoted efficient exploration and

development of offshore tracts in conventional leasing areas, and has been accepted by both government and industry. However, there may be disadvantages in using this system to allocate offshore

frontier tracts. The requirement for upfront cash

bonus payments may be a deterrent to continued

exploration of frontier areas, because these areas

involve greater uncertainty and far higher costs.

Alternative arrangements such as ‘‘work commit-
14 . Oil and Gas Technologies for the Arctic and Deepwater

ment leases’ may be needed to sustain activities

in high-risk deepwater and Arctic regions. In addition, because of low profit margins in frontier

areas, fixed royalties may overtax small fields and

lead to nondevelopment of resources. Bidding systems with other types of lease payments, such as

sliding scale royalties, net profit shares, or even zero

royalties, may provide more incentives to marginal

resource development. Effective implementation of

alternative bidding systems, however, will require

additional experimentation, analysis of costs and

benefits, and adjustments in other lease conditions

such as the size of the lease tracts.

Congressional Options

Option 1: Allow the Secretary of the Interior to

select the bidding system to be used in offshore

frontier areas.

Action: No action required by Congress.

Option 2: Direct the Secretary of the Interior

to continue testing alternative bidding systems in

offshore frontier areas.

Action: Amendment to OCS Lands Act.

Alaskan Oil Export Ban2

Removing the ban on exporting oil produced in

offshore Alaskan areas could provide an added economic incentive to developing offshore resources

in the Arctic. In the 1970s, concern about the Nation’s increasing oil import dependence prompted

Congress to place restrictions on the export of oil

produced on Alaska’s North Slope and in offshore

areas. About half of the oil produced on the North

Slope is now shipped to Gulf of Mexico and Atlantic

Coast refining centers. Exporting oil to closer markets in Japan and other Asian countries could reduce transportation costs and increase the profits

of producing Alaskan oil. The increased profit margins on offshore fields could improve the incentives

for developing marginal resources in Alaskan offshore areas. However, removing the export ban

could have economic and national security costs as

a result of increased dependence on imported oil

‘The House of Representatives passed a 4-year extension of the Export Administration Act, which contains restrictions on the export of

Alaskan oil, on Apr. 16, 1985.

and adverse effects on domestic shipping which

heavily depends on the Alaskan tanker trade. In

addition, it is not certain that export markets in

Japan could be established.

Congressional Options

Option 1: Remove restrictions on exporting oil

produced in Arctic offshore regions.

Action: Amendment to Export Administration

Act.

Option 2: Evaluate advantages and disadvantages of exporting Alaskan oil, with reference to

economics of Alaskan offshore oil production and

market development.

Action: Establish an Alaskan Oil Export Commission to make recommendations on exporting

Alaskan oil.

Environmental Information

The Environmental Studies Program administered by the Minerals Management Service is the

major research program on the effects of oil and

gas development on offshore environments. This

information is used in preparing Environmental

Impact Statements and as an aid to the Secretary

of the Interior in weighing the costs and benefits

of offshore development. The Environmental Studies Program is changing its emphasis in the Alaskan

region from acquiring pre-lease information to acquiring post-lease data needed for management of

oil and gas activities. Funding for the program,

however, has been decreased and led to a reduction in both pre-lease and post-lease studies. Proportionally, the decrease in funds for the Alaskan

regions has been greater than that for temperate

coastal areas. In general, decreases in the Environmental Studies Program budget are not justified

in view of the relative lack of understanding of Arctic and deepwater marine environments, the projected pace of leasing in frontier areas, and the continuing need to monitor offshore oil and gas

activities.

Congressional Options

Option 1: Allow Secretary of the Interior to determine the allocation of research funds for environmental studies of different offshore regions.
Ch. 1—Summary, Issues, and Options ● 1 5

Action: No action required by Congress.

Option 2: Review funding levels for environmental studies in offshore frontier regions in light

of new 5-year leasing schedule.

Action: Conduct congressional hearings on Environmental Studies Program and oversight review.

Appropriate additional funds if found necessary.

Oil Spills

The offshore oil and gas industry has a good record of preventing oil spills. However, it has little

experience in containing and cleaning up oil spills

in offshore frontier environments, where there is

now little oil production. Most current technology

was developed for nearshore and inshore areas and

may not be suited to frontier areas characterized

by severe wind and waves, ice, extended periods

of darkness, and/or low temperatures. Industry has

directed its investments primarily to oil spill prevention rather than containment and cleanup, and

government funding for oil spill technology research

has been low. The OHMSETT (Oil and Hazardous Material Simulated Environmental Test Tank)

Interagency Technical Committee has conducted

limited testing of Arctic oil spill countermeasures

technology, but budget constraints may reduce

future testing. Government evaluation and publication of oil spill equipment test results could provide incentives to industry to improve countermeasures technology. Certain performance

requirements might also encourage the industry to

develop new technology and engineering approaches

for dealing with oil spills.

Congressional Options

Option 1: Increase funding for research on oil

spill countermeasures technology in offshore frontier areas.

Action: Increased appropriations to OHMSETT,

MMS, Environmental Protection Agency, National

Oceanic and Atmospheric Administration, and/or

U.S. Coast Guard oil spill research programs.

Option 2: Develop a program for oil spill equipment testing and publication of results.

Action: Congressional directive to Department

of the Interior through the appropriations process.

Option 3: Establish performance standards for

industry oil spill response capability.

Action: Amendment to OCS Lands Act and/or

congressional directive to Department of the Interior through the appropriations process.

Offshore Safety

The hostile operating conditions in deepwater

and Arctic areas may require greater attention to

personnel safety concerns during oil and gas activities. New technological approaches, management

practices, and monitoring efforts may be needed

to ensure high safety standards in offshore frontier

regions. Improved Minerals Management Service

and Coast Guard monitoring and inspection of offshore facilities could assure minimum safety standards and uniformity of safety conditions. Concern

about possible catastrophic rig accidents has prompted

proposals for better evacuation procedures and techniques, regular evacuation drills, and requirements

for standby vessels. Regulations concerning work

force training and management safety practices

may need to be reviewed and revised for frontier

areas. In addition, it is difficult to evaluate the seriousness of offshore safety hazards because of incomplete and inconsistent safety data. Implementation of Federal safety responsibilities in offshore

frontier areas will require adequate and accurate

data in order to monitor safety performance and

the effectiveness of safety initiatives.

Congressional Options

Option 1: Increase funding for MMS and/or

U.S. Coast Guard safety inspection programs in

offshore frontier areas.

Action: Congressional directive through the appropriations process.

Option 2: Establish standards for evacuation

procedures from fixed platforms and mobile drilling vessels in offshore frontier areas and periodically monitor emergency evacuation drills.

Action: Congressional directive through the appropriations process or Amendment to OCS Lands

Act.

Option 3: Consolidate responsibility for collecting, analyzing, and reporting safety-related data

in a single agency (MMS or U.S. Coast Guard).
16 . Oil and Gas Technologies for the Arctic and Deepwater

Action: Congressional directive through the

appropriations process or Amendment to OCS

Lands Act.

U.S. Coast Guard Programs

The capacity of the U.S. Coast Guard to effectively conduct its missions in Arctic regions is

limited and will be increasingly inadequate as offshore oil and gas development proceeds. Due to the

current lack of activities in northern Alaskan offshore areas, U.S Coast Guard operations in Alaska

are concentrated in the Gulf of Alaska, far to the

south of the prospective Arctic oil areas in the Bering, Chukchi, and Beaufort Seas. The lack of an

operational Coast Guard facility in the Arctic

greatly impedes the agency’s capabilities for search

and rescue, vessel and platform safety inspection,

law enforcement, maintenance of navigation, oil

spill cleanup response, and icebreaking. Despite the

potential for greater human safety and environmental risks in the region as a result of the increase

in oil and gas activities, the Coast Guard currently

has no plans for basing equipment and personnel

in Arctic areas. However, studies of a potential Arctic facility are underway.

Congressional Options

Option 1: Establish a U.S. Coast Guard base in

the Arctic region.

Action: Congressional directive through the authorization/appropriations process.

Ice Information

Arctic oil and gas operations depend on timely

information about the location and movement of

sea ice. Weather conditions and remoteness of facilities potentially make satellite imagery a very

useful source of information on ice conditions.

However, U.S. Arctic satellite-sensing capability

is limited by the number of satellites and the capabilities of existing sensors. In addition, the usefulness of ice information obtained from satellites is

reduced by the length of time needed for processing and delivery to users. Planned improvements

in U.S. satellite systems will increase ice-related

coverage of Arctic areas and contribute to the safety

and efficiency of Arctic oil and gas development.

Use of data from European and Canadian satellites could also assist offshore activities. However,

there are uncertainties as to the timing and extent

of improvements in U.S. satellites, the availability of information from foreign satellites, and the

means for making satellite information available to

the private sector. The Navy/NOAA Joint Ice Center, which has primary responsibility for processing and disseminating satellite ice data, could be

upgraded to provide more timely operational data.

In the absence of improved government ice data

collection and distribution, the industry will have

to place greater reliance on private sector ice information services.

Congressional Options

Option 1: Upgrade U.S. satellite system to improve ice data for oil and gas operations.

Action: Congressional directive through the appropriations process.

Option 2: Increase government acquisition of

ice information from foreign polar satellite systems.

Action: Congressional directive through the appropriations process.

Option 3: Expand ice information processing

and dissemination by the Joint Ice Center.

Action: Increased appropriations for the Navy/

NOAA Joint Ice Center. Establish the Center permanently through authorizing legislation.

Government Information Services

Improved coordination and delivery of government information could facilitate operations in offshore frontier areas. Information and data relating to offshore oil and gas activities are now divided

among several government agencies, including the

Minerals Management Service, the National Oceanic and Atmospheric Administration, the U. S, Coast

Guard, the U.S. Navy, and the Environmental

Protection Agency, Users of offshore technical,

environmental, and leasing information often find

it difficult to identify agency contacts and sources

of information within the government. The centrali-
Ch. 1—Summary, Issues, and Options ● 1 7

zation of information services within a single agency

has been proposed, but this would be difficult to

implement in view of the contrasting responsibilities

of the various agencies. NOAA has established a

system of national ocean service centers, including

an Anchorage, Alaska, center for the Arctic offshore

area, which may provide a prototype for other agencies. These service centers act as regional clearinghouses for environmental and meteorological information gathered by NOAA. Other agencies,

separately or in coordination with NOAA, could

establish similar regional clearinghouses for information distribution to the offshore oil and gas industry.

Congressional Options

Option 1: Establish regional clearinghouses to

collect and distribute government information relating to offshore oil and gas operations.

Action: Congressional directive through the appropriations process.
Chapter 2

The Role of Offshore Resources
Contents

Page

Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

U.S. Energy Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Energy Demand Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Energy Supply Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Resource Projection Problems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Comparability Among Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Reliability of Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Interpretation of Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Other Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

U.S. Exclusive Economic Zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Oil Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Natural Gas Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Resources by Lease Sale Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

TABLES

Table No. Page

2-1. Energy Demand and Domestic Supply: 1978-83. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2-2. U.S. Energy Demand and Supply Forecasts to 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

2-3. Definitions of Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

2-4. Offshore Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2-5. Comparison of Estimates of Alaskan Offshore Oil Resources . . . . . . . . . . . . . . . . . . . . . . . . . . 31

2-6. Comparison of Estimates of Alaskan Offshore Gas Resources . . . . . . . . . . . . . . . . . . . . . . . . . 33

2-7. Estimates of Offshore Acreage With Hydrocarbon Potential . . . . . . . . . . . . . . . . . . . . . . . . . . 34

FIGURES

Figure No. Page

2-1. Profile of Physiographic Features of the Geological Continental Margin of the U.S.. . . . . . 28

2-2. Oil Resources by Planning Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

2-3. Oil Resources in Alaska Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

2-4. Natural Gas Resources by Planning Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

2-5. Natural Gas Resources in Alaska Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

2-6. Minerals Management Service Lease Sale Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

2-7. Distribution of Gulf of Mexico Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . 37

2-8. Trends in Gulf of Mexico Oil and Gas Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

2-9. Distribution of Atlantic Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

2-10. Distribution of Pacific Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

2-11. Trends in Pacific Region Oil and Gas Production.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

2-12. Distribution of Alaskan Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Chapter 2

The Role of Offshore Resources

OVERVIEW

The petroleum and natural gas resources of offshore areas of the United States could be a key additional energy source to help meet U.S energy

needs and limit oil import growth in future years.

Although plentiful energy supplies and declining

world prices have dampened concern about the

energy situation, supply and demand trends indicate potential domestic shortfalls and rising oil

imports by the end of the century. At present, offshore oil accounts for about 11 percent of total domestic petroleum production and offshore natural

gas accounts for about 24 percent of total domestic gas production. The potential for increasing the

contribution of offshore areas to U.S. energy supply

may be large. Most U.S. offshore acreage remains

to be explored, and the search is just beginning in

the deepwater and Arctic frontier areas.

Resource recoverability is determined by a combination of geologic, technologic, and economic factors which can change over time. In addition, petroleum resource statistics are confusing because

each estimate seems to be the result of different

definitions and statistical methods. Given the inaccuracy and uncertainty associated with published

resource estimates, they probably should be considered only as indicators of relative ranking among

prospective oil and gas producing areas.

Offshore areas are expected to contain 21 to 41

percent of the oil and 25 to 30 percent of the natural gas that is undiscovered and recoverable in the

United States. As much as one-third to one-half of

the offshore oil may lie under waters 660 to 12,000

feet deep, If onshore and offshore Alaska are considered together, Alaska may contain as much as

one-half of the total amount of recoverable oil expected to be found in the United States. About 31

percent of the natural gas expected to occur offshore

probably lies in water depths between 660 and 8,200

feet. Gas occurring in the Arctic offshore regions

is now considered to be uneconomical to recover.

California, while having a long history of offshore

petroleum production, still remains largely unexplored in many areas. Similarly, the Atlantic and

Alaskan regions have had only limited exploration,

and as yet their Federal offshore areas have no oil

or gas production. The Gulf of Mexico region continues to produce about 90 percent of the oil and

virtually all of the natural gas produced from

submerged lands.

U.S. ENERGY OUTLOOK

Although the United States is now in a period

of relative stability as far as energy prices and supplies are concerned, energy trends include slowly

increasing demand, declining domestic production,

and rising imports to the end of the century. Although oil imports have decreased in the last 5

years, domestic demand is outpacing supply and

leading to higher import levels. Low oil and gas

prices have reduced incentives to conserve on

energy uses and to substitute alternative fuels, Forecasts indicate that imports could reach record highs

in the 1990s, increasing U.S. vulnerability to supply

disruptions. Against this background, the oil and

gas resources of the offshore areas of the United

States take on new significance in their potential

contribution to future U.S. energy needs.

Energy Demand Trends

U.S. energy demand decreased over the past decade largely because of the increase in the price of

oil and natural gas that began in the early 1970s

and the resulting energy conservation efforts (see

table 2-l). The real increase in the price of both

21
22 . Oil and Gas Technologies for the Arctic and Deepwater

Table 2-1 .–Energy Demand and Domestic Supply: 1978-83

Energy demand

Oil Natural gas Coal Nuclear Hydro Total

Year (MMBD) (TCF) (MMT) (BkWh) (BkWh) (QUADS)

1968 . . . . . . . . . . . . . . . . . 13.4 18.6 509.8 12.5 225.2 60.9

1971 . . . . . . . . . . . . . . . . . 15.2 21.8 501.6 38.1 273.1 67.8

1974 . . . . . . . . . . . . . . . . . 16.7 21.2 558.4 114.0 316.9 72.5

1977 . . . . . . . . . . . . . . . . . 18.4 21.7 625.3 250.9 241.0 76.2

1980 . . . . . . . . . . . . . . . . . 17.0 19.9 702.7 251.1 300.1 75.9

1983 . . . . . . . . . . . . . . . . . 15.2 17.0 736.7 293.7 373.2 70.7

Domestic energy production

oil Natural gas Coal Nuclear Hydro Total

Year (MMBD) (TCF) (MMT) (BkWh) (BkWh) (QUADS)

1968 . . . . . . . . . . . . . . . . . 10.6 18.5 556.7 12.5 225.9 56.7

1971 . . . . . . . . . . . . . . . . . 11.2 20.2 560.9 38.1 269.5 61.2

1974 . . . . . . . . . . . . . . . . . 10.5 20.7 610.0 114.0 304.2 60.8

1977 . . . . . . . . . . . . . . . . . 9.9 19.2 697.2 250.9 223.6 60.1

1980 . . . . . . . . . . . . . . . . . 10.2 19.4 829.7 251.1 279.2 64.7

1983 . . . . . . . . . . . . . . . . . 10.3 16.0 784.9 293.7 332.1 61.2

SOURCE: Energy Information Administration, 1983 Annual Energy Review, DOE/EIA-0384 (83), Washington, DC, April 1984.

fuels was about 250 percent between 1972 and

1983. In the same period, energy use per unit of

gross national product dropped more than 22 percent. In the industrial sector, energy demand declined by 15.5 percent as a result of increased

energy efficiency in various industrial processes and

a shift to less energy-intensive products. In the residential and commercial sectors, energy demand remained nearly constant due to building insulation

efforts and reduced heating and cooling levels. In

the transportation sector, driving mileage has been

reduced, and fuel consumption has become more

efficient since the Corporate Average Fuel Economy (CAFE) standards were put in place.

Today, a combination of stable energy prices and

recovery from the 1982-83 economic recession has

caused demand to grow once again. Total energy

demand in 1984 increased about 7 percent over

1983. Most of the increase is probably to restore

demand capacity lost during the recession. There

are indications, however, that fuel-use efficiency

may be dropping. Driving mileage is up and

automobile manufacturers are producing and selling more cars with lower fuel economy. Just as

higher prices prompted fuel conservation, it appears

that lower petroleum prices may now be encouraging greater energy use.

There is also less incentive to switch from oil and

gas to alternative fuel sources. After the oil and gas

price increases of the 1970s, demand for alternative fuels grew. Electric utilities, in particular, made

greater use of coal and nuclear power in place of

oil and natural gas. However, low oil and gas prices

have now reduced the economic advantage of using

coal, and the future of nuclear power is limited

unless changes are made in the technology, management, and regulation of the industry. Low oil

prices have halted the development of synthetic fuels

made from more abundant resources (e. g., coal,

oil shale, heavy oils, tar sands). Similarly, the high

capital costs of converting direct renewable energy

sources (e. g., solar, wind, wood) has severely

limited their potential for replacing oil and gas.

Energy forecasts indicate that overall U.S. energy

demand will grow modestly to the end of the century and that oil will remain the largest single

energy source. Projections by the Department of

Energy (DOE) and the Gas Research Institute

(GRI) show energy consumption in the United

States growing by about 1 percent per year—less

than half the expected growth rate of the gross national product (see table 2-2). The percentage of

oil used in relation to total energy use is forecast

to be about 35 percent in 2000 as compared to 42
Ch. 2—The Role of Offshore Resources . 23

Table 2-2.—U.S. Energy Demand and Supply Forecasts to 2000

Demand Domestic supply Imports

Energy source GRI DOE GRI DOE GRI DOE

Oil and NGL (MMBD) . . . . . . . . . 16.7 15.2 9.2 8.1 7.5 7.1

Natural gas (TCF). . . . . . . . . . . . 19.0 18.7 15.9 15.9 3.8 2.8

Coal (MMT) . . . . . . . . . . . . . . . . . 1,345.0 1,190.0 — — —

Nuclear (BkWh) . . . . . . . . . . . . . 600.0

—

700.0 —

Hydro (BkWh) . . . . . . . . . . . . . . . 375.0 375.0 – - -

Other (Quads) . . . . . . . . . . . . . . . 2.9 3.3 — – – –

Total (Quads) . . . . . . . . . . . . . 93.3 90.9

SOURCES: 1984 GRI Baseline Projection of U S Energy Supply and Demand, 1983-2000, Gas Research Institute, Chicago, IL,

October 1984; U.S. Department of Energy, Energy Projections to the Year 2010, DOE/PE0029/2. Washington. DC,

October 1983

percent today. This decline does not represent any

significant replacement of oil, but rather indicates

that growth in the electric utility sector will continue to be accommodated partly by coal and nuclear power.

Energy Supply Trends

Despite the large oil and gas price increases of

the 1970s, domestic energy production remained

virtually level over the past decade (see table 2-1 ).

Growth in the production of coal and nuclear power

offset declines in domestic oil and natural gas production, If the contribution of Alaskan crude oil

production is removed, domestic oil production declined more than 18 percent between 1974 and

1983. The slight increase in domestic oil production since 1980 is due entirely to production from

the Prudhoe Bay Field on Alaska’s North Slope.

Domestic oil and gas reserves have declined even

more rapidly than production, despite enormous

increases in resource exploration and development

since 1973, and particularly since 1980. According to DOE, proven reserves of economically recoverable oil dropped from 47 billion barrels in

1970 to 35 billion barrels in 1984,

As a result of the recent increase in energy demand, however, domestic energy production increased in 1984 as compared to 1983. Crude oil production grew slightly with increases in Alaskan

production, and natural gas output was about 11

percent ahead of 1983. Coal production, which declined between 1981 and 1983, was up sharply as

electricity demand rebounded from the recession.

Similarly, the production of nuclear-generated electricity was expanded in 1984, as new power plants

came on line.

Oil import levels have increased as growth in domestic demand has outpaced domestic oil production. Oil imports decreased after the oil embargo

and price increase of 1973, but shortly thereafter

grew to an all time high of 9.3 million barrels per

day in 1977. Over the next 2 years, Alaskan oil

began to flow in significant quantities and U.S. imports of petroleum declined slightly. A second oil

price rise in 1979 and cumulative conservation efforts led to declining imports and a record oil import low of 4.9 million barrels per day in 1983.

However, in 1984, oil imports once again started

to climb and increased about 7 percent over 1983,

accounting for about one-third of U.S. petroleum

requirements.

The DOE and GRI energy forecasts indicate a

continuing decline in the production of domestic

oil and natural gas to the year 2000 (see table 2-

2). In both forecasts, oil and gas imports are expected to increase substantially, to between 7.1 and

7.5 million barrels of oil per day and 2.8 and 3.8

trillion cubic feet (Tcf) of natural gas per day. There

are indications, however, that even the DOE and

GRI projections maybe optimistic and that imports

may reach higher levels. Continued low energy

prices may lead to greater fuel usage, reduced conservation efforts, and limited replacement of oil by

alternative fuels. There are also uncertainties about

natural gas supplies and the possibility that price

controls and a failure to develop unconventional

sources may promote substitution of oil for natural gas.

38-749 0 - 85 - 2
24 . Oil and Gas Technologies for the Arctic and Deepwater

In comparison with the DOE projection of 8.1

million barrels per day and the GRI projection of

9.2 million barrels per day, studies by the Office

of Technology Assessment (OTA)1 and the Congressional Research Service (CRS)2 forecast even

greater declines in domestic production of crude

oil. OTA projected that domestic oil and natural

gas liquids production would decline to 4 to 7 million barrels per day by 2000. CRS was less pessimistic, but still estimated a decline in production

to 7.3 to 8.5 million barrels per day. These production levels indicate that oil imports may range

from 7 to as high as 10 million barrels per day in

2000, contributing to high trade deficits and decreases in energy and economic security.

‘U. S. Congress, OffIce of Technology Assessment, World Petroleum Avaifabifity: 1980-2000 (Washington, DC: U.S. Government

Printing Office, October 1980).

‘Congressional Research Service, ‘‘Domestic Crude Oil Production Projected to the Year 2000 on the Basis of Resource Capability’

Uuly 1984).

Current energy forecasts underline the importance of the oil and gas resources of the U.S. Outer

Continental Shelf (OCS) and the Exclusive Economic Zone (EEZ). Since domestic reserves have

been dropping over the last several years, an increasing percentage of our domestic oil production

must come from oil reserves as yet undiscovered.

Widespread exploration and development of the

lower 48 States make large field discoveries in onshore areas of the United States, outside Alaska,

somewhat doubtful. In contrast to the overall

energy reserve status in the United States, estimated

recoverable oil and gas reserves in Federal offshore

areas have increased steadily in recent years. However, only a small percentage of total U.S. offshore

area has been explored. Offshore resources, particularly those of the unexplored deepwater and

Arctic frontier regions, offer the best hope for

limiting future U.S. energy import dependence.

RESOURCE PROJECTION PROBLEMS

The U.S. Geological Survey (USGS) estimated

in 1981 that 26 to 41 percent of the oil and 25 to

30 percent of the natural gas that is undiscovered

and recoverable in the United States would be

found offshore within the EEZ. However, that estimate is by no means certain. Published projections

of oil and gas reserves and resources are generally

incomplete and lack accuracy. There are several

reasons for this.

●

●

●

Projections of oil and gas resources are generally based on averages or aggregated values

from independent analyses and expert opinions, which results in widely ranging estimates

that are subject to large errors.

Until an area is sufficiently explored, resource

projections are largely inferred from indirect

geological information, e.g., seismic records,

gravity and magnetic data, and geomorphology, and Continental Offshore Stratigraphic

Test (COST) wells.

Information on oil and gas reserves in existing

fields and assessments of resource potential for

frontier regions are considered by the petroleum industry to be proprietary and highly

sensitive, therefore it is unlikely that precise,

detailed information on recoverable reserves

and resources from individual firms will be

available to Congress, the Department of the

Interior, or the public.

The amount of recoverable oil and gas that remains to be discovered beyond the currently estimated reserves will be produced from two sources:

1) extension of known fields through new developments in drilling technology and new techniques

for increasing (enhancing) oil and gas recovery from

old fields; and 2) new discoveries in unexplored

frontier regions and undeveloped areas of proven

regions.

Over three-fourths of the oil discovered thus far

in the United States is located in ‘ ‘giant’ fields of

100 million barrels or more—e.g., the Gulf of Mexico and Prudhoe Bay, Alaska. About 8 percent of

the discovered oil is found in fields smaller than 10

million barrels. Therefore, the reliability of discoverable resource projections for the EEZ will depend on how well geologists and petroleum engineers can predict the existence of giant fields
Ch. 2—The Role of Offshore Resources ● 2 5

offshore, and how accurately they can evaluate the

extent of the recoverable resources that lie therein. 3

When estimates go beyond proved reserves, accuracy rapidly deteriorates with errors of perhaps

50 percent or more.

Comparability Among Estimates

Although resource estimates may be useful to

Congress in considering national policies, their

value lies primarily in indicating the relative reserve

potential from the likely petroleum-bearing basins

rather than as estimates of absolute quantities of

oil and gas available offshore. The primary use of

published resource assessments is for general information.

Published sources have little technical use in either the administration of the offshore leasing program by the Department of the Interior or the formulation of industry leasing strategies. Firms make

large investments to develop detailed information

on resource prospects in the individual basins of

the OCS for the purpose of corporate planning.

Good resource information is a major competitive

factor among oil and gas firms bidding on offshore

tracts, and therefore is considered proprietary.

However, it is unlikely that even the industry has

accurate estimates.

Four independent assessments of the oil and gas

resources of the OCS are currently available to the

public:

1.

2.

3.

4.

It

USGS Circular 860 (1981): Estimates of Undiscovered Recoverable Conventional Resources of Oil and Gas in the United States.

National Petroleum Council (1981): U.S.

Arctic Oil and Gas.

Rand Corporation (1981): The Discovery of

Significant Oil and Gas Fields in the United

States.

Potential Gas Committee (1983): Potential

Supply of Natural Gas in the United States.

is difficult to make area-by-area comparisons

of the estimates of undiscovered oil and gas published in the four resource assessments. The diffi3M. King Hubbert, ‘ ‘Techniques of Prediction as Applied to the

Production of Oil and Gas, ’ Oil and Gas Supply AZodeIing, S. I.

Grass (cd, ) (Washington, DC: National Bureau of Standards Special

Publication 631, May 1982).

culty in comparing these estimates arises from: 1 )

differences in methodologies used in deriving the

resource estimates; 2) differences in reporting statistical data, e.g., errors, ranges, and probabilities;

3) inconsistencies in definitions of resources and reserves; 4) differences in technical and economic

assumptions in deriving recoverable resource

values; 5) the inclusion or exclusion of unconventional resources, e.g., low permeability formations;

6) lack of agreement on boundaries (water depth,

international boundaries, etc. ) of the resource area

being estimated; and the fact that 7) the professional

perspectives of the estimators may influence the

probabilities assigned to the estimates; and 8) the

conditions and assumptions on which the estimates

are based are seldom specified in sufficient detail.

Furthermore, several government agencies with

varying missions often report resource statistics in

different ways to suit their particular purpose. This

may result in inconsistencies among government

reports and add to the confusion.

Reliability of Estimates

It is difficult to determine the reliability and

credibility of the various resource assessments for

many of the same reasons. In addition: 1 ) details

of the methods used for estimating resources are

not published; 2) data bases and geological information used for the assessments are often considered to be proprietary and confidential; and 3) the

process used for deriving resource estimates relies

largely on the ‘ ‘expert opinion’ of geologists and

petroleum engineers.

While it is not entirely accurate to characterize

the collective (averaged) judgment of resource experts as ‘‘subjective, the use of ‘opinions’ in lieu

of science-based hypotheses and experimental data

prevent these expert-derived estimates from being

considered wholly ‘ ‘objective.

There can probably, therefore, be no determination as to which resource assessment is the ‘ ‘best’

or ‘ ‘most accurate. In any oil and gas resource

assessment, the quantitative volumes should be considered speculative and may or may not accurately

reflect the volumes of oil and gas that will or could

be ultimately discovered in any single basin or region. Many of the basins with large estimated po-
26 • Oil and Gas Technologies for the Arctic and Deepwater

tential may prove unproductive; some may yield

petroleum recoveries exceeding even the most optimistic estimates. Estimates are made recognizing

the uncertainties involved, but are based on the current level of knowledge.

Interpretation of Estimates

Aside from problems of comparability and reliability, there are problems associated with interpreting various estimates. Statistics for potential oil

and gas resources are reported using a lexicon that

may confuse and befuddle those unfamiliar with

petroleum resources. Petroleum reserves and resources are frequently explained, as shown in table

2-3.

In addition, crude oil and natural gas resources

are often reported in combined units of ‘‘barrels

of oil equivalent (BOE). This measure is calculated by converting estimated natural gas and natural gas liquids to oil (product) equivalents based

on comparable energy (Btu) units. While BOE resource statistics provide a common unit of measure which is easily communicated and comparable, it can be misleading where natural gas

production is not immediately planned.

For example, the National Petroleum Council

(NPC) study reports a risked mean of 31 billion

BOE in Arctic offshore basins. However, only 57

percent (18 billion barrels) is oil, and the balance

is gas and natural gas liquids, In remote regions

of the Arctic and in many deepwater areas, natuTable 2-3.—Definitions of Reserves and Resources

Past

production

Well

capacity

Delivery system

Present price and

technology limit

Limit of currently

Discovered Undiscovered

Reserves: Oil and gas which has already been found and is considered producible under current prices using currently available technology.

Proved Reserves: Immediately producible portions of the oil and gas reserves that will flow from wells in developed reservoirs and the quantity

of which can be estimated accurately.

Unproved Reserves: Oil and gas that has been discovered but cannot be estimated with as great accuracy and may require additional drilling

and development.

Subeconomic Resources: Oil and gas that has been discovered, but in the judgment of the operators cannot be produced under current prices

with existing technology. Subeconomic resources are sometimes divided into two portions: First, the unrecoverable, high-cost portion of oil and

gas currently left behind in producing reservoirs. Second, oil and gas in other reservoirs that have been found but are not now producing or have

been abandoned because they would cost too much to produce due to size or other problems.

Economic and Subeconomic Resources Needing Further Exploration: Oil and gas that remains to be discovered. Exploratory drilling has not

proceeded to a point where there is physical evidence of the actual presence of oil and gas. Only expectation exists, and estimates of undiscovered oil and gas are based solely upon geologic and engineering extrapolations.

Other Occurrences: Oil and gas left behind that is not expected under any future circumstances to be worth the effort or cost of production, as

well as deposits which are considered too small to find or to produce if found. Other forms of petroleum may be included in this category, e.g., oil

shale, tar sands, heavy oils, etc.

SOURCE: John J. Schanz, Jr., “Oil and Gas Resources — Welcome to Uncertainty,” In Resources (Washington, D. C.: Resources for the Future, March 1978).
Ch. 2—The Role of Offshore Resources ● 2 7

ral gas production is not now economically feasible. Therefore, to combine oil and natural gas into

a single measure can be misleading to those not familiar with the distinction between oil equivalent

resource statistics (which may include unmarketable

natural gas) and crude oil resource statistics.

Other Factors

Estimates of potentially recoverable resources will

change in response to: 1) oil prices, production

costs, and economic conditions; 2) new technological developments that enable more efficient recovery of oil and gas; and 3) new knowledge about resources gained from exploration. For example, the

USGS revised its 1975 resource estimates in 1981

to reflect changes in technology (resource estimates

were included down to water depths of 7,870 feet

in Alaska and 8,200 feet elsewhere); changing economic conditions; and more geological information

gained from exploration. As a result, estimates of

offshore oil potential decreased slightly even with

the additions from the Continental Slope. Offshore

oil resources were estimated at 17 to 49 billion barrels in 1975 and decreased to 17 to 44 billion barrels in 1981. Estimates of natural gas increased significantly from 42 to 81 Tcf in 1975 to 72 to 167

Tcf in 1981.

U.S. EXCLUSIVE ECONOMIC ZONE

The 200-nautical mile U.S. Exclusive Economic

Zone encompasses 1.9 billion acres adjacent to the

coasts of the continental United States. * Approximately 1.3 billion acres of the EEZ is underlain

by the Continental Shelf, the extension of the continental land mass that was flooded when the oceans

rose. Almost half of the U.S. Continental Shelf (815

million acres) lies adjacent to Alaska.

Along most of the U.S. coastline, the Continental

Shelf gradually slopes downward (see figure 2-1)

until it breaks abruptly at the edge of the Continental Slope where it plunges steeply toward the deep

ocean floor. At the transition zone between the deep

ocean and the base of the Continental Slope is the

Continental Rise, which rises gradually from the

Abyssal Plain.5

Water depths over the Continental Shelf range

to more than 600 feet at the edge of the Continental Slope. Undersea canyons have been cut deeply

into the Continental Shelf at the mouths of major

rivers, such as the Hudson, the Mississippi, and

off the mouth of the Chesapeake Bay, The Con4Robert W’. Smith, “The Maritime Boundaries of the United

States, Geographical Review (October 1981), p. 395.

50nc should distinguish between the ‘‘geologic Cent inental Shelf

and the ‘ ‘legal (;ontinenta] Shell. The former is defined by scientific

prim iplc of landfhrm, pos]tion and Seologica] orig~n The latter is a

construct of law imposed by the need for regulating international affairs among coastal nations under the I.aw of the Sea and international agreements.

tinental Slope plunges to depths over 8,250 feet

before merging with the Continental Rise. Depths

over the Continental Rise range between 11,500

and 20,000 feet.

Much of the Continental Shelf was formed under

prehistoric conditions that favored the evolution of

petroleum —accumulated organic-rich sediments,

extremely high pressures from overlying materials,

and high subsurface temperatures. Thirty-four

sedimentary basins with oil and gas potential have

been identified in the U.S. Continental Shelf. The

Department of the Interior recognizes 26 offshore

areas with commercial oil and gas potential for purposes of leasing in the OCS. Sediments in some

of these basins reach thicknesses of more than

43,000 feet. In addition, portions of the Continental

Slope and the Continental Rise are underlain by

a great wedge of sediments and ancient buried reefs

that may contain petroleum deposits. Deep oceanic

basins, particularly the Gulf of Mexico, may also

contain petroleum, but because of the water depths

much less is known about these prospects. G

The breadth of the U.S. Continental Margin

(Shelf, Slope, and Rise) varies considerably, ranging from a few miles along steep segments of the

Pacific Coast to perhaps 500 miles adjacent to parts

of Alaska. The establishment of the U.S. EEZ in

6H, D. Hedberg, U. D. Moody, and R. M. Hedberg, ‘‘Petroleum

Prospects of the Deep Offshore, AAPG Bulletin 63(3):286-300.
28 . Oil and Gas Technologies for the Arctic and Deepwater

Figure 2-1.— Profile of Physiographic Features of the Geological Continental

Margin of the U.S.

Exclusive economic zone

Territorial Contiguous

Sea zone

3 nm 15 nm 200 nm

and

Geological Continental Shelf

I I

I I

I

I Continental crust Oceanic crust

SOURCE: Robert D. Hodgson and Robert W. Smith, “The Informal Single Negotiating Text (Committee II): A Geographical

Perspective, ” Ocean Development and International Law Journal 3:3 -

1983 added about 46 percent more ocean area to

that already under the jurisdiction of the United

States for the purpose of exploring and developing

the living and nonliving resources of the sea. The

net effect was to add approximately 600 million

acres of seabed to that already claimed for exclusive

resource development by the United States offshore

the 50 States.

Oil Resources

The two most widely quoted assessments of offshore oil resources are USGS Circular 860 and the

NPC study. The NPC study dealt only with Arctic resources and, in general, there is some agreement between the two assessments on Arctic oil

potential. Both assessments used an averaging technique (modified Delphi) to aggregate expert opinion of estimates based on ‘‘geological analogies,

i.e. , the prediction of the occurrence of oil in an

unexplored area based on similarities between that

area and one in which oil is known to exist. 7 However, because the statistical treatment of the data

7JOSePh p Riva, Jr., ‘ ‘The Occurrence of Petroleum, World Petroleum Resources and Reserves (Boulder, CO: Westview Press,

1983)

is different in the two assessments, the estimates

can not be directly compared.

Resource estimates from USGS Circular 860 are

the most widely cited and have been used in the

past by the Minerals Management Service (MMS)

in general lease sale planning and for public information (see table 2-4). Total offshore oil resources

according to the USGS study are about 30 billion

barrels, one-third of which is in water depths greater

than 660 feet (see figure 2-2). However, as a result of an institutional reorganization, the MMS

no longer uses USGS estimates in lease sale planning. Henceforth, MMS will be responsible for developing all offshore resource estimates and has

recently revised the estimates of offshore oil and

gas (see box). a

Deepwater Oil Resources

According to the 1981 USGS estimates, about

40 percent of the recoverable oil expected to be

found in the Continental Slope beneath water

depths greater than 660 feet is in the Atlantic

‘Minerals Management Service, Estimatc=s of ~Tndiscot’ered Oil and

Gas Resources for the Outer Continental Shelf (personal correspondence, Feb. 4, 1985),
Ch. 2—The Role of Offshore Resources . 29

Table 2-4.—Offshore Resource Estimates Ocean. Nearly 25 percent of the projected deepwater oil resource is in the Pacific Ocean off California, Oregon, and Washington, and a like

amount is expected to be found in deepwater regions of the Gulf of Mexico. Deepwater resources

in Alaska are estimated to be about 1.1 billion

barrels.

The USGS did not include recoverable oil and

gas that may occur in deep ocean regions, e.g., the

Gulf of Mexico Oceanic Basin or in extremely deep

water in the Pacific Ocean, in its 1981 assessment.

It is possible, therefore, that one-third to one-half

of U.S. offshore oil resources lie under waters ranging in depth from 660 feet to more than 12,000 feet

when the potential of the oceanic basins within the

OCS is included.

Oil

Water depth (billion Gas

(meters) barrels) (TCF)

Alaska

Norton Basin . . . . . . . . . . . . . . . . . . . .

St. George Basin ., . . . . . . . . . . . . . . .

Navarin Basin . . . . . . . . . . . . . . .

(0-200)

(0-200)

(0-200)

(200-2500)

(0-200)

(0-200)

(200-2500)

(0-200)

(200-2500)

0.2

0.4

0.9

0.1

0.2

7.8

0.8

3.6

0.2

2.8

2.4

1.2

0.2

1.0

1.4

0.9

1.0

0.1

0.2

0,4

1.0

0.8

2.3

0

0.9

1.2

2.5

5.6

0

1.0

39.3

4.3

13.8

1.1

42.9

26.1

2.4

0.4

1.3

2.6

1.0

1.3

0.6

0.8

2.4

3.2

5.6

8.6

0.2

3.6

North Aleutian Basin . . . . . . . . . . . . .

Beaufort Sea . . . . . . . . . . . . . . . . . . . .

Chukchi Sea . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico

Central and Western Gulf of Mexico (0-200)

(200-2500)

(0-200)

(200-2500)

Eastern Gulf of Mexico. . . . . . . . . .

Pacific

Southern California . . . . . . . . . . . (0-200)

(200-2500)

(0-200)

(200-2500)

(0-200)

(200-2500)

Central and Northern California . . . .

Washington and Oregon . . . . . . .

Arctic Oil Resources

Resource estimates indicate that Alaska may contain about one-half of the recoverable oil (offshore

and onshore) remaining in the United States. The

NPC assessment estimates the mean undiscovered

recoverable resource in the Arctic to be 18 billion

Atlantic

North Atlantic ... . . . . . . . . . . . . . . (0-200)

(200-2500)

(0-200)

(200-2500)

(0-200)

(200-2500)

Mid-Atlantic . . . . . . . . . . . . . . . . . . . .

South Atlantic . . . . . . . . . . . . . . . . . . .

SOURCE: Minerals Management Service, OCS Summary Reports, 1983, (based

on uSGS Cicular 860, 1981).

Figure 2-2.—Oil Resources by Planning Area

14 –

13 -

12 -

11 -

-

-

-

—

0

5 -

4 -

3 -

2 -

1 -

0

0-660 feet

660-8,200 feet

.-

W

c

SOURCE. Minerals Management Service, OCS Summary Reports, 1983.

Ch. 2—The Role of Offshore Resources Ž 31

Revised Offshore oil and Gas Resource Estimates

Oil (billion barrels) Gas (trillion cubic feet)

Planning area 1981 1985 ‘/0 change 1981 1985 % change

Alaska:

Beaufort Sea . . . . . . . . . . . . . . . . . . . . . . . . . .7.8

Navarin Basin . . . . . . . . . . . . . . . . . . . . . . . . . 1.0

Chukchi Sea . . . . . . . . . . . . . . . . . . . . . . . . . .1.6

St. George Basin . . . . . . . . . . . . . . . . . . . . . . 0.4

Norton Basin . . . . . . . . . . . . . . . . . . . . . . . . . 0.2

Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total Alaska 12.2

Atlantic:

North Atlantic. . . . . . . . . . . . . . . . . . . . . . . . . 1.4

Mid-Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . .

South Atlantic . . . . . . . . . . . . . . . . . . . . . . . . 0.9

Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -

Total Atlantic 5.4

Gulf of Mexico:

Western Gulf . . . . . . . . . . . . . . . . . . . . . . . . . 5.2

Central Gulf . . . . . . . . . . . . . . . . . . . . . . . . . . —

Eastern Gulf . . . . . . . . . . . . . . . . . . . . . . . . . .

Total Gulf of Mexico

Pacific:

Northern California . . . . . . . . . . . . . . . . . . . . 0.5

Southern CaIifornia . . . . . . . . . . . . . . . . . . . . 2.4

Central California . . . . . . . . . . . . . . . . . . . . . . -

Washington and Oregon . . . . . . . . . . . . . . . . 0.3

Total Pacific

Total Offshore 27.0

0.89

0.54

0.37

0,00

0.11

3.30

0.11

0.35

0.22

0.68

3.72

0.41

6.03

0.25

0.36

0.04

2.19

12.2

39.3

5.6

13.8

2.5

2.2

-73 84.6

5.6

14.2

3.6

0.3

-87 23.7

85.4

2.8

- 3 88.2

3.9

1.4

-31

-55 162.7

3.83

3.02

3.47

0.43

1.42

13.85 –78

2.14

6.02

4.04

0.11

12.31 -48

28.76

30.69

2.19

59.84 - 1 3

1.12

2.42

0.51

0.85

4.70 -24

90.5 - 4 4

SOURCE: U.S. ~sdodd Suwey, Olmdm=, Sefln?atee of UndieoovefsdRtoow3mbte Cwwntfond Resoumee of Of/ end C3ee /rr the United States (lWI).

Minera!8 MenaownentServt~ Eethnetee of LJndkoverud0// and G- Resources &the Outer Cent/nentu/ Shelf (personal correspondence,

Feb. 4, 1S86).

barrels while USGS estimates a resource base of

11 billion barrels of crude oil (see table 2-5).

In terms of undiscovered potentially recoverable

oil (based on 1981 technology), according to the

NPC, the Beaufort Sea has the greatest resource

potential in Alaska with 9.5 billion barrels (USGS

estimated 7.8 billion barrels) including both the

Continental Shelf and the Slope (see figure 2-3).

The Navarin Basin ranks second in resource potential with 2.4 billion barrels (USGS estimated 0.9

billion barrels); third is the Central Chukchi Shelf

(NPC estimated 1.7 billion barrels, USGS estimated 0.6 billion barrels); followed by the North

Chukchi Shelf and Slope (NPC estimated 1.5 billion barrels, USGS estimated 0.8 billion barrels);

and St. George Basin with 1.2 billion barrels

(USGS estimated 0.4 billion barrels).

Table 2-5.—Comparison of Estimates of Alaskan Offshore Oil Resources

Oil Resources (billion barrels)

NPC (risked mean) USGS (mean)

Water depth (meters) 0-200 M 200-2500 M 0-200 M 200-2500 M

Beaufort . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.2 0.8

Navarin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 0.1 0.8 0.1

Central Chukchi . . . . . . . . . . . . . . . . . . . . 1.7 — 0.6

St. George . . . . . . . . . . . . . . . . . . . . . . . . . 1.2

—

0.4

N. Chukchi . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 0.3 0.8 0.2

Bristol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.6 — 0.2

Norton . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.3

—

—

Hope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

—

0.2 0.0

Zhemchug . . . . . . . . . . . . . . . . . . . . . . . . . 0.1 0.0 0.0 0.0

Aleutian . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 0.0

Umnak Plateau . . . . . . . . . . . . . . . . . . . . . 0.0 —

St. Matthew - Hall . . . . . . . . . . . . . . . . . . . 0.0

—

— 0.0 —

SOURCES: National Petroleum Council, US. Arcf/c 0// and Gas, 1981; U.S Geological Survey, Circular 880, 1981
32 . Oil and Gas Technologies for the Arctic and Deepwater

Figure 2-3.—Oil Resources in Alaska Planning Areas

8

7

Legend:

0-660 feet

660-8,200 feet

SOURCE: Minerals Management Service, OCS Summary Reports, 1983.

Natural Gas Resources

The USGS estimates that the OCS contains

about 172 Tcf of natural gas. The Potential Gas

Committee (PGC), an industry-staffed group operating through the Colorado School of Mines,

evaluated the natural gas resources that are expected to occur up to a maximum depth of 3,280

feet. It estimated that the OCS to that depth “probably’ contains 35 Tcf of natural gas. (The PGC

“probable” estimate is a modal estimate and may

be comparable to the statistical mean.) Because the

PGC assumed the economic limits of gas production to be about 3,000 feet on the Continental

Slope, the USGS and PGC resource estimates for

natural gas cannot be compared directly. It appears,

however, that the PGC estimates are considerably

more conservative than those of the USGS. Although the PGC has historically been optimistic

about U.S. onshore natural gas resources, it estimates a probable potential offshore supply of 35

Tcf, a possible supply of 76 Tcf, and a speculative

supply of 122 Tcf. Even its most optimistic estimate falls short of the USGS mean estimate of 172

Tcf. In waters 660 feet or less, the PGC estimates

the probable occurrence of 32 Tcf of natural gas,

while the USGS estimate is about 120 Tcf.

As more geological information is gained from

exploratory drilling in frontier regions, natural gas

estimates are revised upwards. In 1975, the USGS

estimated that the Continental Shelf contained between 42 and 81 Tcf (at the 95 and 5 percent probability levels respectively) of natural gas. When

revised in 1981, these estimates were increased to

between 72 and 167 Tcf respectively. The upward

adjustment resulted from indications of the presence of more gas and less crude oil in exploratory

wells in the Atlantic, Gulf of Mexico, and Pacific

offshore regions.

The Gulf of Mexico and the Alaskan Arctic are

expected to contain nearly 82 percent of the natural gas in the OCS (72 and 70 Tcf respectively),

while the Atlantic is estimated to contain 24 Tcf

and the Pacific only 8 Tcf (see figure 2-4).

Deepwater Natural Gas Resources

Approximately 31 percent of the natural gas in

the OCS is expected to occur in water depths between 660 and 8,200 feet. About half of this (27

Tcf) is in the Gulf of Mexico, while 16 Tcf is in

the Atlantic, 6 Tcf in the Arctic, and 5 Tcf in the

Pacific.

Arctic Natural Gas Resources

The USGS estimates that 58 Tcf of natural gas

may occur in the Arctic. The NPC estimates that

69 Tcf of natural gas may be expected to occur in

that region (see table 2-6). The NPC estimate includes natural gas liquids while the USGS estimate

does not. If natural gas liquids (2.5 billion barrels)

are removed from the NPC estimate, the two assessments of Arctic natural gas potential agree within

20 percent.

Over 90 percent of Alaskan offshore gas lies in

depths of less than 660 feet. The remote far north-
Ch. 2—The Role of Offshore Resources Ž 33

Figure 2-4.—Natural Gas Resources by Planning ern regions of the Beau fort and Chukchi Seas are

expected to contain about 78 percent (39 Tcf and

14 Tcf respectively) of the natural gas in the Arctic while the Navarin Basin contains 6 Tcf, St.

George Basin 3 Tcf, and the Norton and North

Aleutian Basins about 1 Tcf each (see figure 2-5).

Area

Legend:

0-660 feet

660-8,200 feet

Resources by Lease Sale

Planning Areas

The EEZ is subdivided into 26 planning areas

by the Department of the Interior for leasing purposes (see figure 2-6). Each planning area encompasses one or more sedimentary basins that have

potential for petroleum resources. Nearly 1.1 billion acres of the total 1.9 billion acres within the

OCS are included in the planning areas. However,

only about 17 percent of the acreage (179 million

acres) in the planning areas is considered to be

underlain by ‘‘promising geological structures’

with significant potential for accumulated oil and

natural gas (see table 2-7).

Over half of the acreage(110 million acres) considered to have promising geological structures for

oil and gas is adjacent to Alaska. About 15 percent

(27 million acres) of the area over promising structures is in planning areas located in the Atlantic

Ocean, where exploration activities have failed to

confirm the presence of commercial quantities of

oil or gas. A similar proportion of the promising

geology (25 million acres) lies in the Gulf of Mexico planning areas which historically have produced

large quantities of oil and natural gas.

0

SOURCE: Minerals Management Service, OCS Summary Reports, 1983

Table 2-6.—Comparison of Estimates of Alaskan Offshore Gas Resources

Gas Resources (trillion cubic feet)

NPC (risked mean) USGS (mean)

Water depth (meters) 0-200 M 200-2500 M 0-200 M 200-2500 M

Beaufort . . . . . . . . . . . . . . . . . . . . . . . . . . . 26.3

Navarin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5

Central Chukchi . . . . . . . . . . . . . . . . . . . . 9.0

St. George . . . . . . . . . . . . . . . . . . . . . . . . . 5.6

N. Chukchi . . . . . . . . . . . . . . . . . . . . . . . . . 5.0

Norton . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4

Hope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1

Bristol. ., . . . . . . . . . . . . . . . . . . . . . . . . . . 0.3

St. Matthew - Hall . . . . . . . . . . . . . . . . . . . <1.0

Zhemchug . . . . . . . . . . . . . . . . . . . . . . . . . <1.0

Umnak ., . . . . . . . . . . . . . . . . . . . . . . . . . . <1.0

Aleutian . . . . . . . . . . . . . . . . . . . . . . . . . . . <1.0

6.7

<1.0

35.0

5.2

3.0

2.3

3.4

1.2

4.3

0.4

—

—

1.1

—

1.7 —

— —

1.0

0.0

0.1

0.0

0.0

—

— —

0.0

—

0.0

<1.0 —

<1.0

SOURCES: National Petroleum Council, U S Arctic 0il and Gas, 1981, U.S. Geological Survey, Circular 860, 1981
34 ● Oil and Gas Technologies for the Arctic and Deepwater

Figure 2-5.—Natural Gas Resources in Alaska

Planning Areas

Legend:

0-660 feet

660-8,200 feet

SOURCE: Minerals Management Service, OCS Summary Reports, 1983.

Gulf of Mexico

The Gulf of Mexico region is the most extensively

developed offshore region of the United States. It

currently produces over 90 percent of total U.S.

offshore oil production and virtually all of the offshore natural gas. The region consists of three lease

planning areas: Western Gulf, Central Gulf, and

Eastern Gulf. Projections indicate that the Gulf of

Mexico will continue to dominate offshore oil and

gas production as the industry expands its exploration into the deepwater frontier areas of the Gulf

Oceanic Basin.

Exploration and development is most advanced

in the Central Gulf of Mexico planning area, which

lies south of the States of Louisiana and Mississippi.

Table 2.7.—Estimates of Offshore Acreage With

Hydrocarbon Potential (millions of acres)

Geological Hydrocarbon

Planning area structures* potential* ●

North Atlantic . . . . . . . . . . . . . . . . . .

South Atlantic ., . . . . . . . . . . . . . . . . .

Eastern Gulf of Mexico . . . . . . . . . . .

Central Gulf of Mexico. . . . . . . . . . . .

Western Gulf of Mexico . . . . . . . . . .

Southern California . . . . . . . . . . . . .

Central and Northern California . . . .

South Alaska (Gulf of Alaska,

Kodiak, Cook, Shumagin) . . . . . .

North Aleutian Basin . . . . . . . . . . .

St. George Basin ... . . . . . . . . . . . . .

Navarin Basin . . . . . . . . . . . . . . . . . .

Norton Basin . . . . . . . . . . . . . . . . .

Hope Basin . . . . . . . . . . . . . . . . . . . . .

Chukchi Sea . . . . . . . . . . . . . . . . . . . .

Beaufort Sea . . . . . . . . . . . . . . . . . . .

Total . . . . . . . . . . . . . . . . . . . . . . . .

17.3

9.4

6.0

9.4

9.3

9.9

7.5

2.0

3.2

29.2

16.0

7.5

8.0

14.0

30.6

179.3

26.0

63.2

58.0

46.0

35.0

12.0

N/A

148.4

12.4

35.0

28.9

8.9

N/A

29.7

19.1

522.6

‘Estimates of the acreage covered by promising geological structures.

Department of the Interior, Final Supplement to the Final Environmental

Statement, Five-Year Lease Schedule, 1982.

“ “Estimates of the acreage having a potential for the generation, migration,

and accumuIation of hydrocarbons. Minerals Management Service,

Resources Assessment Division, 1984.

Thus far, little oil and gas activity has taken place

in the Eastern Gulf of Mexico planning area adjacent to Alabama and Florida.

Resource estimates. The Central Gulf of Mexico planning area is estimated to contain 3.2 billion barrels of oil and 34 Tcf of natural gas, which

is more than half of the total undiscovered economically recoverable oil resources in the Gulf of Mexico region. The Western Gulf of Mexico planning

area is expected to be rich in natural gas (26 Tcf),

but contains only 2 billion barrels of oil. The Eastern Gulf of Mexico planning area is estimated to

contain 1.2 billion barrels of oil and only 1.6 Tcf

of natural gas. Remaining oil reserves in the Gulf

of Mexico region are estimated to be 3 billion barrels of oil and 40 Tcf of natural gas. g

Physical and geological characteristics. The Con

tinental Shelf in the Gulf of Mexico region slope:

gently seaward at an angle of less than one degree

It forms a broad plain of relatively shallow water

ranging in breadth from 12 miles off the alluvia

fan of the Mississippi River to as much as 140 mile

off the mouth of the Crystal River in Florida. Th

‘Minerals Management Service, Gulf of Mexico Summary Repo

(Washington, DC: U.S. Department of the Interior, September 1983

p. 8.
Ch. 2—The Role of Offshore Resources ● 3 5

Figure 2-6.—Minerals Management Service Lease Sale Planning Areas

Washington

Oregon

Northern

California

Central

California Mid-Atlantic

Southern

California South Atlantic

New Orleans

Straits

Gulf of Mexico

150° 158° 162 “ 168 “ 174° 180° 174° 166° 162° 156o 150° 144° 130° 112o 126° 120o

80°

55”

50°

45°

Beaufort Sea r-

,“

.

Aleutian Arc I

1 1 1 I 1 I

100° 174” 160° 1620 150° 150” 144° 130°

70“

65“

60°

55”

50°

NOTE: Maritime boundaries and limits depicted on the maps, and divisions shown between planning areas, are for initial planning purposes only.

SOURCE: Minerals Management Service.
36 ● Oil and Gas Technologies for the Arctic and Deepwater

Continental Slope is relatively steep, ranging between 2 and 45 degrees. Beyond the base of the

Continental Slope, the Abyssal Plain of the Gulf

of Mexico Oceanic Basin reach depths of up to

12,000 feet at the outer edge of the EEZ. Although

the Continental Shelf in the Gulf of Mexico region

is extensive, 42 to 68 percent of the acreage within

the Gulf of Mexico lease planning areas is in waters

deeper than 660 feet (see figure 2-7).

Geological conditions that may occur in the Gulf

of Mexico lease planning areas include unstable

sediments on the sea floor, active faults, shallow

gas accumulations, and underlying karst topography consisting of limestone caverns and voids in

the seafloor. The area off the Mississippi Delta and

along steeply sloping areas of the Continental Slope

may be subject to mass sediment movements.

Leasing and exploration. The Gulf of Mexico is

the most heavily explored and extensively developed offshore petroleum region in the world. The

region has been explored for more than 50 years

and has been producing oil and natural gas for more

than 35 years. Nearly 21,000 wells have been drilled

offshore in the Gulf of Mexico, most of them in the

Central Gulf of Mexico planning area.

While exploration in the historically productive

areas of the Central and Western Gulf of Mexico

planning areas continues at a high level, the offshore industry’s interest in deepwater tracts has also

increased. The deepest exploratory well in the Gulf

of Mexico was drilled in 1980 in the Mississippi

Canyon in 2,210 feet of water, and several other

wells have been drilled in waters ranging from 1,500

to 1,835 feet.

Several tracts leased in the Atwater Valley sector of the Central Gulf of Mexico planning area

are in waters of 3,500 feet and deeper, and one

block in the Port Isabel area of the Western Gulf

of Mexico is in 3,500 feet of water.10 Industry interest in deepwater tracts is centered on the area

referred to as the ‘‘flexure play, a sloping deepwater site that rapidly descends at the edge of the

Continental Shelf.

Development, production, and reserves. Crude

oil production from the Gulf of Mexico region was

IOData Offshore Services, Supplement to the Ocean COnsfrUCfJOn

Report (Houston, TX: Offshore Data Services, July 23, 1984).

about 310 million barrels in 1983, and natural gas

production was approximately 3.9 billion cubic feet.

Between 1972 and 1980, oil production in the Gulf

of Mexico declined each year (see figure 2-8). This

trend was reversed in 1981 and oil and condensate

production is now at pre-1977 levels. The rebound

in Gulf of Mexico oil production is considered to

bean anomaly, however, and oil production is expected to soon resume its previous decline. Gas production may have reached its peak in 1981 and is

also expected to begin a noticeable decline. At the

beginning of 1984, Gulf of Mexico oil reserves were

estimated at 3.4 billion barrels and natural gas at

43.7 Tcf.11

Atlantic

The Atlantic region, while one of the most

geologically studied oceanic regions in the world,

is considered to be a frontier region for oil and natural gas exploration. The region consists of four

lease planning areas: North Atlantic, Mid-Atlantic,

South Atlantic, and Florida Straits. There is no

commercial crude oil or natural gas production

from the Atlantic region, and no reserve estimates

are available.

Resource estimates. Over three-quarters of the

Atlantic region’s undiscovered economically recoverable crude oil resources (4. 2 billion barrels) and

about two-thirds of its natural gas (15.4 Tcf) lie in

water depths of 660 to 8,200 feet. Total undiscovered recoverable resources in the three lease

planning areas of the Atlantic region are estimated

to be 5.4 billion barrels of oil and 23.6 Tcf of natural gas.

Nearly 60 percent of the oil (3.1 billion barrels)

and natural gas (14.6 Tcf) within the entire Atlantic region is expected to occur in the Mid-Atlantic

planning area, between two-thirds and threequarters of it in water depths between 660 and

8,200 feet. The North Atlantic planning area is estimated to contain 1.4 billion barrels of crude oil and

5.6 Tcf of natural gas, while the South Atlantic area

is estimated to contain only 900 million barrels of

crude oil—all in waters ranging in depth from 660

to 8,250 feet—and 3.8 Tcf of natural gas.

1 IMiner~S Mma~ement service, Federaf OffShort statistics (Washington, DC: U.S. Department of the Interior, 1984).
Ch. 2—The Role of Offshore Resources • 37

0

*l- ”

0

&
38 . Oil and Gas Technologies for the Arctic and Deepwater

2

1

Figure 2-8.—Trends in Gulf of Mexico Oil and

Gas Production

1955 1960 1965 1970 1975 1980

Year

SOURCE: Minerals Management Service, Gulf of Mexico Summary Report,

1983.

Physical and geological characteristics. The Continental Shelf in the Atlantic region varies in width

from 14 miles off Cape Hatteras to 200 miles off

the coast of New England. From the break at the

edge of the Continental Shelf to the base of the Continental Slope, water depths plunge to between

6,560 and 9,840 feet. From the base of the Continental Slope, the Continental Rise extends gradually seaward to depths of 16,405 feet in the Abyssal

Plain of the oceanic basin at the outer edge of the

EEZ.

The major geological feature of the North Atlantic lease planning area is the Georges Bank plateau

on the eastern edge of the Continental Shelf off

Cape Cod. About 58 percent of the waters within

the North Atlantic planning area are 660 feet or

less, and 35 percent are 6,560 feet or deeper (see

figure 2-9).

Deep canyons intersect the Continental Slope in

the Atlantic region. The Baltimore Canyon Trough

is a major physiographic feature of the Mid-Atlantic

planning area, extending 300 miles from northeast

to southwest. It appears likely that the area of greatest hydrocarbon potential in the Atlantic region is

located in the deeper waters of the Continental

Slope of the Mid-Atlantic planning area, where a

possible extension of Mexico’s Reforma-Chiapas

oil-bearing reef complex may be buried under miledeep ocean sediment. Seventy-eight percent of the

area within the Mid-Atlantic lease planning area

is overlain by waters deeper than 6,560 feet.

The South Atlantic area is dominated by the

Blake Plateau, a broad gently sloping segment of

the Continental Shelf off Florida and Georgia, and

the Carolina Trough, a steep sloping segment of

the Continental Slope trending from northeast to

southwest off North and South Carolina. Over twothirds of the South Atlantic lease planning area is

in water depths of 6,560 feet or deeper.

Geological conditions that may affect oil and natural gas development in the Atlantic region include:

shallow recent faults, shallow gas deposits, mass

movement of sediments, filled channels, erosion

and scour, sand waves, faults present below the unconsolidated sedimentary section, and gas-charged

sediments. 12 The northerly flowing Gulf Stream

also may affect exploration and development of oil

and gas in areas influenced by its currents.

Leasing and exploration. The first Atlantic region sale was held in the Mid-Atlantic lease planning area in 1976, Exploration in the Atlantic

region peaked in 1979. Since that time, the disappointing results of earlier tests coupled with general economic conditions and worldwide petroleum

markets has slowed the pace of the offshore industry’s exploration efforts.

Pacific

The Pacific region is considered the cradle of the

offshore oil and gas industry in the United States.

In the 1890s, numerous shallow wells were drilled

from wooden piers along southern California

beaches. From these piers, the offshore petroleum

industry ventured onto offshore platforms and expanded its operations to the Gulf of Mexico. It was

not until 1950, however, that oil and gas production from offshore platforms in State waters began

in the Pacific region. It was also off southern California in the Santa Barbara area where the most

serious offshore well blowout occurred in 1969. The

impression that the Santa Barbara blowout made

on the public continues to influence the Federal offshore leasing program, although a similar incident

has not occurred again in the United States.

Four lease sale planning areas are located in the

Pacific region: Southern California, Central California, Northern California, and Washington and

lZMiner~5 Managment Service, Mid Atlantic Summary Repoti

(Washington, DC: U.S. Department of the Interior, 1983), p. 6,
Ch. 2—The Role of Offshore Resources ● 3 9

Figure 2-9.— Distribution of Atlantic Planning Areas by Water Depth

North Atlantic Planning Area

Water depth (meters)

0-200

——— — — — .

200-400

——— — — —.

———— .

\

— -

>2000

\

0/0 of area

58%

2 %

1%

1%

3 %

Mid-Atlantic Planning Area

Water depth (meters) % of area

0-200 20%

———— —

——— —

— — —

000-2000 7%

— —

>2000 68%

South Atlantic Planning Area

Water depth (meters) 0/0 of area

0-200 36%

———-— -

————— -

30 ”/0

>2000

SOURCE: Office of Technology Assessment
40 . Oil and Gas Technologies for the Arctic and Deepwater

Oregon. A large proportion (over 90 percent) of

the area within the lease sale planning areas in the

Pacific region is in water depths of more than 660

feet. Eleven sedimentary basins with potential for

containing hydrocarbons are located in the Pacific

region. The Santa Maria, Santa Barbara Channel,

and Borderland basins in southern California are

nearly geographically contiguous and offer the highest potential for petroleum development.

Oil and gas development in the Pacific region

is concentrated in the Southern California area.

Production from this area makes California the second ranking oil producing State and third ranking

in natural gas production from the Federal Outer

Continental Shelf. The most frequent oil and gas

discoveries in the Pacific region have been mostly

small fields of 100 million barrels or less. However,

80 percent of the combined reserves of oil and natural gas occur in larger fields ranging up to 400

million barrels.

Resource estimates. Total undiscovered economically recoverable crude oil resources are estimated to be about 4.6 billion barrels for all Pacific

planning regions. Over half (2.4 billion barrels) is

expected to occur in the Southern California

Borderlands and Santa Barbara Channel lease planning areas. The largest proportion of crude oil is

estimated to be located in the Central and Northern California lease planning area (1.9 billion barrels). Only 300 million barrels are estimated to exist

in the Washington and Oregon area.

Total undiscovered economically recoverable

natural gas resources (7.6 Tcf) are expected to be

similarly distributed among the lease planning

areas, with the most (2. 5 Tcf) located in the Santa

Barbara Channel, and a nearly like amount (2.3

Tcf) in the Central and Northern California lease

planning areas. Approximately 60 percent of crude

oil and natural gas within the Pacific region lease

planning areas is expected to occur in water depths

of 660 to 8,200 feet.

Physical and geological characteristics. The

breadth of the Continental Shelf in the Pacific region ranges from about 25 to 30 miles off Point

Conception in California to over 100 miles off San

Diego. The Continental Slope plunges to depths

between 1,300 and 9,750 feet at the base of the

Slope. Depths in the Abyssal Plain beyond the Continental Rise within the EEZ may reach depths of

about 14,675 feet off Washington and Oregon. Seventy six percent of the area in the Central and

Northern lease planning areas and 48 percent of

the area in the Southern California Borderland lease

planning area are in water depths of 6,560 feet or

more (see figure 2-10). Depths in the Santa Barbara Channel may reach 2,050 feet.13

Of the offshore areas in the Pacific region that

have been explored for oil and gas, the Santa Barbara Channel and the Santa Maria basin have been

most productive. In both instances, onshore oil and

gas development adjacent to Point Conception and

Point Arguello preceded petroleum discoveries offshore. The Point Arguello field within the Santa

Maria basin is considered the largest field yet discovered in the U.S. Outer Continental Shelf. Its

potential is rated at 300 to 500 million barrels.

The Pacific region lies along an axis of known

seismic activity, and the potential for earthquakes

is the major engineering factor affecting design of

offshore platforms and underwater pipelines. Other

hazards may exist in the form of subsidence,

seafloor erosion, shallow gas deposits, and mass

sediment movements.

Leasing and exploration. Oil and natural gas

leasing in the Pacific region began in 1963 in the

Central California lease planning area. A total of

14 oil and gas fields have been identified in the Pacific region. Two of these are natural gas fields; six

are oil fields; and six are a combination of oil and

gas. Oil has been discovered at wells in waters ranging from 1,097 to 1,544 feet deep off Point Arguello

in southern California, but most of the oil discovered is heavy crude which may require development

of special lift technologies to produce from those

depths economically .14 Exxon is planning to install

a production platform (Hondo ‘‘B”) in 1,200 feet

of water in the Santa Ynez unit in 1987.

Development, production, and reserves. Crude

oil production from the Pacific region peaked at 31

million barrels in 1971 and decreased to 10.2 million barrels in 1980. Pacific crude oil production

1qMiner~s Management Service, Pacific Summary Report (Washington, DC: U.S. Department of the Interior, 1983), p. 9.

I+ Oil and Gas Journal ‘ ‘Offshore Southern California’ (Jan. 9,

1984), p, 58.
Ch. 2—The Role of Offshore Resources • 41

Figure 2-10.— Distribution of Pacific Planning Areas by

Central and Northern California Planning Areas

Water depth (meters) 0/0 of area

——— — ———

———— — -

120/0

Water Depth

\

>2000 760/.

Southern California Planning Area

Water depth (meters) 0/0 of area

0-200 10%

—————— —

———— .

\

— -

>2000 480/o

SOURCE: Off Ice of Technology Assessment

rose to over 28 million barrels in 1983 (see figure

2-1 1). Natural gas production followed a similar

trend, peaking in 1971 at 15.7 billion cubic feet

while decreasing to 2.9 billion cubic feet in 1979,

and rebounding to nearly 18 billion cubic feet by

1983. Due to new discoveries, original reserve estimates for crude oil increased to 1.2 billion barrels

in 1983 and natural gas to 2 Tcf.

Alaska

Figure 2-il.—Trends in Pacific Region Oil and Gas

Production

35

0 5

n

35

o

1972 1974 1976 1978 1980 1982 1983 -

The Alaska region is remote, its operating con- Year

ditions are hostile, exploration and production costs SOURCE: Minerals Management Service, Pacific Summary Report, 1983,
42 ● Oil and Gas Technologies for the Arctic and Deepwater

are high, and its potential for oil and gas resources

enormous. There is currently no oil or gas produced

from Federal offshore lands in the Alaska region.

About 4 billion barrels of crude oil have been produced thus far from State offshore leases in the

Cook Inlet since before 1954. In addition, onshore

discoveries at the North Slope (Prudhoe Bay and

Kuparuk fields) indicate that there may be 10 billion barrels of recoverable crude oil and 35 Tcf of

natural gas directly adjacent to offshore areas in

the Beaufort Sea. The occurrence of these petroleum resources on State lands which are adjacent

to the Federal Outer Continental Shelf is considered to be an encouraging indication that vast petroleum resources may occur offshore.

The Alaska region consists of 15 lease sale planning areas: 1) Gulf of Alaska; 2) Kodiak; 3) Lower

Cook Inlet-Shelikof Strait; 4) Shumagin; 5) North

Aleutian Basin; 6) St. George Basin; 7) Navarin

Basin; 8) St. Matthew Hall; 9) Norton Basin; 10)

Bowers Basin; 11) Aleutian Basin; 12) Aleutian

Arc; 13) Hope Basin; 14) Chukchi Sea; and 15)

Beaufort Sea. Planning areas 1 through 4 are in

the Gulf of Alaska subregion; 5 through 12 are in

the Bering Sea subregion; and 13 through 15 are

in the Arctic subregion. This assessment considers the Bering Sea subregion and the Arctic subregion—the offshore subregions north of the Aleutian Islands—as the ‘ ‘Arctic’ for the purpose of

assessing Arctic technology.

Resource estimates. The Beaufort Sea lease sale

planning area is estimated to contain about 70 percent of the undiscovered economically recoverable

crude oil and natural gas (8 billion barrels and 39

Tcf expected to be found in the subregions north

of the Aleutian Islands. The Chukchi Sea planning

area, which lies to the west of the Beaufort Sea,

is expected to contain about 4 billion barrels of

crude oil and about 14 Tcf of natural gas. In total,

over 80 percent of the crude oil and 76 perecent

of the natural gas which may occur north of the

Aleutian Islands in the Arctic and sub-Arctic lease

planning areas of Alaska are expected to be in the

Beaufort and Chukchi Seas.

Physical and geological characteristics. The Continental Shelf adjacent to Alaska represents about

one-half the total U.S. Continental Shelf. Breadth

of the Alaskan Continental Shelf varies significantly, from as narrow as 8 miles at the eastern end

of the Gulf of Alaska to perhaps as wide as 500 miles

or more in the northwest Chukchi Sea.

The Continental Slope adjacent to Alaska drops

steeply to the abyssal depths. South of the Aleutian Islands, the Slope plunges between 16,400 and

19,680 feet in the Aleutian Trench. Depths in the

Abyssal Plain of the Gulf of Alaska range to about

13,120 feet. Maximum depths in the Navarin Basin

lie between 11,480 and 12,790 feet, while the maximum depths in the Arctic Ocean within the U.S.

EEZ are about 7,870 feet.

Over 80 percent of the area within the Navarin

Basin lease sale planning area is in water depths

of about 660 feet or less while about 83 percent of

the area in the Beaufort Sea planning area is in

waters 66 feet or less (see figure 2-12).

The southern Alaskan lease sale planning areas

along the Alaskan peninsula and the Aleutian

Islands are in seismically active areas where earthquakes and possible tsunamis must be considered

in designing oil and gas exploration and production systems. Sediment instability, which may result in sediment slides and slumping in areas

seaward of about 160 to 213 feet, may occur in the

Alaska region. In the Bering Sea, faulting, shallow

gas-charged sediments, and sediment erosion and

transport are geological factors that must be considered in offshore engineering design.15

Leasing and exploration. The first oil and gas

lease sale in Federal waters off Alaska was in the

Gulf of Alaska in 1976. Since that time, about 3.8

million acres have been leased in Alaskan waters,

This represents more leased acreage than any other

offshore region, with the exception of the Gulf of

Mexico.

Exploration efforts in the Yakataga area of the

Gulf of Alaska, which began in 1976, resulted in

11 dry holes. Since that time, the industry has

shown less interest in exploration in that area. Eight

exploratory wells drilled in the Lower Cook Inlet

planning area between 1978 and 1980 also yielded

dry holes, and no further exploration has taken

place.

lsMiner~s Management Service, Bering Sea Summary Re~ti

(Washington, DC: U.S. Department of the Interior, 1983), p. 33.
Ch. 2—The Role of Offshore Resources ● 4 3

Figure 2-12.— Distribution of Alaskan Planning Areas by Water Depth

Navarin Basin Planning Area St. George Basin Planning Area

Water depth (meters) 0/0 of area Water depth (meters)

0/0 of area

—————— . ——————— .

———— — ———— —

1000-2000 3 %

\ - “

1000-2000 90/0

— \ -

—

>2000 >2000 19%

Chukchi Sea Planning Area Norton Basin Planning

Water depth (meters) Water depth (meters) % of area —

o-1 o 5 %

————— — ————— —

———— —. .

200/0

400/o

Beaufort Sea Planning Area

Water depth (meters) 0/0 of area

Sea” level

o-1o n 1 00/0

30-40

40-50

—

SOURCE: Office of Technology Assessment.
44 ● Oil and Gas Technologies for the Arctic and Deepwater

In the Bering Sea subregion, six deep stratigraphic test wells have been drilled. Exploration

has recently commenced in the St. George Basin

and Norton Sound planning areas. Planning for

exploration in the Navarin Basin lease planning

area is currently underway.

Exploration in the Arctic subregion has shown

mixed results. The disappointment of the failure

of Sohio Alaska Petroleum Company’s Mukluk exploration well, which reportedly cost $140 million,

is offset by the Shell commercial discovery at Seal

Island in the Beaufort Sea planning area (joint

Federal-State lease) near the Prudhoe Bay onshore

field. The next exploration well in the Beaufort Sea

will be at Exxon’s Antares site about 45 miles northwest of the Mukluk site.
Chapter 3

Technologies for Arctic and

Deepwater Areas
Contents

Page

Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......

The Arctic Frontier . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ... .... .. .+.

Field Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Technology Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Deepwater Frontiers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overview . . . . . . . . . . . . . . . . . . . . . .....+.. . . . . . . . . . . . . . . .........

Field Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Environmental Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Technology Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLES

Table No.

3-1. World Offshore Oil Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-2. Proposed Arctic Environmental Design Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-3. Arctic Environmental Design Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-4. Summary of Cooperative Arctic Research Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-5. Deepwater Drilling and Production Achievements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-6. Deepwater Environmental Design Condition s..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

47

50

50

52

55

63

73

73

75

76

78

Page

49

56

57

73

74

76

FIGURES

Figure No. Page

3-1. Progression of Production Platforms for the North Sea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-2. Water Depth Records for Drilling Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-3. Production Platform Technologies for Frontier Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-4. Mobile Offshore Drilling Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-5. Arctic Exploration and Development Milestones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-6. Environmental Load Comparison for Representative Gravity Structures . . . . . . . . . . . . . . . .

3-7. Arctic Ice Zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-8. Ice Keel Gouging Sea Floor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-9. Extent of Arctic Sea Ice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-10. Alternative Arctic Production Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-11. Guyed Tower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-12. Subsea Wells & Production Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-13. Dynamic Positioning for Deepwater Drilling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-14. Subsea Production System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-15. Underwater Production System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

48

49

50

52

53

56

58

61

62

71

74

75

79

84

85
Chapter 3

Technologies for Arctic and

Deepwater Areas

OVERVIEW

Technology employed by the offshore petroleum

industry has changed dramatically over the past 20

years, allowing the international petroleum industry

to explore and produce in environments that were

considered almost prohibitive two decades ago. This

technology development which has revolutionized

the offshore petroleum business is a result of adaption, innovation, and integration.

Industry began its move to deep and hostile environments by first applying land-based techniques

to the marine environment in discrete incremental

steps. Progressively, industry resolved the problems

encountered offshore by adapting existing systems

or techniques or by designing new ones as needed.

Experience in the Gulf of Mexico, where exploration and production have moved from land to

shallow water to deep water, demonstrates this progression of technology adaptation.

New technologies also have resulted when a major challenge or opportunity called for innovative

approaches. For example, dynamic positioning was

a major innovation during the government’s 1960

Mohole Project; acoustic-guided hole reentry was

a major innovation of the government’s Deepsea

Drilling Project of the 1970s; and innovations in

diving and underwater vehicles grew out of Navy

programs in the 1960s and 1970s. In private industry, Deep Oil Technology’s tension leg platform, IMODCO’s single point mooring system,

Shell’s first semi-submersible rig in the 1960s, Exxon’s deepwater guyed tower, and Conoco’s tension leg platform in the 1980s are also examples

of major innovations.1

Finally, the integration of marine and ocean engineering with petroleum engineering and the business of oil drilling and production has brought var-

‘ U. S. Congress, Office of Technology Assessment, Ocean N4argin

Drilling—A Technicaj Memorandum (May 1980); and Proceedings

of the Offshore Technolo~r Conference (May 1984).

ied experience to bear on design, construction,

safety and reliability. The basic principles of each

field have been used effectively to design new systems to develop and produce petroleum resources

in the hostile marine environment (see figure 3-1).

Today more than one-quarter of world oil production is from offshore regions (see table 3-l). That

portion has been growing at a rate of nearly 10 percent per year for the past decade, and major exploration activities continue off the East, West, and

Gulf Coasts of the United States; in offshore Alaska;

in the Asia-Pacific, especially the China Sea; off

Latin America, especially Brazil; in the northern

North Sea; and off Canada. Several of these regions

could be categorized as hostile environments because of storms, severe waves and currents, deep

water, or Arctic or sub-arctic conditions.

For example, exploration has been underway for

several years under the severe ice conditions of the

Beaufort Sea off the United States and Canada; in

iceberg conditions along Greenland and eastern

Canada; and under severe wind, wave, current,

and deepwater conditions along the eastern Canadian and U.S. coasts, in the North Sea, and off

southern Australia. Outside of the United States,

the major offshore production experience in very

hostile environments has been in the North Sea.

The major offshore exploration experience in hostile waters (without production to date) has been

off the coast of Canada.

The Canadian Beaufort Sea exploration activities have been in the forefront of operations in

severe ice and cold conditions. Eastern Canada and

U.S. Atlantic Coast offshore exploratory drilling

have set rough water records. Exploratory activities in the Mediterranean and off the U.S. Atlantic coast have set water depth records (see figure

3-2).

4 7
48 . Oil and Gas Technologies for the Arctic and Deepwater

Figure 3-1 .—Progression of Production Platforms for the North Sea

1968 1975 1976 1978

Leman AUK A Brent A Cormorant A

SOURCE Shell 011 Co

In each of these situations, new technologies were

necessary for effective operations in very harsh environments. These technologies ranged from deepwater risers to concrete gravity structures to deepwater pipelines. Some examples of production

platform technologies for hostile environments are

shown in figure 3--3.

Offshore petroleum activities are commonly

divided into three phases: 1) exploration; 2) development; and 3) production. Exploration includes

1500

ft

1350

ft

1200

ft

1050

ft

&

ft .

750

ft

450

ft

ft

150

ft

1990 rr World Trade

Troll Field Center Tower

some pre-lease activities such as geological and geophysical surveys as well as the exploratory drilling

that occurs (in the United States) after a lease sale.

Development begins after an oil or gas discovery

is determined economic and includes the delineation of the reservoir as well as the drilling of production wells and the design and construction of

all facilities for producing a field. Production begins

with the flow of oil or gas to a market and concludes

when a field is depleted. In offshore frontier regions,

it is not unreasonable to expect exploration to con-
Ch. 3—Technologies for Arctic and Deepwater Areas ● 49

Table 3-1 .—World Offshore Oil Production

Oil production

(million bbl/day)

1983 1984

Region or area (actual) (projected)

Middle East . . . . . . . . . . . . . . . . . . . . 3.74 3.88

Latin America/Caribbeana 

. . . . . . . . . 3.24 3.36

North Sea . . . . . . . . . . . . . . . . . . . . . . 2.88 3.05

United States (GOM + Calif.) . . . . . . 1.68 1.78

Southeast Asia and Oceania. . . . . . . 1.53 1.56

West Africa . . . . . . . . . . . . . . . . . . . . 0.80 0.80

U.S.S.R. . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.17

Mediterranean . . . . . . . . . . . . . . . . . . 0.14 0.15

Total . . . . . . . . . . . . . . . . . . . . . . . . . 14.19 14.75

Percent of onshore + offshore. . . . . 26.6°/0 27.70/o

aLatln AmerlcalcarlbbeanIncludes Mexico, Venezuela, Trlnldad, Brazil. and

Argentina as key producers

SOURCE Offshore Magazine, May 1984

tinue for 10 years or more, development work to

continue for 10 years, and production to continue

20 or more years. One would expect, therefore, that

if discoveries are made in U.S. deepwater or Arctic regions, the major activities would continue well

into the next century.

The three phases described above do not start

and end abruptly; they usually overlap to a considerable extent. Exploration for smaller fields may

continue long after major fields in a region are in

full production. The development of a field may

proceed in stages with the addition of gas injection,

water injection, or other systems to enhance recovery as the field is being produced. And production

usually starts before a field is completely developed,

especially if it is very large and complex.

Since the focus of this assessment is the deepwater

and Arctic frontiers where no production has

begun, the technologies discussed fall into two categories: 1) exploration systems which have been

used for several years; and 2) production systems

which have not been used but exist in designs,

plans, and sometimes prototype test equipment.

Figure 3-2.—Water Depth Records for Drilling Operations

Years 1965 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984

Shell 2290’

2500 Gabon Shell

Gabon

3460’

Exxon

Exxon

4500 Surinam 4348’

—

Seagap

3862 r

Phillips

Aust.

4505’

5000 Africa 4876 BNOC

Texaco U.K.

5500 Canada

5624’

6000 C.P. F.

France

6500

t

L

6448’

Shell

70001- New Jersey 69

Shell

7500 New Jersey

SOURCE Proceedings, DOI EEZ Symposium, Nov 1983, updated 1984
50 . Oil and Gas Technologies for the Arctic and Deepwater

Figure 3-3.—Production Platform Technologies for Frontier Areas

Statfjord 8 Magnus

Concrete Gravity Base Platform Steel Template- Hutton

(Norway) Jacket Platform Tension-Leg Platform Block 2280 Troll

(1982) (U. K.) (U. K.) Guyed Tower (U. S.) Concrete Gravity-Base

(1982) (1984) (1984) Platform

However, even though these production systems prospective field characteristics, and the proximity

have not been used in the regions under consider- to other developments. For example, a discovery

ation, many individual components are similar to in the Alaskan Beaufort Sea near Prudhoe Bay

those already in service in other regions. A total probably would be developed using much of the

technical system will, therefore, be built from a same technology as that used on the nearby land

combination of tried and tested subsystems and sites. Because of the site-specific nature of most offcomponents newly designed to meet added demands. shore oil and gas technology and also because of

The types of drilling, production, and transportation systems for each frontier area must be

selected to fit the prevailing conditions of the working environment (e. g., ice, deepwater, or storms),

the great variety of technology possibilities available, discussions in this chapter are based on specific systems which may be used in the Arctic and

deepwater scenarios developed by OTA.

THE ARCTIC FRONTIERS

Overview Offshore exploration in the Arctic region began

in the mid- 1970s in State waters of the Beaufort

Commercial oil activities in the Arctic date back Sea, Prior to this, the only significant activity in

to a State lease sale in December 1964 onshore in the Alaskan offshore was outside the Arctic in Cook

the Prudhoe Bay area. Production from the onshore Inlet and the Gulf of Alaska. Oil production from

North Slope fields began in 1977 and in 1984 was offshore platforms in Cook Inlet began in 1964. Ex1.6 million barrels per day. ploratory drilling in the Gulf of Alaska in the late
Ch. 3—Technologies for Arctic and Deepwater Areas . 51

1970s produced no discoveries of economic significance.

The first exploratory wells in the waters north

of Alaska were drilled from natural islands in Steffenson Sound (e. g., Gull Island in 1974 and Niakuk

Island) followed in 1977 by drilling from a builtup sea ice platform in Harrison Bay. Since then,

many exploratory holes have been drilled from

manmade gravel islands or off the barrier islands

along the Beaufort Sea coast. Exploratory drilling

in the Bering Sea region began in 1982. Drilling

in the Bering Sea has been conducted in the summer ice-free season with technologies that have been

used in temperate offshore regions. A concrete

island drilling structure is now being used for exploratory drilling north of Cape Halkett in Harrison Bay.

The first Federal

Alaska was the joint

offshore activity in Arctic

Federal/State Beaufort Sea

lease sale in December 1979. Since then, the pace

of offshore activity and the rate of technological advancement have increased significantly. The first

wholly Federal offshore lease sale took place in October 1982 in the Beaufort Sea. To date, the Federal Government has conducted four more sales in

Arctic Alaska, three in the Bering Sea—Norton

Sound, the St. George Basin, and the Navarin

Basin—and a second in the Beaufort Sea (Diapir

Field).

In May 1982, Sohio and Exxon jointly announced tentative plans to develop the 350-millionbarrel Endicott field (also known as the Sag River/

Duck Island field) portion of the joint Federal/State

lease sale area. By February 1985, Sohio had received all necessary permits and launched work

leading to the first commercial oil production in

U.S. Arctic waters. In November 1983, Sohio

began drilling the first exploratory hole in the

Mobile offshore exploratory drilling unit, like those used in offshore Arctic areas, is towed to new drilling site
52 ● Oil and Gas Technologies for the Arctic and Deepwater

Mukluk area of Diapir Field. However, Mukluk

was determined nonproductive. In May 1984, Shell

announced a large oil discovery from Seal Island

in a joint Federal/State sale area. In both cases,

drilling was from manmade gravel islands. Exxon

drilled the first exploratory well from an Arctic

mobile offshore drilling unit (MODU) in late 1984

northwest of Mukluk. This used a concrete island

drilling system known as “Super CIDS, ” which

can be moved to another location if desired after

drilling is completed at the site2 (see figure 3-4).

Offshore petroleum development in the Arctic

will be a major technological challenge. The envi2’ ‘Drillers Seek Alaska Supergiant, OfIshore (January 1984),

Figure 3-4.—Mobile

ronment is severe and will dictate a rigorous approach to design and construction of all primary

and support systems. While considerable data have

been collected, additional engineering data will

need to be compiled and verified. The cold temperatures, ice, harsh weather, and remoteness of

many Arctic regions will force the use of costly

equipment to achieve the required reliability. Some

of the exploration and development milestones in

offshore Arctic technology are shown in figure 3-5.

Field Characteristics

The field characteristics of the six key Arctic planning areas are given below.

Offshore Drilling Unit
Ch. 3—Technologies for Arctic and Deepwater Areas ● 5 3
54 . Oil and Gas Technologies for the Arctic and Deepwater

Beaufort Sea

There are four main types of geologic settings

in the Beaufort Sea which potentially contain oil.

They are listed below in the order of probability.

Only the first two are candidates for exploratory

drilling at this time.

Ellesmerian Sequence. —This prospective sequence extends from Smith Bay on the west to Mikkelsen Bay on the east, becomes thinner as it extends north from land, and ends at approximately

71 013‘ N latitude. It includes the Lease Sale 71 area

which incorporates Harrison Bay. Since the Ellesmerian Sequence includes the Prudhoe Bay fields,

oil similar to the Prudhoe type may be found in

the Lease Sale 71 area. This means an oil with an

average gravity of about 280 and with a low sulphur

content; therefore, a good quality oil. The area of

Ellesmerian potential has gentle structural folds

which means that it could contain several very large

accumulations of oil instead of numerous small

ones.

Tertiary Structures. —These structures are east

of the Ellesmerian Sequence and extend from

Camden Bay to the Canadian border. This means

that they are east of the Lease Sale 71 area but

within Lease Sale 87 which occurred in August

1984. The seaward extent of these structures is approximately to 70035 N latitude. These structures

contain more convolutions and peaks than the

Ellesmerian Sequence which means that the area,

if productive, may contain more smaller oil fields.

These structures also are located in regions of more

severe ice conditions.

Growth Fault Structures. —These structures

relate to the growth faults and roll-over anticlines.

They overlap the Ellesmerian Sequence in the

northeasterly portion of Lease Sale 71 and then extend seaward. Little is known about possible oil

fields in these structures.

Cretaceus Tertiary Clays. —These formations

are expected to contain scattered smaller fields and

are less promising than the Growth Fault Structures for finding oil. They are located in the central and western Beaufort shelf regions.

Chukchi Sea

The Chukchi Sea appears to contain three areas

with favorable hydrocarbon potential. Most favorable is the Central Chukchi Shelf, which is

northwest of Alaska—particularly the area along

the northern coast. It contains a very thick sedimentary section and many anticlines. It is the offshore

extension of the Colville Trough—the province of

North Slope oil and gas. Reservoir rocks are potentially the same as those in the Sadlerochit Group

and the Kuparuk River sandstones.

The southern part of the Central Chukchi Shelf

and the Northern Chukchi Shelf are the other two

potential areas. The southern part is an overthrust

zone similar to the foothills province of the Brooks

Range. The North Chukchi Shelf contains great

thicknesses of (inferred) Cretaceus and Tertiary

rocks containing shale diapirs.3

Reservoirs in this area could be located from

5,000 to 25,000 feet below the seafloor with an average well depth of 10,000 feet. It is geologically possible that a giant oil field in excess of 1 billion barrels in size could exist in this area.

Norton Basin

Due to the limited geologic information available on Norton Basin, reservoir and production

assumptions have been made based on similar

geologic basins for which more data were available;

specifically, these are the Anadyr Basin of northeast Siberia and Cook Inlet in Alaska. The assumptions are that the average reservoir depths range

from 2,500 to 7,500 feet, that the recoverable reserves per acre could range from 20,000 to 60,000

barrels, and that the initial well productivity could

range from 1,000 to 5,000 barrels per day. Field

sizes could be in the range of 100 million barrels

or more.4

3Dames & Moore, “Chukchi Sea Petroleum Technology Assessment , report prepared for the Minerats Management Service (December 1982).

4Dames & Moore, ‘ ‘Norton Basin OCS Lease Sale No. 47 Petroleum Development Scenarios, report prepared for Bureau of Land

Management (August 1980).
Ch. 3—Technologies for Arctic and Deepwater Areas ● 5 5

St. George Basin

The St. George Basin is floored and flanked by

folded Mesozoic rocks that extend from southern

Alaska to eastern Siberia. Geophysical data and the

extrapolation of onshore information to offshore

areas suggest that suitable source beds, reservoir

rocks and traps all exist within the St, George Basin.

Very little data are available with which to speculate

on field characteristics.5

North Aleutian Basin

The North Aleutian Basin is a large sedimentfilled structural depression that underlies portions

of the Alaska Peninsula and the Bering Sea. Within

the basin, Mesozoic basement rocks are overlain

primarily by Cenozoic sedimentary rocks. The information garnered from nine wells drilled on the

Alaska Peninsula adjacent to the axis of the basin

is encouraging for the prospect of discovering

hydrocarbons. The majority of potential oil and gas

traps within the basin are believed to be associated

with anticlinal structures.

Navarin Basin

Navarin Basin includes three thick sedimentary

sub-basins. There are also several large anticlinal

structures, smaller folds, diapirs, and stratigraphic

traps. There is potential for giant oil fields in excess of 100 million barrels. Due to the great thicknesses of the sedimentary deposit, reservoirs could

occur at depths below the seafloor, ranging from

shallow to very deep. Reservoir depths are estimated between 6,500 and 11,500 feet in the northern portion of the Basin and between 3,300 and

13,000 feet in the southern portion. G

Environmental Conditions

Petroleum resource development in the offshore

Arctic is conducted under unique cold-region, highlatitude environmental conditions. Among the conditions are: ice and its many impacts; ocean floor

geotechnical properties; seasonal fog; and periods

‘Dames & Moor-e, ‘ ‘St. George lh+in Petroleum Technology Assessment, repot-t prepared for Bureau of Land hlanagcment (August

1980)

bDames & Nloore, “ Na\’arin Basin Petroleum Technology Assessment, reported pmparcd for Bureau of Land NI anagemcnt (June

1982)

of up to 24 hours of light or darkness. Offshore conditions are severe and the locations are remote and

difficult to support. In order to operate successfully

and to minimize the risk to personnel, facilities, and

the environment, these environmental conditions,

and their impact on materials, logistics, operations,

and human factors, must be taken into consideration. Because of these conditions, time relationships

become critical—not only for exploration but also

for data gathering, logistics, production, and virtually every other operational consideration. Figure 3-6 illustrates environmental load comparisons

for different structures and regions to show the significance of wave and ice loads.

The northern Alaska environment can be

thought of as a frigid desert with some precipitation, low temperature, high wind, and periods of

extended fog. The climate in the areas north of the

Bering Strait is very harsh. Based on data from the

Climatic Atlas, early air temperatures vary from

a low of approximately – 470 F to a high of approximately 570 F. Temperatures even lower than

– 50° F occur at Pt. Barrow. The areas south of

the Bering Strait have a less severe climate. In the

Norton Basin, the extreme low temperature is

– 36° F; in the Navarin it is – 110 F; and in the

St. George it is30 F. The maximum 100-year wind

north of the Bering Strait is 97 knots. This increases

south of the Bering Strait to a maximum of 108

knots in the Navarin Basin.7

7B’. A. 13rower and H. W. Set-by, Climatic A das of the Outer Continentai Shelf Waters and Coastal Regions of Alaska (1977).

Offshore platforms in frontier areas

tremendous environmental

Photo credit: Shell Oil

must withstand

forces

38-749 0 - 85 - 3
56 Ž Oil and Gas Technologies for the Arctic and Deepwater

Figure 3-6.—Environmental Load Comparison for Representative Gravity Structures

l:- - 111 I I Ill

SOURCE: Hans O. Jahns, “Offshore Outlook-Technological Trends: American Arctic,” Offshore Mechanics and Arctic Engineering Symposium (Dallas, Texas,

February 1985).

The northern Alaska OCS is relatively stable

seismically. A review of observations made over the

past 20 years in the Beaufort Sea region from the

coast out to about 100 miles offshore shows four

seismic events, each equal or less than 4.5 on the

Richter Scale. Significant seismic activity, however,

is located along the Mid-Arctic Ridge in the Eurasian Basin of the Arctic Ocean and along the Aleutian Chain off southwest Alaska. Oil exploration

and development operations in the southern Bering Sea must take into account seismic activity

along the Aleutian Chain.

There is some controversy about the completeness and accuracy of existing data on environmental

conditions in the offshore regions. Some believe the

Climatic Atlas data may overestimate oceanographic conditions, while others believe that given

extremes may be even greater than existing data.

The American Petroleum Institute is sponsoring

work to produce a recommended-practice document that will include ranges of wind, wave, and

current values based on more accurate and recent

measurements. The revised values being considered are shown in table 3-2. Based on these estimates, maximum wave heights could vary from

about 40 feet in the Beaufort Sea up to 90 feet in

Table 3-2.—Proposed Arctic Environmental Design

Conditions

Significant Surface

Maximum 100-year wave currents

100-year winda

height velocity

Area (knots) (feet) (knots)

Beaufort Sea. . . . . . . . . 60 to 80 20 to 30 1 to 6

Chukchi Sea ., . . . . . . . 60 to 80 20 to 30 1 to 5

Norton Basin . . . . . . . . . 55 to 85 (90)b

30 to 40C1 to 4

St. George Basin . . . . . . 55 to 85 (88)b

40 to 50 2 to 4

Navarin Basin . . . . . . . . 50 to 80 (90)b

40 to 50 1 to 3

aTheSe are I hour averages to combine with extreme waves. Totally wave independent values would be somewhat higher, but structural loading calculations generally consider joint effects of winds and waves.

%hese are wave independent numbers.

cvalues for water depths greater than 75 ft. For shallower water, wave heights

are limited by breaking waves.

SOURCE: Exxon, 1984,

the St. George and Navarin Basins (corresponding

to the 100-year storm).

Most experts agree that for design purposes sea

ice is the most significant environmental parameter in the Arctic offshore. The duration of ice cover

can vary from 10 months or more duration for the

Beaufort Sea and Chukchi Sea to 1 month or less

in the southwest Alaska St. George Basin. In some

years there is no ice in the St. George Basin. Since

the Navarin Basin is quite large, ice conditions vary

considerably from north to south. Ice thicknesses
Ch. 3—Technologies for Arctic and Deepwater Areas • 57

vary correspondingly. The Climatic Atlas data

show single-year, plane ice thicknesses of up to 7

feet in Diapir and 2.5 feet in St. George.

Additional offshore Arctic environmental design

conditions for five of the lease sale planning areas

are shown in table 3-3. These data are derived from

the Climatic Atlas and are considered representative although site-to-site variations may be substantial.

Ice

Ice problems largely dictate criteria for Arctic design and operations. Sea ice creates the major difficulties. However, other ice, such as ice islands,

floebergs, and structural icing on platforms, ships,

and helicopters also present problems. The characteristics of sea ice, pressure ridges, and ice movement are the main concern in the design of Arctic

structures. Some ice islands are so large that major damage could result from a collision between

them and an offshore structure. Fortunately, because of the scarcity of ice islands, the probability

of such an occurrence is relatively low. More likely

events are the collision of pressure ridges with certain types of platforms and the ride-up of sea ice

onto gravel islands. Ice ride-up can occur when the

wind or current forces acting on ice cover force the

ice against the land or an offshore structure. If the

forces are large enough the ice can be driven up

onto the structure or inland for distances of 300 feet

or more. Pressure ridge keel seabottom gouging

depths are a design concern which influences the

depth of burial of offshore pipelines and seafloor

well heads.

Sea ice is the single most important environmental factor affecting operations in the Arctic. Ice

affects all aspects of oil and gas activities—from the

design and construction of facilities which can

withstand ice conditions to planning for transportation or possible rescues.

There is no simple description for Arctic sea ice.

Even the initial formation of crystals varies widely

depending on the roughness of the sea. With calmer

seas, the crystals are larger and more platelike. In

rougher waters the crystals are smaller and more

granular. Once crystals have formed and have developed a thin skin on the surface of the water, the

growth of the ice takes place on the underside. Salt

brine pockets develop between the lattice networks

of relatively pure water crystals. Over a period of

time these pockets drain. The process of drainage

is complicated by the percolation of summer melt

through the ice. Multi-year ice becomes nearly

drained of the salt and takes on a bluish hue.

The strength of ice is dependent on many factors including brine content, crystal orientation,

temperature, age, and ice type. Recent data show

that multi-year ice strengths may fall within the upper range of first-year ice strengths and in some

cases (granular ice) may not be as strong. However, statistically and probabilistically, multi-year

Table 3-3.—Arctic Environmental Design Conditions

Temperature Minimum

Wind Ice Ice daylight Water Distance

chill Min duration thickness hours depth from shore

Area (“F) (“F) (months) (feet) (hours) (month) (feet) (miles)

Beaufort Sea -90 -47 10 7 0 ‘-Jan. 33-200 3-40

Dec.

Chukchi Sea -85 -44 8-10 5-7 0 Jan. 30-150 3-45

Dec.

Norton Basin -72 -36 8 3.5 4.5 Dec. 30-85 9-62

St. George Basin -35 3 1-1/2 2.5 7.0 Dec. 344-472 60-180

Navarln Basin -54 -11 5 3.0 6.0 Dec. 240-450 400-700 ——-——

NOTES:

——

1 Wafer depth values represent approximately 95 percent of the water depths — the extreme high and low depths were

excluded

2 Distance from shore for Navarin Basin IS from Dutch Harbor in the Aleutians, all others are from the mainland

3 Daylight hours shown are for time the sun IS above the horizon In addition, twilight hours are often added to these

numbers, especially for the far north regions.

4 The ice thickness values apply to annual sheet ice

SOURCE W A Brewer and H W Serby, Climatic Atlas of the Outer Continental Shelf Waters and Coastal Regions of Alaska,

1977
58 Ž Oil and Gas Technologies for the Arctic and Deepwater

ice is stronger than first-year ice. While first year

ice may grow to 6 to 7 feet thick, multi-year ice

may grow to about 12 to 16 feet thick. In shallow

water, shore-fast ice areas, first-year ice as thick

as seven feet has been observed. The ultimate

thickness depends on many factors including the

radiant solar energy absorbed, long wave period

energy radiated from ice into space, temperature

of the air above the ice, and the thermal insulation, or inversely, the heat conductivity of the layer

of ice and any snow cover. An equilibrium occurs,

and the ice thickness is stable when the amount of

heat absorbed by the ice from the water is in balance with the heat absorbed from the ice by the air.

However, a large amount of thickness ‘ ‘growth’

can be attributed to pressure ridge building and

rafting. 8

Sea ice modification results from interactions

with the wind and ocean currents, The build-up

of forces within the ice floes can cause the fracturing of the plates and a restructuring of the ice. The

ice may be split apart resulting in long openings,

perhaps tens or hundreds of kilometers long. Should

these be sufficiently wide for the passage of a ship

or whales they become ‘‘leads. Many are very

narrow, however, and immediately refreeze or close

again as the ice continues to move.

8W, F. Weeks and G. Cox, “The Mechanical Properties of Sea

Ice, A Status Report, in Ocean Science and Engineering (9:2).

Having once parted, the two walls may be driven

together causing upheavals and downward thrusts

of the sheets and the formation of pressure ridges.

Pressure buildup within ice floes may also cause

deformation resulting in pressure ridges and rafting. The surface height of the ridge sails formed

may be as much as 25 feet, while the depth of the

ridge keels thus formed may be as great as 100 feet.

The restructuring of the broken ice results in various orientations of blocks. Any preferred orientation of ice crystals within the ice structure prior

to ridging becomes randomized as broken blocks

are tilted and tumbled. Interstices between the

submerged blocks fill with sea water. The heat-sink

capacity of the ice blocks can cause this water to

freeze in the smaller voids and at block-to-block

contact points. This often will occur in the first 6

to 8 feet. Also, a strong ice structure can develop

in this depth zone due to heat flow to the surface

which allows for further solidification of the rubble. Below this depth the blocks will generally form

a weaker conglomerate. Rafting of ice of similar

thickness will double the local ice thickness.

The location of the ice determines to a great extent how it responds to external forces. The sea ice

north of Alaska can be considered as being made

up in three zones (see figure 3-7):

1. the fast ice zone, which includes the grounded

ridges, when they exist and any extension of

Figure 3-7.—Arctic Ice Zones

SOURCE U.S. Army Cold Regions Research and Engineering Lab, 1984.
Ch. 3—Technologies for Arctic and Deepwater Areas • 59

2.

3.

the fast ice resulting from the ice cover being

anchored to the grounded ice;

transition ice zone: a transitional zone between the rotating ice pack and relatively motionless fast zones; and

polar pack ice: mostly multi-year ice that covers the central Arctic Ocean rotating in a gyre.

The shelf north of the Beaufort Sea is narrow:

about 50 miles wide and breaks at a depth of 200

to 225 feet. Shallow waters extend over a large portion of the shelf near Harrison Bay with the 60-foot

isobath being about 45 miles offshore. Off Camden

Bay in the eastern Beaufort, however, the 60-foot

isobath is only about 11 miles offshore.

In the Beaufort Sea, the fast ice generally begins

to melt in late May-early June. Near the coast this

process is accelerated by rivers flooding over the

ice surface. Once the fast ice melts away from the

shore, its anchorage is lost and it can be moved by

wind and currents. Such movement can cause the

ice to break into smaller and smaller floes, further

accelerating the dissipation process through melting and by being driven away from the area, Open

water frequently exists along portions of the Beaufort Sea coast during the months of July, August,

and September. The length of the open water

season, however, is variable and is frequently controlled by the prevailing winds. Some seasons the

winds drive the pack ice offshore far beyond the

continental shelf. In other years, onshore winds

keep the pack close to shore. During these summers, coastal shipping can be greatly restricted,

even prevented. In 1975, some barges supplying

the North Slopes were caught and had to winter

over in the ice at Prudhoe Bay.

The grounded ridge zone is an area of considerable pressure ridge formation activity. The shallow

depth, however, limits keel depths of the ridges.

The grounded ridge zone is not continuous, does

not necessarily occur at the same locations each

year, and, where such ridges form, the resulting

ice rubble may be quite extensive and massive or

of minor consequence.

The transitional ice zone is one of great energy,

The cracks and leads open and close in this zone

as the pack deforms under wind and current drag

forces. Pressure ridges are formed from floes driven

against one another and from the sliding, shearing action between the various ice masses. Keels

formed in these may be driven by a combination

of wind, current, and ice interactions into water

depths shallower than their keel depths. Here the

ice keel can be pushed into the seabed, and like a

cutting tool, gouge depressions and furrows in the

sediments (see figure 3-8). As this happens repeatedly, the seafloor is completely scarred by ice

gouges. In water depths of less than 45 feet, ice

gouging occurs very frequently, but in these waters

shore currents and storms can cause filling by sediment. Beyond the 45-foot depth, ice gouges are not

filled and will remain until altered by later ice gouging. Ice gouge orientation tends to follow depth

contours.

The polar pack region is composed primarily of

multi-year ice. However, it too is subject to the interactions of winds, causing leads to open and close.

Pressure ridges are continually formed. The ice

pack north of Prudhoe Bay drifts clockwise with the

movement of the Beaufort Sea Gyre. Ice islands,

large icebergs which originate from the northern

coast of Ellesmere Island, can also be found drifting within the gyre. These ice islands may be 150

feet thick. Ice islands in this gyre may remain there

for decades before leaving the Arctic Ocean. From

time to time ice islands are grounded in the coastal

waters of the Beaufort Sea.

There are significant differences in the ice in the

Bering Sea as compared to the Arctic Basin. The

Alaskan shelf south of the Bering Strait is quite

wide. The majority of the Navarin Basin lease sale

area is in water depths ranging from 300 to 600

feet. Multi-year ice can drift into the northern part

of the Bering Sea but even that portion of the sea

becomes ice-free during the summer. Ice is formed

each year in the northern part of the Bering Sea

to thicknesses of about 1 to 2 feet. Fast ice in the

very northern Bering Sea may grow to a thickness

of more than 4 feet but multiple rafted ice can be

over 15 feet thick. Ice starts forming at the shore

and extends outward and southward. The edge of

the ice may be driven southward by wind forces.

Pressure ridging occurs but, like the average ice

thickness, is much less than in the Arctic Basin

waters. Ridges may have sails of 15 feet above the

surface and keels four to six times as deep. Currents through the Bering Strait generally run northward. There is an occasional reversal which can
60 . Oil and Gas Technologies for the Arctic and Deepwater

Photo credit: SEDCO

First mobile offshore drilling unit in U.S. Beaufort Sea—Exxon’s Super CIDS
Ch. 3—Technologies for Arctic and Deepwater Areas Ž 61

Figure 3-8.—lce Keel Gouging Sea Floor

Legend:

d - gouge depth

w - gouge width

- gouge orientation

h - lateral embankment height

z - water depth

sf - sea floor

N - true north

--’ S f

(Recent tests indicate gouge depths can vary from 3 feet in shallow lagoons to

15 feet in open ocean water depths of about 100 feet.)

SOURCE: U.S. Army Cold Regions Research and Engineering Lab, Report 83-21, 1983

bring thicker Arctic Ocean ice with larger features

southward. The maximum and minimum extents

of the sea ice cover in the seas off the Alaska coast

are shown in figure 3-9.

Other ice conditions may be hazardous. When

combined with freezing conditions, the winds and

waves produce an icing spray which can cause

dangerous ice build-up on ships and structures. The

interactions of blocks of floating sea ice with waves

can propel the ice into the sides of ships and structures resulting in large localized forces. During

some atmospheric conditions, fixed wing aircraft

and helicopters traveling at critical altitudes can be

subjected to icing, creating dangerous situations.

Other Factors

Fine, silty sediments and sub-bottom permafrost

are the two geotechnical factors of concern in Arctic waters. Permafrost exists only in the Arctic

Ocean. In the southern part of the Bering Sea near

the Aleutian Chain, seismicity is also of concern.

The engineering properties of the upper sediments of the ocean floor must be considered in the

design of foundations for bottom-founded structures. The possibility of mud slides must be considered in the foundations of structures placed on

the steeper slopes of the Navarin Basin. Industry

is conducting investigations of the instability of

sediments and the design of foundations for these

conditions.

Permafrost could affect the design and routing

of pipelines in the Beaufort Sea. Some related design problems include the differential thaw subsidence of permafrost and adjacent foundations,

thaw subsidence around wells, and frost heaving.
62 • Oil and Gas Technologies for the Arctic and Deepwater

Figure 3-9.— Extent of Arctic Sea Ice

Summer Minimum and Winter Maximum

165° 1700 175° 55° 180° 1750 1700 165 “

SOURCE: American Geographical Society, New York, New York, 1975.
Ch. 3—Technologies for Arctic and Deepwater Areas . 63

In general, the Arctic environmental factors

affecting the design, installation, and operation of

offshore systems vary depending on the season of

operation and upon the ice conditions. But data on

ice condition, oceanographic, meteorological, and

geotechnical factors are relatively sparse for many

areas. And, like all Arctic operations, collection of

additional data is costly.

Meteorological data are particularly sparse for

the areas north of Alaska and in the Bering Sea.

Satellites and ice buoys are used to obtain ice movement and weather data for the regions north of

Point Barrow. However, much of the sensory data

do not have the resolution necessary for many applications. Unfortunately, most of the visual sensors are usable only during the daylight summer

months, and even then their effectiveness is lowered

due to clouds and fogs that develop above melting

ice and evaporating ice melts. The lack of sufficient

ice and meteorological data has severely limited the

ability to detect and forecast ice movement and

weather conditions for the Arctic region.

Technology Development

OTA has developed three Arctic scenarios to illustrate the approaches that may be used to develop

and produce Alaskan oil discoveries, based on

today’s knowledge of the environment and suitable

technology (see box). A complete production system for these conditions does not currently exist.

Because of the very high costs involved, there is

a significant incentive to improve system reliability

and cost effectiveness by using advanced technologies. A range of engineering development, tests,

and evaluation may be required before industry can

safely and economically produce possible petroleum

discoveries in hostile offshore Arctic environments.

Figure 3-10 illustrates some of the production

platform systems and structures that currently appear to be the most favored alternatives for each

of the Alaskan offshore planning areas. In each

case, the system is based on operating experience

in a related situation or a similar environment.

Technology for exploring, developing, and producing oil and gas in offshore Arctic environments

appears to be progressing at a pace compatible with

government leasing schedules and industry’s contemplated development schedules. Prior to a sale

in a planning area, industry usually proceeds with

research and engineering programs to develop

baseline data, design criteria, and engineering designs for exploration and production systems which

match the expected conditions. This research and

engineering effort is intended to: 1) establish the

feasibility of systems and the confidence that these

systems can be constructed and operated safely; 2)

estimate system costs to guide in economic evaluations of the resource prospects, and thus help establish the lease bid level; 3) identify key site-specific

information needed for system selection and design

if oil and gas discoveries are made; 4) ensure that

post-lease sale exploration, development, and production could be brought onstream on approximately the time table assumed in pre-lease sale economic analyses; and 5) enable industry to move

quickly to drill exploration wells.

After the discovery of economic reserves resulting from exploratory drilling, considerably more

research and development, data collection, and

testing is necessary for industry to move into the

development and production phases in the Arctic.

Some research and development areas are more

critical than others, especially when economics are

considered. The following areas are judged to be

important to future Arctic development.

Ice

Additional research is needed to obtain basic data

on ice properties and ice strengths under different

conditions as actually encountered in the field, on

the strength characteristics of pressure ridges and

of the ice within such ridges, and on variations of

ice properties.

Although data on ice and its properties are high

on the list of needed research, there is a significant

data base on ice strengths and properties. Industry is developing more data on ice feature size and

geometries and conducting model tests to investigate ice/structure interactions. Ridges are being

sampled, their ice strengths determined for the

appropriate ridge thermal profile, and ridge temperatures are being monitored throughout the year.

In almost all cases, exploratory drilling structures

are instrumented to measure the loads exerted by
64 . Oil and Gas Technologies for the Arctic and Deepwater
Ch. 3—Technologies for Arctic and Deepwater Areas ● 6 5

Wit@’ depths aid” high Wa&es @rnb@ed’witb ice fm’ces could impose 1-fbrcxs actirig to Wertum bottom”

foufided structures. Although such strwtu= are iristalkd in t@ I%&& Sea &t equivakri~ depths, they are

not subject to the horinoti i= for@$ *’*t wd~ ~ ‘@@f@t@@~ *~w* ~wJf% ad Arctic Stru~-

tures would require dditf.o~~ Stmgth marf@$s “. ;

b and temperata= conditi- also af%ct t~~ ‘cm &i support servkes. In the Navarin Basin,

the fquenq of ice rfdg~~ fmport~t * *@”~@? ~u~ @F th~ck * fi~~ Or -M of rfied

ice can be avoided or their effects rnitigat~ by icebr%ak@%. In Harrison Bay and Norton Basin, keels from

press@’e ridges could penetrate the seabud, rcquiringpipt~~e~ to~ burkd beneath gouge depth. Although

no major -e piPIiUe SYSWIKM exist k &ctic waters, ikenthk~ by sub= P1OWS =~ pipelfne fnst~atkm by the bottom tow method am considered ikadbk. k HarriMn Bay, however, permafiwst precautions

would be rlec=s=’y to prevent the hot@ fkom melting the piemdbst and possibly causing soil subsidence.

While these conditions have been handled succes~y onshore on the North Slope, pipeline trenching into

subsea Permafmt 10 to 20 feet deep wo~d q@~ C~Y ~d @MSS~V@XXI*iIMX”Y not Yet buflt Or test~”

As a result, most plans for developing ntarshom fields’ in tbe Beat.rfort Sea favor building a causeway to

support a pipeline to shore.

S& soils-+ potential problem in some -of H an Bay and the Navarin Basin-could require

either soil strengthening or more elaborate fwdation diisigns. P@*ti approaches used elsewhere to overcome soft soils include piles, wicks or drains, replacing the soil with gravel, cement infection to strengthen

soils, kwgerbear%g tmrfiwe areas for gravity structure, and dredging out the soft-bottom to reach freer

soil underneath. Structures for soft sea bottoms ham been ddgned for pre-lease sale technoioW verifkation and structure costing in l?kvarin Bay, but extensive site-$pecifk soil surveys would be requir@ for

final design of bottom-found~ or gravity stru~~

Finaily, strong bottom cuments and storm W~VCS @SW-@*~ti~des@ Considerations for

~mmums, piPlines, ad SuPpOrt ~stems in the NQrttxI @~IWW%X *fns* In the Nortons $to- ‘ayes

can cause liquef-ion in some of the finer sediments (e.g., near the Yukon delta). In the Navarm,

which has the most severe winds and waves of aU the Aladu@ A* #an.ning areas, a serni-submemib~e

-tit-the ~~t *le P@om W* =’v~* =-~-o=-–wodd ~ -u*d” me wit wo~d

maintain its position with anclmrs where bottom conditi.a~ are suitable, or with dynamic ~sitioning equipment including cornputcr-contro~~ main propulsion and thruster units and acoustic signals emitted by

beacons on the seafloor. Similar wmi-submm=sib~es have been used successfdy in the North Sea and eastern Canada under severe weather conditions.

,

Exp&3ratkm

the size of the field~’However, desi~ requirements for production structurti are more stringent than those

for expbrath due to the larger investment in wells and the longer service life of the equipment” me 2@

to 3&year life of a field implies a greater probability of encountering more severe environmental conditions

{e.g., the 100-year storm).
66 . Oil and Gas Technologies for the Arctic and Deepwater

The scenarios assume that gravel islands (possibly with cassion-retained protection) would be used

for field development in Harrison Bay and Norton Basin, and gravity platforms in Navarin Basin. The

oil would be treated on the gravel islands or gravity platforms, and stored in either onshore or offshore

storage tanks (Harrison Bay and Norton Basin) or in gravity structures (Navarin Basin). Alternatives to

gravity storage now under consideration by industry include moored tankers tied to an icebreaking, single

anchor leg mooring; totally subsea storage; and steel jacket platforms with internal storage.

Large gravel islands may become prohibitively expensive as water depth increases beyond 50 or 60

feet. An alternative preferred by some is the bottom-founded gravity structure similar to those used in the

Canadian and U.S. Beaufort Sea for exploratory platforms. Designs are proposed for many types of these

structures including conical shapes to reduce ice forces. Another advantage of such a structure is the ability

to construct it in one piece at a shipyard and then tow it to the site for installation, thus lowering onsite

construction costs substantially.

Infrastructure and Support Services

In addition to the severe environment, the primary consideration in designating infrastructure and

support services is the distance of the field from established bases onshore. For example, the established

facilities at Prudhoe Bay provide the basic infrastructure for operating in Harrison Bay. Work camps, maintenance shops, living accommodations, and catering operations already exist, and procedures for working

and coping with the environment have been established. However, reliance on the Prudhoe Bay infrastructure as the sole support base could have prohibitively high transportation costs, and a satellite base closer

to Harrison Bay would be needed.

Some support for Norton Basin exists at Nome, but it is not nearly as extensive as at Prudhoe. In

anticipation of increased oil activity, Nome plans to build a deepwater harbor—a causeway with docking

facilities. Alternatively, Dutch Harbor could be used as the support base.

Navarin Basin poses the greatest logistics problems of the three scenarios because it is so remote. Dutch

Harbor on Unalaska Island in the Aleutians-a World War 11 Navy base and already a base for oil company exploration operations and a center for fishing activity—could be a support base for Navarin. Dutch

Harbor is ice-free so all necessary supplies and equipment could be transported thereby conventional cargo

vessels year-round. It also is a potential location for a storage and transshipment terminal. Other developed Aleutian harbors such as Cold Bay have been considered but at present lack sufficient harbor facilities

or water depth. Even Dutch Harbor, however, is too far from the Navarin Basin to be the sole support

base, and a forward base may be established on either St. Matthew Island or St. Paul Island. Use of St.

Matthew Island poses environmental and regulatory concerns because it serves as a wildlife refuge.

Transportation

Selection of combinations of transportation modes are governed by the southern markets to be served,

reliability, magnitude of field development, costs, and the availability of spare TAPS capacity as North

Slope onshore production begins to decline in a few years. The most likely transportation scenarios for

the three production areas were chosen. Critical considerations include offshore pipeline depth sufficient

to avoid ice scour and ice keel gouging, and permafrost protection for subsea pipelines in Harrison Bay,

and the cost of various tanker and terminal variations for long-distance transshipment from Norton and

Navarin Basin. Some recent industry studies have shown that use of ice-reinforced tankers with icebreaker

suport is the most cost effective system for Navarin and Norton. Also, the use of a transshipment terminal

does not appear economical until production rates go beyond 1 million barrels per day.
Ch. 3—Technologies for Arctic and Deepwater Areas Ž 67

Arctic Scenarios

Parameters Harrison Bay Norton Basin Navarin Basin

Environmental conditions:

Temperature and wind chill . . . . . . . .Extremely low: –47°F, 15 knot

winds; –90°F wind chill temp.

Ice conditions ... . . . . . . . . . . . . . .Severe: 10-month coverage; within

shore fast ice zone; plane fast ice

7 ft, rafted ice 22 ft, ridges 75 ft

Winter daylight . . . . . . . . . . . . . . . . . . None in Dec. -Jan., 2.5 hr/day in

Nov., 6.5 hr/day in Feb.

Approximate distance from shore .. ..20 mi

Water depth . . . . . . . . . . . . . . .......50 ft

Other . . . . . . . . . . . . . . . . . . . . . . . . . Permafrost precautions to prevent

melting and subsidence

Exploration:

Number of wells . . . . . . . . . ........6

Type of rig. . . . . . . . . . . . . . . . . . . . . .Arctic land rig on gravel islanda

Development:

Peak production rate (B/D) . .......500,000

Type of platform . . . . . . . . . . . . . . . . .Gravel islanda

No. of platforms/islandsc . . ........7

Number of rigs . . . . .. . . . . ........2 per island

Total number of wellsc . ...........271

Field size (billion barrels) . . . . . . . . . . 2.0 d

Initial production (B/D). . ..........4,000

Infrastructure and support services:

Support base . . . . . . . . . . . . . . . . . . . . Prudhoe Bay; closer satellite base

Air service . . . . . . . . . . . . . . . . . . . . .Daily; Deadhorse (Prudhoe Bay area),

Fairbanks and Anchorage

Land access . . . . . . . . . . . . . . . . . . . .Year-round–Dalton Hwy from

Fairbanks; winter ice roads on land

fast ice

Sea access . . . . . . . . . . . . . . . . . . . . .Annual sealift for barges in open

water season (Aug. -Sept.)

Transportation:

To shore . . . . . . . . . . . . . . . . . . . . . . . Pipelines-buried beneath gouge

depth with permafrost protection

Moderately low: –36°F, 11 knot

winds; –72°F wind chill temp.

Moderate: 8-month coverage; smooth

ice 3.5-4 ft, rafted ice 15 ft,

ridges 75 ft; dynamic ice

movement

Some

40 mi

50 ft

Strong bottom currents, storm waves

and surges; potential for gascharged sediments

6

Jackup

125,000

Gravel isianda

4

2 per island

136

0.5

2,000

Dutch Harbor; some facilities in Nome

Commercial airport in Nome

None

Deepwater harbor planned in Nome;

Dutch Harbor ice-free year-round

for conventional cargo vessels

Onshore or offshore storage tanks to

offshore deep draft mooring and

transfer terminal for onloading to

250,000 DWT ice-reinforced

tankers with icebreaker escorts

Low: –11 oF, 25 knot winds;

-54°F wind chill temp.

Light-moderate: 5-month coverage;

smooth ice 3 ft, rafted ice 12-18

ft; ridge frequency more critical

than thickness

Some

400-700 mi

450 ft

Severe storms, wind-driven waves,

spray icing; remoteness poses

extreme logistics problems; soft

soils potential

6

Semisubmersible

500,000

Gravity platformb

7, plus 2 service

2 per platform

271 2.0 d

4,000

Dutch Harbor or Cold Bay; forward

base on St. Matthew Island or St.

Paul Island; 2 advanced service

bases

Commercial airport in Nome;

helicopter from forward base

None

Deepwater harbor planned in Nome;

Dutch Harbor ice-free year-round

for conventional cargo vessels

Storage in gravity structures;e

offshore deep draft mooring and

transfer terminal for onloading to

150,000 DWT ice-reinforced

tankers with icebreaker escorts’

Onshore . . . . . . . . . . . . . . . . . . . . . . . .Along-the-shore pipeline connects

with TAPS offshore; or pipeline to

west coast of Alaska with icereinforced offshore tanker terminal

aFor ~ fI w~r @ms and g~er in r+arfi~ BSy and Norton Eaeirr, savarai alternatives to gravel iSiarrdS exist and may be preferable depending on 9raVel availability, exact water depths.

soils, and othar site-specific conditions. The efternatives are concrete, ateai, hybrid structural built as caissons or cmplata tmttom-mounted units.

bprinciPi aftarnat~ piatform is a steel, pile-founded st~ure; ChOiCS depends WI s~ ~~t~s.

CTIM num~r of piatfotms and @is sslamd for each acanarfo is probably a miniMUm. Total nurnbr Of wdhl iOti@l mm.

dsuch a ~W ~~ ~ze is rare, and mis assum@on is dkpubyj by industry Isxperta. This report does not assume thSf this is the moat iikdy fieid Si=?e, bti onlY indicates how develop~nt

migM proceed with such a fieid size. eGra~ @~s ~~n u~d in the ~gh -her wnd~ions in t~ N@r SSS wffh a fsrgs Mkgm Of ~rfSnCS for fhlSr Sd Mditions ~d 110 iCS.

fTnnsw~t~n a~ernat~w i~iu~a pi@ne t. St Mafi~ i~nd oroneof the prfMiof i$~nds for~n~ @ ~nkors; ws @ a tran~hi~l’lt terrnir@i ill the Aieutians; and Use Of icebraaking tankers.

SOURCE: office of Technology Assessment.
68 ● Oil and Gas Technologies for the Arctic and Deepwater

Harrison Bay Scenario

(Beaufort Sea)

Planning and permitting I l l

Construct exploration Island

Explora tion and d g

Prepare and submit plans

I

1234 5
rton Basin Scenario

orthern Bering Sea)

\
70 ● Oil and Gas Technologies for the Arctic and Deepwater

Navarin Basin Scenario

(Central Bering Sea)

Location of discovery

I I I I 1

Planning and permitting (

I I I

I

Explo ration and d elineation drilling

Discovery

I

Construct platforms #1, 2 and 3 and facilities

I I I I I I I I I I I I I I I I I

Years

Schedule

Semisubmersible exploration rig

Gravity production platform
Ch. 3—Technologies for Arctic and Deepwater Areas • 71

Figure 3-10.— Alternative Arctic Production Structures

Gravel islandsa

— 1

Concrete or Jacket structured

steel towersc

aM~~t ~ff~hore exploratory dr[l[lng has been done from these man-made Islands and the first offshore development (In 40 ft water) Is Ilkely to use a gravel Island plat ”

b$~~such ~a~510n.type platform now In operation In Alaskan Beaufort for exploratory drlllm9 (Cf DS)

c

These types of structures would be extension of technology developed for North Sea

dThese structures may be extension of both North Sea and Cook Inlet developments

SOURCE Proceedings DOI-EEZ Symposium, Nov. 1983

sea ice. Other programs have made use of natural

islands to make load measurements. 9

Ice Reconnaissance

Increased surveillance from satellites and by aircraft is needed to provide real time data. Ice

surveillance is important for structural design purposes, logistics, and tanker transportation design

and planning. Many companies have utilized all

relevant satellite data to describe ice conditions. Ice

movements have been measured for several years

by wireline movement stations and drift buoys.

‘Artl< Petroleum operators Association, I~csi-ription of’ Research

Projkts ((;al~aq, (;anada, 1982 and 1983); Amcrlcan Society of Nlcc han ]( al F.nqinccrs, Procccdin,qs of’ the OL%horr Alechanirs and.4 r(--

tic I’;n{qjnccr]n,y SJ”rnposium (Ihicv. Orleans, 1 984); and Proceedings

c)f the Offshore “1’cchnolo,q (;onfi’rcncc (Ma> 1984).

Helicopters and fixed wing aircraft are used to assist

in making ice forecasts for operations that could

be hampered by ice invasions.

Marine Pipelines

More rapid and effective trenching techniques

below ice-gouge depths, and rapid and effective

techniques for alignment, connection, and repair

of pipelines are essential. Recognizing that Arctic

pipelines are a critical future design problem, more

cost-effective installation techniques and designs for

areas with warm subsea permafrost are being investigated. Repetitive surveys are being conducted

in the Beaufort Sea to assess gouge depths and the

rate at which gouges are being filled by wave and

ice actions on the seafloor.
72 ● Oil and Gas Technologies fof the Arctic and Deepwate r

Photo credit: Mobil Oil Co.

Concrete gravity platform in the North Sea

Tankers search is needed to collect seafloor response data,

Development of design data to permit more con- to develop wave propagation and attenuation

fidence in the design of icebreaking tankers, espe- models, and to establish soil response characteristics. cially those which could successfully operate in the

Beaufort and Chukchi Seas on a year-round basis, Those projects are indicative of the scope of rewill be important. search and engineering programs underway by the

oil industry. In addition to programs that are proSeismicity prietary to individual companies, over 275 joint industry programs that deal with wide-ranging

For two of the planning areas, St. George and aspects of Arctic technology have been undertaken

North Aleutian Basins, a unique problem exists by member companies of the Alaska Oil and Gas

concerning strong motion seismic (earthquake) Association (AOGA) (see table 3-4). Many Canaactivity associated with the subduction of the Pa- dian design projects, strength tests, and model tests

cific plate beneath the North American plate. Re- are also applicable to the U.S. offshore,
Ch. 3—Technologies for Arctic and Deepwater Areas ● 7 3

Table 3-4.—Summary of Cooperative Arctic Research Projects

Area

Subject N. Aleutian St. George Navarin Norton Sound Chukchi Beaufort General

Ice properties, physical . . . . . .

Ice properties, mechanical . .

Waves . . . . . . . . . . . . . . . . . . . . .

Currents . . . . . . . . . . . . . . . . . . .

Geotechnical . . . . . . . . . . . . . . .

Structures . . . . . . . . . . . . . . . . .

Oil spill. . . . . . . . . . . . . . . . . . . .

General technical . . . . . . . . . .

Transportation c 

. . . . . . . . . . . . .

Cost wells . . . . . . . . . . . . . . . . .

Whale mammals . . . . . . . . . . . .

0—

3

2

6

2—

—

—

1

—

5—

4

3

4

4—

—

1

2

—

15

—

2

3

2

7

—

—

2

1—

14—

2

4

4

4—

—

2

2

1

14—

1

1

2

4—

—

1—

—

62

—

9

7

11

17

3

1

6—

3

—

15

1—

2

19

9

14

2

—

1

alce Mechanical property studies are considered common to all lease areas.

bThis includes equipment used for research, such as stress sensors, and operations, i,e,, ice movement detectors ar?d nleasurenlent devices.

cThis includes pipeline and tanker studies.

SOURCE: Alaska Oil and Gas Association (AOGA), Technical Subcommittee of the Lease Sale Planning and Research Committee, January 1985.

THE DEEPWATER FRONTIERS

Overview

The petroleum industry has developed technologies incrementally as exploration and production

have moved from shallow to deepwaters. In this

progression, as the severity of the environment has

increased, additional design requirements have

been recognized. To meet these requirements, offshore structures have become larger and more

costly. The logistic support for construction and

operation has likewise increased. Government

agencies have also had to increase their capabilities

to monitor industry’s activities to assure safety and

environmental protection.

This section discusses technologies for oil and gas

development in water depths greater than 1,320

feet. There has been extensive exploration at such

depths but no production to date. Many of the technologies required for deepwater production are

available although not applied commercially at this

time, As new technologies are applied to deepwater

frontier areas, testing and verification will be

needed. Some new concepts may be abandoned and

others developed further. Safety is a major concern

in offshore engineering and construction. Technologies used must provide reliability, not only to

assure human safety but also to minimize the risk

of losing a platform or other structure and to minimize operational costs.

A number of technological areas are critical in

deepwater petroleum development. These include:

1) structural design, which ranges from the metallurgy of the steels or composition of materials used,

through welding techniques and ocean floor platform foundation engineering; 2) techniques for installation, maintenance and repair of structures,

risers, and pipelines; 3) drilling, well control, and

completion; and 4) technologies for support operations, such as diving and navigation. Human diving capability is limited to approximately 1,640 feet,

with only experimental dives to 2,300 feet. Thus,

one-atmosphere manned vehicles and remotely controlled unmanned vehicles may become increasingly

important for support services. Navigation technologies are important during seismic surveys, exploration drilling, and platform and pipeline installations. This includes acoustic, radio, and

satellite technologies for seismic survey navigation;

directional drilling; and ship, submersible, and

remote vehicle operations.

Historically, the offshore petroleum industry has

a good record of developing adequate technology

to meet ever more challenging conditions as development has moved to more hostile environments

farther offshore. Some existing systems—especially

compliant platforms and subsea wells—have the capability of fairly direct extension to deeper water.

Others—e.g., deepwater risers, control and well
74 ● Oil and Gas Technologies for the Arctic and Deepwater

maintenance technologies—may need further development for use in deep water.

New technological achievements are being made

continually as new resource discoveries are made

in deeper waters. For example, in Norske Shell’s

Troll Field in 1,148 feet of water in the North Sea,

a large concrete gravity structure is under detailed

design and testing. Exxon has initiated production

from its Lena guyed tower in approximately 1,000

feet of water in the Gulf of Mexico (see figure 3-

11). Other structures are planned for Gulf of Mexico discoveries in up to 1,500 feet of water.

In addition, advanced conceptual designs exist

and some component testing has been accomplished

for systems to be used in water depths up to 2,000

to 2,500 feet. Among these systems are Exxon’s

submerged production system, Chevron’s subsea

wellhead system, and Conoco’s tension leg platform. It is reasonable to expect that in a few years

several types of structures and production systems

will be built for use in these water depths.

Figure 3-11 .—Guyed Tower

Beyond about the 2,500-foot depth, there has not

yet been as much activity aimed at developing specific production systems because opportunities for

significant petroleum discoveries at that depth are

still more speculative. However, oil exploration in

deepwaters of the U.S. Exclusive Economic Zone

(EEZ) is underway. Sonat’s drillship Discover

Seven Seas drilled for Shell Offshore, Inc., in water

depths of more than 6,000 feet in the Wilmington

Canyon area of the Atlantic coast during 1983-84.

Other leases have been sold in the Atlantic with

water depths of about 7,500 feet. Blocks were leased

in water depths of approximately 5,800 feet in the

April 1984 Gulf of Mexico sale. And blocks in approximately 10,000 feet of water are now being offered offshore California.

Deepwater achievements of various system components are shown in table 3-5. The history and

status of subsea well and facility water depth records

are shown in figure 3-12.

Based on its deepwater drilling and production

achievements, the petroleum industry believes that

there are no significant technological limits to operations in up to 8,000 feet of water. Petroleum basins

which are developed in the deepwater frontiers will

require new technologies which will be deployed

for the first time. Because these new systems are

being developed continually, it may not be reasonable to establish water depth or other regulatory

limits based on present technologies. But sufficient

precautions must be taken to assure that the govTable 3-5.—Deepwater Drilling and Production

Achievements (through March 1985)

Record

water depth

experience

Component or to date

activity (feet) Place, date

Exploratory drilling ., . . . . . . . . 6,952 U.S. Atlantic, 1984

Development drilling . . . . . . . . . 2,500 Mediterranean, 1983

Fixed steel/production

platform . . . . . . . . . . . . . . 1,025 Gulf of Mexico, 1978

Guyed tower production

platform . . . . . . . . . . . . . . . 1,000 Gulf of Mexico, 1983

Floating production platform . . 460 Tunisia, 1982

Tension leg platform . . . . . . . . 485 North Sea, 1984

Subsea wellheads . . . . . . . . . . 1,007 Brazil, 1984

Subsea production system . . . . 500 North Sea, 1982

Deepwater pipeline . . . . . . . . . . 2,060 Sicily, 1979

Tanker loading systems . . . . . . 530 North Sea, 1980

SOURCES: Proceedings of the Offshore Technology Conference (1984); USGS

Circular 929, EEZ Symposium Proceedings (November 1983);

Ocean Industry (July 1984); Engineering News Record (Aug. 16,

1984); 0il and Gas Journal (July 16, 1984 and Oct. 15, 1984)
Figure 3-12.—Subsea Wells & Production Facilities

History and Current Status

1950 1960 1970 1980 1990

Year

SOURCE DOI EEZ Symposium, November 1983, update 1984

ernment regulations imposed on offshore operations

are appropriate and the responsible government

agencies monitoring offshore operations have the

skills and technology necessary for judging the adequacy of industry’s engineering designs, equipment, and procedures.

Field Characteristics

The three key offshore planning regions including deepwater frontier areas are the Atlantic, Gulf

of Mexico, and the Pacific. This section describes

the field characteristics for these three regions.
76 ● Oil and Gas Technologies for the Arctic and Deepwater

Atlantic

Since there have been no commercial oil discoveries in the Atlantic region, it is not possible to predict the field characteristics. There is reason to

believe, however, that some of the reef formations

present in the Bay of Campeche, Mexico, may extend northward to the deepwater basins in the

Atlantic. If this is the case, oil fields could be similar to the prolific offshore fields with high well flow

rates now producing in Mexico, If such fields were

found in the Atlantic, it would be a significant commercial discovery.

Gulf of Mexico

The Gulf Coast reservoirs range in size from very

small (less than 5 million barrels of recoverable oil)

to major oil fields of over 100 million barrels. The

median oil field size is 29 million barrels and the

mean size is 66 million barrels. Of the 105 analyzed

oil fields, 21 are over 100 million barrels. These

reservoirs also vary widely in other characteristics.

Formations often consist of unconsolidated sands

which require gravel packing and hole conditioning. Generally, production rates are modest. A

1,500-barrel-per-day well in the Gulf of Mexico is

considered very good. Drilling rates (feet per day)

are high. This high drilling rate may not be sustainable in deepwater if the upper formations require several casing strings to be set near the surface. More often 4 weeks is required to drill a

deepwater well. As experience is gained, these deepwater operations may speed up.

Pacific

All the known West Coast oil fields lie off central and southern California. Many of these fields

produce relatively heavy oil. In addition, the oil

often contains sulfur. The West Coast oil is shipped

to the Gulf Coast for refining.

Drilling is slower and more difficult in this region. Structures are often faulted and are hard to

delineate. However, there are some very large and

productive fields in California. The Point Arguello

field is one of the largest discoveries in U.S. (Outer

Continental Shelf (OCS) history. Recoverable reserve estimates range from 400 to 500 million barrels, and combined field flow rates are projected

to reach 160,000 barrels per day by the end of the

century. In addition, total flow rates from the fields

off Santa Barbara County are expected to reach

450,000 barrels per day by the early 1990s. The

east Wilmington field further south in Long Beach

produces 120,000 barrels per day. These three fields

have the highest production rates in the lower 48

States.

West Coast drilling rates offshore are slow by

comparison with the Gulf Coast. A typical offshore

well requires 6 to 8 weeks to complete. Gravel packing is often necessary. If more than one reservoir

is present at a drill site, the casing may be perforated to enable the wells to produce from multiple zones.

The low gravity, asphalt-base oil means that

processing facilities are complex. This, coupled with

the thick formations, makes the typical West Coast

platforms larger than Gulf Coast platforms. Sixtywell platforms are common, and large expensive

production facilities are the norm. It can be expected that this trend will continue in deep water.

Environmental Conditions

Important environmental parameters that affect

the design of production platforms and systems are

summarized in table 3-6 for the Atlantic, Gulf, and

Pacific regions. These values are based on general

industry practice. Conditions that are peculiar to

a specific region are discussed below.

Table 3-6.—Deepwater Environmental Design

Conditions

Typical

Maximum wind current

velocity* ● Maximum velocity*

(knots) 100 year (surface to

(1 hour wave height 200 ft.)

Region duration) (feet) (knots)

Atlantic . . . . 90 85 3.0

Gulf . . . . . . . 90 70 3.0

Pacific . . . . . 60 60 2.0

“Exact value of current velocity varies and is highly dependent on precise

location, particularly in the Atlantic and Gulf,

“ “For 10 meter elevation; higher elevations may be subject to higher velocities

and gusts.

SOURCE: Office of Technology Assessment.
Ch. 3—Technologies for Arctic and Deepwater Areas . 77

Atlantic

Hurricanes, other severe storms, and the Gulf

Stream are major environmental factors in the

Atlantic region. The Gulf Stream presents problems in both exploratory drilling and for production systems if commercial discoveries are in areas

affected by its currents. The current velocity is up

to 5 knots near the surface and in the range of 3

knots to a depth of more than 1,000 feet. This high

current velocity may require streamlined risers for

exploratory drilling and must be considered in the

design of compliant structures if they are used. The

major impact of the Gulf Stream is confined to the

southern portion of the Atlantic region. The MidAtlantic a-rid North Atlantic areas

affected since they are not in the

the current. However, warm core

are only slightly

main stream of

eddies may spin

off the Gulf Stream and affect systems in these

areas.

Seafloor instability, especially on the Continental Slope, may require that specific sites be avoided

or that special foundation stabilization techniques

be used and/or developed. Other environmental

conditions in the Atlantic region generally are less

severe than in the North Sea and more severe than

in the Gulf of Mexico. The design methods, as well

as the operational experience gained from the Gulf,

probably can be upgraded to meet Atlantic development requirements.

Gulf of Mexico

Hurricanes are also a major environmental factor in the Gulf of Mexico. Industry has a great deal

Photo credit: Scripps Institution of Oceanography

Rough seas are an important environmental design condition in offshore frontier areas
78 . Oil and Gas Technologies for the Arctic and Deepwater

of experience in designing fixed offshore structures

to withstand the high winds and waves generated

by these intense storms, and this experience recently

has been applied to Exxon’s Platform Lena which

is a compliant structure. Mud slides are another

unusual environmental factor in the Gulf. These

slides may cause foundation instability in some

areas. Another factor is the Gulf of Mexico loop

current and the eddies which are produced by that

current. These eddies affect operational practices

and the design of structures since they may cause

vibrations which could lead to metal fatigue or other

failures. Generally, in the Gulf, there is a wealth

of experience to draw upon as development moves

into deep water.

Pacific

The wind and wave conditions in the Pacific region are less severe than either the Atlantic or the

Gulf of Mexico, but earthquakes area factor which

must be considered in system designs. Design criteria and analytical methods have been developed

for the entire West Coast, and these have been applied successfully to numerous offshore structures.

Earthquakes should not pose serious problems for

properly designed compliant structures since the

natural vibration response periods of these structures are well outside the high energy portion of

the earthquake spectrum. Soil characteristics must

also be considered in system designs for the Pacific

region because of the steep slopes present in some

areas.

Technology Development

Exploratory Drilling

The offshore drilling industry currently has a fleet

of 13 drillships and semi-submersibles capable of

drilling in waters deeper than 3,000 feet. Of these,

four drilling units are capable of drilling in 6,000

feet of water and one in 7,500 feet of water.

Several technical advances have made this deepwater capability possible. These include: 1) dynamic positioning utilizing controllable pitch

thruster propulsion units and computerized automatic station-keeping systems (see figure 3-13); 2)

reentry systems utilizing television and sonar instead of guidelines; 3) electrohydraulic blow out

preventer control to reduce signal transit time; and

4) marine risers equipped with syntactic foam

buoyancy material and improved riser couplings.l0

Limitations to exploratory drilling in very deep

water come primarily from environmental conditions and a low formation fracture gradient. Excessive current velocities (approximately 5 knots or

greater) could prevent some dynamically positioned

drilling units from maintaining their position because of the large amount of power required to

counteract such forces. Also, wave heights exceeding 20 feet can interrupt drilling operations

from a dynamically positioned drill ship. Some of

these limitations may be overcome through the use

of a dynamically positioned semi-submersible with

substantially greater station-keeping capability than

existing vessels. Abnormally high formation pressures, particularly at shallow formation depths, can

also cause difficulty in deepwater drilling and could

limit or prevent development of some deepwater

reserves.

Field Development

Nearly all offshore fields to date have been developed using fixed-leg platforms. During the

1970s, industry progressed from the capability to

design and install fixed-leg platforms in about 400

feet of water to design and installation for the current record depth of 1,025 feet for Shell’s Cognac

platform in the Gulf of Mexico. Designs also have

been completed by Exxon for a fixed-leg platform

for installation in 1,200 feet of water in the Santa

Barbara Channel. Technically, fixed-leg platforms

can be built for a water depth of 1,575 feet or more.

However, due to the large amount of steel required

and limitations of fabrication and installation methods, there is probably an economic limit for these

structures at a water depth of about 1,480 feet.11

There are several concepts for extending water

depth at which production systems can be installed;

for example, the guyed tower, the buoyant tower,

IIJA, S, Johnson and G, 0. Smith, ‘ ‘The Technology of Drilling

in 7,500 Feet of Water’ (Society of Petroleum Engineers, Paper 12793,

1984); and J. C. Albers, “Exploratory Drilling Systems” (Outer Continental Shelf Frontier Technology Symposium, 1979).

] IF. P. Dunn, ‘ ‘Deep Water Drilling and Production Platforms in

Non-Arctic Areas” (National Academy of Sciences, 1980); and R.

L. Geer, ‘‘ Engineering Challenges for Offshore Exploration and Production in the 1980s’ (BOSS Conference, 1982).
Ch. 3—Technologies for Arctic and Deepwater Areas • 79

Figure 3-13.—Dynamic Positioning for Deepwater Drilling

LBS hydrophore

SOURCE: Proceedings of the Offshore Technology Conference, 1984
80 ● Oil and Gas Technologies for the Arctic and Deepwater

the tension leg platform, and the subsea production system. All but the subsea production systems

are ‘‘compliant structures, which are designed to

move slightly with environmental forces of wind,

waves, and current as opposed to conventional

structures which rigidly resist such loads.

The guyed tower is a tall, slender structure that

requires less steel than a fixed-leg platform. Guy

lines or anchor lines are used to resist lateral forces

and to hold the structure in a nearly vertical position. Exxon has recently installed the first guyed

tower, Lena, in 1,000 feet of water in the Gulf of

Mexico. The platform, with space for 58 wells, is

secured with 20 guy lines, eight main piles, and

six perimeter torsion piles.12 Current technical opinion is that guyed towers are structurally and economically feasible in water depths to about 2,500

feet. Beyond these water depths, the guyed towers

will require much greater amounts of steel to maintain an acceptable stiffness.

The buoyant tower is a tall, slender structure like

the guyed tower but is maintained in a vertical position by large buoyancy tanks rather than by guy

lines. Rotation at the base is accounted for either

by an articulated joint or by a flexible foundation.

The tension leg platform is a floating platform

fixed by vertical tension legs to foundation templates on the ocean bottom. OTA has selected a

tension leg platform for its hypothetical deepwater

scenario (see box). Buoyancy is provided by the

pontoons and columns of the hull. The buoyancy

that is in excess of the platform weight maintains

the legs in tension in all loading and environmental

conditions. The floating hull of the tension leg platform, similar to that of a semi-submersible, is

secured at each corner by a number of so-called tendons. The hull pulls upon the tendons so that they

never go slack, even in the trough of the maximum

design wave and when carrying maximum operating loads.

The substantial advantage of the tension leg platform is its relative low cost sensitivity to increases

in water depth. The principal design influence of

increasing water depth is in the tendon and riser

lengths, with the hull size and weight increasing

relatively slowly with water depth. The main disadvantages of a tension leg platform are the operational complexity of its well and tendon systems

relative to fixed platforms and its limited deck load

capacity.

The first tension leg platform was installed in

1984 by Conoco in 485 feet of water in the North

Sea. This probably is not an economical water

depth for a tension leg platform, but its installation in the North Sea will provide the experience

and information needed to successfully install these

units in deeper waters.

Practical application of tension leg platforms will

start where it is no longer economically attractive

to construct a fixed-leg platform. This water depth

is estimated to be around 1,500 feet, depending on

location. For intermediate depths of 1,000 to 2,500

feet, the guyed tower is thought to be the attractive alternative. Theoretical maximum water depths

for tension leg platforms are estimated by Conoco

to be 6,000 feet by the year 1990 and 10,000 feet

by the year 2,000.

Subsea production systems are also a major alternative for deepwater field development. With these

systems, wells are drilled from a floating rig and

completed on the seafloor. Several such systems

have been extensively tested in operations in shallow

water. These include Exxon’s system in the Gulf

of Mexico (see figure 3-14), Hamilton’s Argyll Field

in the North Sea, and Shell/Esso’s system in the

Cormorant Field in the North Sea.

Currently, there are more than 100 offshore

subsea well installations in operation in water

depths of up to 960 feet. An additional 36 subsea

well completions currently are scheduled for installation. *3 One of these is a subsea well completion by Chevron offshore Spain in a water depth

of 2,500 feet.

Subsea well completions can be either “wet’ or

“dry” systems. The wet system is relatively insensitive to water depth and can be installed in deepwater in the same manner as shallow water. Its application is limited only to the water depth capability

of the floating drilling unit and the flowline installation technique, In the dry system, the well head

12P. H. Kelly, F. B. Plummer, and P. J. Pike, ‘‘The Lena Guyer

Tower: A Pioneering Structure” (Proceedings of the DOT Conference, 1983).

13M. Tubb, “ 1983 Subsea Completion Survey, ” Ocean Industry

(October 1983).
Ch. 3—Technologies for Arctic and Deepwater Areas • 81

Deepwater Technology Scenario

To assess deepwater technology, OTA selected one hypothetical prospect located offshore the central

California coast approximately 3$ miles west of Point Conception in water 3,000 to 4,100 feet deep. Assumptions about field conditions, exploration and development, infrastructure and support services, and transportation for this deepwater scenario are shown in the accompanying table. It should be noted that the

assumptions made for this area are illustrative, and actual conditions may vary substantially. The oil accumulation could be deeper, the gravity of the crude could be sour, and well spacing might need to be

closer. All of these factors would increase the cost of development and change the technical approaches

chosen for this scenario.

Schedule

The schedule begins with the lease sale and ends with the completion of development drilling-a total

of 13 to 14 years. First production is assumed to occur 10 years from the lease sale date. This schedule

is probably optimistic because it assumes the minimum time to obtain the necessary governmental approvals.

It also assumes that detailed design of the platform will begin at the time of discovery and proceed concurrently with permitting and approval. Timeframes would also increase if the area is more difficult to develop

than postulated (e.g., heavier crude, sour crude, nonsircular field), or if two platforms are required instead

of one.

Exploration and Development

Water depth in the scenario area is within present industry capabilities for exploration. Several

dynamically positioned drilling units, ship-shape and semi-submersible, currently are able to drill exploratory

wells in water depths of 6,000 to 7,500 feet. Drilling units of this type are equipped with computer controlled main propulsion and thruster units. The unit is kept on location by these thrusters with positioning

data from a continuous acoustic signal emitted by one or more beacons located on the seafloor. The use

of this dynamic positioning equiment has made these drilling units independent of the constraints imposed

by a mooring system.

Development of a discovery in a water depth of 3,000 to 6,000 feet appears to be technically feasible

but has not yet been achieved. Several development methods are possible, including tension leg platforms,

floating production systems, and subsea production systems. The method selected for this scenario is the

tension leg platform with surface completed wells. These have been designed for water depths up to 3,000

feet, but there has not yet been a commercial discovery in such depths. A subsea production system is

an alternative for this scenario but most designs to date are not self-contained units; storage and processing

facilities would be required on a separate platform. Satellite subsea wells oculd be used in conjunction with

a tension leg platform especially with a more elongated field shape.

Sixty directional wells would be drilled from the tension leg platform and would have individual conductors from the ocean bottom to the lower deck for completion and hook-up in a manner similar to (although operationally more complex than) methods used for fixed, bottom-founded platforms. Alternative

designs provide for incorporation of the conductors inside the mooring legs or for completing the wells on

the seafloor. With the latter method, an ocean floor manifold would be required and one or two risers would

bring oil to the surface.

Transportation and Infrastructure

For environmental reasons, California State prefers a subsea pipeline rather than shuttle tankers to

transport crude oil to shore. Deepwater pipelaying capability has advanced to where the technology (but

not the actual equipment) exists to install a 20-inch pipeline in water depths of 7,500 to 10,000 feet. However, actual experience has been limited to water depths of about 2,000 feet. A tensioned 20-inch pipeline

riser would be installed between the ocean floor template and the deck of the tension leg platform. The

pipeline would be connected to the riser through a pull-in assembly.
82 ● Oil and Gas Technologies for the Arctic and Deepwater
Ch. 3—Technologies for Arctic and Deepwater Areas ● 8 3

Deepwater Scenario

(Offshore California)

 Location Of discovery

Riser and control system

I

Approval of plans by governmental agencies

I I I

Design and contruct offshore facility

I

L I Development drilling

I

I

Design and construct pipeline

I

I

Firsl production

I I 1 ,

I

3 4 ‘ 5 6 7 8 11 12 13 14 15 16 17 18 19 20

Years

Schedule

Tension leg production platform
84 • Oil and Gas Technologies for the Arctic and Deepwater

Figure 3-14.—Subsea Production System

SOURCE: Exxon.

is housed in a dry, atmospheric chamber on the

seafloor. Flowline connection and maintenance

work can be performed by workmen inside the

chamber in a normal atmospheric, shirt-sleeve environment. The workmen are transported to and

from the chamber in a tethered, atmospheric diving bell which mates to the chamber allowing completely dry access for nondivers. Current development of subsea systems seems to favor the wet

instead of the dry system.14

Most of the subsea installations are single well

completions with the well producing through a

flowline to shore or to a fixed or floating platform.

In a few installations, the subsea wells are tied into

“Robert C, Visser, ‘ ‘Deep Water Drilling and Production Capabilities, Department of Interior Hearing (May 1977).

an underwater manifold with a common production riser to a floating production unit. One such

system is represented by Shell/Esso’s Underwater

Manifold Center recently installed in 500 feet of

water in the North Sea (see figure 3-15). This system provides for a number of subsea wells clustered

on an underwater template with associated manifolding and control equipment. Maintenance operations are performed with a remote vehicle connected to a production platform located several

miles away. 15

An inherent limitation of the subsea production

system is the need to have surface facilities to proc15T, BaStiaanSe and J. R. Liles, ‘ ‘Overview of the Central Cormorant Mannifold Centre Project ( 1974- 1983), Proceedings of the

Offshore Technology Conference (1983).
ess the oil and gas for transport to market. Additionally, all well work that cannot be handled by

thru flow-line techniques requires an expensive,

floating platform. Artificial lift to bring the product to the sea surface is complex and difficult to

maintain with hydraulic or electric pumps. However, gas lifting is suitable for these subsea wells.

The application of subsea production systems is expected to be more suited to the development of satellite reservoirs where oil can be routed to a preexisting platform.

One of the assumptions that was made for OTA’s

deepwater scenario was an essentially circular field.

This enables the use of a single tension leg platform from which directional development wells can

be drilled to fully develop the discovered reserves.

In reality this is rarely the case and, particularly

with a long and narrow field, it may be desirable

to use subsea completed wells in conjunction with

a tension leg platform. This approach may make

it possible to more completely drain the reservoir

and to develop a deepwater field more economically.

Transportation

Conventional pipelaying techniques such as the

lay barge, reelship, surface tow, and bottom tow

will require adaptation before they can be applied

to deepwater situations such as those involved in

offshore California. While deepwater pipelaying capabilities have improved considerably, driven particularly by the need to lay pipelines in deepwater
86 ● Oil and Gas Technologies for the Arctic and Deepwater

areas of the Mediterranean, such techniques and

required equipment are not fully developed, widely

available, or in commercial demand. Semi-submersible, ship-shape, and more conventional bargeshape hulls have been used in the current generation of deepwater pipelay vessels. Other more advanced vessel designs are based on inclined ramp

or J-curve methods as opposed to using the conventional ‘‘stinger. Bottom-tow or flotation techniques are also considered viable deepwater techniques. 16

Pipelay capabilities have advanced considerably

in order to deal with the specific problems attached

to deepwater pipeline installations. These problem

areas include: pipe failure due to propagating

buckle phenomenon, longer unsupported span

lengths, higher strain levels, more severe sea states,

longer pipe exposure time during pipelays, and the

need for greater accuracy in the control of vessel

motions, new mooring techniques, and new classes

of thicker diameter pipe.

In general, most of these problems have been successfully solved or are being solved through improved techniques, equipment modifications, or

changes in basic technological applications. Vessels

capable of laying pipe in deep water may now incorporate the following features: automatic position control systems; high tension capacity; advanced mooring systems; automatic welding,

including single-station pipe joining or double joining capability; large pipe storage capacity; and use

of computer simulations to optimize a pipelaying

spread.

At the present time, it appears feasible that pipelines up to 20-inch (51 centimeters) diameter can

be laid in water depths of 4,000 feet using existing

or slightly modified equipment, although proven

installation has taken place in only 2,000 feet.

Saipem’s dynamically positioned semi-submersible

pipelayer Castoro SEI laid 3 20-inch lines across

the Strait of Sicily in the Mediterranean in 1979

in waters to 2,000 feet.

An alternative to pipeline transportation of the

crude oil to shore is the use of a floating storage

and loading system from which shuttle tankers

would move the crude to market. A variety of systems have been developed to provide floating offshore storage and/or treatment and loading systems

for transferring oil to shuttle tankers. Offshore storage and loading systems were initially designed to

allow continuous production in areas with severe

weather conditions or with deep trenches inhibiting

pipelines such as in the North Sea. These systems

now have been greatly expanded or modified to aid

in the use of subsea production systems, to allow

marginal field development, and to initiate production from a field as early as possible.17

Floating ship-shape or semi-submersible production facilities and combined production/storage/

loading facilities recently have become attractive

to offshore operators. Floating production units are

gaining acceptance by the oil industry as alternatives to fixed platforms for deepwater applications.

Many floating systems are already in operation,

mostly converted semi-submersible drilling rigs and

tankers. State-of-the-art installations include Shell’s

multiwell floating production, storage, and offloading system for Tunisia’s Tazerka field in 460 feet

which is tied-in to subsea wells. No systems of this

type are currently available for use in water depths

in excess of about 3,000 feet.

l~Dames & Moore, GMDI, and Belmar Engineering, ‘‘Deep water

Petroleum Exploration and Development in the California OCS,

report prcparcci lor the Minerals Management Service (January 1984).

17D. M. Coleman, “Offshore Storage, Tanker Loading, and

Floating Facilities, Outer Continental Shelf Frontier Technology

Symposium (1979); and ‘‘A Complete Producing System for Deep

Water , Proceedings of the DOT Conference (1983).
Chapter 4

Federal Services and Regulation
Contents

Overview. . . . . . . . . . . . . . . . . . . . . . . ................. .

Research and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Federal Research Programs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Future Research and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Federal Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

Environmental Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Navigation Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Icebreaking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

. . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . .

. . . . . . . . . . . .

. . . . . . . . . . . . .

. . . . . . . . . . .

Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Injury and Fatality Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Safety Regulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

Arctic Search and Rescue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Improving Offshore Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLES

Table No.

4-1. Representative MMS-Sponsored Arctic and Deepwater Research Pr

4-2. Coast Guard Polar Icebreakers , . . . . . . . . . .

4-3. Comparative Government Polar Icebreaker Figures

4-4. Condition of Coast Guard Icebreaking Fleet

4-5. Comparable Industry

Figure No.

Rates (

jects 

. . . . . . .

. . . .

. . . . . . . . . .

983) . . . . . .

4-1. Loran-C Coverage of Alaska . . . . . . . . .

4-2. Offshore Drilling Injury Rate . . .

. . .

.

. . .

. .

Page

89

89

89

91

92

92

96

98

103

104

106

109

111

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9 9

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9 9 . . .

 . 100

106

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9 6

105
Chapter 4

Federal Services and Regulation

OVERVIEW

The oil and gas development process largely is

controlled by private industry after leasing lands

from the Federal Government. However, industry must adhere to the terms of the leases which

include safety and environmental regulations and

stipulations. There is, therefore, a significant Federal responsibility to develop effective environmental standards, establish safe practices, monitor development activities, inspect operations,

enforce regulations, and provide backup for emergency situations. These are broadly defined as regulatory responsibilities.

In addition, the Federal Government performs

a number of public services which can affect the

pace, the cost, and the reliability of future offshore

development. Some of these services are provided

for multiple public uses and offshore development

is just one of these. Satellite data collection and provision of navigation systems are examples. Other

services may be provided to fulfill broad national

needs. Basic and applied research that will add to

general knowledge of ice mechanics, oceanography,

and materials applications in the Arctic are examples.

The Federal Government is both a regulator

(e.g., of personnel safety) and a facilitator (e.g.,

in providing environmental information) of offshore

development. Key questions about these two Federal

●

●

●

●

responsibilities are:

Are present technology and institutional arrangements adequate for meeting Federal

responsibilities?

Is the level of Federal involvement in the development of Arctic and deepwater frontiers

adequate?

Does the present level of Federal activity in

these areas adequately safeguard the public interest?

Is the division between Federal and private efforts appropriate?

RESEARCH AND DEVELOPMENT

The level of difficulty and the technical complexity of offshore petroleum systems in Arctic or deepwater regions dictates the need for substantial research and development efforts by industry and

government. Industry sponsors research directed

at developing or improving cost-effective and environmentally safe oil production systems. The Federal Government sponsors research which may

enable it to perform its regulatory or service functions and research which advances the state of the

art and knowledge in materials, environmental conditions, and technology.

Federal Research Programs

Although no major Federal program is focused

on long-range development of Outer Continental

Shelf (OCS) deepwater or Arctic frontier technologies, some work of this type is sponsored by the

Sea Grant Program. The lack of this type of research may be partly a result of the executive

branch and petroleum industry views that such efforts are properly left to private companies rather

than the government. However, several Federal

agencies have direct or indirect missions which re89
90 ● Oil and Gas Technologies for the Arctic and Deepwater

quire research activities related to the development

of offshore petroleum resources. These are the Department of the Interior (DOI), the National

Oceanic and Atmospheric Administration (NOAA),

the U.S. Coast Guard and the Maritime Administration (MarAd) of the Department of Transportation, and the Department of Energy (DOE). In

addition, the Office of Naval Research (ONR), the

National Science Foundation (NSF), and the U.S.

Army support Arctic research efforts which have

spin-offs or goals which are related to offshore petroleum work.

As the regulating agency for the development of

offshore oil and gas, the Minerals Management

Service (MMS) in DOI supports several technology research and environmental assessment programs. The most important offshore technology research effort is the the Technology Assessment and

Research Program (TA&R). The TA&R Program

is designed to meet the need for an independent

Federal assessment of the status of offshore technology so that MMS operations personnel can carry

out their ‘ ‘regulatory’ or ‘‘inspection’ activities.

The program focuses on technologies pertaining to

blowout prevention, verification of the integrity of

structures and pipelines, and oil spill containment

and cleanup.

The TA&R program supports the following

MMS functions: safety and pollution inspection,

enforcement actions, accident investigations, permit and plan approvals, and well control training

requirements. Where technology gaps are identified, original research is performed. Studies are

conducted by universities, private companies, and

government laboratories. Each work task provides

for technical dialog between investigators, the industry, and MMS operations personnel. These investigators are used as staff adjuncts who present

their work to MMS operations personnel through

a technology transfer network of working groups

known as Operations Technology Assessment

Committees located in regional OCS offices and

in headquarters.

Projects are conducted wherever possible in advance of OCS leasing. The TA&R Program, together with the technology transfer network, also

is used by MMS as the primary method for identifying the “best available and safest technologies, ”

which industry is required by law to use. About

one-third of the projects are assessments and twothirds examine technology gaps. Although the program covers all Federal leasing areas, a major emphasis is on the Arctic and deepwater. About onethird of TA&R projects are participatory with the

industry (see table 4-l).

The Outer Continental Shelf Environmental

Assessment Program office of NOAA undertakes

or manages much of the environmental data collection program under the MMS Environmental

Studies Program. Additionally, the National

Weather Service, a part of NOAA, collects and disseminates weather data, and NOAA participates

with the U.S. Navy in the operation of the Joint

Ice Center. NOAA also has recently announced a

research project to study Arctic storms.

The DOE Arctic program has acted as a clearinghouse for government and industry technology

research. In addition, technology programs have

included sea ice engineering properties; geotechnology related to sediments and their interactions

with ice and seismicity; and concept studies of the

development of petroleum resources found below

Table 4-1 .—Representative MMS-Sponsored

Arctic and Deepwater Research Projects

Engineering properties of multiyear sea icea

Ice forces against Arctic offshore platforms

Reliability of concrete structures in the Arctica

Assessment of ice accretion on offshore structures

Fracture toughness of steel weldments for Arctic

structures

Dynamic response of offshore structures due to waves

and vortex shedding

Unmanned free-swimming undersea inspection

technology

Fluidic mud pulser for measurements while drilling

systems

Acoustic transmission of digital data from underwater

sensors

Control of blowout fires with water sprays

Subsea collection of oil from a blowing well

Demonstration of the capability of a robot inspection

vehicle for the performance of useful work

Applications of risk analysis in offshore safety

Early detection of damage in offshore structures by a

global ultrasonic inspection technique

Development of improved blowout prevention procedures

for deepwater drilling operations

Environmental cracking of high strength tension

members in seawatera

aJoint project with industw.

bJoint project with another a9encY.

SOURCE: Minerals Management Service.
Ch. 4—Federal Services and Regulation ● 9 1

the ice canopy in deep Arctic waters. In the past,

DOE sponsored a research program directed at

long-range technology development, including a

sizable drilling technology program. Some DOE

drilling research is now carried out under the DOE

geothermal program, and there may be spin-offs

to petroleum drilling.

MarAd sponsors research related to the future

of the U.S. shipping industry. In order to understand the problems of commercial ships in navigating the Arctic Ocean, MarAd has supported studies

in ice navigation. Using Coast Guard icebreakers,

trafficability studies have measured power requirements, the time required to navigate through iceinfested waters, and the forces imposed on ships

by the ice. Funding for this work has been significantly reduced in recent years.

ONR traditionally has supported research in

those disciplines which would provide the basis for

the understanding of natural phenomena and which

might be used in the development of new equipment or at-sea naval operations. Research information developed by ONR academic investigators

is generally published in the scientific literature and

thus available to the agencies and industries involved in Arctic energy resource development.

NSF supports a broad range of basic research

addressing Arctic scientific problems. The NSF research grants that pertain to offshore areas include

biological, oceanographic, geological/geophysical,

glaciology, meteorology and atmospheric sciences,

and engineering.

The U.S. Army Cold Regions Research and

Engineering Laboratory is a specialty laboratory

operated by the U.S. Army Corps of Engineers.

The laboratory focuses on geophysics and engineering in the world cold regions as these subjects

relate to military operations and construction. The

laboratory also possesses a large library that works

in conjunction with the Library of Congress to access the world literature on the geophysics and engineering of the cold regions. The Army laboratory

has a long and distinguished record of work on

problems related to the science and engineering of

the polar oceans. This has focused on problems

caused by the presence of ice, ice islands and

icebergs, snow cover, and subsea permafrost. Most

research on polar ocean problems has been funded

by other government agencies and private industry.

Photo credit: ARCTEC, Inc.

Model ice-breaking tanker (a scale replica of the SS

Manhatten) being tested to measure force required

for passage through first-year ice

Future Research and Development

It appears that industry’s research and development needs will continue to be met in a timely manner without any significant changes in Federal policy or incentives. However, there are concerns

related to the government role in supporting and

monitoring future research, maintaining national

facilities, and supporting excellence in universities

and other research institutions. Some have been

concerned about the uncoordinated and fragmented

nature of Federal programs, and suggestions have

been made to consolidate or coordinate research

through a joint industry/government/academic

council.

Most industry spokesmen support the existing

MMS research program which concentrates on

matters directly related to that agency’s regulatory

role. However, they believe any expansion of this

program may overlap with industry activities. Academic researchers generally maintain that the present government effort is not sufficient to assure adequate support for basic and advanced engineering

research and to provide continuing support for education. Larger and longer term commitments may

be needed to accomplish relevant basic research,

to prepare academic institutions to better accommodate and address specific industry needs, and

to ensure a steady supply of well-trained and

talented scientists and engineers.
92 ● Oil and Gas Technologies for the Arctic and Deepwater

While cooperative industry research has produced hundreds of reports on critical subjects, very

few of these have been made available to the public. Most research and data are kept confidential

by the participants, but it could possibly be made

public after a certain time period. There is generally a need to promote more cooperation between

the Federal Government, industry, other public

groups, and other governments in Arctic programs.

Efficient data collection often requires coverage over

territories of several nations (e.g., Canadian and

Alaskan Beaufort Sea regions). Cooperative research with public groups could assist communication of the results and the implications of development options.

One of the greatest values of federally sponsored

research is the ability of some agencies to design

programs with multi-year continuity so that basic

problems can be consistently studied and long-term

data can be collected and applied. This is essential

to an undemanding of some basic phenomena such

as ice movement and forces, meteorological, and

oceanographic processes. It is, therefore, important

to maintain continuity in many of the governmentsupported research efforts.

One approach to enhancing Federal research

efforts is contained in the Arctic Research and Policy Act (ARPA) of 1984. The Act finds that Federal Arctic research is fragmented and uncoordinated and that a comprehensive policy and program

to organize and fund Arctic scientific research is

necessary to fulfill national objectives. National Arctic objectives specifically cited in the bill, which require or would benefit from a more comprehensive scientific research effort, include development

of the living and nonliving resources of the Arctic,

environmental protection, national security, mitigation of the adverse consequences of development

to Arctic residents, and better understanding of

global weather patterns.

ARPA creates two new institutions—the Arctic

Research Commission and the Interagency Arctic

Research Policy Committee—to carry out the purposes of the Act. The Interagency Arctic Research

Policy Committee is composed of representatives

of all Federal agencies with responsibilities in the

Arctic. The National Science Foundation chairs the

Committee and is responsible for ensuring the implementation of national Arctic research policy.

ARPA calls for a 5-year implementation plan,

which, at a minimum, must assess national needs

and problems regarding the Arctic and the research

necessary to address those needs and problems. The

Arctic Research Commission is, in essence, an independent advisory board. The Commission is responsible for: developing and recommending an integrated national research policy; facilitating

cooperation among Federal, State, and local governments; and assisting in developing the 5-year

plan.

However, ARPA provides no additional funding for Arctic research. Moreover, although the law

urges agency coordination and integration of research programs, there is no authority in the bill

to direct departmental budgeting. Therefore, departments will continue to set their own research

priorities based on agency-specific missions. Without research funds and with authority limited to

giving advice and making recommendations, the

Commission’s present duties are limited. However,

both the 5-year implementation plan and the survey of Arctic research that the Interagency Committee will conduct will be useful if they help coordinate the overall Federal Arctic research effort.

FEDERAL SERVICES

Environmental Information seismicity—for the design and operation of offshore

structures and supporting systems.

Firms engaged in offshore oil and gas develop- The offshore industry receives information on

ment require a great deal of technical environ- these conditions from both Federal and private

mental information—information about weather, sources, and many firms collect their own data as

ice, oceanographic conditions, soil mechanics, and well. Federal environmental data services are de-
Ch. 4—Federal Services and Regulation ● 9 3

signed to serve the public at large, broad sectors

of the economy, and the needs of other Federal

agencies. Such information is used by the offshore

petroleum industry to gain information on global,

regional, and local conditions over both short and

long timeframes. There is no charge for most Federal forecast or operational data products. However, charges are assessed for some products that

have more identifiable users (e. g., for provision of

LANDSAT images), and often users must pay for

the communications devices (e. g., dedicated phone

lines) used to access information.

The main Federal agencies involved in collecting, processing, and disseminating offshore environmental information are NOAA, Navy, the National Aeronautics and Space Administration

(NASA), and the Air Force. NOAA is the primary

point of contact between civilian users and Federal

agencies. Principal NOAA units are the National

Weather Service; National Environmental Satellite, Data, and Information Service; and the National Ocean Service. The Navy/NOAA Joint Ice

Center plays a key role in disseminating ice charts

and other ice-related information. NOAA has several units involved in maintaining and improving

user services, notably two Ocean Service Centers

in Anchorage, Alaska and Seattle, Washington.

Most data used by Federal agencies come from

federally operated satellites, ships, and other systems. However, agencies also incorporate data from

private sources. Site-specific information used by

firms developing oil and gas resources is usually

obtained from private firms, including the firms

contracted to conduct actual operations. For example, operators in an area affected by ice movements

may supplement information received from Federal agencies with direct observations from company supply vessels or helicopters.

‘‘Value-added private firms take> historical

and/or forecast data from Federal sources, refine

it by additional processing and interpretation, and

often supplement it byadditional observations.

Such firms tailor products to specific user needs,

giving forecasts with greater frequwncy and more

geographic specificity than usually can be obtained

from Federal agencies.

Information Needs

There are some problems with the current provision of offshore environmental information. Voids

exist in historical and near real-time data. There

is less information available about some types of

environmental conditions and some offshore regions. Greater precision and accuracy are needed

in describing and forecasting conditions. For some

activities, the environmental information available

may be insufficiently precise. Many users desire

greater accuracy and better spatial resolution in the

observations and forecasts. In addition, products

may be too infrequent. Some users suggest that the

time intervals between measurements of conditions,

and between measurements and delivery of information to users, should be shortened. The need for

more accurate, longer range forecasts has also been

stressed. 1

Data are lacking for a variety of reasons. For example, the sensors mounted on current NOAA satellites are impeded by clouds, fogs, blowing snow,

and in the case of sensors restricted to the visible

spectrum, darkness. Outside of well- traveled ocean

routes and populated coastal areas, data to supplement satellite observations are limited. Minimal archived data are available for use in ‘‘ hindcasting"

conditions. Much of the satellite data which could

be available are not collected and that collected are

usually not archived because of either a lack of funds

or the absence of a specific program to do so.

Nontechnical problems also affect the performance of Federal agencies. Many NOAA programs

have been targeted for reduction and may find it

difficult to cope with the increases in user demands

likely to occur with the expansion of Arctic development. Suggestions have also been made that the

Federal Government establish a single focal point

for collecting, evaluating, and disseminating environmental data.

An OTA survey showed that improvements may

be needed in many information areas for pre-lease

sale planning and, to an even greater extent, for

site development. Types of information most fre-

‘ ~<ifloll(il ,\[l\ II, )11 ( J )Ili]llill(t ( )11 ( ~ (<iili ,irl(l :\tIn( )~[)t)(r (, ‘‘( )[ 1,(111

,S( r I, I( (, It II r }]( ,\’(it 1( II] ‘ I. J((rI {I(i I \ 1

 ( ~}1 1 I
94 ● Oil and Gas Technologies for the Arctic and Deepwater

quently mentioned as needing improvements are:

ice-related information in the Chukchi and Beaufort

Seas, and to a lesser extent, the northern Bering

and Norton Sound; soil geotechnical properties in

every offshore area; permafrost in the Chukchi and

Beaufort; storm surges in the Chukchi and northern Bering; wave climatology in the Chukchi and,

to a lesser extent, the Bering; currents in the

Chukchi; and wind velocity and visibility in the

northern Bering, and bathymetry, to a lesser extent, in all areas. Information about air temperature, precipitation, and tides was generally seen as

being satisfactory or not requiring major improvement.

Better data about environmental conditions could

result in financial savings and improve the safety

of offshore operations. Lack of information about

environmental conditions may cause overdesign of

drilling platforms and ships. Better information

could reduce a portion of the costs associated with

overly conservative design.

Several rigs have been lost to severe storms in

non-Arctic areas, at a cost of scores of lives and tens

of millions of dollars, and oil spills have resulted

from ship accidents. While human error has often

been a contributing factor, better information about

storms could help prevent recurrences of these

events.

Operations are planned and carried out on the

expectation of suitable weather, ice, and ocean conditions. Adverse environmental conditions often

cause offshore operations to be suspended. When

expensive pieces of equipment and their supporting systems are laid up due to unforeseen changes

in environmental conditions, additional expenses

quickly accumulate. For example, lease costs for

semi-submersibles can exceed $50,000 per day, with

weather-related losses of over $1 million per rig per

year not uncommon. Similarly, many days are lost

for resupply operations due to weather conditions.

It is possible that better information could reduce

such losses.2

More efficient ship routing, based on better information, could also result in large savings in time

at sea, and associated costs in fuel, damage to cargo,

and other items.

‘Jet Propulsion Laboratory, ‘ ‘Ocean Services User Needs Assessment” (Apr. 5, 1984), pp. 4-29.

Photo credit: Gulf 0il Corp.

A great deal must be known about ice forces to allow

safe Arctic operations

Future Information Services

Federal agencies are undertaking several initiatives that may improve environmental information

services. For example, the NOAA Ocean Service

Center concept appears particularly promising as

a way to improve contacts with users of NOAA

services. Several technological improvements also

are important, including new sensors scheduled to

be placed on future satellites. These advances, especially new satellite systems, could substantially reduce data gaps. New Navy oceanographic and Air

Force meteorologic satellites will penetrate cloud
Ch. 4—Federal Services and Regulation ● 9 5

cover and other low visibility conditions with

microwave sensors.

For extremely high resolution, synthetic aperature radar (SAR) imagery is needed. No U.S. satellite is scheduled to carry a SAR during this decade. However, planned European Space Agency

(ESA), Canadian, and Japanese satellites are

scheduled to have SARs. NASA has proposed to

establish a SAR receiving station in Alaska to collect data on offshore Alaskan areas from the ESA

satellite ERS-1, and NOAA has expressed interest in disseminating and perhaps processing such

data. Acquisition of SAR data would greatly improve existing information on sea ice, and the offshore industry has gone on record in support of the

proposed NASA receiving station and associated

data processing capability. However, some uncertainties remain about acquiring the ERS-1 SAR

data. Funding for the NASA and NOAA initiatives

to handle such data have not yet been approved.

It is also uncertain whether ERS-1 will be launched

on time, and whether its sensors will be switched

on while it is flying over Alaska.

It is equally uncertain whether operational products and real-time data would be provided as a result of accessing the ERS-1 SAR data. The offshore

industry wants processed images made available to

forecasters or industrial users within hours of data

acquisition. Current NASA plans are to process

data several days after acquisition. Near real-time

dissemination of data would require additional

processing capacity, and NASA does not see its

function as including provision of operational

products or real-time data. However, companies

surveyed by the Jet Propulsion Laboratory at the

California Institute of Technology expressed a

willingness to contribute to a NOAA-sponsored

pilot program to develop real-time SAR data dissemination, depending on the results of further

study.

Another uncertainty lies in Administration plans

for funding reductions for meteorological satellites

from two polar orbiters to one. According to

NOAA, a one-polar-satellite system would meet the

core of U.S. weather forecasting requirements.

However, the frequency with which any one area

would be covered would be reduced from once

every 6 hours to once every 12 hours. Reduction

of frequency would have significant effects on

prediction of weather affecting Alaska, Hawaii, and

other Pacific territories, and on activities using satellite data services, This would be especially true

in areas poorly covered by nonsatellite information

gathering systems, including most of the offshore

frontier areas. In addition, the amount of information shared with other countries would be reduced,

potentially affecting reciprocal information exchanges.

In addition, the Administration is seeking to increase the role of the private sector in supplying

environmental information services. In March

1983, the Administration endorsed the transfer of

nondefense remote sensing satellite systems—

LANDSAT, civilian weather satellites, and any

future ocean sensing satellites—to the private sector. Weather services and, to a lesser extent, future

ocean sensing services are considered by many people to be public goods, appropriate for the Federal

Government to provide, even if at a loss. Congressional concern culminated in an authorization bill

signed into law prohibiting the sale of the weather

satellite system to the private sector. Plans for the

sale of LANDSAT have continued, however, and

legislation to transfer LANDSAT to the private sector was enacted in July 1984 (Public Law 98-365).

Industries involved in offshore oil and gas development fear that nongovernmental managers of

LANDSAT may not devote adequate resources to

further develop remote sensing technology and that

costs may greatly increase. 3

Current NOAA plans are to transfer a portion

of its nautical chart-making to the private sector.

As with satellite commercialization, the Administration sees advantages in reducing the Federal role

in an area where the private sector could take over

operations. Critics have argued that safety could

be reduced if fewer charts were made or if people

were reluctant to purchase updated charts because

of increased charges. There is also concern about

Federal liability in marine casualty cases.

3U. S, Congress, OffIcc of Technology .Assessmcnt ‘‘ Remote Sensing and the Prit’atc Sector: Issues for Discussion-A ~’cchn ical hlcnlorandum ” (Washington, DC: U S. Gof’crnmcnt Printing Office,

March 1984).
96 ● Oil and Gas Technologies for the Arctic and Deepwater

Navigation Services

Federal agencies operate ground stations and satellite platforms that beam radio transmissions used

to navigate and to position vessels and structures.

Such transmissions are vital to many offshore operations, such as vessel positioning for seismic surveys, positioning of platforms, pipeline laying, and

tanker transport. Radio aids provide a high level

of accuracy, combined with broad coverage. They

are especially important in situations where visibility is reduced. Arctic operations in particular are,

or will be, dependent on radio aids. This is because

Arctic waters are relatively poorly charted and contain many hazards, short-range aids such as buoys

are often difficult to maintain in Arctic waters, and

visibility is reduced in many areas by extended

darkness and frequent storms or fog.4

This section covers only those navigation services which are known as ‘‘radiodetermination.”

This encompasses both radionavigation and radiolocation, or positioning for purposes other than

navigation. Federal agencies usually use the term

‘‘radionavigation when describing Federal services in this area. While Federal radio systems are

used by the civil sector for uses going beyond

navigation, the statutory responsibility of Federal

agencies only extends to providing a level of service that is sufficient for safe and efficient navigation. Radiolocation or positioning generally requires more precise data.

Federal Radionavigation Systems

Offshore operators commonly use their own

shore-based portable positioning systems or contract with private companies for such systems during seismic exploration and for rig positioning,

where high accuracy is needed. For many purposes,

however, systems operated by the U.S. Coast

Guard, Navy, and Air Force are vital to offshore

exploration, production, and transportation of oil

and gas.

The Coast Guard operates two types of longrange radio aids, LORAN-C and OMEGA.

LORAN-C operates by measuring differences in

4Maritime Transportation Research Board, ‘‘Maritime Services to

Support Polar Resource Development” (Washington, DC: National

Academy Press, 1981).

the time of receipt between radio pulses from

transmitters several hundred miles from each other.

The usable range of LORAN-C is up to 1,500

miles, depending on system configuration. Worldwide, there are 43 U.S.-operated LORAN-C stations. While Alaskan waters up into the Bering Sea

are covered by LORAN-C, waters north of Point

Clarence either are not covered or coverage is subject to interference (see figure 4-l). At the present

time, there are no plans to extend LORAN-C coverage to Arctic regions not currently served.

OMEGA is a radionavigation system similar to

LORAN-C, operating at lower frequencies. It has

greater range, covering the entire world, but its accuracy is less: 2 to 4 nautical miles for predictable

and repeatable accuracy. Eight stations, two of

which are in the United States, comprise the

OMEGA system.5

The Navy operates a satellite system called

TRANSIT, with the Coast Guard as the point of

contact for civilian users. More than 90 percent of

users of TRANSIT are civilians. The TRANSIT

5Nevin A. Pealer, ‘ ‘Federal Radionavigation Planning, ” Proceedings of the National Technical Meeting of the Institute of Navigation (January 1984).

Figure 4.1.— Loran-C Coverage of Alaska

45“N

1

40“N

170 “w 160°W 150 “w 140 “w

SOURCE: Transportation Systems Center, “Benefits and Costs of Loran-C Expansion Alternatives in Alaska,” April 1983.
Ch. 4—Federal Services and Regulation ● 9 7

system has five satellites in polar orbit, with

worldwide coverage. The limited number of satellites in the TRANSIT system means that, depending on their location, users experience gaps lasting

from 30 minutes to several hours in the reception

of transmissions. Transmission gaps are greatest

at the equator, less at northern latitudes.

Present Federal plans are for LORAN-C,

OMEGA, and TRANSIT to be phased out and

eventually replaced by the Global Positioning System (GPS), which is to be operated by the Air

Force. As with TRANSIT, the Coast Guard is to

be the contact agency for civilian uses of GPS.

When fully developed, the GPS will use 18 satellites, with three operating spares also in orbit. GPS

is intended to provide highly accurate, continuous,

worldwide positioning information for weapons dePhoto credit: Rockwell International

The Global Positioning System (GPS) will provide

radionavigation services for Arctic operators

livery systems; however, it also will be used by

civilians for nonmilitary purposes.

GPS is currently in a research/demonstration

phase. Some test satellites have been launched and

used to verify the GPS concept. Launches of the

satellites that will establish the operational system

are scheduled to begin in late 1986, By 1987 or

1988, two-dimensional coverage suitable for marine

operations should be achieved, with full threedimensional coverage suitable for aircraft available

by late 1988 or early 1989. TRANSIT is to be terminated in 1994, or as soon as the military can

change over to GPS, which is expected to be complete by the early 1990s. Although termination

dates for LORAN-C and OMEGA have not been

fixed, suggested dates range from soon after 1994

to beyond 2000. The Coast Guard favors continuation of LORAN-C at least until 2000. Foreign

LORAN-C stations could continue to operate for

some time after domestic U.S. stations are terminated, depending on foreign governmental support.

The European Space Agency (ESA) is conducting studies on the feasibility of a 24-satellite civilian navigation system called NAVSAT. Funding

may come from indirect charges, rather than

through direct user charges. NAVSAT may have

advantages over GPS in that it would be a civilianoriented system, whereas GPS is primarily a military system. The timeframe for development of

NAVSAT is not clear. In addition, the Soviet

Union is developing a satellite navigation system

called GLONASS that will be similar to GPS. It

is not clear when GLONASS will become fully

operational. Although initially intended for use by

Soviet civil aviation and special-purpose ocean

vessels, GLONASS may eventually be offered for

worldwide use free of charge.

Radionavigation Needs

Different radiodetermination tasks require different levels of accuracy. For example, seismic surveys require extremely high repeatable accuracy

levels. Vessel navigation generally requires less accurate satellite data. OMEGA is adequate for ocean

navigation, especially away from the coastal zone,

but for other purposes does not provide sufficient

accuracy. LORAN-C gives greater accuracy, and

the continuous broadcasts of LORAN-C are an im-
98 ● Oil and Gas Technologies for the Arctic and Deepwater

portant asset. LORAN-C capabilities are sufficient

for most coastal navigation. A major drawback of

LORAN-C is its lack of coverage of northern

Alaskan waters. LORAN-C and other nonsatellite

systems are also more susceptible to atmospheric

interference. TRANSIT provides greater accuracy

than LORAN-C, but its usefulness is lowered by

gaps in transmissions.

Whether or not current radiodetermination systems should be upgraded depends largely on evaluation of the prospects for GPS. Concerns have

emerged regarding GPS agency/user relations, the

accuracy of GPS information provided to civilian

users, the timing of the phase-in of the system, and

costs and charges to users.

If TRANSIT were phased out before GPS were

made available, the overall level of Federal service

would be lowered. Many users seek assurances that

GPS will provide services comparable to existing

systems, and that other systems will continue to

operate until GPS provides such levels of service.

The offshore industry believes that GPS user

charges are acceptable in principle, but that such

charges should be ‘ ‘equitably’ assessed. Industry

groups have opposed plans that would favor recreational boaters or fishermen.

Icebreaking

Alaskan Arctic waters are ice-covered or experience significant ice concentrations for all or part

of the year. Specialized vessels that can operate in

ice-infested waters will be needed if development

is to proceed. Possible missions performed by

icebreaking or ice-capable vessels related to oil and

gas operations include opening of shipping lanes

and drilling vessel sites, protection of drilling operations against drifting ice, supply of operations, pollution response, search and rescue, and transport

of petroleum products. In U.S. waters, missions

such as supply operations and transport of products are private sector responsibilities. Missions

such as pollution response and search and rescue

are undertaken by both private and Federal units.

The Coast Guard also carries out vessel-towing and

other rescue and safety-related missions.

The need for icebreakers will vary with the location of oil and gas fields, their size, and their distribution. Because it is difficult to project what the

conditions of oil and gas development will be, projections of future icebreaker needs are uncertain.

If fields are close to shore, use of pipelines, aircraft,

hovercraft, and land transport over ice would minimize the need for icebreakers. However, in many

situations, especially for remote fields, it may be

advantageous to use icebreakers. For example, air

operations tend to be far more expensive than ship

operations, especially for supply tasks involving

large volumes. In addition, helicopter range is

limited, and aircraft are more limited than ships

by weather conditions.

Federal Icebreaking Services

With the transfer of Navy icebreaking functions

to the Coast Guard in 1965, the Coast Guard became the sole Federal agency to operate icebreakers.

Apart from its own missions, such as enforcement

of laws and treaties, the Coast Guard also provides

icebreaking support to other Federal agencies for

such purposes as scientific observation and supply

of installations. In the early 1980s, Coast Guard

polar icebreakers spent an average of 127 days per

year in the United States and western Canadian

Arctic. G

The Coast Guard currently maintains five polar

icebreakers (see table 4-2). In terms of numbers,

the Coast Guard icebreaking fleet ranks third in

the world, behind the Soviet and Canadian fleets

(see table 4-3). Private icebreaking services are

available in some U.S. Arctic areas. For example,

tugboat-pushed barges supply North Slope oil operations, breaking ice each year from August until

October.

However, some believe that the Coast Guard has

barely adequate resources to undertake current

operations and would have inadequate resources

to carry out the expanded duties brought about by

increased oil and gas development in the Arctic.

Apart from the two Polar class ships, the Federal

icebreaking fleet is in fair to poor condition (see

table 4-4). The U.S. polar icebreaking fleet is one

of the the world’s oldest, with a median age of about

30 years. Two of the four original Wind class vessels

were ret i red several years ago, and the other two

still in service have poor crew facilities and defi6U. S. Coast Guard, “United States Polar Icebreaker Requirements

Study” Ull])f 1984), p. A-11.
Ch. 4—Federal Services and Regulation ● 99

Table 4.2.—Coast Guard Polar Icebreakers

Icebreaking capability:

Year Length Displacement Shaft continuous/ ramming

Icebreaker built (ft) (long tons) horsepower (ft) (ft) Complement Homeport

Westwind . . . . 1944 269 6.260 10,000 3 11 181 Mobile, AL

Northwind . . . . 1945 269 6,260 10,000 3 11 181 Wilmington, NC

Glacier. . . . . . . 1955 310 8,678 21,000 4 14.5 280 Long Beach, CAa

Polar Star . . . . 1976 399 12,688 60,000 6 21 164 Seattle, WA

Polar Sea. . . . . 1978 399 12,688 60,000 6 21 164 Seattle, WA

aTo be moved to Seattle, spring 1985

SOURCE. U S Coast Guard

Table 4-3.—Comparative Government Polar Icebreaker Figures

Length Draft Displacement Shaft Powera

Icebreakingb

Nation Vessel/class Built (ft) (ft) (tons) horsepower plant capability (ft)

U.S.S.R.

U.S.S.R.

U.S.A.

U.S.S.R.

Japan

Canada

Canada

(private)

U.S.S.R.

U.S.S.R.

U.S.S.R.

Canada

(private)

USA

Canada

Canada

Argentina

Canada

(private)

W. Germany

Japan

Canada

(private)

Canada

USA

Leonid Brezhnev . . . . . .

Sibir . . . . . . . . . . . . . . . . .

Rossiya . . . . . . . . . . . . . .

Lenin . . . . . . . . . . . . . . . .

Polar Star . . . . . . . . . . . .

Polar Sea. . . . . . . . . . . . .

Yermak class . . . . . . . . .

(3 ships)

Shirase. . . . . . . . . . . . . . .

Louis St. Laurent . . . . . .

Kalvik class. . . . . . . . . . .

(2 ships)

Moskva class . . . . . . . . .

(5 ships)

Kapitan Dranitsyn . . . . .

class (2 ships)

Kapitan Sorokin . . . . . . .

class (2 ships)

Canimar Kigoriak . . . . . .

Glacier . . . . . . . . . . . . . . .

MacDonald . . . . . . . . . . .

Radisson class . . . . . . . .

(3 ships)

Almirante Irizar. . . . . . . .

Ikaluk class. . . . . . . . . . .

(2 ships)

Polarstern . . . . . . . . . . . .

Fuji . . . . . . . . . . . . . . . . . .

Robert Lemeur . . . . . . . .

Labrador . . . . . . . . . . . . .

Northwind . . . . . . . . . . . .

Westwind

1975

1977

1985

1959

1976

1978

1974-76

1982

1969

1983

1959-69

1980-81

1977-78

1979

1955

1960

1978-82

1978

1983

1982

1965

1982

1953

1944-45

446

439

399

442

440

366

289

400

433

433

299

310

315

316

391

258

387

328

272

290

269

36

34

31

36

30

31

26

31

28

28

28

28

28

24

31

25

35

29

18

30

28

25,000

19,240

13,000

20,241

17,600

14,000

7,000

15,360

14,900

14,900

6,500

8,000

9,160

8,055

14,500

6,000

14,800

8,566

6,512

7,000

7,000

75,000

44,000

60,000 or

18,000

36,000

30,000

24,000

23,200

22,000

22,000

22,000

16,360

21,000

15,000

13,600

16,200

14,900

20,000

12,000

9,000

10,000

10,000

N

N

GT or

DE

DE

DE

TE

GD

DE

DE

DE

GD

DE

DE

DE

DE

GD

GD

DE

GD

DE

DE

8

7

6 +

6

5

4-5

5

4.5

4.5

4.5

4-5

3.5

3.5

3.5

3.5

3-4

3

3

3-4

3

3

aPower plants: N = nuclear; GT = gas turbine; DE = diesel electric; TE = turbo-electric; GD = geared diesel.

bEstimated continuous, level icebreaking capability at 3 knots.

cThis table does not include some ~ vessels (subarctic icebreakers) that are capable of icebreaking OpOKdiOflS in seasonally ice-covered COaStat seas and lakes outside

the polar regions. These ships are owned by Canada (2), Denmark (2), Finland (9), W. Germany (1), Sweden (6), USA (l-Mackinaw), U.S.S.R. (34), and E. Germany (1).

dAll government-owned icebreakers except for those Canadian vessels noted as Private.

SOURCE: U.S. Coast Guard.
100 ● Oil and Gas Technologies for the Arctic and Deepwater

Table 4-4.—Condition of Coast Guard Icebreaking

Fleet

Icebreaker type

Wind Polar

Category class Glacier class

Prime mission equipment/

science facilities . . . . . . . . . . 2 3 3

Habitability . . . . . . . . . . . . . . . . 1 2 5

Hull and ship structure. . . . . . . 1 3 5

Main propulsion . . . . . . . . . . . . 4 3 4

Auxiliary . . . . . . . . . . . . . . . . . . . 1 3 4

Command and control . . . . . . . 2 4 4

5 = excellent; 4 = good; 3 = fair; 2 = poor; 1 = Inadequate

SOURCE: U.S. Coast Guard.

ciencies in steering and firefighting systems. These

older icebreakers are considered by the Coast

Guard to be nearing the end of their ability to provide reliable service. Their active service is projected to end in the late 1980s.

The Coast Guard currently assumes that it will

continue to have an icebreaker fleet of five ships,

although it is possible that a four ship system will

be adopted. Because of the long lead-times involved

in the design, construction, and testing of icebreakers— about 5 to 8 years—decisions must be

made soon concerning the number of icebreakers

desired and their characteristics (size, draft, propulsion systems, equipment, etc.). Congress has authorized the construction of at least two new Polar

class icebreakers by the end of fiscal year 1990.

Future Icebreaking Needs

Offshore developments in Arctic regions may require icebreaker support for much of the year. Different levels of service could be provided by the

Coast Guard. The Coast Guard believes that the

continuous presence of Coast Guard icebreakers is

not required in the Arctic at this time; rather, it

seeks to maintain the ability to enter Arctic waters

and perform required missions. If a continuous

presence were needed, different icebreaker design

and/or more northern icebreaker basing would be

required.
Ch. 4—Federal Services and Regulation ● 101

The most capable icebreakers in the Coast Guard

fleet, the Polar Star and the Polar Sea, are capable of transiting continuously through over 6 feet

of first-year ice at 3 knots, without backing and

ramming. They can break through ice thicknesses

of 21 feet by backing and ramming. There is some

disagreement regarding the adequacy of these ships

for operations in all Arctic winter conditions. The

Coast Guard believes that the Polar class vessels

have sufficient characteristics, while some other

sources believe that far more powerful icebreakers

are needed. If many operations take place in the

Beaufort and Chukchi Seas, as opposed to the Bering, icebreakers will have to meet more rigorous

requirements. The Coast Guard is currently deciding the class of future polar icebreakers.

A problem for year-round service is the endurance of icebreakers. The gas turbine engines on the

Polar class vessels, used for heavy icebreaking, consume large amounts of fuel and require relatively

frequent refueling. Even in conditions where diesel

electric engines are used, icebreakers that have long

traveling times to reach Arctic duty experience endurance problems. The home bases of the polar fleet

are Seattle, Long Beach, Mobile, and Wilmington,

with two (soon to be three) of the five polar

icebreakers based in Seattle. From Seattle to the

North Slope is at least a 2-week voyage. Currently,

there are no refueling stations north of the Aleutians. If a more substantial Coast Guard icebreaking presence were to be established, vessels with

greater endurance would be needed or refueling and

other support facilities would have to be constructed

closer to offshore operations. One problem with

northern basing is that the closer the operations base

is to the Arctic, the farther away it would be from

Antarctica, where many missions are carried out.

It is also thought that ship maintenance would be

more difficult if northern bases were used. The

Coast Guard has no present plans to establish

northern basing for icebreakers.

Some Arctic areas such as the eastern Beaufort

are relatively shallow for long distances offshore and

shallow draft icebreaking capability may be needed.

Such icebreakers must be able to operate in less than

20-foot water depths and to break ice continuously

2 to 3 feet thick.7 The Coast Guard currently lacks

‘Lawson W. Brigham, ‘ ‘Future U.S. Coast Guard Shallow-Draft

Icebreaker Requirements in Alaska, Proceedings of the Symposium

on Science and Arctic Hydrocarbon Exploration: The Beau/brt Experience (September 1983).

vessels that combine sufficient strength to transit

through Arctic ice with shallow enough drafts to

come close to shore. The new generation of Polar

icebreakers planned for purchase by the Coast

Guard will also be deep-draft. The Coast Guard

is waiting to see what level of commitment industry will be making to offshore exploration before

deciding what type of shallow-draft icebreaking

service may be needed.

Icebreakers are expensive to build and operate.

Total annual costs of operating four to five icebreakers under various alternatives range from $35

to $50 million. Icebreakers support the missions of

a number of agencies besides the Coast Guard,

especially the Department of Defense and the National Science Foundation. Participating agencies

and groups pay a proportionate share of Coast

Guard expenses incurred on icebreaking missions,

including pay, maintenance, and fuel costs. Because

Coast Guard icebreaking is dependent on the yearto-year operational plans of several agencies, Coast

Guard planners face considerable uncertainty. If

a single agency decides not to utilize icebreaking

services, the Coast Guard may have to withdraw

a ship from service. The Coast Guard is currently

seeking a revision of the cost-sharing system.

There are also questions about the extent to

which icebreaking services should be provided to

private firms developing offshore oil and gas.

Icebreaking could be a private sector activity, with

icebreakers owned and operated by private firms.

Or the government could be reimbursed by the offshore oil and gas industry for all or part of its

services.

No Federal icebreaking assistance is provided

routinely to North Slope commercial operations.

The position of the Coast Guard is that responsibility for routine icebreaking for marine commerce

rests primarily with the marine industry and not

with the Federal Government. However, if available commercial icebreaking services are inadequate, the Coast Guard will provide icebreaking

assistance. Decisions on the availability and adequacy of commercial services are made by Coast

Guard District Commanders.

There is a need for the Coast Guard to continue

icebreaking services in support of such statutory

mandated missions as search and rescue, emergency response, enforcement of laws and treaties,
102 ● Oil and Gas Technologies for the Arctic and Deepwater

Photo credit: Gulf Canada

Floating conically-shaped mobile drilling unit “Kulluk” operating in the Canadian Beaufort Sea with icebreaker support

and pollution response. However, private operators feel that they can provide the offshore oil and

gas industry icebreaking services such as supply and

channel breaking. At the present time, there are

few U.S. private sector icebreakers, and current

capabilities are limited to the summer months. As

oil and gas development proceeds, these capabilities may expand. The Coast Guard would probably still be called upon for icebreaking support in

emergency ice conditions.

There are incentives for industry to provide its

own icebreaking or contract with private firms for

icebreaking services to support oil and gas development. Special Coast Guard requirements for

larger ships increase the cost of Federal icebreakers

and icebreaking services in comparison with private services and would add to any Federal user

fees. Also, without the need to design and operate

vessels for the multi-mission roles that Coast Guard

vessels must fulfill, private sector icebreaking vessels

could be tailored to meet industry missions. 8

In general, private icebreaking firms have been

strong supporters of user fees, believing that they

could not compete against taxpayer-subsidized

Coast Guard services. The Coast Guard advocates

8National Petroleum Council, U, S. Arctic Oil and Gas, Working

Paper-26 (December 1981), pp. IV 52-54.
Ch. 4—Federal Services and Regulation • 103

assessing any user fees only for activities beyond hand to be a free subsidy to the petroluem industhe statutory responsibilities of the Coast Guard. try. Presently there are no plans for Coast Guard

Coast Guard policy for the Arctic is not clearly icebreakers to be used to directly support petroleum

established and may not be until there is increased exploitation and commerce. If such support were

oil and gas development. A 1982 interagency study provided, it would be appropriate for user fees.

declared that ‘ ‘although Arctic petroleum development could be argued to be in the national interest, the services of Coast Guard icebreakers to fa- ‘Department of Transportation, ‘ ‘Coast C~uard Roles and Nlmlons”

cilitate commerce could be argued on the other (hlarch 1982), p 157.

SAFETY

Offshore oil and gas operations entail hard and

dangerous work. Special risks are presented in frontier regions because of harsh environments and

remote locations. Offshore operators have made

substantial efforts to safeguard health and safety,

and the safety record of offshore operations appears

equal to or better than the record of comparable

onshore industries. Still, there is a need for continuing attention to ways in which the Federal Government can assist in preventing work-related injuries and fatalities.

As in other industrial sectors, offshore employers

vary greatly in their safety records. Industry associations and many employers have strongly promoted safety, e.g., through sponsoring training of

personnel, while other employers have been more

lax. Public concerns about offshore operations have

been stimulated by incidents that resulted in the

death of a large number of workers. The best

known of these incidents are the sinkings of the converted floating hotel Alexander Kielland (North Sea

1980, 123 fatalities), the Ocean Ranger (Eastern

Canada 1982, 84 fatalities), and the drill ship

Glomar Java Sea (South China Sea 1983, 81 fatalities). The last two were U.S. flag casualties. Offshore incidents in 1984 included a fire on the Enchova Central Platform off Brazil with 41 fatalities,

and a natural gas explosion that killed 4 on the

Zapata Lexington Number 26 semi-submersible rig

in the Gulf of Mexico.

Offshore hazards can be categorized in different

ways. A Marine Board report separates hazards

according to the type of offshore activity: construction, drilling and well maintenance, production,

and transportation. 10 Exploratory drilling is often

considered to be the most hazardous phase of offshore operations, perhaps because less is known at

that stage about formation characteristics. Only

about one-fifth of all offshore employees are engaged in drilling; however, they experience a

disproportionately larger number of accidents.

Accidents can also be categorized according to

the facility where they occur: tankers, fixed platforms, mobile rigs, and support vessels and structures.11

Another division emphasizes the scale of accidents. There are individual accidents, such as

falls, being struck by objects, and being pinned between objects. There are also occupational health

problems separate from accidents, such as hearing

loss due to machinery noise. Then, there are larger

scale, catastrophic incidents, such as rig sinkings.

Catastrophic incidents have occurred because of

storms, structural failures, and capsizings. Other

fatalities have resulted from well blowouts, explosions, and fires. Unlike most onshore occupations,

offshore jobs pose hazards to off-duty workers, who

often remain in close proximity to the work-site.

Multiple fatalities and injuries also have resulted

from transportation accidents involving helicopters

and supply vessels.

This section focuses on several potential safety

problems present in frontier regions. In general,

1 ~M arlne ~omd, Sa fc(}, and Offshore Oil ( \\’ash ington, I~C” N~ltional Acacicm} Press, 1’981 ), pp. 142-143.

1 I MITR~ Corp, , He~th and En\;ronn]enra/ Eff&’CS Of ~)i) ~d ~:1.$

Tc’chnolo+es: Researrh Needs (’July’ 1981), p. ~’iii.
104 . Oil and Gas Technologies for the Arctic and Deepwater

Photo credit: Peter Johnson, OTA

Roughnecks on the drilling rig floor at Shell’s Seal

Island discovery in the Beaufort Sea

the same types of offshore operational hazards are

present no matter where operations take place, from

the day-to-day dangers of working with machinery in confined spaces to unusual events such as

evacuation under storm conditions. The high levels

of investment required in frontier areas and the involvement of larger companies with relatively wellorganized health and safety programs may make

the future safety record of operations in such areas

comparable to operations in more benign regions.

Still, other things being equal, frontier conditions

compound operational risks.

The environmental conditions in offshore frontier areas—extreme cold, ice, extended periods of

darkness, blizzards and fog in the Arctic and severe

storm conditions in the sub-Arctic and many deepwater areas—increase the dangers of operations.

The remote location of many rigs in frontier areas

makes evacuation of personnel more time-consuming and difficult, and delays medical treatment. The

cold temperatures found in the Arctic and other

northern regions are hazardous both in their direct

effects on human health and in their reduction of

worker efficiency. Although employees usually work

in heated areas, at times they are exposed to cold.

Human ability to perform tasks (e. g., in terms of

reaction time) declines with decreasing temperature. 12 Bulky protective clothing worn for warmth

12R. Goldsmith, ‘ ‘Cold and Work in the Cold, ” Encyclopedia of

Occupational Safety and Health (Geneva: International Labor Organization, 1983).

may interfere with tasks in ways that cause injury

risks to increase.

In situations where quick rescue is impossible,

exposure suits are essential to survival in cold water.

The time it takes for severe hypothermia and subsequent death to occur varies with such factors as

water temperature, the weight and physical condition of the person in the water (thinner people

suffer quicker heat loss), the type of clothing they

are wearing (heavier clothing provides greater insulation), and the person’s behavior (e. g., curling

up in a fetal position decreases the rate of heat loss).

Without an immersion suit, even a heavily clothed

person in good physical condition can survive for

only a few hours in winter seas. More lightly clothed

people die from hypothermia in much less time.

With a suit, survival time is increased many-fold.

A major factor contributing to the deaths resulting from the Ocean Ranger disaster was the lack

of exposure suits on board. Within a few minutes

of entering the water, personnel were too numb to

grasp life ropes and rings thrown to them from the

rescue vessel. A Coast Guard rule went into effect

in August 1984 requiring exposure suits for personnel on mobile offshore drilling units, among

other types of vessels, that are located in specific

offshore areas.

Injury and Fatality Statistics

There is currently no single comprehensive

source of statistics on U.S. offshore accidents, and

there are no reliable injury and fatality rate statistics for offshore operations beyond those compiled

by the International Association of Drilling Contractors (IADC) for individual workplace accidents

in offshore drilling. The lack of data makes it difficult to evaluate the level of safety achieved by oil

and gas operators, safety-related equipment, and

Federal regulation. It also makes it difficult to assess

the effects on safety when changes are introduced.

The data bases that do exist do not separate incidents that occur in frontier regions. To date, there

have been no major (catastrophic) accidents in U.S.

frontier areas. However, such accidents have

occurred to U.S. facilities in other areas.

Several different agencies and organizations keep

offshore accident records, using a variety of reporting systems. The Coast Guard requires accidents
Ch. 4—Federal Services and Regulation • 105

to be reported if they result in an injury causing

absence from work for more than 72 hours. The

Bureau of Labor Statistics (BLS) collects data on

those accidents which cause the employee to be unavailable for work at the beginning of his next workday. The IADC collects data on accidents which

cause 12 hours of work to be lost.

The BLS and IADC standards are roughly comparable, but their statistics often differ due to different data bases. For example, IADC usually

reports drilling-related injuries, while BLS covers

all aspects. IADC statistics are derived from companies employing about 90 percent of the offshore

drilling workers, while BLS relies on statistical

sampling. In addition, the IADC does not include

accident statistics from catastrophic incidents or

accidents involving personnel not employed by

drilling contractors, such as oil company representatives and employees of firms providing drilling

muds, well cement, or specialty tools. Neither the

IADC nor the Coast Guard ordinarily include statistics on accidents and fatalities for helicopter personnel transfer and resupply operations, unless the

12

11 -

10 -

9 “

8 “

“

. -

= 5 -

4

-

3 -

2 -

1 “

o -

1976

Figure 4-2.—Offshore

helicopters and supply vessels collide with offshore

facilities.

Injury Rates

Available data indicate that offshore injury rates

have declined in recent years (see figure 4-2). IADC

figures show the accident rate for offshore drilling

has been declining since 1976 equaling a reduction

of over 60 percent. However, the IADC reported

an increase in the incidence of injuries for the first

9 months of 1984 as compared with 1983. Overall, offshore drilling injury rates are comparable to

those in the mining sector and are less than onshore

drilling injury rates (see table 4-5).

Using a 72-hour reporting standard and ending

with 1981, Coast Guard data show a similar trend

for the offshore industry since 1978. According to

the Coast Guard, over 80 percent of OCS injuries

are caused by human factors, rather than equipment failure. A major cause of accidents is inexperience: about 75 percent of the injuries occur to

workers with less than 1 year on the job, and about

Drilling Injury Rate

1977 1978 1979 1980 1981 1982 1983

Year

Injury rate equals the incidence of lost time accidents per 200,000 man-hours.

SOURCE: International Association of Drilling Contractors
106 ● Oil and Gas Technologies for the Arctic and Deepwater

Table 4.5.–Comparable Industry Injury Rates (1983)

Injury rate per

Industry 200,000 manhours

Total private sector . . . . . . . . . . . . . . . . . 3.4

Construction . . . . . . . . . . . . . . . . . . . . . . . 6.2

Mining (other than oil and

gas extraction). . . . . . . . . . . . . . . . . . . . 4.4

Anthracite mining . . . . . . . . . . . . . . . . . . . 6.1

Total oil and gas extraction: . . . . . . . . . . 4.6

Onshore oil and gas drilling . . . . . . . . 10.36*

Offshore oil and gas drilling . . . . . . . . 4.2*

“Statistics from IADC.

SOURCE: Bureau of Labor Statistics.

30 percent to workers with less than 6 months experience. However, some workers contend that

some accidents listed as being caused by human error are the result of unsafe management practice

rather than worker carelessness. In boom periods,

when operations expand, there is an influx of new

workers, and accident rates increase. In slack periods, only more experienced workers are retained.

Fatality Rates

There are fewer reliable statistics on offshore

fatality rates. Unlike offshore injuries, the data

available show no clear pattern of decline in fatalities. Coast Guard data show the fatality rate

(deaths per 210 million man-hours) for offshore

drilling fluctuating between 1976 and 1981, with

a high of 226 and a low of 80. Fatality rates for the

offshore oil and gas industry as a whole fluctuated

between a high of 118 and a low of 54 in this time

period. The reliability of these statistics is unclear,

as the Coast Guard lacks data on man-hours

worked. 13

The Coast Guard is seeking to establish an improved injury and population data collection system. One change will be the collection of data in

computer form. Perhaps the most important improvement sought is better information on the number of workers and the hours worked offshore. This

is necessary to monitor progress towards the Coast

Guard and Federal goal of decreasing injuries and

fatalities. If a new permanent data collection system cannot be implemented, the Coast Guard

hopes to make a comprehensive assessment of injury and population data in 1988. The last statistical assessment of offshore injury and fatality rates

made by the Coast Guard was in 1982.

Consistency among data systems would aid in

evaluating the effectiveness of safety measures. A

report by the Marine Board of the National Research Council recommended several improvements in the present inspection and data system,

including the formation of a system that acquires

comprehensive event and exposure data; relates

events to specific employers, locations, operations,

and equipment; calculates frequency and severity

rates, and analyzes trends; and permits monitoring of the relative safety performance of owners and

employers, locations, and activities.14

The Marine Board also concluded that a single

lead agency should be established to handle safety

data and recommended MMS in this role. MMS

was seen by the Marine Board as having a stronger

presence offshore than other agencies, and it

believed that MMS would better integrate safety

data into day-to-day regulation. On the other hand,

the Coast Guard is also a strong candidate since

it has the bulk of the offshore personnel safetyrelated responsibilities.

Safety Regulation

Offshore Regulatory Structure

Under the OCS Lands Act and its regulations,

private industry is responsible for ensuring the

safety of offshore operations:

Each holder of a lease or permit under the Act

shall ensure that all places of employment within

the lease area or within the area covered by the

permit on the OCS are maintained in compliance

with workplace safety and health regulations of

this part, and, in addition, free from recognized

hazards . . . . Persons responsible for actual operations, including owners, operators, contractors,

and subcontractors, shall ensure that those operations subject to their control are conducted in

compliance with workplace safety and health regulations of this part and, in addition, free from

recognized hazards. 15

IJTestimony of Thomm Tutwiler, Hearing before the Subcommittee

on Panama Canal/Outer Continental Shelf of the Committee on the

Merchant Marine and Fisheries, House of Representatives (June 16,

1983)

14Marine Bored, Safety In fomnation and Management on the Outer

Continental Shc4f (Washington, DC: National Academy Press, 1984).

1533 CFR Sections 142. l(a) (b).
Ch. 4—Federal Services and Regulation ● 107

Private industry responsibility for safety is governed by a complex regulatory structure. Depending on where they are located, offshore facilities are

affected by several sets of mandatory and voluntary authorities and standards. These include

international agreements and conventions, flag nation standards, coastal nation standards, and nongovernmental organizations.

The International Maritime Organization

(IMO), whose membership includes most of the

world’s maritime nations, sets standards on marine

safety, pollution, and navigation. IMO member

states have adopted many of these standards as minimum requirements, supplementing IMO standards as deemed necessary with their own regulations. The International Labor Organization also

has recommended safety standards in consultation

with IMO. Among other related actions, IMO has

published a Code for the Construction and Equipment of mobile drilling units (1979) and a convention on Safety of Life at Sea (SOLAS) (1974), which

contain man y safety recommendations. Recent

SOLAS lifesaving requirements include provision

of above-water means of escape from enclosed

lifeboats in case of flooded capsizings, lifeboat release mechanisms that permit both on-load and offload releases, and requirements for training on use

of all survival equipment, including life rafts.16

The nation under whose flag a given mobile

drilling unit is registered has its own set of regulatory authorities governing design, construction, and

operation of rigs and their equipment. The nation

off whose coasts a rig is operating may have jurisdiction over aspects of operation. In addition, state

or provincial governments may have additional

standards.

Nongovernmental organizations such as the

American Bureau of Shipping (ABS) conduct design and construction review and surveys for ships,

rigs, and other marine equipment. Most insurance

underwriters require classification by societies such

as ABS before they will insure a ship or rig. The

Coast Guard accepts certain ABS inspections in lieu

of direct Coast Guard inspection. Other U.S. private organizations with notable roles include the

IADC, which collects accident statistics and advises

1 bRobert 1.. Markle, “SOIJ4S Chapter III, Proceedings of the

,~arine Safet,v council Uanua.v 1984)

members on safety matters; the American Petroleum Institute, which publishes standards and recommended practices for facility and component

design, construction, and operation, as well as personnel training; the Underwriters’ Laboratories,

which performs classification and testing for such

things as fire protection systems; and the American Society of Mechanical Engineers, which publishes industry codes for piping and pressure vessels.

Federal Safety Responsibilities

The OCS Lands Act gives primary offshore

safety responsibilities to the Coast Guard and

MMS. The Coast Guard is the lead agency for personnel protection, and enforces most regulations

controlling workplace safety. MMS enforces regulations bearing on safety as part of its responsibility

for the regulation of drilling and production. Both

the Coast Guard and MMS have responsibilities

for reviewing the design and construction of facilities. MMS also evaluates installation of fixed facilities to ensure that they are in compliance with

plans and that no significant damage has occurred

during installation.

Both agencies have regulations covering training, drills, and emergency procedures on offshore

facilities. Each agency has provisions for conducting scheduled and unannounced inspections to ensure compliance. The Coast Guard is normally the

lead investigating agency for cases of collisions,

deaths and injuries, damage to floating facilities,

and failures of or damage to propulsion, auxiliary,

emergency, and other safety-related systems. MMS

is the lead agency for cases of fires and explosions,

pollution, and failure of or damage to fixed facilities. For incidents where they do not have lead

agency responsibility, each agency participates in

any investigation that bears on its jurisdiction.

Other agencies with offshore safety roles include

the Occupational Safety and Health Administration (OSHA) and National Institute of Occupational Safety and Health (NIOSH). Memoranda

of Agreement have been signed between agencies

delineating jurisdictions. The Memorandum of Understanding between the Minerals Management

Service and the Coast Guard gives authority for

regulating specific operations dealing with drilling

to MMS, and other aspects of OCS operations to

the Coast Guard.
108 ● Oil and Gas Technologies for the Arctic and Deepwater

COAST GUARD

Coast Guard regulations deal with hazardous

working conditions offshore and apply to the performance of safety-related equipment and drills for

personnel for the evacuation of facilities. The Coast

Guard reviews and approves design, construction,

alteration and repair for vessels, rigs, and floating

facilities. The Coast Guard also regulates the safety

of commercial diving operations.

The Coast Guard is in the process of modifying

safety standards for mobile offshore drilling units,

fixed structures, and mobile well servicing units.

For mobile offshore drilling units, revisions are being considered regarding ballast control, fire protection, and lifeboat and life raft launching under

adverse conditions. One proposal would require

that a mandatory safety briefing be given to each

arrival on board. Other regulatory changes under

consideration would apply to fixed as well as mobile

facilities.

Other possible changes include: 1) expanding

regulations to more specifically cover support units,

such as specialized vessels used for standby, supply,

and well servicing; 2) expanding workplace safety

rules, including personal protective equipment, and

guarding of openings; 3) clarifying division of

responsibility with OSHA; 4) updating evacuation

and firefighting standards; 5) clarifying best and

safest technologies (BAST) regulations; and 6) clarifying training requirements.

The Coast Guard also conducts research to improve prevention of offshore work-related injury

and illness. Investigations are being conducted on

such things as improving the seakeeping characteristics of mobile offshore drilling units. Current

research contracts include investigation of ballast

systems, tension leg platform design and serviceability, and methods for evacuation of Arctic drilling units.

MINERALS MANAGEMENT SERVICE

MMS, the lead offshore Federal agency, has the

power to halt operations or even cancel a lease if

it determines that such operations constitute a sufficient hazard. MMS issues OCS Orders for each

region that cover such things as well control, production safety systems, pollution prevention and

control, and structural safety. Lessees have to show

compliance with the orders to obtain permits to drill

and produce.

MMS conducts technical reviews and approves

design, fabrication, and installation of all fixed OCS

facilities. For floating facilities, MMS has approval

of the design and fabrication by the Coast Guard.

MMS also conducts inspections of facilities to check

for compliance with regulations and is the lead

agency for the investigation of accidents involving

fires, blowouts, and explosions. MMS regulation

is done primarily through working with the operator/lessee rather than with contractors or subcontractors.

During inspections, MMS technicians monitor

testing of drilling safety equipment, check to see

that required equipment is in place, and review

records to verify that periodic tests have been performed. Violations can be punished with a warning or order to shut down the operation.

SHARED COAST GUARD/MMS RESPONSIBILITIES

Both the Coast Guard and MMS review design,

construction, and installation of offshore facilities.

Which agency will be responsible for a given facility depends whether it is fixed on the seafloor or

floating. Some facilities may require both Coast

Guard and MMS approval, due to their change in

character from being a floating facility while in transit to the site to being fixed when on site. The tension leg platform is even more complex. The surface portion and the legs are approved by the Coast

Guard while the ocean floor foundation is the

responsibility of MMS.

MMS design verification and fabrication inspection are largely conducted by approved third-party

verifiers who, while paid for by the construction

or operating company, verify to the responsible

agency that the facility meets regulatory requirements, An inspection of fixed structures during or

immediately after construction or installation is a

part of the third-party verification system. Postinstallation underwater inspections are not required

in subsequent years, but may be needed, particularly in frontier areas.

Post-installation inspection requirements of the

legs or the underwater portion of the floating structure of the tension leg platform have not been deter-
Ch. 4—Federal Services and Regulation ● 109

mined. However, other floating structures certified

by the Coast Guard such as mobile drilling units

and ships generally undergo a regular docking for

inspection. MMS announced its intention in 1980

to develop requirements for periodic structural inspection of fixed offshore facilities.

As new concepts evolve, certification responsibilities may change and certification procedures

may be blurred. For example, ocean sub-sea completion systems and future ocean floor production

facilities may require different arrangements. The

government’s regulatory role in the inspection of

underwater portions of the structure during the life

of the structure is now limited,. The government

does require structural integrity data from industry after a platform has been installed and is subjected to a major event, such as a storm or collision. As structures become more complex and are

located in deepwater or Arctic areas, inspection

techniques must also become more sophisticated.

Government-sponsored research may be necessary

to enhance Federal inspection capabilities for the

future.

OTHER FEDERAL AGENCIES

The Memorandum of Understanding between

OSHA and the Coast Guard states that the Occupational Safety and Health Act (which is enforced by

OSHA) applies to offshore working conditions, but

‘ ‘does not apply to working conditions with respect

to which the Coast Guard or other Federal agencies exercise statutory authority to prescribe or enforce standards affecting occupational safety and

health.” OSHA enforces standards in State waters

out to the 3-mile limit (out to 9 miles for Texas and

Florida), except in California and Alaska, which

administer federally approved safety and health programs. OSHA does not conduct separate offshore

inspections. If Coast Guard inspectors detect violations of OSHA standards in the course of inspections, they notify OSHA. The two agencies have

agreed to coordinate activities and exchange data

in areas where they may overlap. OSHA turns over

to the Coast Guard all worker safety and health

complaints, while Coast Guard makes available to

OSHA the results of Coast Guard accident investigations. OSHA is proceeding with rulemaking to

improve workplace standards for onshore oil drilling

and servicing, which could be useful to offshore

operations.

Other Federal agencies with lesser roles include

NIOSH, U.S. Department of Health and Human

Services; and BLS of the U.S. Department of Labor. NIOSH does research related to preventing

work-related injury and illness. They have sponsored research on diving hazards and on identifying injury causal factors on drill rigs. They have

recently released recommendations for protecting

workers on land-based drill rigs which may partly

apply to offshore drilling operations. The BLS is

responsible for collecting and reporting statistics for

work-related injury and illness.

Arctic Search and Rescue

Offshore development in the Arctic presents

special safety problems. Ice, extreme cold, occasional white-outs and fog, and possibly, long distances from human settlements, make evacuation

difficult. It is uncertain how evacuation will be conducted from rigs surrounded by ice. Conventional

lifeboats and land capsules cannot be used. For the

near future at least, helicopters, suitable fixed-wing

aircraft, and/or icebreaking ships will have to be

maintained by private or Federal sources. Because

of lack of Federal resources, it is likely that offshore

developers will have primary responsibility for their

own rescue efforts.

The Coast Guard is the lead Federal search and

rescue agency in maritime regions. It coordinates

its efforts with those of other Federal agencies, especially the Department of Defense, and with State

and local governments and the private sector.17 In

addition, the Coast Guard reimburses fuel expenses

for the Coast Guard Auxiliary, a volunteer organization that performs about one-fifth of Coast

Guard search and rescue missions. The Air Force

is lead agency for search and rescue in land areas

and is frequently called on for maritime search and

rescue. The Air Force also operates the Mission

Control Center at Scott Air Force Base, Illinois,

through which Search and Rescue Satellite Aided

Tracking (SARSAT) rescues are coordinated.

Many rescues have been made through the Civil

Air Patrol and Coast Guard responding to SARSAT information,

SARSAT is a search and rescue package

mounted on one NOAA polar orbiting meteorolog17u, S, coast Guard, “National Search and Rescue Plan” ( 1981).
110 • Oil and Gas Technologies for the Arctic and Deepwater

ical satellite. Three Soviet cosmos satellites in the

COSPAS system also have search and rescue sensors. Eventually, the system will probably consist

of two U.S. and two Soviet satellites. As of December 1984, over 300 people have been rescued as a

result of COSPAS-SARSAT in the brief period of

time in which these satellites have been in operation. About half of these people were U.S. citizens.

SARSAT detects emergency signals from small

inexpensive transmitters activated on ships, aircraft,

and other vessels in distress. SARSAT offers many

advantages, especially in remote areas such as the

Arctic, where ship and aircraft passages are infrequent and they may not be found when in distress.

Locating vessels is much faster if they are equipped

with SARSAT transmitters. However, the Administration has proposed placing SARSAT aboard

LANDSAT or another satellite and its future is uncertain.

Some deficiencies have been identified in Coast

Guard capabilities to carry out search and rescue

missions. Problems include age of vessels, lack of

adequate maintenance, lack of training of personnel, excessive overtime required of personnel, and

problems in retaining experienced personnel. Personnel policies that have increased the concentration of Coast Guard officers in desk jobs and decreased rotation have been criticized as lessening

the amount of experience officers would otherwise

gain in search and rescue.18

1 eCO~greSS]on~ Rewarch sen,i~e, ‘‘The U.S. Coast Guard (Mar.

1, 1982).
Ch. 4—Federal Services and Regulation ● 111

There has been little demand for Arctic search

and rescue, due to the lack of commercial and

recreational activities in the region. It is reasonable to assume that given expansion of Arctic offshore activities, incidents requiring some search and

rescue operations will increase.

However, Coast Guard search and rescue capabilities are constrained in the Arctic. All Coast

Guard units in the 17th District are located far from

Arctic offshore areas—the closest unit is a small

LORAN station at Port Clarence, about 400 miles

from Barrow-and all of the major units are on the

other side of the State. The ice-strengthened vessels

stationed in Alaska are designed for light ice conditions. No unit has icebreakers capable of transiting ice 3 feet and greater in depth, as would be

essential for search and rescue during most of the

year in northern Alaskan waters. The nearest such

vessel, the Polar Sea, is in the Arctic approximately

5 months out of the year (February through April

and September through November). At other

times, it is based in Seattle, Washington, several

days voyage from offshore Arctic sites.19

Due to the distance of Coast Guard stations from

Arctic operations, lack of permanently stationed

icebreakers, and lack of icebreakers capable of

winter-round operations, current Coast Guard Arctic search and rescue efforts depend largely on air

operations out of Kodiak, Alaska. Air operations

are limited by darkness and weather conditions.

The Coast Guard currently has no plans to establish a more permanent Arctic presence, and many

search and rescue tasks in the Arctic will be performed by industry itself rather than by the Coast

Guard. Industry vessels and helicopters positioned

in northern Alaska will have swifter response times

than Coast Guard units. Several industry helicopters are already available at Prudhoe Bay. The

Coast Guard will coordinate search and rescue efforts of various entities when appropriate.

Improving Offshore Safety

There are economic incentives for the industry

to prevent accidents, which can mean time lost from

operations and money spent defending against

‘qMarine Board, ‘ ‘U.S. Capability to Support Ocean Engineering

in the Arctic” (Januar) 1984)

lawsuits. Insurance rates reflect safety records and

insurance costs can become exorbitant as a result

of bad safety records. Industry believes that more

government regulations are not needed to improve

safety and that the industry is already overregu -

lated. The Marine Board of the National Research

Council concluded that:

. . . current technology and engineering systems

now in use on the OCS appear to provide adequate workplace safety . . . there is no evidence

that additional regulations regarding workplace

safety are needed for frontier areas nor that major developments in workplace safety technology

are indicated. 20

However, the Marine Board and others have

pointed out possible improvements that could be

made in technologies, training, management techniques, and regulation to improve offshore safety.

What constitutes a reasonable level of safety, and

what costs are reasonable to reach that level, is a

subjective decision. Improvements to workplace

safety are possible in at least three areas: 1 ) evacuation, 2) management, and 3) regulation.

Evacuation

Offshore rigs may carry several types of craft for

evacuation of personnel in emergency situations.

These include life boats, survival capsules (a type

of covered lifeboat designed for heavy seas), and

inflatable life rafts. With the exception of life rafts,

these craft are generally boarded on the rig and then

lowered into the water. While there have been

many safe evacuations, it is often difficult to launch

these craft from offshore rigs. Factors such as high

winds, heavy seas, height above water (craft may

have to be lowered 50 or more feet) and awkward

positioning (rigs may be listing 10 or more degrees

at the time of evacuation) make the 1aunch hazardous. In some cases, such as the Alexander L.

Kielland and Ocean Ranger, evacuation craft have

been battered against structures, killing and injuring personnel. Though all launching systems are

vulnerable to weather conditions, new systems utilizing free-falling boats reduce launching dangers

by removing personnel more swiftly and placing

them further away from rigs.21

zo~~arlne ~Oard, &fi~\, and ~f]shorr ~i], P. 1.5

2 I De{ Norskc \’critas, “ E~acuation of Personnel by Sea’ (.AuSust

1983), pp. 11 -]~,
112 . Oil and Gas Technologies for the Arctic and Deepwater

Facilities surrounded by ice have special evacuation problems. Different methods of evacuation

from those used on water are being investigated,

including air-cushioned vehicles and vehicles using

Archimedean screw propulsion. While these systems are suitable for some ice conditions, they have

problems, including difficulty in negotiating steep

pressure ridges. The Coast Guard is now testing

a Norwegian free fall system, and should soon issue

an approval which would allow rig owners to install the system. Another system utilizing ramps to

direct survival craft away from rigs is still in the

conceptual stage.

Personnel can also be evacuated from offshore

structures, lifeboats and other craft, and from the

water itself by helicopter, standby vessel, or a ship

dispatched from shore. Legislation has been introduced to require that standby vessels be stationed

nearby offshore facilities. Vessels not stationed in

the immediate vicinity could not arrive quickly to

assist at isolated facilities, and even helicopter rescue

may take a long time, depending on the location

of facilities in distress and of the helicopters themselves. (If standby ships are not stationed close by,

they suffer the same disadvantage. The standby

ship for the Ocean Ranger was 8 miles away at the

time it was radioed for assistance. ) Helicopters may

not be able to operate in severe weather conditions

and are less suitable for evacuating divers suffering decompression injuries. The psychological

reassurance brought to personnel by knowledge that

a boat is nearby also may be considered.

Standby vessels are required in Norway, Great

Britain, and Canada. In the United States, standby

boats are not required by regulation but are stationed voluntarily by some employers. Standby

vessels may not always be the most appropriate

means of evacuation. For example, helicopters can

take injured people to shore more quickly than can

a ship and are not impeded by sea states. In some

ice conditions, aircraft, icebreakers, or ice-strengthened rescue ships would be necessary. A Norwegian

governmental commission investigating the Alexander L. Kielland incident concluded that the

Norweigan requirement that standby vessels be stationed be abolished in favor of regulatory flexibility. 22

zl[~l~~ K~d,.Std[i dll~ I.:Kl] }$rl]]f’f, .Safi,[!, oflihorc ((Mo, .Norw arry:

L1rli~(,rsitctsiiJr]agt.t, 1984), p ~

Separate investigations of the Ocean Ranger

sinking by the National Transportation Safety

Board and the U.S. Coast Guard Marine Board

of Investigation recommended that the Coast

Guard require owners or operators to provide

standby vessels. The Coast Guard Commandant,

however, did not concur. Coast Guard regulatory

revisions will rule on standby vessels. 23

The safety of evacuation methods might be best

advanced through performance requirements.

Without specifying a system, employers could be

required to provide adequate means to evacuate

personnel within a certain time. Performance standards have the advantage of increasing the flexibility

of employers in meeting requirements. The Coast

Guard plans to increase use of performance standards in several areas, using industry standards as

a guideline.

Even if rescue ships or helicopters arrive swiftly,

they may not be able to recover personnel without

specialized equipment. In the case of the Ocean

Ranger, standby ships were unable to rescue

anyone despite courageous attempts, mostly due

to the lack of nets, baskets, cranes, or other systems which could be used to recover persons too

weak to assist themselves. Other problems discovered in the course of investigations of the Ocean

Ranger incident included design limitations of the

standby ships (e. g., high freeboard), lack of training and protective clothing for their personnel, and

lack of facilities for treating hypothermia.

Injuries also occur in the course of transferring

people between offshore structures and standby

boats. Usually, personnel are transferred using

baskets or nets suspended from cranes. Extendable,

flexible bridge concepts are being explored by some

sources.

Management

Responsibility for safety is not always clearly

delineated on offshore rigs. A common practice has

been for Toolpushers (drilling supervisors) to be

formally in command while rigs are anchored, while

Masters (maritime captains) are in command while

the rig is being moved. In addition, a representa-
Ch. 4—Federal Services and Regulation Ž 113

tive of the company contracting out the unit may

have considerable informal authority. This arrangement has at times resulted in confused lines of

responsibility, especially during emergencies. Poor

coordination between the drilling unit and shorebased personnel and lack of a well-defined chain

of command can slow response time, as was demonstrated in the Ocean Ranger incident. The Coast

Guard has undertaken a review of licensing regulations in order to clarify rules for assignment of

responsibility y.

In addition, safety problems and solutions often

lie in the attitudes and actions of personnel, rather

than equipment. Some offshore companies and

drilling contractors give safety a high priority using

the safety records of prospective contractors as an

element in the bid selection process. Many companies hold safety meetings where workers can voice

safety concerns.

Training is the foundation for safety. MMS requires that training be given to specialized personnel. Many offshore companies operate training

schools or pay for employees to attend such schools.

However, investigations of catastrophic offshore incidents have found that training of personnel, including those responsible for operating systems

crucial to the safety of others, has been inadequate

on some rigs. For example, no one on board the

Ocean Ranger had more than a rudimentary understanding of the ballast control system, and there

were no trained lifeboat crews.

Among other applicable regulations, the Coast

Guard requires that emergency drills be held at least

once each month on manned offshore facilities. For

mobile drilling units, a boat drill is required at least

once each week in which all personnel report to their

stations and demonstrate their ability to perform

their assigned duties, and weather permitting, at

least one lifeboat is partially lowered and its engine

started and operated. Each lifeboat is to be lowered

to water, launched, and operated at least once every

3 months. There are, however, no requirements

that Federal inspectors witness and evaluate the

adequacy of evacuation drills on OCS facilities.

According to some observers, drills are not held

according to this schedule or are pro forma exercises on some rigs, held only to meet minimum regulatory requirements. Similarly, personnel have reported that they have not been informed of their

emergency assignments even though posting of such

information is required. Periods of large turnover

of personnel on rigs increase the difficulty of establishing a high degree of proficiency (e. g., through

teamwork) in safety-related tasks. The Marine

Board has recommended that Federal regulations

include mechanisms that promote more active company attention to safety, such as pubic visibility and

accountability, safety performance standards, and

personnel standards.

Regulation

Despite the great number and variety of regulatory requirements bearing on offshore safety, there

are no specific requirements that employers submit safety plans that aim at an integrated assessment of the adequacy of safety measures, such as

drills, evacuation plans, and lines of responsibility.

There are existing requirements that bear on planning

, but there is no separate rig-by-rig review that

looks at all of the components of technology and

management practices that are involved in offshore

safety.

Regulations mandate scheduled inspections of all

facilities at least once a year, supplemented by an

unspecified number of periodic, unannounced inspections. These are performed by the Coast Guard

and MMS. A drilling technician inspects rigs on

an average of once a month after drilling begins.

If a violation is found, sanctions range from a warning, with 1 week given to correct the deficiency,

to shutdown of the piece of equipment, the well,

or the entire operation. Also, an investigation is

conducted following any accident, and notices are

sent to all lessees and operators describing incidents,

apparent causes, and actions taken by operators to

prevent a recurrence. Civil and criminal penalties

are provided for infractions of requirements.

However, the Ocean Ranger disaster pointed out

important deficiencies in Coast Guard inspection

procedures. After the initial inspection in December 1979, no subsequent formal inspections of the

Ocean Ranger were carried out, aside from one

brief visit from an official. Although its certification had expired in December 1981, no reinspection was made up to the time of the February 1982

sinking. Although the Coast Guard directed that
114 • Oil and Gas Technologies for the Arctic and Deepwater

the lifeboats and life rafts on the Ocean Ranger be

replaced within 2 years, no replacements were made

and no effort was made by the Coast Guard to

ascertain whether its directive had been carried out.

In addition, the rig was not manned according to

requirements of its inspection and cargo ship safety

equipment certificates.

In general, the Coast Guard relied on the classification given to the Ocean Ranger by the American Bureau of Shipping (ABS) as proof of design

adequacy, and the Coast Guard did not independently assess such things as the capability of the

ballast pumping system. ABS ratings focus on certification of structure, machinery, and equipment,

and do not cover personnel competence, training,

or safety management practices.24

The Coast Guard has had difficulty in carrying

out the required number of inspections on fixed

platforms due to funding limitations.25 It is unclear

how the Coast Guard will handle inspections should

activities be significantly expanded in Arctic regions. Currently, Coast Guard inspection resources

are concentrated in the Gulf of Mexico, and aside

from several small LORAN stations, all Coast

Guard installations in Alaska are located in southern portions of the State, many hundreds of miles

away from frontier areas.

Z4Roy~Comission on the ocean Ranger Marine Disaster, Report One: The Loss of the Semisubmersible Drill Rig Ocean Ranger

and Its Crew (Canada: Canadian Ministry of Supply and Services,

1984).

ZjThomas TutWi]er, in Proceedings of Safec,v of Life Offshore SYm -

posium (International Association of Drilling Contractors and Scripps

Institute of Oceanogmphy, June 1983), p. 54,

Inspection alternatives considered by the Coast

Guard include relinquishing some scheduled inspections to MMS, the lessee, or to a third-party.

However, the Coast Guard would continue unannounced inspections on a small percentage of facilities, and worker complaints could trigger other

inspections. The main disadvantage of self-certification is the possibility that inspections would be

less strict, thereby lowering safety. Third-party inspection analogous to current third-party verification of design and construction would be preferable

in this regard, if such firms were held to strict standards. An issue to be resolved is who would bear

the cost of third-party inspections. Industry currently pays for third-party verification.

Whether safety levels can indeed be maintained

or increased within the Coast Guard’s budgetary

constraints is uncertain. The Coast Guard believes

that savings resulting from delegating inspections

will enable it to concentrate resources on the rigs

with poor records. Improved data collection is

essential to this goal, however.

OSHA does not conduct its own offshore inspections. OSHA’s position is that if the Coast Guard

exercised authority over workplace safety and

health, OSHA authority is superseded. However,

the Coast Guard does not have detailed workplace

safety rules, and it is unclear which, if any, OSHA

rules apply. The Coast Guard has a regulatory project to develop more detailed Coast Guard workplace safety standards. Review is also needed of

respective OSHA and Coast Guard responsibilities.
Chapter 5

Economic Factors
Contents

Page

Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Costs of Offshore Exploration and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Exploration Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

Development and Operating Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

Transportation Costs.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118

Lead-Times to Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Profitability of Offshore Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Economic Rent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

Minimum Economic Field Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Government Lease and Tax Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Fixed Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Other Lease Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Prices and Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Market Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Alaskan Oil Markets: Export of Alaskan Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Alaskan Natural Gas Markets: Alaskan Natural Gas Transportation System . . . . . . . . . . . . . . . . 126

TABLES

Table No. Page

5-1. Comparative Offshore Exploration and Development Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

5-2. Profitability of Offshore Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

FIGURES

Figure No. Page

5-1. Corporate Cash Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120

5-2. Profitability of Offshore Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

5-3. Alternative Lease Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

5-4. Flow of Alaskan Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

5-5. The Alaska Natural Gas Transportation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
Chapter 5

Economic Factors

OVERVIEW

Exploration and development of oil and gas resources in the Arctic and deepwater frontiers depend largely on potential profitability. Economic

incentives are needed for industry to develop the

technology for resource development in the frontiers. Factors which influence project profitability

include costs, timeframes, prices, markets, and government lease and tax payments. In general, higher

costs and longer lead-times to production tend to

lower profit margins in offshore frontier areas. As

a result, the sensitivity of project economics to

changes in various factors is higher in frontier areas

than in mature producing regions such as nearshore

Gulf of Mexico.

OTA has analyzed the economic attractiveness

of oil and gas development in offshore frontier regions. Using a computer simulation model, cash

flow profiles were developed for different types of

offshore fields based on the technical scenarios presented in chapter 3. Ten hypothetical fields are discussed, consisting of representative large and small

fields in nearshorc Gulf of Mexico, California deepwater, and three Alaskan basins. The estimates of

costs, timeframes, and other variablcs used in the

model are only approximations of those which may

be encountered with actual projects in these offshore

areas. The’ results of the simulations do not represent the actual economics of prospects. They are

used principally to illustrate how changes in economic factors can affect the profitability of oil and

gas development in different offshore regions.

Remoteness, difficult operating conditions, and

high engineering costs are characteristic of frontier

areas. Extremely large oil and gas discoveries are

needed to offset the high costs and long timeframes

of exploration and development. Small fields may

not yield adequate profits to justify development.

The OTA analysis shows that while a 40- to 50-

million barrel field may be profitable in the Gulf

of Mexico, in the Alaskan offshore it may take a

discovery of 1 to 2 billion barrels of recoverable reserves to make a project profitable.

Government lease and tax payments affect the

profitability of offshore fields differently in the frontiers than in other leasing areas. The OTA computer simulation indicates that leasing systems

based on alternative types of lease payments rather

than fixed royalties may increase the profits and

reduce some of the risks associated with frontierarea fields. In general, the profitability’ of oil and

gas development in offshore frontier areas will be

increased by real oil and gas price increases. In the

Alaskan regions, the availability of economic market outlets for oil and gas—the development of export markets for Alaskan oil and the development

of processing and transportation systems for

Alaskan natural gas—could improve the economic

profile of offshore fields.

COSTS OF OFFSHORE EXPLORATION AND

DEVELOPMENT

Harsh environments and difficult operating con- frontier regions. Costs are important determinants

ditions, greatly increase the costs of’ oil and gas ex - of the economic feasibility of producing oil and gas

ploration and development in Arctic and deepwater in offshore areas. In general, offshore exploration

117
118 ● Oil and Gas Technologies for the Arctic and Deepwater

and development costs are influenced by the ocean

environment (e. g., waves, ice, currents), water

depth, field size and flow, proximity to support and

transportation infrastructure, and elapsed time to

production start up. Long lead-times to first production also add to the risks and uncertainty of

frontier-area oil and gas activities.

The major categories of project costs—exploration costs, development costs, operating costs, and

transportation costs—have been estimated for

hypothetical small and large fields in five offshore

regions (see table 5-l). These estimates are based

on costs included in the National Petroleum Council study of U.S. Arctic Oil and Gas and other

sources, and have been escalated to 1984 dollar

equivalents. 1 hey are not exact figures, but are

intended to be indicative of relative cost ranges in

different offshore regions. More precise cost estimates can only be derived if and when a discovery

is delineated and a production system is designed

for a specific site and set of operating conditions.

Exploration Costs

Exploration costs include the cost of the drilling

rig, logistical support, exploration wells, and delineation wells. They do not include the lease bonus

payment. In this analysis, it is assumed that the

wildcat exploratory success rate is 1 in 10 and that

each successful discovery includes the cost of drilling

10 exploratory wells. In addition, it is assumed that

five appraisal or delineation wells are drilled into

each oilfield before development begins, except in

the nearshore Gulf of Mexico where only three are

drilled. Additional delineation wells are needed for

frontier-area fields to justify the high costs of development.

Ocean environment and water depth account for

most of the variation in exploration costs owing to

requirements for specially designed drilling equipment in hostile environments and to operating conditions that may cause delays. Total exploration

costs are generally independent of field size. The

average cost of drilling exploratory and appraisal

‘National Petroleum Council, U.S. Arctic Oil and Gas (December 1981); Dames and Moore, GMDI and Belmar Engineering, Deep

Water Petroleum Exploration and Development in the California OCS,

Report prepared for the Minerals Management Service (January

1984).

wells in the more conventional Gulf of Mexico leasing area is estimated at $6 million per well. In comparison, single exploratory wells are estimated to

cost an average of $27 million in the California

deepwater scenario and $55 million in the Navarin

Basin of offshore Alaska. In this analysis, the total

costs of an exploration program are estimated at

$78 million in nearshore Gulf of Mexico as compared to $825 million in the Navarin Basin.

Development and Operating Costs

Development costs include the cost of the drilling

platforms or islands and the development wells. In

most regions, platforms and facilities account for

65 to 70 percent of total development costs. These

costs vary not only with the harshness of the operating environment and water depth, but also with

field size. In this analysis, it is assumed that there

are no economies of scale associated with platform

construction or development drilling, except in the

nearshore Gulf of Mexico scenario. There are economies of scale associated with operating costs. Operating costs are calculated on an average annual basis

and include labor, repair and maintenance, fuel,

power, water, and other support functions.

Development costs for a 50-million barrel oil field

in 400 feet of water in the Gulf of Mexico are estimated at $168 million, including platform costs of

$112 million and drilling costs of $56 million. These

costs escalate quickly with the depth of water and

the severity of ice, wind, and wave conditions. Total

development costs for a 300-million barrel field in

California deepwater (3,300 feet) are estimated at

$900 million. Development costs for a 2-billion barrel field in Alaska’s Harrison Bay, which has severe

ice conditions, are estimated at $6.3 billion, and

in the Navarin Basin, with its greater water depth

and harsher wind and wave conditions, at over $11

billion. Operating costs range from $10 to $25 million per year in the more temperate and accessible

Gulf of Mexico and California regions to $100 to

$250 million per year in the Alaskan offshore areas.

Transportation Costs

Transportation costs depend on many factors,

including distance from markets, the availability

of transportation infrastructure, and the harshness
Ch. 5—Economic Factors • 119

Table 5-1 .—Comparative Offshore Exploration and Development Costs (estimates for OTA computer simulation)

Water Field Exploration Development Operating Transportation Production

depth size cost cost cost cost lead-times

Area (feet) (mmb) ($ million) ($ million) ($ mill/yr) ($/bbl) (years)

Gulf of Mexico

Small field . . . . . . . . . . . . 400 15

Large field . . . . . . . . . . . . 400 50

Cal. Deepwater

Small field . . . . . . . . . . . . 3300 150

Large field . . . . . . . . . . . . 3300 300

Norton Basin

Small field . . . . . . . . . . . . 50 250

Large field . . . . . . . . . . . . 50 500

Harrison Bay

Small field . . . . . . . . . . . . 50 1000

Large field . . . . . . . . . . . . 50 2000

Navarin Basin

Small field . . . . . . . . . . . . 450 1000

Large field . . . . . . . . . . . . 450 2000

78

78

105

168

7

12

$0.00

$0.00

2

2

16

24

$2.50

$2.00

10

10

400

400

450

900

435

435

1038

2076

72

102

$6.50

$5.00

8

9

$12.50

$10.00

12

12

720

720

3162

6324

120

168

825

825

5460

10920

132

240

$6.50

$5.00

11

11

NOTE Costs refer to total, undiscounted outlays, in 1984 dollars.

SOURCE. Office of Technology Assessment.

of the operating environment. In this analysis, these

costs are calculated on a per-barrel basis and include

the cost of transporting oil from the production facility to the nearest U.S. market. Transportation

costs include pipelines, tankers, and transshipment

terminals. The costs of transporting oil to markets

varies greatly among regions, but decreases with

larger field sizes in all regions due to economies of

scale.

Because of the availability of transportation systems and processing facilities in nearshore Gulf of

Mexico and the ability to share pipelines, transportation costs are assumed to be absorbed in development costs in the Gulf fields. Transportation

costs are estimated at $2 to $2.50 per barrel in the

deepwater California area, where it is assumed that

subsea pipelines are layed in extremely deep water

to the West Coast. In the Norton and Navarin

Basins of Alaska, where systems involve icebreaking tankers and transshipment terminals for transport to the lower 48 States, costs are estimated at

$5 to $6.50 per barrel. The Harrison Bay project,

where oil is transported to shore via pipeline and

to southern transshipment terminals through the

Trans-Alaskan Pipeline System (TAPS), is assumed

to have a transportation cost per barrel of $10 to

$12. The transportation costs for the California and

Alaskan scenarios could be reduced by shared or

common facilities which could serve several fields.

Photo credit: American Petroleum Institute

The existence of the Trans-Alaska Pipeline System

(TAPS) will affect the economics of oil produced in the

Beaufort Sea near Prudhoe Bay

Lead-Times to Production

Far longer time periods are needed for exploration and development in offshore frontier regions

than in traditional areas. In the nearshore Gulf of

Mexico scenarios, first production is assumed to

occur 2 years after the lease sale. In contrast, in

the California deepwater and Alaskan scenarios,

first production does not begin until a minimum

of 8 to 12 years after the lease sale. These schedules

may underestimate the actual timeframes of activity in frontier regions, because they assume mini38-749 0 - 85 - 5
120 . Oil and Gas Technologies for the Arctic and Deepwater

mum time for obtaining necessary government approvals. The analysis also assumes that platform

design will commence at the time of the discovery

and proceed concurrently with the approval

process.

For example, it is assumed in the Harrison Bay

scenario that 5 to 6 years elapse between the time

the lease is acquired and the time when a discovery is made (see figure 5-1). It takes another 5 to

6 years before permits are obtained and production facilities are designed and constructed. It is

therefore a minimum of 12 years before the company sees a return on a sizable investment and the

discovery contributes to cash flow. Peak production of 500,000 barrels per day occurs in the third

year after beginning production. The total life of

the field is 27 years from first production.

Figure 5-1.—Corporate Cash Flow

Harrison Bay — Large Field

Peak production

I

-4 I 1 I I

3 5 7 9 11 13 15 17 19

Project years

SOURCE Off Ice of Technology Assessment

PROFITABILITY OF OFFSHORE DEVELOPMENT

Potential profits are the primary incentives for

investments in offshore oil and gas exploration and

development. In general, investments depend on

finding suffcient recoverable reserves of marketable

oil and/or gas to justify costs. In this analysis, the

economic returns to industry and government from

offshore oil and gas development are estimated by

a computer simulation model (see box). This model

calculates the net present value of all expenditures

and revenues associated with the 10 hypothetical

fields. By discounting these cash flows to the

present, the analysis accounts for the time value

of money and lost opportunities for alternative investments. The model includes a number of assumptions regarding prevailing economic conditions and the investment and production schedules

associated with each oil field. It incorporates all relevant tax and leasing policies.

Economic Rent

The analysis of the net present value of investments has implications for the profitability of

alternative investments and for the bidding behavior of firms for offshore leases. The net present

value of offshore oil and gas development represents the profits available after a firm has received

its normal return to capital, assumed in this analysis to be 10 percent per year. These profits are

referred to as ‘‘excess profits’ or ‘ ‘economic rent.

A firm’s estimate of its share of the economic rent

would be the upper limit to the amount it would

be willing to bid as a bonus payment for the right

to explore and develop an offshore tract. High competition in a lease sale might lead a firm to bid all

of its economic rent as the bonus, leaving it with

a normal return on its investment. If the estimate

of a firm’s economic rent is negative, this indicates

that a firm may not make a normal return on the

investment.

The Federal Government receives its share of the

economic rent from a field in the form of taxes, including corporate income taxes and windfall profits taxes, and lease payments such as production

royalties. The tax and leasing system selected by

the government is intended to extract economic rent

from offshore fields without destroying corporate

incentives to undertake the required investments.

In designing lease and tax payments, the government must balance the need to obtain fair market

value for offshore leases with the need to provide

the necessary incentives for development.

The calculation of the net present value of the

10 hypothetical offshore fields shows all of them to
Ch. 5—Economic Factors ● 121

OTA Computer Simulation Model

be

OTA and outside consultants have developed a computer simulation model to evaluate the economics

of offshore oil and gas development projects. The model is based on a standard “discounted cash flow”

analysis of the economic potential of investments. For each often hypothetical fields (small and large fields

in the Gulf of Mexico, deepwater California, and three Alaskan regions), the model calculates the net present

value of industry and government revenues based on prescribed parameters. Some of these parameters

can be altered to evaluate the effects of changes in various factors on oil field economics.

The descriptive characteristics of the 10 hypothetical oil fields and associated costs are given in table

5-1. The simulation of each oil field is deterministic and follows field-specific investment and production

schedules. The estimated costs and schedules are intended to be representative of actual conditions that

oil companies may encounter in the offshore basins under consideration.

Other model inputs are financial parameters which describe the general economic environment in which

exploration and development take place. Fiscal parameters incorporate applicable governmenttax and leasing

regulations. The sensitivity of field economics to changes in prices, leasing systems, or taxes can be assessed

by altering these parameters. The financial and fiscal parameters given below are those used in the base

case model simulations.

Base Case Financial Parameters:

Crude oil market price, mid-1984 ($ per barrel) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $29.00

Growth rate of real oil price (annual) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . O percent

General inflation rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 percent

Corporate discount rate (real terms) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 percent

Project financing (debt/equity) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 percent

Base Case Fiscal Parameters:

Production royalties (fixed) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12% percent

Rental fees (per acre) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3.00

Corporate income tax (marginal rate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 percent

Taxable income was reduced by immediate expensing of dry hole costs and 80 percent of intangible drilling costs; depreciation of 20 percent of intangible

drilling costs and 95 percent of tangible drilling coats; and the 10 percent investment tax credit.

Companies are assumed to have sufficient income from other sources in the United States to make use of all allowable tax deductions and credits as

soon as they become available.

Financial calculations are baaed on a "ful-cycle" treatment of the exploration/development process. In the fixed royalty cases, the cost of nine dry

wildcat wells is associated with each field (wildcat success rate of one in ten).

Windfall Profits Tax (1984 rate on new oil) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22.5 percent

The Windfall Profits Tax does not apply to Arctic areas and is scheduled to expire after 1993. It thus should not affect frontier-area fields. In the model,

this tax is only levied on the nearshore Gulf of Mexico fields.

profitable in terms of total available economic corporate net present value might not be developed

rent (see table 5-2). However, the government takes

more than its share of the economic rent from two

of these fields-the small fields in the Gulf of Mexico and in the high-cost Navarin Basin. In this analysis, Government payments include a royalty rate

of 121⁄2 percent and corporate income taxes on the

deepwater and Arctic fields. Windfall profits taxes,

which should expire by the time frontier-area fields

begin production, are levied only on the near shore

Gulf of Mexico fields. In addition, the Gulf of Mexico fields are assessed the traditional royalty rate

of 16% percent. The fields which show a negative

under the assumed cost, price, and leasing conditions.

Minimum Economic Field Size

In high-cost offshore regions, very large field sizes

are needed to offset exploration and development

costs and still yield a normal return on investment.

The amount of recoverable reserves needed to yield

a normal economic return after subtracting costs

and government payments is termed ‘ ‘minimum

economic field size. In the offshore frontier areas,
122 ● Oil and Gas Technologies for the Arctic and Deepwater

Table 5-2.—Profitability of Offshore Development

(from base runs of OTA computer simulation)*

Water Field Government

depth size Net present value ($ million) share

Area (feet) (mmb) Total Corporate Government (percent)

Gulf of Mexico

Small field . . . . . . 400 15 62.9 -0.6 63.5 101

Large field . . . . . . 400 50 563.0 211.9 351.1 62

Cal. Deepwater

Small field . . . . . . 3300 150 223.2 28.2 195.0 87

Large field . . . . . . 3300 300 807.2 264.1 543.1 67

Norton Basin

Small field . . . . . . 50 250 261.9 7.6 254.3 97

Large field . . . . . . 50 500 978.0 264.4 713.6 73

Harrison Bay

Small field . . . . . . 50 1000 735.2 81.8 653.4 89

Large field . . . . . . 50 2000 2989.4 955.8 2033.6 68

Navarin Basin

Small field . . . . . . 450 1000 780.6 -149.9 930.5 119

Large field . . . . . . 450 2000 2176.5 121.2 2055.3 94

.Government payments include 121⁄2 percent royalties and corporate income taxes on frontier fields; 162/3 percent royalties

corporate income taxes, and windfall profits taxes on nearshore Gulf of Mexico fields.

SOURCE: Office of Technology Assessment

Figure 5.2.—Profitability of Offshore Development

Small and Large Fields

3.0

2.8

2.6

2.4

2.2

2.0

—c 1.0

0.8

0.6

0.4

0.2

0.0

-0.2

Net present value

Corporate

Government

Corporate & government

Gulf California Norton Harrison Navarin

far greater reserves are needed to yield profitable

investments because of the greater costs and longer

period of time over which these costs must be carried before repayment begins.

The analysis shows that reserves of approximately 40 to 50 million barrels of oil would support development in 400 feet of water in the Gulf

of Mexico. However, a 100- to 150-million barrel

field must be discovered to justify development costs

in a deepwater environment, as in the California

scenario, In the Alaskan offshore scenarios, minimum economic field sizes are as great as 250 to 500

million barrels of oil. In the difficult operating conditions of the Navarin Basin, even the l-billion barrel field may not be profitable for a company to develop (see figure 5-2).

SOURCE: Off Ice of Technology Assessment
Ch. 5—Economic Factors ● 123

GOVERNMENT LEASE

The combination of lease payments and taxes

levied on offshore fields by the government affects

the degree of profit- and risk-sharing between industry and government in oil and gas development.

Activities in offshore frontier areas are differentiated

by their small profit margins and their higher level

of risk and uncertainty. For this reason, government payments affect frontier-area fields differently

than those in other leasing areas.

Fixed Royalties

In addition to the initial cash bonus payment,

lease payments in the United States traditionally

have been fixed royalties based on the value of the

resources produced. The royalty rate has been decreased from the standard 162/3 percent (one-sixth)

to 121⁄2 percent (one-eighth) in offshore frontier

areas to improve the economics of resource development. Fixed royalties are levied on gross income

and are counted as an addition to development costs

in analyzing the potential profitability of projects.

With fixed royalties, there is no allowance for such

factors as field size, production costs, and lead-times

to production when taking the government’s share

of the economic rent. In offshore frontier areas,

where costs are higher and lead-times longer, fixed

royalties may overtax fields and remove the economic incentive for development.

In general, royalty rates can alter production

decisions on small or marginal fields, which in frontier areas may contain substantial resources. In the

OTA analysis, the small field in the Navarin Basin

is unprofitable to develop under fixed royalties,

even though it is assumed to have reserves of 1 billion barrels of oil (see figure 5-3).

Other Lease Payments

Alternative lease payments may be more effective in promoting oil and gas development in offshore frontier areas. Profit-shares and sliding scale

royalties are two types of payments believed to promote greater profit- and risk-sharing between industry and government. Eliminating lease payments would provide an even greater incentive to

exploration and development in frontier areas. In

AND TAX PAYMENTS

Figure 5-3.—Alternative Lease Payments

Effect on Marginal Fields

250

200

150

100 I

Lease payment

1/8 royalty

u

Net profit share

O royalty

I I I

California Norton Harrison Navarin

Corporate net present value

SOURCE: Office of Technology Assessment.

this case, the government would receive its share

of the economic rent through cash bonuses and

taxes.

Although there are several types of profit-sharing

systems, the United States has used a ‘‘fixed capital recovery’ profit-sharing system in tests in offshore leasing. There have been 215 tracts sold with

this type of lease payment between 1980 and 1983.

Firms share at least 30 percent of their profits with

the government, but first recover their initial investment and the cost of carrying that investment

from year to year. Cost recovery is allowed according to a set formula or ‘‘capital recovery factor.

Because the lease payment is levied on net income, profit-sharing systems allow for the high costs
124 ● Oil and Gas Technologies for the Arctic and Deepwater

of production in frontier areas and can provide incentives for the development of most field sizes. The

capital recovery factor also takes into account the

long timeframes of frontier-area projects, so that

a company is not taxed too early in the life of the

field. When profit-sharing with a 200 percent capital recovery factor is used as the lease payment in

the OTA simulation, the small Navarin Basin field

becomes profitable to develop (see figure 5-3).

The major disadvantage of profit-sharing systems

is that they are more difficult to administer than

royalty lease payments. In the fixed capital recovery system, profit share rates and capital recovery

factors must be established prior to lease sales and

calibrated to the operating conditions of different

regions. Other types of profit-sharing systems, such

as a symmetric system where the government shares

in both profits and losses, could reduce the pre-lease

analytic burden. Symmetric profit-sharing also has

superior risk-sharing features. However, in most

profit-sharing systems, the costs and profits associated with individual fields must be calculated and

verified, thus requiring government access to industry cost information. Profit-sharing systems generally require more extensive recordkeeping on the

part of both the industry and government.

The advantage of sliding scale royalties is that

they vary with production rates, and thus extract

a lower payment from smaller and/or less productive fields. However, the OTA analysis showed that

sliding scale royalties perform no better than fixed

royalties as neither can be set below the legal minimum of 121⁄2 percent. Because of the low profit

margins in frontier areas, most fields cannot bear

a lease payment above the minimum royalty even

at higher rates of production. A zero royalty or a

sliding scale royalty which slides down to zero may

be appropriate to high-cost frontier regions. A zero

royalty makes the deepwater and Arctic fields far

more profitable to develop (see figure 5-3).

PRICES AND MARKETS

Market Prices

Current and anticipated market prices are important incentives to exploration and development

activities. Crude oil prices can have a major impact on the profitability of offshore frontier fields,

particularly small or marginal fields, Fields which

are uneconomic under current market conditions

may be profitable given an increase in real crude

oil prices. Similarly, decreases in real prices can

remove the economic incentive to develop offshore

resources. Present predictions are for real oil prices

to decline in the short term and rise in the long

term. Investments made now in oil and gas projects will be based on long-term views of energy markets, real price trends, and technological developments.

It is assumed in the OTA base case model

simulations that there is no increase in the real price

of oil, and that any associated natural gas is not

produced because of low market prices or lack of

available markets. According to the OTA analysis, a 1-percent increase in the real price of oil could

substantially increase

as net present value)

corporate returns (measured

for the oil field scenarios in

offshore frontier areas. The previously unprofitable

Navarin Basin field in Alaska becomes economic

to develop with the real price increase. Higher oil

prices, however, simply change the size of the marginal fields rather than eliminate them.

Alaskan Oil Markets: Export

of Alaskan Oil

Restrictions on the export of Alaskan oil can result in increased costs of transporting offshore oil

to U.S. consuming markets and reduce the profitability of Alaskan offshore fields. The Prudhoe Bay

field, discovered on Alaska’s North Slope in 1968,

contains 10 billion barrels of oil reserves and is the

largest single source of oil in the United States. In

the 1970s, concern about dependence on foreign

oil imports prompted Congress to enact a series of

laws placing restrictions on the export of oil produced on Alaska’s North Slope and in offshore

areas. The Alaskan oil export restrictions of the
Ch. 5—Economic Factors • 125

Export Administration Act of 1979 expired in February 1984. Currently, export of Alaskan oil is being restricted by other statutes.

About half of the oil now produced on the North

Slope is shipped to California and West Coast markets, and the remainder is transported through the

Panama Canal or the Trans-Panama Pipeline to

U.S. markets on the Gulf Coast and Atlantic

seaboard. Removing the ban on Alaskan oil exports

to allow shipment to Asian markets could reduce

the transportation costs of the producers, if these

foreign markets could be developed. However, this

could have negative impacts on the U.S. maritime

industry now engaged in the Alaskan oil trade and

on overall U.S. energy import requirements.

The cost of transporting Alaskan oil to the Gulf

Coast is high because of the long distance and the

requirement under the Merchant Marine Act of

1920 (the Jones Act) that this oil be carried in U.S.

flag tankers. It is estimated that it costs $4.20 per

barrel to ship oil from Alaska to the Gulf Coast in

U.S. flag tankers as compared to a cost of $0.90

per barrel for shipment to Japan in U.S. flag

tankers and $0.50 per barrel for shipment to Japan in foreign flag tankers2 (see figure 5-4). A trans2Stephcn Eule and S Fred Singer, ‘‘Export of Alaskan Oil and

Gas, ‘‘ in ~ree Market Energy, S. Fred Singer (ed. ) (New York: Universe Books, 1984), p. 123.

portation cost savings from exporting Alaskan oil

to closer markets could increase the wellhead price

received for oil produced from onshore and offshore

fields.3 The higher profits, which would be distributed among the producers and Federal and State

governments, may have effects similar to a price

increase in improving the development prospects

of marginal fields.

The North Slope tanker trade to the Gulf Coast

currently engages approximately 40 percent of the

ships in the U.S. tanker fleet and 65 percent of the

U.S. shipping capacity. The U.S. Maritime Administration estimates that the loss from eliminating this trade would be 68 ships and over 4,000 jobs,

and that it might also jeopardize $600 million in

outstanding Federal loan guarantees on the tankers.4 Many North Slope oil producers have investments in tanker capacity and also are ambivalent about exporting oil to markets outside the

United States.

Small tankers needed by the Department of Defense in times of emergency could be displaced by

removing the export ban. About one-third of the

3CongressionaI Research Service, ‘‘ F.xports of Domes[ ic Crude Oil

(Dec. 8, 1983), pp CRS 4-6.

‘General Accounting Office, ‘‘Pros and Cons of Exporting Alaskan

North Slope Oil” (Sept 26, 1983), p. 10

Figure 5-4.— Flow of Alaskan Crude Oil

SOURCE: Stephen Eule and S. Fred Singer, Free Market Energy (New York: Universe Books, 1984)
126 . Oil and Gas Technologies for the Arctic and Deepwater

tankers used in the North Slope oil trade have potential military use because of their small size (less

than 80,000 deadweight tons) which permits them

to haul products into foreign harbors. It is estimated

that removing the Alaskan oil export ban would

eliminate about 13 percent of the supply of tankers

available to the military for defense needs.5 In addition, it would be difficult to ship Alaskan oil domestically in the event of a national emergency if

this idle transportation capacity were eliminated.

Although exporting Alaskan oil to Japan could

substantially improve the U.S. trade deficit with

that country, it would somewhat increase the U.S.

overall dependence on oil imports. Substitute oil

for U.S. refineries could be imported partly from

nearby sources such as Mexico and Venezuela, but

a share also may be imported from Middle Eastern countries. This would decrease overall U.S.

energy security, which the Alaskan oil export ban

is designed to increase. In addition, severe economic losses would be suffered by Panama, which

would lose revenues from the transit of Alaskan oil

through the Panama Canal and the Trans-Panama

Pipeline.

. ..— — —

5Congressional Research Service, <‘Exports of Domestic Crude Oil’

(Dec. 8, 1983), p. 7,

In the short-term, Japan is constrained in its need

for U.S. oil by world energy surpluses and contractual commitments to other suppliers.6 However,

in the long term, Japan might benefit from access

to a secure source of oil and might be more receptive to importing oil from Alaska. In addition, new

oil reserves for throughput of the Trans-Alaskan

pipeline will be needed as Prudhoe Bay production

begins its decline in the late 1980s. Lifting the oil

export ban for offshore fields, which probably will

not come on stream until the mid-1990s or later,

could provide an incentive to exploring and developing costly Arctic areas and new reserves for the

pipeline.

Alaskan Natural Gas Markets:

Alaskan Natural Gas

Transportation System

A system for transporting Alaskan natural gas

to U.S. consuming markets could also increase the

profitability of Alaskan offshore fields. Planning and

financing of the Alaskan Natural Gas Transporta-

“’Japan Doesn’t Want Alaskan Oil Anyway,’ Business Week (Mar.

12, 1984), p. 25.
Ch. 5—Economic Factors ● 127

tion System (ANGTS), the pipeline system intended to transport Alaskan natural gas to the lower

48 States, is currently on hold. Alternative processing and transportation systems have been proposed, but have the same cost and financing problems as the ANGTS.

Construction of the Alaskan segment of the pipeline has been postponed until economic and energy

market conditions allow project financing. The

ANGTS is designed as a 4,800-mile pipeline network carrying natural gas from Alaska’s North

Slope to the U.S. West Coast and the Midwest.

Plans were made for the construction of the

ANGTS during the domestic energy shortages and

sharp oil price increases of the mid-1970s. However, by the time ANGTS plans were completed

in 1981, there were energy surpluses and depressed

prices. The only sections of the pipeline which have

been completed are the Eastern and Western legs

transporting natural gas from Calgary, Canada, to

the U.S. West Coast and Midwest (see figure 5-5).

The potential high market price of Alaskan gas

and associated marketing problems have been the

main cause for a lack of financing for completing

Figure 5-5.—The Alaska Natural Gas Transportation System

— Mainline segments of the Alaska Natural .

Gas Transportation System Financed and

“Prebuilt” on the basis of Canadian

Natural Gas Imports.

San

Francisco

h

SOURCE Off Ice of the Federal Inspector, Alaska Natural Gas Transportation System, Washington, D C
128 • Oil and Gas Technologies for the Arctic and Deepwater

the ANGTS. Current cost estimates of finishing the

ANGTS are $40 to $50 billion, with the Alaskan

segment alone estimated at $25 to $30 billion.7 The

tariff which would be charged to cover the costs of

building the pipeline makes the projected price of

Alaskan gas uncompetitive in its designated markets, in the short term. Estimates of the delivered

price of Alaskan gas in 1989-90 are about $7.50

per thousand cubic feet, above the projected price

of about $6.00 per thousand cubic feet for lower

48 gas in 1990.6

7Stephen Eule and S. Fred Singer, ‘‘Export of Alaskan Oil and

Gas, ” (New York: Universe Books, 1984), p. 140.

*General Accounting Office, “Issues Facing the Future Use of

Alaskan North Slope Natural Gas” (Washington, DC, 1983), pp.

16-19.

Alternative proposals to ANGTS include using

Alaskan natural gas as raw material for a petrochemical facility or a methanol industry, or converting it to liquefied natural gas (LNG) for export

to Japan. However, depressed world energy prices,

marketing problems, limitations on Alaskan gas exports, and government commitments to ANGTS

make these proposals unlikely alternatives to the

pipeline system. A substantial increase in real gas

prices may make the ANGTS or another Alaskan

natural gas project economically feasible. A market outlet could be provided for natural gas now

being produced, and reinfected, on Alaska’s North

Slope. In addition, the availability of natural gas

processing and transportation infrastructure could

improve the profitability of Alaskan offshore oil and

gas development projects.
Chapter 6

Federal Leasing Policies
Contents

Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Rate and Extent of Offshore Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Background ....... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Area-Wide Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

The Role of the Coastal States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Special State/Federal Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Congressional Leasing Moratoria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

Military Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Disputed International Boundaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

Areas of Potential Dispute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

Dispute Settlement Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Leasing Policies for Offshore Frontier Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

Bidding Systems.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154

Lease Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158

Tract Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

Joint Bidding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

TABLES

Table No. Page

6-1. Five-Year OCS Leasing Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

6-2. State Role in Offshore Oil and Gas Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

6-3. Advantages and Disadvantages of Alternative Bidding Systems . . . . . . . . . . . . . . . . . . . . . . . . 155

FIGURES

Figure No. Page’

6-1. Gulf of Mexico Bidding by Water Depth. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

6-2. Trends in Gulf of Mexico Average Bids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138

6-3. Deferrals of Offshore Acreage for Military Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

6-4. U.S.-Canada Boundary in Georges Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

6-5. U.S.-Canada Boundary in Beaufort Sea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150

6-6. U.S.-U.S.S.R. Boundary in Bering Sea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152

6-7. Gulf of Mexico Boundaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153
Chapter 6

Federal Leasing Policies

OVERVIEW

The Federal Government is the largest single

owner of energy resource lands in the United States.

It controls approximately 730 million acres onshore— mostly in western States—and nearly 1.9

billion acres in the offshore U.S. Exclusive Economic Zone (EEZ). Industry access to the vast government landholdings for oil and gas development

is essential to meeting the country’s future energy

needs. However, energy development on Federal

lands must be balanced with other land uses and

with protection of the environment.

Federal leasing of offshore areas for oil and gas

development is conducted under the Outer Continental Shelf (OCS) Lands Act of 1953, as amended

in 1978. The 1978 amendments to the Act require

that offshore leasing balance expeditious energy development with the interests of the coastal States

and environmental concerns. The first Federal offshore lease sale was held in the Central Gulf of

Mexico in October 1954. Leasing in the more hostile environments of the Arctic began in 1979 and

in the deepwater areas of the lower 48 States in

1981.

At the same time that leasing in offshore frontier areas was growing, the rate of leasing was

greatly accelerated. In the 1980s, the Department

of the Interior implemented a system of ‘area-wide

leasing, expanding the offshore acreage considered for each lease sale. Interior also increased the

number of lease sales held each year, Opposition

to the accelerated leasing schedule from coastal

States, environmental groups, and others resulted

in several delays to the lease schedule and some

modification of the area-wide leasing approach.

Delays in the leasing schedule also resulted from

the continuing dispute between the coastal States

and the Federal Government over the appropriate

division of power and revenues in offshore leasing.

Although the controversies have primarily concerned issues in nearshore leasing—means of mitigating adverse effects on coastal areas and methods of dividing revenues from oil and gas basins

crossing State/Federal boundaries—they have created uncertainty in frontier-area leasing as well.

The extent of leasing in offshore frontier areas has

also been constrained by deferrals of offshore acreage for military uses and controversies regarding

international boundaries.

Some changes have been made in Federal leasing policy in recognition of the increased costs and

risks of oil and gas development in offshore frontier areas. The primary lease term has been extended from 5 to 10 years and royalties have been

lowered for most frontier areas. However, additional changes may be needed in bidding systems,

the size of the lease tracts, and other leasing terms

and conditions to provide the incentive for comprehensive exploration and development of the

energy resources of Arctic and deepwater frontiers.

RATE AND EXTENT OF OFFSHORE LEASING

Background dustry had been developing oil and gas resources

offshore for many years prior to that under State

Federal leasing of offshore areas for oil and gas leases and permits. Offshore oil was first produced

development began soon after the passage of the from piers off Summerland, California in 1896. The

OCS Lands Act of 1953,1 but the petroleum in- States of Louisiana, California, and Texas began

leasing in the 1920s. The first Federal offshore lease

sale was held in the Central Gulf of Mexico in Oc-

‘ Pub. Law 83-212, 67 Stat. 462 ( 1953), 43 USC 1331-1356, tober 1954.

131
132 Ž Oil and Gas Technologies for the Arctic and Deepwater

The OCS Lands Act of 1953 provided the basic

policy for the development of offshore oil and gas

resources under Federal jurisdiction. It authorized

the Department of the Interior to lease these areas

to private persons for development, and it established general guidelines for managing the leasing

process and post-lease activities. In 1969, an oil well

blowout in the Santa Barbara Channel off California increased public awareness of the environmental

risks of offshore leasing. This concern was coupled

with greater uncertainty about future U.S. energy

supplies after the Arab oil embargo of 1973. In

1974, Congress began to amend the 1953 Act to address these concerns, which culminated in the enactment of the OCS Lands Act Amendments of 1978.2

The 1978 Amendments made fundamental and

somewhat controversial changes in offshore leasing policy. The Amendments opened up the decisionmaking process for offshore leasing to give affected parties—primarily the coastal States—the

opportunity for greater involvement. Stricter criteria and standards were included in consideration

of environmental factors and competing land uses.

New emphasis was placed on the public revenue

from OCS development and the receipt of fair market value for oil and gas resources. From 1978 on,

Federal offshore leasing for oil and gas development

had to balance energy policy goals with State, environmental, and revenue considerations.

In addition, the OCS Lands Act Amendments

introduced the requirement for a 5-year schedule

of proposed lease sales.3 The June 1979 leasing

schedule, which was revised in June 1980, was the

first prepared in accordance with the requirement.

This schedule increased the number of sales to be

held in frontier areas; approximately one-half of

the sales were scheduled for Alaskan and deepwater

regions. In October 1981, however, the U.S. Court

of Appeals ruled that the leasing program did not

meet the requirements of Section 18 of the OCS

Lands Act Amendments and remanded the program to the Secretary of the Interior for revision.

A 5-year leasing program drafted by the new Secretary of the Interior, James Watt, in mid-1981 did

subsequently withstand the legal challenge for adequacy.4 This program, which covered the period

‘Pub. Law 95-372, 92 Stat. 629 (1978), 43 USC 1801-1866.

‘Section 18, Supra note 1.

‘California v. Watt, No. 80-1894 (D. C. Cir. 1983).

August 1982 through June 1987, proposed dramatic

increases in the acreage to be offered and leased

in an effort to increase domestic energy production.

Approximately one billion acres of Federal offshore

lands were to be offered for lease in the 5-year

period. This was far more than the 50 million acres

offered for lease in the entire period from October

1954 through June 1982. Under the new concept

of ‘area-wide leasing, the acreage offered was increased from a previous average of 1 to 2 million

acres per sale to 20 to 50 million acres per sale. In

addition, the leasing schedule itself was accelerated

to an average of eight sales per year, compared to

an average of five sales per year in the previous 5-

year period.

Most of the land to be leased under the 1982-87

schedule was in the frontier areas. Out of a total

of 41 lease sales, there would be 16 offerings off

Alaska, 12 in the Gulf of Mexico, 8 off the Atlantic Coast, 4 off California, and one reoffering sale.

Several new Alaskan offshore areas would be

opened to leasing for the first time. In total, over

56 percent of the acreage to be offered was off the

Alaskan coast and another 20 percent was in the

deepwater areas of the Gulf of Mexico, the Atlantic, and the Pacific.

Early opposition to the 1982-87 accelerated leasing program caused a number of delays in its implementation. Of the 21 lease sales scheduled

through the end of 1984, only seven were held on

the originally scheduled date. Opponents, mostly

coastal States and environmental groups, challenged several sales with litigation on the basis of

alleged violation of the requirements of the OCS

Lands Act Amendments, the Coastal Zone Management Act, and relevant environmental laws. In

addition to that opposition, Congress delayed sales

by prohibiting the use of appropriated Interior Department funds for leasing and development of specific OCS basins in the Pacific, Atlantic, and Gulf

of Mexico. However, of the lease sales scheduled

for 1982-84, all but four—the two Georges Bank

sales in the North Atlantic and two Alaskan sales—

had been held by the end of 1984,

In 1983 and 1984, record amounts of OCS acreage were offered and leased. For the first time, substantial acreage was leased in Alaska-in the Diapir

Field, and the Navarin, Norton and St. George

Basins—and in the deepwater areas off the lower
Ch. 6—Federal Leasing Policies . 133

48 States. In the Gulf of Mexico area-wide lease

sales of 1983-84, more than 26 percent of the tracts

leased were in water depths beyond 2,000 feet and

18 percent in water depths beyond 3,900 feet. Prior

to 1983, leasing in water depths beyond 2,000 feet

rarely exceeded 5 percent of the total acreage. Similarly, new deepwater acreage was leased in the

Atlantic and Pacific regions.

In January 1984, the new Secretary of the Interior, William Clark, announced his intention to

decrease the acreage considered for leasing under

the 1982-87 leasing schedule because of State and

environmental concerns. However, Secretary Clark

continued to support the general concept of areawide leasing, particularly in the Gulf of Mexico.

A revised leasing schedule issued in October 1984

indicated that the six Gulf of Mexico area-wide lease

sales to be held between May 1985 and April 1987

would take place as scheduled (see table 6- 1). Several of the remaining Alaskan, California, and

Atlantic sales, however, were delayed and some

were reduced in acreage. Despite these modifications to the leasing schedule, the magnitude and

Table 6-1 .—Five-Year OCS Leasing Schedule (8/82-6/87)

Schedule date

Region Sale # Location Original Current

Re-offering . . . . . . . . . . . . . . . . . . . AT, CA, AK

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Pacific . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Pacific . . . . . . . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Pacific . . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Pacific . . . . . . . . . . . . . . . . . . . . . .

Atlantic. . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Alaska. . . . . . . . . . . . . . . . . . . . . . .

Atlantic . . . . . . . . . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . . . . . . . . . .

Gulf of Mexico . . . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . . . . . . . . . . .

RS-2

71

52

69-1

69-2

57

70

76

72

78

74

73

79

80

82

83

81

87

84

88

89

85

92

98

111

102

91

100

94

95

96

107

104

97

105

99

101

108

109

110

86

Diapir Field

Georges Bank

Texas, LA

MS, AL, FL

Norton Basin

St. George Basin

Mid-Atlantic

Central Gulf

South Atlantic

Western Gulf

Central CA

Eastern Gulf

Southern CA

North Atlantic

Navarin

Central Gulf

Diapir Field

Western Gulf

Gulf/Cook Inlet

St. George Basin

South Atlantic

Barrow Arch

N. Aleutian Basin

Central Gulf

Mid-Atlantic

Western Gulf

Cent/North CA

Norton Basin

Eastern Gulf

Southern CA

North Atlantic

Navarin Basin

Central Gulf

Diapir Field

Western Gulf

Kodiak

St. George Basin

South Atlantic

Barrow Arch

Central Gulf

Shumagin

Aug 1982

Sept 1982

Oct 1982

Oct 1982

Oct 1982

Nov 1982

Feb 1983

Apr 1983

May 1983

JuIy 1983

Aug 1983

Sept 1983

Nov 1983

Jan 1984

Feb 1984

Mar 1984

Apr 1984

June 1984

JuIy 1984

Oct 1984

Dec 1984

Jan 1985

Feb 1985

Apr 1985

May 1985

June 1985

Aug 1985

Sept 1985

Oct 1985

Nov 1985

Jan 1986

Feb 1986

Mar 1986

Apr 1986

June 1986

JuIy 1986

Oct 1986

Dec 1986

Jan 1987

Feb 1987

Apr 1987

June 1987

As scheduled

Oct 1982

Postponed

Nov 1982

Mar 1983

Mar 1983

Apr 1983

As scheduled

As scheduled

As scheduled

As scheduled

Dec 1983

Jan 1984

Oct 1984

Postponed

Apr 1984

As scheduled

Aug 1984

As scheduled

Postponed

Sept 1985

Postponed

Postponed

Dec 1985

As scheduled

Oct 1985

As scheduled

Dec 1987

Dec 1985

As scheduled

Apr 1987

Nov 1987

Sept 1986

As scheduled

Dec 1966

As scheduled

Postponed

July 1988

July 1989

May 1987

As scheduled

Dec 1987

SOURCE: Minerals Management Service, 1985.
134 ● Oil and Gas Technologies for the Arctic and Deepwater

pace of OCS lease sales, still set at seven to eight

per year, remain significantly greater than previous schedules.

The Department of the Interior is now soliciting

comments from industry, coastal States and other

interested parties on a new 5-year OCS Leasing

Program for the period mid-1986 through mid1991. The overlap between the two schedules in

1986/87 is intended to provide a transition period

from one program to the next. Eleven sales have

been carried over from the previous 5-year leasing

schedule (see box).5

The new 5-year leasing schedule proposes a total

of 43 sales: 33 standard sales, 5 frontier exploration sales, and 5 supplemental sales. The frontier

exploration sales are scheduled for areas of Alaska

where resource assessment is incomplete and in5Department of the Interior News Release, ‘‘Secretary Hodel Releases Draft Proposed OCS Oil and Gas Program, (Mar. 21, 1985).

Proposed Five-Year OCS Leasing Schedule (7/86-6/91)

Region sale # Location Proposed date

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . 105 Western Gulf July 1988

Supplemental 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1986

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 Navarin Basin Sept. 1988

Alaska ● . . . . . . . . . . . . . . . . . . . . . . . . . . . . Beaufort Sea Dec. 1988

Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 Southern California Apr. 1987

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . 110 Central Gulf Apr. 1987

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Chukohl Sea May 1987

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1987

Supplemental 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1987

Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96 North Atlantic Nov. 1987

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 Shumagin Dec. 1987

Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91 Northern California Dec. 1987

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1988

Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gulf of Alaska Mar. 1988

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Eastern Gulf May 1988

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 St. George Basin July 1988

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1988

Supplemental 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1888

Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Atlantic Oct. 1988

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . North Aleutian Basin Dec. 1088

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1989

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Norton Basin Mar. 1989

Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Central California May 1989

Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108 South Atlantic July 1989

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1889

Supplemental 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1989

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Navarin Basin Sept. 1989

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Beaufort Sea Dec. 1989

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1990

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chukchi Sea Mar. 1990

Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Southern California Apr. 1990

Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . June 1990

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1990

Supplemental 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1990

Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shumagin Sept. 1990

Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . North Atlantic Oct. 1990

Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Northern California

Alaska*

Dec. 1990

. . . . . . . . . . . . . . . . . . . . . . . . . . . . Kodiak Jan. 1991

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1991

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . St. George Basin Apr. 1991

Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Washington-Oregon Apr. 1901

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Eastern Gulf May 1991

Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hope Basin June 1991

%wtl.r axfwwetlon eetee, @p@ementef eelee-Annuel Wee for eeleoted dreinm, development, endfor rejeoted IM blocks outsldo the Centrel and We$tem Gulf of Mexico.

SOURCE: Department of the Intortor News Releaee, Mar. 21, 19SS.
Ch. 6—Federal Leasing Policies Ž 135

dustry interest appears to be low. An added presale

step, a Request for Interest, will be used prior to

these sales to determine if industry interest warrants holding the sales. The supplemental sales will

be held in August of each year for selected drainage, development, and/or rejected bid blocks outside the Central and Western Gulf of Mexico.

Annual lease sales will still be held in the two

most prospective areas: the Central and Western

Gulf of Mexico. Outside of these areas, the pace

of leasing will be slowed from one sale every 2 years

to one sale every 3 years. In addition, a ‘‘flexibility

provision” has been added to allow the pace of leasing to be adjusted to economic conditions. Sales

in certain areas (Northern, Central, and Southern

California; Eastern Gulf of Mexico; Navarin Basin;

Beaufort Sea; North Aleutian Basin; and St.

George Basin) may be accelerated if changes in oil

prices or new geologic data warrant.

Area- Wide Leasing

The area-wide leasing system made fundamental changes in the lease tract offering process. Prior

to 1983, under what is called the ‘ ‘tract nomination’ sale system, the Department of the Interior

offered a limited number of specific tracts for leasing based on the geological prospects for oil and

gas as interpreted by the government. Between the

first offering of offshore leases under the OCS

Lands Act Amendments in February 1979 and the

beginning of the area-wide sale system in April

1983, about 23 million acres were offered for

leasing.

Under area-wide leasing, the Department of the

Interior offers an entire lease sale planning area for

leasing. Tracts may be selected from every unleased

tract and from tracts where the leases have expired.

Recommendations are still made by the States and

other Federal agencies for exlusion of tracts from

the sale. But under this system, industry is permitted to choose where its investments in exploration will be made without being double-guessed by

the Department of the Interior.

About 546 million acres have been considered

by the industry in the 11 area-wide lease sales held

through the end of 1984. This is actually an overestimate, because it includes blocks previously sold

as well as double-counting for 35 million acres offered twice in the Gulf of Mexico. About 63 percent of this or 346 million acres was actually offered for leasing in the area-wide sales. Of this,

industry leased 13 million acres. Based on these

numbers, area-wide leasing is a misnomer. The system should more accurately be called ‘ ‘area-wide

consideration or ‘‘area-wide selection.

In theory, area-wide leasing was adopted to provide the industry an opportunity for early selection

of tracts which offer the best prospects for discovery of oil and gas. In operation, it also has resulted

in an increased rate of leasing. Industry faulted the

tract nomination system because the Department

of the Interior made its own determinations of resource potential and often failed to include many

of the tracts nominated by industry. However,

critics of the area-wide system maintain that a return to a nomination system where the Department

of the Interior assures that industry nomination will

be honored would allow sufficient freedom of tract

selection.

Under revised area-wide leasing procedures announced by Secretary of the Interior William Clark

in January 1984, firms make specific recommendations on selected tracts at the call for information stage (the initial phase of the leasing process).

Secretary Clark requested that the industry target

those tracts in which they are seriously interested

and reduce ‘‘scenery’ selections (those intended

to mask bidding strategy). In this way, environmental assessment can be focused on specific areas

of interest to the industry. Better information can

also be provided to State and local governments and

environmental groups early in the area identification process so that they may prepare for the later

consultation phase.

Secretary of the Interior Don Hodel adopted a

modified area-wide leasing system for use during

the 1986-91 5-year leasing schedule. Although

essentially the same as the Clark system, it is here

called the ‘ ‘focused approach’ intended to focus

lease offerings on promising acreage.

Both the industry and the Department of the Interior defend the concept of area-wide leasing,

noting that the United Kingdom and Canada have

successfully used this approach for offshore leasing

for a number of years. From the standpoint of tech-
136 . Oil and Gas Technologies for the Arctic and Deepwater

nology development, the industry also asserts that

expensive offshore technologies will only be developed and financed if the industry has profitable

leases.

The shift from tract nomination to area-wide

leasing has raised opposition from some coastal

States and environmental groups, which allege that

area-wide leasing is nothing more than a “fire sale’

and giveaway of the Nation’s resources and, because of the magnitude of the sales, a threat to the

ocean and coastal environments. The industry,

however, defends the integrity of the area-wide approach in terms of efficient resource development,

fair value received for Federal leases, and environmental protection. The Minerals Management

Service (MMS) also denies that the environment

is receiving any less attention under the area-wide

leasing system than under the tract nomination approach.

The area-wide leasing debate has focused largely

on the Gulf of Mexico. About 70 percent of the

acreage offered under the area-wide system through

January 1985 has been in that region. Less attention has been given to the potential impact and effectiveness of area-wide leasing in deepwater and

Arctic frontier regions because of limited experience with leasing in these areas. The Gulf of Mexico, being a mature producing region where the

geology and petroleum prospects may be estimated

more accurately, is considerably different from

frontier regions where little or no production has

occurred and where each new well is considered a

wildcat. Analysis of the results of area-wide leasing in the frontier areas is difficult because few areawide sales have been held in these regions.

Those critical of area-wide leasing have emphasized two aspects of public policy: 1) receipt of

fair market value for government-owned resources;

and 2) environmental implications of an accelerated, broad-based leasing program.

Fair Market Value Concerns

The OCS Lands Act Amendments of 1978 require that the government receive fair market value

for offshore leases, although no precise definition

of fair market value is given. Controversy has resulted from the fact that the average bonus bid per

acre has declined under the area-wide system, and

that fair market value may not be received for leases

under area-wide offerings. The average bid per acre

under the tract nomination system between 1979

and 1983 was $2,388. Since the beginning of areawide leasing in 1983, bonus bids have averaged

about $529 per acre.

The debate over the receipt of fair market value

under area-wide leasing has centered on economic

analyses done by National Economic Research

Associates, Inc. (NERA) for the State of Texas in

support of the State’s discussions with the Department of the Interior over disposition of escrow

money from Federal/State tracts in the Gulf of

Mexico.6 NERA’s analysis attributed the reduced

bonus bids received in area-wide lease sales in the

Gulf of Mexico to several factors:

●

●

o

●

Supply and Demand: Based on classical economic theory of supply and demand, the more

tracts offered in a lease sale, the lower the bids

will be as a result of less competition.

Fixed Budgets: If firms have fixed budgets for

lease acquisition, they will tend to bid lower

on a larger number tracts offered in an areawide sale than they would if fewer tracts were

offered in a nomination sale.

Bargain Hunting: If firms can acquire leases

cheaply, they will be willing to accept higher

risks of dry holes.

Time Value of Money: If production maybe

delayed, firms will reduce their bids to offset

the cost of discounting the investment.

The NERA study concluded that area-wide

leasing will not accelerate energy production,

because development is determined by the

profitability of individual leases and not the

rate and number of lease purchases.

In conducting its analysis, NERA also found that

water depth had little relationship to the lower bids

received in the Gulf of Mexico. NERA did not

undertake an analysis of data relating bids to tract

depths, but rather related bid levels to distance from

shore. Distance from shore and water depth are

generally, but not consistently, related. By assumbLetter and attachments from Governor Mark White to Secretary

of the Interior William Clark (May 25, 1984) and afiidavit and exhibits of Jeffery J. Leitzinger, Senior Consultant, National Economic

Research Associates, Inc.
Ch. 6—Federal Leasing Policies ● 137

ing a one-to-one relationship between distance offshore and water depth, the NERA study may have

masked the true effects of water depth on bid levels.

An OTA analysis of bonus bids and water depth

in five area-wide leases sales in the Gulf of Mexico

suggests that a trend relationship may exist between

lower bonus bids and leases in water depths of 600

feet and greater (see figure 6- 1). Bids in deepwater

frontier areas may be lower as a result of the increased risks and higher costs associated with exploration and development of oil and gas.

The lower bids in the Gulf of Mexico area-wide

lease sales may also be due to a number of other

factors. These include pessimism over future oil

prices; the failure of the industry to find oil and

gas in highly prospective areas of the Atlantic and

Pacific; the fact that the leased tracts in the Gulf

of Mexico had been ‘ ‘picked over’ previously; and

the increase in the minimum bid from $25 to $250

per acre by the Department of the Interior.7 In ad7Nat ionat Ocean Industries, Area-Wide Leasing: Nationaf Boon

or Industry Boondoggle?, (Washington, DC: 1984).

dition, it has been pointed out that the downward

trend in bids in the Gulf of Mexico actually began

under the tract nomination system in 1980 and continued under the area-wide system (see figure 6-2).

In general, fair market value is a difficult concept to define. The U.S. Court of Appeals upheld

the accelerated leasing program of the Department

of the Interior, noting that the law does not require

the maximization of revenues, only the receipt of

a fair return for Federal leases. The Department

of the Interior points out that bonus payments represent only about one-fourth of the revenues received from offshore oil and gas leases and thus are

not the only consideration in assessing fair market

value. Federal payments are also received in the

form of taxes, royalties, and rentals.

Environmental Concerns

Environmental concerns related to area-wide

leasing focus on the inability of the States and the

Federal Government to evaluate potential environmental impacts from offshore development in lease

Figure 6-1 .–Gulf of Mexico Bidding by Water Depth

20

18

16

14

6

4

2

0

0

●

. High bonus bids

in Gulf of Mexico

area-wide sales

Water depth (thousand feet)

SOURCE: Office of Technology Assessment.
138 ● Oil and Gas Technologies for the Arctic and Deepwater

Figure 6.2.—Trends in Gulf of Mexico Average Bids

4,853

3,18!

—

Sale no.:

4,53 —

—

3,699

3,293

2,446

58 A58 A62 62 A66

I Nomination sales]

SOURCE: National Ocean Industries Association.

sales covering broad, diverse areas. It may be difficult for State and local governments to plan for

and assess the impacts of OCS development under

area-wide leasing because of the extent of the area

considered and the uncertainty of which portions

will be offered for sale. In addition, environmental

groups assert that general statements of environmental impacts are not useful, and detailed analyses of vast areas that will not be leased is wasteful.8

The Department of the Interior stresses that prelease and post-lease environmental regulations and

State and local consultation are the same under

area-wide leasing as under the tract nomination system. The steps and procedures required by law to

identify, assess, and disclose possible environmental

8Department of the Interior, Final Supplement [o the F’ina/ En vironmental Statement, Vol. 2, Comments from Industry and Public

Interest Groups (Fall 1981).

2,023 1,895

1,090

72

667

74 79 81

0’

Area wide sales

impacts which may result from offshore oil and gas

development are being followed. The industry

believes that environmental assessments under areawide leasing are better. Consideration of larger

areas may lead to a broader knowledge of geohazards, marine biology, physical oceanography,

and environmental baselines.

Environmental information, however, is but one

factor considered by the Secretary of the Interior

in a leasing decision. Environmental interests argue

that mere pro forma adherence to legal requirements is not sufficient. Environmental information

should also be adequately considered by the Secretary in the decision process. Environmentalists

maintain that the Secretary of the Interior is not

assigning appropriate weight to environmental risks

in balancing OCS oil and gas development with

possibilities of environmental harm.
Ch. 6—Federal Leasing Policies ● 139

THE ROLE OF THE COASTAL STATES

Background

Ownership of offshore oil and gas resources has

been the source of major disagreements between

the Federal Government and the coastal States for

nearly 50 years. Realizing the extent of the petroleum wealth that lay below the seabed off their

shores, California, Louisiana and Texas began

asserting their rights of ownership to the submerged

lands as early as 1937. The spat between the States

and the Federal Government over offshore petroleum resources became known as the “Tidelands

Issue. This issue figured prominently in the politics of that era and influenced Federal-State relationships for nearly two decades. Even today, the

struggle continues over the appropriate balance of

power, authority, and revenue entitlements that

coastal States should exercise over resources in the

Federal portion of the Continental Shelf.

Prior to 1945, the seabed resources beyond the

internationally recognized 3-mile Territorial Sea

were not owned by any nation or individual in

accordance with customary international law at that

time. On September 28, 1945, President Harry S

Truman by Executive Proclamation declared that

the United States has exclusive control and jurisdiction over the natural resources of the seabed and

subsoil of the Continental Shelf adjacent to the

United States. g This unilateral claim to the resources of the Continental Shelf was not recognized

under international law until it was ratified by the

First Law of the Sea Conference held in Geneva

in 1958. The Convention on the Continental Shelf

recognized that a coastal nation ‘ ‘exercises over the

Continental Shelf sovereign rights for the purpose

of exploring it and exploiting its natural resouces.” 10

Between President Truman’s proclamation in

1945 and international recognition of coastal nations’ authority in 1958, intense disputes arose between the coastal States and the Federal Government over who had the authority to regulate

development and who would benefit from the rich

petroleum resources that lie beneath the seabed.

‘Excc. Proclamation No, 2667; 59 Stat. 884 (1945).

101 s ~sT 471 ; TIAS 5578.

The judicial answer to the question of ownership

and control of the resources of the Continental Shelf

came in 1947 when the United States Supreme

Court in U.S. v. State of California decided that

the Federal Government and not California had

“paramount rights” and power over the 3-mile

Territorial Sea (recognized by international law at

that time), including full dominion over the resources of the submerged lands.11 In subsequent

suits filed by Louisiana, Texas, and Florida the

Court applied the same legal principle and awarded

jurisdiction over the submerged lands to the Federal Government. The Court allowed some extended State claims in the Gulf of Mexico because

of the special conditions under which Florida and

Texas were admitted to the Union .12

Although the coastal States’ legal challenge for

control of offshore petroleum resources failed, a political assault in the Congress paid off. In 1953,

Congress enacted the Submerged Lands Act, which

effectively reversed the Supreme Court’s decision

in U.S. v. State of California by conveying all rights

that the Federal Government claimed in the nearshore submerged lands to the coastal States.13 It

gave the States the title and ownership of the

submerged lands and natural resources seaward of

their coasts out to 3 nautical miles. With the contentious issue of State claims to the Continental

Shelf resolved, the Congress simultaneously enacted

the OCS Lands Act of 1953, which established Federal leasing authority in the OCS seaward of the

State-controlled zone.

However, the conflict between the coastal States

and the Federal Government over oil and gas beneath the seabed did not abate with the enactment

of the Submerged Lands Act and the OCS Lands

Act. Disagreements continued over drainage of oil

from reservoirs beneath adjacent Federal and State

properties, and the apportionment of revenues from

oil in disputed areas. As the pace of offshore oil and

gas development increased under the leasing procedures of the OCS Lands Act, coastal States voiced

“332 US 19 (1 947)

I z ~’ s,..~, 10ujsjana, 339 US 699 ( 1950); Lr. S. t’. Texas, 339 U.S.

707 (i950).

IJpublic LaW 83-3 I ; 67 Stat. 29 (1 953); 43 USC i301 -1315.
140 . Oil and Gas Technologies for the Arctic and Deepwater

their concerns over the adverse environmental and

social impacts that could result from operations off

their shores.

In response to concerns that unplanned development of the coastal region could lead to irreparable environmental damage, the Congress enacted

the Coastal Zone Management Act (CZMA) in

1972. The CZMA authorized Federal grants to

coastal States as incentives to establish coastal zone

management plans. Once a State coastal zone management plan is approved by the Secretary of

Commerce, all Federal actions within the coastal

zone, or which ‘ ‘directly affect’ the coastal zone,

are required to be conducted in ‘‘a manner which

is, to the maximum extent practicable, consistent

with approved State management programs. In

the past, coastal States have asserted that the act

of offering offshore leases ‘‘directly affects’ the

coastal zone and that leases should be subject to

a determination of consistency with the adjacent

State’s coastal zone management program. However, in 1984, the United States Supreme Court

in Secretary of the Interior v. California held that

OCS oil and gas lease sales per se are not Federal

activities “directly” affecting the coastal zone

within the meaning of the CZMA, and therefore

do not require State consistency determinations at

the time leases are offered.14

The CZMA was amended in 1976 to establish

a Coastal Energy Impact Program (CEIP).15 The

CEIP was designed to provide States and local governments with financial assistance to meet needs

resulting from energy activities in coastal regions,

including the development of OCS oil and gas.

Enactment of the CEIP was predicated on the belief

that coastal States are likely to encounter greater

impacts from energy development than inland

States because of their geographic location with regard to offshore petroleum, ports for energy imports and exports, and electric power generating

stations which require large volumes of cooling

water. The CEIP, although scheduled to continue

through 1986, has not been funded since 1980.

The OCS Lands Act of 1953, as amended in

1978, declares it national policy that:

. . . the outer Continental Shelf is a vital national

resource reserve 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; .. .16

Although the congressional statement of national

policy emphasizes the importance of offshore petroleum reserves and acknowledges that they should

‘‘be made available for expeditious and orderly development, the Act concurrently recognizes that:

. . . exploration, development, and production of

the minerals of the outer Continental Shelf will

have significant impacts on coastal and noncoastal areas of the coastal States .. .17

The Secretary of the Interior is therefore responsible for balancing what are sometimes conflicting

national policies: providing for secure domestic

sources of oil and gas from the OCS while at the

same time protecting environmental values and

respecting the plans, goals and objectives of sovereign coastal States and local governments.

In response to concerns about the potential impact of offshore petroleum development on the

coastal States and local communities, Congress set

forth as national policy in the 1978 Amendments

the principles that: 1) States and local governments

may require Federal assistance to protect their

coastal zones; 2) States and local governments are

entitled to participate in the policy and planning

decisions of the Federal Government; 3) States and

local governments have rights and responsibilities

to protect the environment and the population from

adverse impacts of offshore petroleum activities;

and 4) the petroleum industry has the responsibility

for ensuring the environmental and personal safety

of offshore operations.

The OCS Lands Act as amended in 1978 is

unique among Federal statutes which authorize

leasing, sale or disposal of public resources. Much

more State and public involvement in lease planning and Federal licensing and permitting is mandated in the administration of the OCS leasing program than is required for similar leasing of coal,

onshore oil and gas, or other minerals on Federal

lands. When considered in conjunction with the requirements of the CZMA, the National Environmental Policy Act of 1969, the Federal Water Poli+ca~e No. 82.1326, (Decided Jan. I I, 1984).

15public Law 94-370, 90 Stat. 101s (1976).

IbSection 3(3), Supra note 1.

ITSection 3(4), Supra note 1.
Ch. 6—Federal Leasing Policies . 141

lution Control Act as amended, and the Clean Air

Act, the OCS Lands Act provides an unprecedented opportunity for coastal State involvement

in the offshore oil and gas leasing program.

The 1978 OCS Lands Act Amendments call for

State and local government consultation, comments, or coordination at six separate points in the

planning, leasing, exploration, and productiondevelopment sequence: 1) during the formulation

of the 5-year leasing program; 2) at the time of review of environmental impact statements regarding the 5-year leasing program; 3) prior to a proposed lease sale; 4) with regard to oil and gas that

may straddle adjoining Federal and State properties; 5) at the issuance of exploration permits; and

6) during the review of production and development plans. In addition, the Secretary of the Interior is directed to provide the necessary information to State and local governments to assist them

in responding to Federal actions (see table 6-2).

At no point in a lease sale can a State absolutely

veto lease planning or sale preparation. However,

States can make recommendations through the consultation and commenting provisions. After leases

are awarded, the coastal States have the power of

approval of exploration and development plans,

which must be consistent with their coastal zone

management programs. Pipelines, ports, or storage and transfer facilities for supporting offshore

oil and gas operations that are located within the

3-mile Territorial Sea or on the shore must also conform with a State’s coastal zone management plans

and other local zoning or land use laws within the

police powers of the State. As a condition of Federal approval of a State coastal zone management

program, provision must be made for giving adequate consideration to energy developments in the

national interest of the United States.

Notwithstanding the ample provisions made in

the OCS Lands Act and the CZMA for coordinaTable 6-2.—State Role in Offshore Oil and Gas Leasing

Subject Action Authority

Outer Continental SheIf

Leasing Program

Environmental Impacts

Proposed Lease Sale

Leasing Within 3 Miles of

State’s Territorial Sea

Geological and Geophysical

Exploration Plans

Production and Development

Plans

OCS Oil and Gas Information

State and local government

comments on proposed 5-year

plan and on Secretary’s annual

review of the plan.

Comments by the State on draft

environmental impact statements

at time of revisions in the 5-year

leasing program and at submission of exploration and

development and production

plans.

Coordination and consultation with

State and local officials concerning size, timing or location

of proposed lease sale.

Consultation with regard to

development of shared oil pools.

Certification of consistency with

State coastal zone management

plans.

Coordination and consultation with

State and local officials and

certification of consistency of

production and development

plans with the State coastal zone

management program.

Secretary directed to provide

information on proposed plans,

reports, environmental impact

statements, tract nominations,

and other information, including

privileged information in the

custody of the Secretary.

OCSLA Sec. 18

NEPA Sec. 102(D)

OCSLA Sec. 25

OCSLA Sec. 19

OCSLA Sec. 8(g)

OCSLA Sec. 1 l(c)

CZMA Sec. 307(c)(3)

OCSLA Sec. 25

CZMA Sec. 307(c)(3)

OCSLA Sec. 26

SOURCE: Office of Technology Assessment
142 . Oil and Gas Technologies for the Arctic and Deepwater

tion and cooperation among Federal, State and

local governments, a number of disagreements have

arisen that add to the uncertainties facing the offshore oil and gas leasing program. These controversies contribute to contentious relationships between

some coastal States and the Federal Government

regarding offshore resource development. The failure of the Executive Branch to deal with these issues

to the mutual satisfaction of the States and the Federal Government has prompted the Congress to

seek legislative solutions.

Special State/Federal Problems

Coastal Zone Management Consistency

Coastal States consider the lease sale as a critical point in the OCS oil and gas development process. At this point, contractual obligations are

assumed and property rights are conveyed to successful bidders. The States believe that the act of

leasing is the beginning of a process that inextricably leads to exploration, and if commercial discoveries are made, to production and development

by the lessees. For this reason, the States believe,

lease sales themselves should be consistent with

State coastal zone management programs.

The Department of the Interior insists that the

act of leasing in Federal waters is not an action that

“directly affects’ the coastal zone. Only when

physical activities, such as exploration, begin on

a lease are there activities that ‘‘directly’ affect the

coastal States. Haggling over the consistency issue

has resulted in several lawsuits that have delayed

leasing decisions and introduced uncertainty in the

leasing process for a decade.

In January 1984, the U.S. Supreme Court

decided the question of whether a lease sale

‘ ‘directly affects” the coastal zone, and therefore

whether the Secretary of the Interior must certify

that the lease sale is consistent with an approved

State coastal zone program. The case, Secretary

of the Interior v. California’8 reversed the decision

of the 9th Circuit Court of Appeals in California

v. Watt.19 In Secretary of the Interior v. California, the Supreme Court concluded in a 5-4 opinion that lease sales are not activities ‘‘directly affect1~78 L. Ed, 2d. 496; 52 USLW 4063 (1984).

j 9683 F. 2d. 1253 (9th Circuit, 1982).

ing the coastal zone’ within the meaning of the

CZMA. The State’s position with regard to the significance of the lease sale in the exploration and

development sequence was dismissed by the Court

as a policy argument that had previously been resolved by the Congress in enacting the legislation.

Response to the Supreme Court’s decision came

swiftly in the 98th Congress. Bills were introduced

in both Houses of the Congress to overrule the decision, but laws have not been enacted, 20 These proposals would substitute the term “significantly

affecting’ for the term “directly affecting, ” which

was judged by the court to exclude the Federal act

of leasing OCS oil and gas. By substituting the term

‘ ‘significantly’ for ‘‘directly, sponsors of the bills

hoped to invoke the liberal interpretation of the

term ‘‘significantly’ that has been used by the

Courts in interpreting the National Environmental

Policy Act.

Revenue Sharing

The immense value of the oil and gas that lay

below the seabed offshore the United States has

been the crux of a long-term battle between the Federal Government and the coastal States over control of the so-called submerged lands. Although the

Congress transferred ownership of the natural resources in coastal waters out to 3 nautical miles to

the States in 1953, the States have never taken their

eyes off the Federal revenues that have been

garnered from leasing OCS oil and gas.

In the 30 years between 1953 and 1983, the Federal Government has received over $68 billion from

offshore oil and gas leases. The coastal States claim

that they are entitled to share in these proceeds because State and local governments endure fiscal,

social and environmental impacts which result from

increased oil and gas activity in the OCS. Coastal

States support their arguments for revenue sharing by noting that inland western States with Federal lands within their borders share 50 percent of

the proceeds received by the Federal Government

for minerals development on such lands.21 Equity,

the coastal States claim, requires that the Federal

Government similarly share offshore revenues with

States adjoining the OCS. The Federal Govern-

—

ZOH, R, 4589 and S. 2324, (98th Congress, 2d. sess. , 1984).

Z[ Mineral Lands Leasing Act, 30 USC 181 et. Seq.
Ch. 6—Federal Leasing Policies . 143

ment contends that, on balance, OCS development

has a net positive effect on adjoining coastal States.

The coastal States increased their efforts to convince the Congress to enact an OCS revenue sharing bill when funding cutbacks for support of State

coastal zone management programs were proposed

at the same time that OCS oil and gas development

was being accelerated and the National Sea Grant

College Program 22 was zeroed by the Reagan

Administration in fiscal year 1982. As a result, legislation was introduced in the 97th Congress (H.R.

5543) to establish an ‘‘ocean and coastal resources

management and development fund’ to be transferred to coastal States from OCS revenues. The

bill passed the House of Representatives by a 260-

134 vote in the 97th Congress, but no action was

taken in the Senate.

An identical bill (H. R. 5) was introduced in the

98th Congress. Similar legislation has been introduced in the 99th Congress. The legislative proposals would set aside 10 percent of the OCS

revenues in any fiscal year when revenues exceeded

the amount received during fiscal year 1982 ($7.8

billion). It provided a cap of $300 million as the

maximum amount that could be transferred to the

fund in any year. All of the coastal States bordering on the ocean, plus those on the Great Lakes,

the U.S. affiliated Caribbean Islands, Pacific Trust

Territories, and U.S. protectorates in the Pacific

Ocean would share in the fund. Money would be

distributed from the fund as block grants.

States receiving these block grants would be required to spend specific proportions of the funds

received for coastal zone management, mitigation

of impacts from coastal energy development, and

enhancement and management of living marine resources and other natural resources. The entitlement for each State would be determined by formulae based on the level of leasing adjacent to the

State, volume of oil and gas produced from the adjacent OCS, proposed oil and gas lease sales to take

place within the 5-year leasing program, coastalrelated energy facilities located within each coastal

State, shoreline mileage of the State, and coastal

population of each State.

Similar legislation was introduced in the Senate,

but the bills were not acted upon. The House of

22 Nat10na] Sea Grant program ( 1966), 33 USC 1121-1124.

Representatives attached the provisions of H.R. 5

to a fisheries program authorization bill (Title I,

S. 2463) and forwarded it to the Senate. The Senate rejected the House amendment which included

provisions for ocean and coastal block grants and

decided to resolve the disagreement in Conference

Committee. The Senate receded from its demands

to reject the block grant proposals and agreed to

the House amendment with modifications. The

House agreed to the conference report on S. 2463,

but consideration by the Senate was delayed until

the waning days of the 98th Congress. During the

last days of the 98th Congress, in the face of concerted opposition by a number of Senators, the conference report was still pending when Congress adjourned.

The Administration opposed the revenue sharing proposals introduced in the 97th and 98th Congresses because of their impact on the Federal

budget; the inclusion of territories, islands and

States that would have no OCS development off

their shores; and the earmarking of the use of the

block grants for coastal zone management activities. In general, the offshore oil and gas industry

supported the concept of revenue sharing with the

hope that States which have a stake in the revenues

from the OCS would be more receptive to offshore

development.

OCS Escrow Funds

Drilling in Federal waters within 3 miles of

seaward limits of State waters contained within

the

the

Territorial Sea stands a risk of tapping a common

pool of oil that straddles the Federal/State boundary. Section 8(g) of the OCS Lands Act provides

for agreements between the Secretary of the Interior

and the Governors of affected States to apportion

the proceeds of oil and gas removed from the Federal side of the border area. If agreement is not

reached between the State and the Secretary within

90 days after an announced sale, the Department

of the Interior may proceed with the lease sale providing all revenues received from the sale are placed

in escrow pending agreement between the parties

on apportioning the monies. In the absence of

mutual agreement, Federal Courts may be called

on to decide the equitable division of the money.

Nearly $5.4 billion has accrued in the escrow

account to date. The States of Texas, Alaska,
144 . Oil and Gas Technologies for the Arctic and Deepwater

Mississippi, Florida, California, Louisiana, and

Alabama are scheduled to share the escrow money

with the Federal Government. Negotiations over

the apportionment of the escrow funds have proceeded intermittantly between the States and the

Department of the Interior.

As a result of the sharp disagreement over the

States’ share of the escrow fund, opposition to areawide leasing in the Gulf of Mexico is building in

States that have up to now enthusiasticall y supported offshore oil and gas development. Both Louisiana and Texas filed lawsuits in early 1984, and

Alaska joined them in December 1984. In August

1984, Secretary of the Interior William Clark offered non-litigating States an arrangement which

included 162/3 share of bonus and rental receipts.

The States are seeking a larger share of the escrow

funds plus an acceptable share of future income

(e. g., royalties) from these tracts.

Congressional Leasing Moratoria

The Department of the Interior has been prohibited by Congress from offering certain areas in

portions of the North Atlantic, Central and Northern California, Southern California, and Eastern

Gulf of Mexico planning areas during fiscal years

1982-85. Congress placed restrictions in the annual

Interior appropriations acts on spending funds for

the purpose of pre-lease preparation or holding certain lease sales.

In fiscal year 1982, 736,000 acres were placed

under a moratorium in Sale 53 in the Central and

Northern California lease area. In fiscal year 1983,

the moratorium was expanded to include 35 million acres off California and New Jersey. In fiscal

year 1984, 53 million acres were placed under a

moratorium. This included 8.7 million acres in

Georges Bank in the North Atlantic, 35 million

acres in Central and Northern California, 1.6 million acres in Southern California, and 7.7 million

acres in the Eastern Gulf of Mexico .23 In fiscal year

1985, moratoria were continued on the same sales

with the exception of the Eastern Gulf of Mexico.

Secretary of the Interior William Clark assured

Congress that the Eastern Gulf of Mexico would

not be leased until problems with the Department

of Defense and the State of Florida are resolved.

About 45 million acres of the OCS are currently

under congressional moratoria.

The moratoria appear to have resulted from a

combination of several factors: 1) they were partly

a political response to the intractable approach of

former Secretary of the Interior James Watt toward

placing one billion acres of OCS up for sale; 2)

Members of Congress shared the frustration of the

coastal States with the reduction in funds for coastal

zone management and Sea Grant College programs; 3) coastal States and environmental groups

continued to disagree with the MMS over tract

deletions and cancellation of pending OCS sales;

4) the Administration continued to oppose sharing

offshore revenues with coastal States; 5) the Department of the Interior and the States failed to

reach agreement on division of escrow revenues

from drainage tracts; and 6) Department of Defense pressure to force agreement with the MMS

on deferrals or deletions of lease tracts for military

and national defense uses may have prompted some

Members to support the moratoria.

Several authorization bills were introduced in the

98th Congress which also would have imposed

legislative moratoria on OCS leasing and exploration and development of offshore California and

New England .24 None of these bills were enacted.

However, action within the House Committee on

Appropriations Subcommittee on the Department

of the Interior and Related Agencies achieved the

same objective through the less-visible appropriations process.

The Department of the Interior has objected to

the imposition of congressional moratoria, but to

little avail. Factions within State and local governments and environmental groups have supported

the leasing moratoria. The offshore industry actively opposes any moratoria. The industry cites

its outstanding environmental safety record and the

national need for secure domestic energy resources

as reasons why current leasing moratoria should

be lifted.

Zspublic Law 98-146.

24s 760 H. R. 2059, S. 1103, H. R. 2581. (98th Congress, 1 St. and

2nd. sessijns 1983-1984).
Ch. 6—Federal Leasing Policies • 145

MILITARY OPERATIONS

Military strength and dependable energy supplies

are considered to be the foundations of U.S. national security. Recognizing this fact, the Department of Defense has indicated its support for expediting exploration and development of the energy

resources in the OCS. However, as offshore oil and

gas development expanded since 1953, there was

greater interaction between military use of sea space

and the offshore petroleum activities. As OCS development pushed further seaward into deeper

waters and expanded into frontier regions, the incidents of encounters, interference, and incompatibility between the two uses of the ocean became

more numerous.25

Conflicts between offshore oil and gas uses and

military uses will probably increase in the future.

The Department of the Interior accelerated the rate

and extent of leasing in the OCS as a means to hasten the exploration and development of offshore oil

and gas beneath the seabed. At the same time military exercises and activities offshore have increased

in response to greater emphasis on military preparedness, With the advent of sophisticated electronic equipment for both military and industrial

use, there may be potential for electromagnetic interference which could present yet another hazard

in addition to physical interference.

Agreements between the Department of Defense

and MMS over deferrals and exclusions of lease

tracts for military reasons historically have been negotiated quietly with little fanfare. Disagreements

between the agencies were well hidden. However,

what was once handled on a routine case-by-case

basis seems now to be turning into a problem too

broad and complex to be dealt with ad hoc. The

most recent indication of this is the provision in the

Department of Defense Authorization Act of 1984

that directs the Secretary of the Navy to inform the

Congress of the potential effects of offshore oil and

gas operations on naval operations and to define

offshore zones where oil and gas drilling could cause

appreciable impacts on naval operations.26

ZSFOr ~ h~~tOV of conflicts between the military and the oil industry in the offshore areas see, Norman Breckner et. al., The Navy and

the Common Sea, (Washington, DC: Ofiice of Naval Research, 1972).

Zcpub]ic Law 98-94, Section 1260 (Sept. 24, 1984).

The Navy transmitted the information required

in the 1984 Defense Authorization Act to the Congress on May 29, 1984.27 In the memorandum, the

Navy identified six operational areas with potential for conflicts between military operations and

offshore oil and gas development. Air Force and

NASA operations were also included in the Navy’s

response. The identified activities include: 1) submarine transit lanes in the North Atlantic area; 2)

fleet operations, missile flights, and high-performance aircraft testing, as well as classified uses in

the Mid-Atlantic lease area; 3) submarine transit

lanes, ballistic missile testing ranges, and sonar

testing as well as the NASA Cape Canaveral launch

range in the South Atlantic area; 4) aircraft carrier flight operations, flight training, air-to-surface

missile testing, and equipment testing in the Eastern and part of the Western Gulf of Mexico areas;

5) fleet operations, missile testing, testing of submarine electronic systems, submarine transit lanes,

and gunnery training in the Central, Northern, and

Southern California areas; and 6) classified uses of

an unspecified nature in part of one Alaskan planning area. In addition, underwater listening posts

which probably require protection from industrial

interference are located on the Continental Shelf

offshore both the Atlantic and Pacific Coasts and

adjacent to Alaska.

MMS and the Department of Defense have taken

steps to minimize offshore conflicts in the military

and NASA operating areas. Since 1979, between

40 and 55 million acres have been set aside or deferred from OCS leasing, and perhaps as much as

75 million additional acres maybe leased only with

operating restrictions included to protect military

interests28 (see figure 6-3). Estimates of acreage affected by military operations should probably be

ZTLetter of tmnsmitt~ from Under Secretary of the N=y James

F. Goodrich to the President of the Senate George Bush, with

enclosures (May 29, 1984).

ZBThe exact acreage which are subject to mi]itary operating restrictions is not available from MMS. About 42 million acres in the Eastern Gulf of Mexico lease planning area is subject to density controls

and military clearance. Approximate acreage subject to control in other

lease sale planning areas is estimated as: North Atlantic area—12 million acres; Mid-Atlantic area—10 million acres; Western Gulf of Mexico area—7 million acres; Northern and Central California-678 thousand acres, Southern California-7 million acres.
146 . Oil and Gas Technologies for the Arctic and Deepwater

Figure 6-3.—Deferrals of Offshore Acreage for Military Uses

Central and

Northern

California

Charleston , .,

Tampa

NOTE: DOD areas not to scale,

SOURCE: US. Department of the Interior, Minerals Management Service.

considered conservative because some classified offshore uses have not been identified for security reasons. TheOCS acreage deferred from oil and gas

exploration and development, plus the OCS acreage which requires approval by the Department of

Defense and therefore is constrained by operating

stipulations (1 15 million acres), is about 30 percent

greater than the total onshore area withdrawn for

wilderness use on public lands in Alaska and the

lower 48 States (88.6 million acres). Operating constraints include review and military approval of timing, placement, and location of rigs and platforms;

provisions for suspension of operations at the request of the military; restrictions on electromagnetic

radiation; and release of the military from liability

for harm resulting to oil and gas operations from

military operations .29

Z9Lease Sde 79, Federaf Reg3”ster (Dec. 6, 1983), p. 54796; Lease

Sale 82, Feder& Register (Aug. 27, 1984), p. 33987; Lease Sale 80,

Federaf Register, (Sept. 17, 1984), p. 36481.

Western I

I

Gulf of Mexico

On July 25, 1983, the process of minimizing conflicts was addressed in a Memorandum of Agreement between the then Secretary of the Interior

James Watt and Secretary of Defense Casper

Weinberger. In the memorandum, the Department

of Defense acknowledged that ‘ ‘The OCS (Outer

Continental Shelf) leasing program of the Department of Interior is an integral part of the nation

energy security program . . . and thus important

to national defense. ’30 The two departments agreed

to work together to assure that offshore development does not conflict with military training and

other activities essential to the readiness of U.S.

armed forces. Therefore, as a result of this Memorandum of Agreement, instead of relying entirely

on leasing deferrals, the Department of Defense has

expressed its willingness to promote compatible military and offshore oil and gas operations, whenever

sOMemorandum of Agreement between the Department of Defense

and the Department of the Interior on Mutual Concerns on the Outer

Continental Shelf Uuly 21, 1983).
Ch. 6—Federal Leasing Policies • 147

possible, through the use of time-sharing agreements. The Navy and Air Force have, in some

cases, offered to modify their activities to accommodate OCS exploration operations.

This policy, though workable, is not entirely

satisfactory to industry. For example, to regulate

the density of oil and gas operations in a portion

of the Eastern Gulf of Mexico planning area, the

Air Force adopted a policy that allows drilling operations within a 30-by-36 mile area, This system of

density control over oil and gas operations has been

termed the ‘‘postage stamp’ approach. Eventually,

the intent of MMS and the Air Force appears to

be to periodically relocate the ‘ ‘postage stamp’ so

other areas in the Eastern Gulf of Mexico can be

explored. There is also the possibility that more

than one exploration area may be allowed at the

same time. Several companies are now planning

to drill in the first ‘ ‘postage stamp. However, outside of this ‘ ‘postage stamp, Shell Oil Co. was

tentatively denied approval in November 1984 for

an exploration permit to explore a previously leased

block in the DeSoto Canyon of the Apalachicola

Embayment of the Eastern Gulf of Mexico lease

sale planning area off Eglin Air Force Base. This

was the first time the Department of Defense had

attempted to deny a qualified owner of an OCS

lease access to that lease for exploration. As a result, the policies and procedures for regulating the

density of oil and gas operations in military control areas are under review by the Department of

Defense and MMS.

The Department of the Interior is currently considering the establishment of ‘ ‘military reservations ‘‘ in offshore areas. 31 Authority for the withdrawal of OCS acreage from leasing is found in two

statutes: 1) Section 12 of the OCS Lands Act (Public Law 82-21 2); and 2) Withdrawal of Lands for

Defense Purposes Act (Public Law 85-337). The

OCS Lands Act vests authority in the Secretary of

Defense, with the approval of the President, to

designate OCS areas off-limits for oil and gas development for ‘ ‘national defense’ purposes. In addition, the Secretary of Defense may suspend operations on a previously existing lease with provisions

for buyback from the lessee. The Withdrawal of

~1 Testimony of Wi]liam llet~enberg, Director, Minerals Management Service, before the House Committee on Interior and Related

Agencies Appropriations (May 10, 1984), p. 605.

Lands for Defense Purposes Act (Section 2) reserves

the authority for withdrawing OCS areas from leasing for military purposes to Congress. Under the

Act, applications for withdrawal must be acted upon

by Congress before military reservations in the

OCS are created. The two laws seem to be in

conflict.

Whether the Executive Branch or Congress has

authority to effect withdrawal of OCS lands for military purposes remains a question. The Withdrawal

of Lands for Defense Purposes Act, having been

approved in 1958, is the most recent expression of

congressional intent. Legal interpretation often

gives the latest statute preference over the one prior

in time in the absence of an expressed repeal. If

this interpretation is accepted to resolve the conflicts between the two laws, only Congress has the

authority to establish offshore military reservations.

This would probably require the introduction of legislation and appropriate hearings in conjunction

with action by both Houses of Congress. On the

other hand, another line of legal reasoning is that

when Congress amended the OCS Lands Act in

1978, it did not change the law and thus implicitly

reaffirmed the authority of the Secretary of Defense.

MMS, in responding to the current concerns of the

Department of Defense, has referred to military exclusions in OCS sales as ‘‘deferrals. This has

avoided facing the issue of whether Congress or the

executive branch has final authority to withdraw

acreage from consideration for OCS oil and gas

leasing. If the OCS Lands Act governs, the Secretary of Defense, with the approval of the President,

can unilaterally withdraw OCS acreage for military use without the direct involvement of the Department of the Interior in the decision.

The withdrawal of OCS lands from oil and gas

development for military reservations could, for

practical purposes, remove a significant amount of

potentially productive OCS acreage from future oil

and gas development. In addition, operating restrictions on oil and gas activities in other portions of

the OCS that may be considered suitable for shared

uses could result in additional costs to the lessees

and could delay the exploration-development sequence. Congressional concerns over conflicts between military use and oil and gas development

may have contributed to the moratoria imposed in

the appropriations process on OCS lease sales in
148 ● Oil and Gas Technologies for the Arctic and Deepwater

the North Atlantic, Central and Northern Califor- tions , the oil and gas industry could be pernia, Southern California, and the Eastern Gulf of manently denied access to an even larger area than

Mexico during fiscal years 1982-85. If the current has been temporarily affected by the congressionally

deferrals of OCS acreage now honored by MMS imposed moratoria (about 45 million acres in fiscal

result in withdrawal of areas as ‘‘military reserva- year 1985).

DISPUTED INTERNATIONAL BOUNDARIES

National jurisdiction over most of the known or

potential resources on or under the U.S. Continental Shelf is largely uncontested. On March 10, 1983,

when President Reagan established an EEZ for the

United States, resource jurisdiction over the Continental Shelf within 200 miles of the U.S. coastline

became even more firmly established. However,

in some potentially important resource-producing

areas in proximity to Canada, Mexico, Cuba, and

the Soviet Union, international boundaries have

been (or could be) contested. Settlement of these

disputes may become of more concern as the United

States—and these adjacent or opposite countries—

improve capabilities to search for resources in more

hostile environments and in deeper waters.

The primary responsibility for negotiating treaties to resolve these types of disputes lies with the

U.S. Department of State. Typically, the Department of State consults with the Department of the

Interior regarding subsea features and the resource

potential of areas in dispute. Treaties must be

ratified by Congress.

Areas of Potential Dispute

Gulf of Maine and Georges Bank

Jurisdiction over the Gulf of Maine and Georges

Bank east of Cape Cod has been disputed between

Canada and the United States. The region is a productive fishery and, although preliminary exploratory efforts on Georges Bank have been disappointing, it is considered to have potential for oil

and gas. Maritime jurisdiction was disputed over

an area between 13,000 and 18,000 square nautical

miles in size. The dispute was submitted to the International Court of Justice (ICJ) for arbitration,

pursuant to a boundary settlement treaty between

the United States and Canada. The Court announced its decision on October 12, 1984.

Both the United States and Canada presented

arguments to support their claims based on the

ecology of the region, socioeconomic factors, and

historic practices. The Court rejected these arguments, noting that ‘‘the respective scale of activities connected with fishing-or navigation, defense,

or, for that matter petroleum exploration and

exploitation— cannot be taken into account as a

relevant circumstance or, if the term is preferred,

as an equitable criterion to be applied in determining the delimitation line. ’32 In determining an

equitable line, the Court relied most heavily on geographical arguments. Thus, of primary importance

was the notion that the delimitation should aim at

an equal division of ‘areas where the maritime projections of the coasts of the States between which

delimitation is to be effected converge and overlap . As a second criterion, the Court considered

the length of coastline of each country in the Gulf

of Maine. Accordingly, the middle of the three

segments of the boundary line was adjusted in recognition of the greater length of the U.S. coastline

in the region.

The Court gave Canada jurisdiction of the living and non-living resources of the northeast portion of Georges Bank (see figure 6-4). The United

States had originally claimed the entire Bank while

Canada had claimed about one-half of it. Thus, in

this area, the line was established essentially midway between the claims of the two states. Canada,

however, gained control over important fishing

areas, most notably, scallop grounds.

As a result of this decision, Canada now may

issue oil and gas leases on its portion of Georges

Bank, The same, of course, is true for the United

States in areas now under its jurisdiction. Thus,

szrnternation~ court of Justice. Case Concerning Delimitation of

the Maritime Boundary in the Gulf of Maine Area: (CanaddUnited

States of America), (Oct. 12, 1984), p. 102.
Ch. 6—Federal Leasing Policies • 149

44°N

40“N

Figure 6-4.—U.S.-Canada Boundary in Georges Bank

68°W 64“W

44“N

Emerald

Bank

LaHave

Bank

\ & .

\

Boundary determined by

the International Court of Justice

‘\\ \

Boundary turning points

D

A 4401 1‘12”N 67016’46”W

B 42“53’14”N 67044’35”W

50 fathoms Canadian \\ C 42 0

31‘08”N 67‘28’05”W

Claim \ D 40‘27’05”N 65 0

41‘59”W 40” N

68°W 64°W

oil and gas activities which occur on one side of the

line could affect the other side. For instance, a gyre

located over Georges Bank virtually assures that

oil spilled on either side of the line will drift to the

other side, Although U.S. and Canadian Coast

Guards have developed a joint marine pollution

contingency plan for the area, neither the United

States nor Canada currently has a formal process

in its OCS leasing operations for dealing with the

environmental and socioeconomic concerns of the

other country. Transboundary coordination and cooperation regarding OCS development activities

adjacent to common boundaries could avoid many

potential environmental problems.

Beaufort Sea

The offshore boundary between the United

States and Canada in the Beaufort Sea also is in

dispute. The area in question is small relative to

the total continental shelf areas of both countries

(6, 180 square nautical miles), but favorable geologic

conditions suggest it is potentially rich in hydrocarbon resources. Canada contends that the 141st

meridian of longitude dividing Alaska and the

Yukon delimits the offshore boundary. The United

States claims that the boundary should be established using the equidistance principle, thus placing the boundary further east (see figure 6-5). The
150 ● Oil and Gas Technologies for the Arctic and Deepwater

Figure 6-5.—U.S.-Canada Boundary in Beaufort Sea

150 145 140 135 130

I I 1 I

Beau fort

Sea

nm

I

70

145 140 135

legal basis for the Canadian claim is not altogether

clear, but appears to rely on ambiguous language

in the 1825 boundary agreement between the

United Kingdom and Russia which specifies that

the line of demarcation shall extend along the 141st

degree of west longitude ‘‘in its prolongation as far

as the Frozen Ocean. ’33 Moreover, Canada has

used the line as a national offshore fence for several purposes (e. g., oil and gas exploration permits

have been issued up to the 141st meridian).

The United States does not agree that the United

Kingdom-Russia Treaty of 1825 extended the land

boundary into offshore areas, nor does the United

States agree that any special circumstances exist that

would justify such an extension. In the absence of

‘‘special circumstances, the 1958 Continental

Shelf Convention calls for an equidistance line to

be drawn. At this time, the crux of the matter appears to be what constitutes special circumstances,

since the phrase is only vaguely defined in the 1958

Convention, and the 1982 United Nations Convention on the Law of the Sea does not provide any

more detailed guidance.

The Beaufort Sea dispute has been quiet since

1975, and both countries have imposed an informal moratorium on offshore exploration and licenssD~vid v~derzwaag and Cynthia Lamson, ‘‘ocean Development

and Management in the Arctic: Issues in American and Canadian

Relations, unpublished paper for the United State-Canada Arctic

Policy Forum (Banff, Alberta, Oct. 20-22, 1984).

sing in the disputed area. Although the Georges

Bank ICJ decision supports the principle of equidistance modified by the amount of coastline held

by each country—a finding which appears to favor the United States position in the Beaufort

Sea—U.S. officials urge caution concerning the applicability of the Georges Bank decision to the

Beaufort Sea. It is held by both countries that the

circumstances of the Beaufort Sea dispute are

unique and, therefore, the Georges Bank decision

does not necessarily set a precedent for the resolution of the issue.

If an agreement locating the line cannot be

reached, the United States and Canada may wish

to consider other types of solutions to the problem.

Joint exploration and development by Canada and

the United States may be possible even though there

are no specific provisions in the OCS Lands Act

for joint activity. An executive agreement, which

many scholars agree can overrule existing law,

might be utilized to allow joint exploration and/or

development to take place. In the absence of such

an agreement, there still appears to be no legal reason why the United States, in concert with Canada, cannot hire a single firm or consortium to explore the area for both countries. Section 11 of the

OCS Lands Act does not prohibit exploration without leasing. If exploitable resources are discovered,

both countries might consider offering the disputed

area for lease to one lessee while agreeing to decide

at a later date how revenues are to be divided.

Bering Sea

The location of the line which separates Soviet

and American resource jurisdiction in the Bering

Sea also has been disputed. The line was established

when Alaska was ceded to the United States by

Russia in 1867. However, the Soviet Union and

the United States have not been able to agree upon

the method to be used in locating the line. The

Soviets advocate use of the “rhumb line” method,

a technique in use at the time the treaty was negotiated. The United States contends that the more

modern “great circle’ method of calculation best

reflects the intentions of the negotiators of the 1867

Convention and should be used .34 The rhumb line

s4HarV Il. Marshall, “International Boundaries and the 5-Year

Outer Continental Shelf Oil and Gas Leasing Program. ” Paper presented at the meeting of the Outer Continental Shelf Policy Committee, New Orleans, Louisiana, (Oct. 26, 1984), p. 11.
Ch. 6—Federal Leasing Policies . 151

method places the line further east than the great

circle method, and hence reduces the area assigned

to the United States.

The 1867 line passes through the potentially oilrich Navarin Basin; thus, there are important economic reasons for resolving the dispute. Upcoming sales in the Norton Basin and Chukchi Sea may

also border on the 1867 line. The issue is even more

important because the United States leased Navarin

Basin tracts in 1984. Bids were received on 17 tracts

within the disputed zone created by the two lines

(see figure 6-6). However, these bids will not be

finally accepted until the dispute is resolved. If it

is later determined that it is not in the interest of

the United States to accept these bids, deposits,

which are being held in escrow, will be refunded

with interest. However, if the dispute is resolved

and the bids are accepted, bidders will be required

to pay the remaining four-fifths bonus and the first

year’s rental and execute the lease .35 Although four

rounds of discussions concerning this sensitive issue

have taken place since 1981, there is no indication

as to when an agreement will be reached. Notwithstanding agreement on the location of the

boundary, petroleum deposits may straddle the line.

The methods used for apportioning common deposits in the North Sea between the United Kingdom and Norway may also be useful in the U. S.-

Soviet boundary area.

If the United States and the Soviet Union cannot agree to a division of the area, several other

options might be considered. A buffer zone could

be created within which no oil and gas exploration

will be allowed. An interim regime could be established that would permit exploration and provide

the framework for future development and sharing of petroleum resources.36 However, the possibility of joint U.S.-Soviet development of Navarin

Basin resources in the foreseeable future is considered remote. Among other problems would be that

of technology transfer, but that possibility, if successfully pursued, could have a positive effect on

the two countries’ relations .37

35’ Final Notice of Sate: Navarin Basin. Federal Register, (Mar

16, 1984), 49(53): 10065.

sbRobert B. Krueger, ‘ ‘Bering Sea Petroleum: A New Meeting

Ground for the Soviet Union and the United States, unpublished

paper (January, 1983),

sTW1lliam E, Westermeyer, “Aspects of Arctic Energy Development, Geopolitics of Energy (March 1984), 6(1 ):7.

Continental Shelf

Delimitation of the outer boundary of the extensive U.S. Continental Shelf is another type of

boundary issue. Given the vast amount of Continental Shelf acreage over which the U.S. may be

entitled to assert resource jurisdiction, Continental Shelf delimitation is probably a more significant

issue than delimitation of either opposite or adjacent state boundaries. In principle, the United

States could assert resource jurisdiction under the

‘‘exploitability clause’ of the 1958 Geneva Convention on the Continental Shelf, which defines the

outer edge of the shelf as the point at which ‘ ‘the

superjacent waters admit of the exploitation of the

natural resources. The limits of exploitability are

continuously being pushed into deeper and deeper

water. However, precise rules have been promulgated in the 1982 Law of the Sea Treaty (Article

76) which, in some cases, would enable coastal

States to extend Continental Shelf jurisdiction

beyond the 200-mile EEZ. Even though the United

States has not signed the Law of the Sea Treaty,

it has stated that its only objections to the Treaty

are the Part XI provisions pertaining to exploitation of the deep seabed beyond the limits of national

jurisdiction.38 The United States intends to abid e

by all other provisions, and, in particular, may use

the Article 76 criteria for delimiting its Continental Shelf. Legislation introduced in the 98th Congress defined the Continental Shelf in terms consistent with Article 76.

The Law of the Sea Treaty is not yet in force.

However, eventually it is expected to be operative

for those countries that have signed and ratified it.

Moreover, the Treaty will be a major factor in the

development of state practice even for those countries that have not signed it. Many of its provisions

may now be considered to be customary international law. Others will eventually be accepted as

customary law, and thus generally become applicable even for non-signatories.

Gulf of Mexico

Delimitation of the Continental Shelf of the

United States may involve conflicts with opposite

or adjacent countries. One such instance may be

SaStatement by the President The White House, OffIce of the press

Secretary, (Mar. 10, 1983). ‘

38-749 0 - 85 - 6
152 ● Oil and Gas Technologies for the Arctic and Deepwater

70(

65’

60“

55°

50°

Figure 6-6.—U.S.-U.S.S.R. Boundary in Bering Sea

170” 175° 1800 175 ‘ 1700 165° 160 “

I I I I I I

I

East Siberian

Sea Wrangel

Island I

.

Chukchi Sea

Komandorskiye /

/

/

Pribilof

Islands

70”

65”

/

.: ● 4*$-

/

\ . .

500

I 1 1 I I I I

170 “ 175° 1800 1750 170° 165° 160”

between U.S. Great Circle Line (U.S. claim)

and U.S.S.R. rhumb line (U.S.S.R. claim). Area

is about 30 miles wide.

SOURCE: Minerals Management Service
Ch. 6—Federal Leasing Policies ● 153

in the Gulf of Mexico. The United States, Mexico

and Cuba border the Gulf, and their Continental

Shelf claims could overlap in several areas (see figure 6-7). The United States has negotiated treaties with Mexico and Cuba delimiting boundaries

in those areas where exclusive economic zones

overlap. Neither treaty, however, has been ratified

by the United States Senate. Some questions have

been raised concerning Mexico’s use of certain

uninhabited islands off the coast of the Yucatan

Peninsula as baseline points for the purpose of

determining its EEZ boundary .39 If these islands

are not used to fix the Mexican EEZ boundary, the

United States may be able to extend resource jurisdiction in some areas. However, the U.S. Department of State and many scholars regard the Mex40 Moreover, the Unite d ican claim as legitimate.

States uses islands as baseline points off its own

coast.

~gscnatc Committee on Foreign Relations, ‘‘Three Treaties Establishing Maritime Boundaries Between the United States and Mexico, Venezuela, and Cuba, Executive Report No. 96-49 (Aug. 5,

1980), p. 7.

+OHarV R. Marshall, ‘‘ International Boundaries and the Fi~e-Year

Outer Continental Shelf Oil and Gas Leasing Program, paper presented at the meeting of the Outer Continental Shelf Policy Committee (New Orleans, Oct. 26, 1984), p. 14.

Figure 6-7.— Gulf of Mexico Boundaries

Cuba I

Shaded areas — areas beyond the EEZs of bordering states.

Two areas exist in very deep water (10,000 to

12,000 feet) in the central Gulf of Mexico beyond

the 200-mile exclusive economic zones of the bordering countries. The ‘ ‘western hole’ is bordered

by the EEZs of the United States and Mexico and

the ‘ ‘eastern hole’ is bordered by the EEZs of the

United States, Mexico, and Cuba. Although there

currently is little interest and no experience in exploiting resources in these deepwater areas beyond

the EEZ, sediments do occur in both areas, and

hence there is at least a possibility that hydrocarbons may be found.

The United States has not yet addressed the question of jurisdiction within the two holes. Interest

in doing so at this time is low. Prospects for oil and

gas development in these areas are considered to

be remote, given the extreme depths and high costs

of exploration and development. Nevertheless, all

of the area within the holes can potentially be

claimed by the littoral states according to the criteria of either Article 76 of the Law of the Sea

Treaty or the 1958 Continental Shelf Convention .41

Since several methods exist for determining the extent of the Continental Shelf, claims to these areas

could overlap. Thus, bilateral or trilateral negotiations eventually may be needed to settle any disputes created by overlapping claims.

Dispute Settlement Mechanisms

Several mechanisms are available for resolution

of boundary disputes. Third parties may or may

not be involved in the process. A negotiated settlement without third-party intervention is usually

preferable. Arbitration or mediation may also be

considered. The Georges Bank dispute was settled

by arbitration. This is a voluntary process, but the

parties to an arbitration commit themselves to abide

by the decision of the arbitrator. Mediation is also

a type of arbitration, but the mediator of a dispute

has no authority to impose a settlement. The

mediator simply brings the parties together to help

facilitate a solution to their problem. Numerous

variations of these basic strategies are possible.

Determination of the proper location of the 1867

Convention Line in the Bering Sea will likely be

+ 1 Robert smith, Office of the Geographer, U.S. Department of

State, personal communication, (Oct. 30, 1984).
154 . Oil and Gas Technologies for the Arctic and Deepwater

made through bilateral negotiations between the

United States and the Soviet Union. Four meetings

already have taken place, the most recent of which

occurred in July 1984. It is unlikely that either the

United States or the Soviet Union would submit

any dispute to a third party for arbitration or mediation if negotiations break down.

The United States and Canada will probably

wish to give more thought to the advisability of

using binding arbitration to settle the Beaufort Sea

dispute if they perceive that, as in the Georges Bank

dispute, the arbitrator will simply split the difference

between claims without considering special circumstances. If bilateral negotiations are not successful

in determining a mutually acceptable boundary

line, mediation or some other conciliatory procedure may be needed. For example,

LEASING

tries could establish a joint U.S.-Canadian working group to devise an equitable solution and

submit it to both governments for consideration.

The Law of the Sea Treaty also provides for the

settlement of disputes through, for example, the International Tribunal for the Law of the Sea. When

and if the Treaty comes into force, Mexico and

Cuba could conceivably request that Continental

Shelf delimitation in the Gulf of Mexico be determined by Treaty arbitration or conciliation procedures. Such mechanisms would be unavailable

to the United States as a non-party. Presumably,

if the issue becomes important to settle but cannot

be settled through negotiation, an international tribunal not established by the Treaty, such as the

ICJ, could be utilized.

the two counPOLICIES FOR OFFSHORE

FRONTIER AREAS

Bidding Systems

The OCS Lands Act of 1953 authorized two bidding systems for use in offshore leasing: 1) cash

bonus bid with a fixed royalty; and 2) royalty rate

bid with a fixed cash bonus. The United States has

traditionally allocated offshore tracts on the basis

of the highest cash bonus bid with a fixed royalty

payment based on the value of production. This

bidding system is easy to administer, has appeared

to promote efficient exploration and development

of offshore tracts, and has been generally accepted

by both government and industry.

However, in the 1978 OCS Lands Act Amendments, Congress required the Department of the

Interior to test alternative bidding systems on not

less than 20 percent and not more than 60 percent

of the offshore acreage offered for lease each year

for a 5-year period ending in September 1983. The

five alternative bidding systems specified for testing

were: 1) cash bonus bid with sliding scale royalty;

2) cash bonus bid with freed net profit share; 3) cash

bonus bid with fixed royalty and fixed net profit

share; 4) profit share bid with fixed cash bonus;

and 5) work commitment bid with fixed cash bonus

and fixed royalty. Congress wanted to determine

the effect of these bidding systems on competition

for offshore leases, government revenues, and oil

and gas exploration and development.

At the end of the testing period, the Department

of the Interior still prefers the traditional bidding

system for offshore leasing. After evaluating the

alternative bidding systems in theory and/or in

practice, the Department of the Interior concluded

that their disadvantages outweighed their advantages in offshore leasing, as outlined in table 6-3.

In testing the alternative bidding systems, it was

found that they had little effect on the level of competition for OCS tracts, which is more directly related to an area’s resource potential than to the

method of leasing. No firm conclusions were

reached regarding the development efficiency and

revenue effects of alternative bidding systems, however, because most tracts leased under the alternative systems had not yet begun production .42

42Mincr~s Management service, “Report to Congress on Fiscal

Year 1982 Outer Continental Shelf Lease Sales and Evaluation of

Alternative Bidding Systems, ” (April 1983), p. 57.
Ch. 6—Federal Leasing Policies ● 155

Table 6-3.—Advantages and Disadvantages of Alternative Bidding Systems (authorized by OCS Lands Act

Amendments of 1978)

Bidding system

Bid variable Fixed payment Description Advantages Disadvantages

Cash bonus

Cash bonus

Cash bonus

Cash bonus

Royalty rate

Net profit

share

Work

commitment

Fixed royalty

Sliding scale

royalty

Fixed net

profit share

Fixed royalty

and fixed net

profit share

Fixed cash

bonus

Fixed cash

bonus

Fixed cash

bonus

Leases awarded on the basis

of highest cash bonus payment plus percent of

revenues, not less than

121⁄2%. Usually 162/3%.

Leases awarded on the basis

of highest cash bonus plus

percent of revenues, which

increases with production.

Leases awarded on the basis

of highest cash bonus plus

percent of profits after

capital recovery. Profit

share not less than 30°/0.

Leases awarded on the basis

of highest cash bonus plus

percent of revenues and

percent of profits.

Leases awarded on the basis

of highest percent of

revenues offered, plus fixed

cash bonus.

Leases awarded on the basis

of highest percent of profits offered, plus fixed cash

bonus.

Leases awarded on the basis

of dollars to be spent on

exploration, plus fixed cash

bonus.

Generally accepted

bidding system in

United States. Easy

to administer.

May lower bonus bids

and increase competition. Lease payments vary with field

productivity.

May lower bonus bids

and increase competition. Lease

payments vary with

field profitability.

May lower bonus bids

and increase competition.

Lower upfront payments may increase

competition.

Lower upfront payments may increase

competition.

Provides for rapid

exploration.

upfront cash bonuses may

limit competition. Fixed

royalties may overtax

small fields and constrain

development.

Royalties may still be too

high for small fields. May

try to avoid higher royalty

on productive tracts by

slowing production.

Difficult to design and

administer. May cause

“gold-plating.”

Regulations never written

as too complex.

High royalty rate bids may

constrain development.

High net profit share bids

may constrain development.

Government must forego

high bonuses. Exploration

program may be

inefficient.

SOURCE: Office of Technology Assessment.

Both theory and experience indicate that the

royalty bidding system and the profit-share bidding

system may lead to the abandonment of small or

marginal fields and prevent efficient development

of resources. These systems tend to promote

unrealistically high royalty rate bids or profit-share

bids in competitive lease auctions. The high lease

payments add to the costs of production and make

development of some fields unprofitable. Royalty

bidding in two offshore lease sales was found to lead

to excessive royalty rate bids, which may discourage

later investments.43 Profit-share bidding was never

tested.

The cash bonus bidding systems with either a

fixed net profit share or sliding scale royalties have

43 Department of the Interior, Office of OCS program Coordination, ‘ ‘An Analysis of the Royalty Bidding Experiment in OCS Sale

No. 36, ” (1975) and Bureau of Land Management, “Preliminary

Analysis of Royalty Bidding vs Bonus Bidding at the Cook Inlet Sate, ”

(Nov. 13, 1977),

been more favorably evaluated in regard to development efficiency. Under both of these systems,

lease payments vary with either field productivity

or other factors. However, after it was tested in a

total of 13 lease sales, the fixed net profit share system was not proposed for further use because of

its complex accounting and administrative requirements.44 While sliding scale royalty systems have

proved easier to administer, they may discourage

generally higher levels of production in order to

avoid higher royalty rates. Despite this drawback,

the Department of the Interior preferred the cash

bonus bid with sliding scale royalty system to other

alternative bidding systems .45

~+ Resource Consulting Group, “Issues Associated with the Use of

the Net Profit Share System for Leasing Outer Continental Shelf Oil

and Gas Acreage, report to the Minerals Management Service (Sept.

27, 1982).

+5 Bureau of Land Management, ‘‘ Bidding System Design for OCS

Sale 71 ,“ (May 4, 1982).
156 ● Oil and Gas Technologies for the Arctic and Deepwater

Neither the work commitment bidding system

or the combined fixed royalty and profit share system were tested in offshore lease sales. It is believed

that work commitment bidding reduces government cash bonus revenues and may promote inefficient exploration efforts if not carefully designed.46

Regulations were never written for the cash bonus

bid with fixed royalty and fixed profit-share system, which is seen as administratively burdensome

and complex.

The Department of the Interior has generally

used the cash bonus bid with a lower royalty of 121⁄2

percent (1/8) for leasing offshore tracts in frontier

areas. This is the minimum royalty rate allowed

by law and is used in recognition of the increased

costs of developing oil and gas resources in hostile

environments. The lower royalty rate is offered on

blocks where analyses indicate that small discoveries may not be developed under the standard 162/3

percent royalty. Starting in August 1981 through

the end of 1984, the bonus bidding system with a

1/8 royalty has been used for leasing a total of 1,041

tracts in 19 lease sales. In general, the lower royalty

rate has been offered on tracts in difficult ocean

environments off Alaska and in deepwater areas of

the other OCS planning regions.

The traditional cash bonus bid with fixed royalty

bidding system has appeared to work well in conventional leasing areas such as the Gulf of Mexico

in terms of assuring adequate competition for OCS

tracts, fair returns to the government, and efficient

exploration and development .47 In frontier areas,

the use of this system with a lower royalty rate has

increased the economic incentive to explore in highcost regions. In general, the cash bonus bid with

fixed royalty bidding system has distinct advantages

in its administrative simplicity, incentives for rapid

exploration, and immediate returns to the government in the form of cash bonuses.

However, there may be disadvantages to allocating offshore frontier tracts by this bidding

system. The requirement for upfront cash bonus

4GR~~OurCe planning Associates, Inc. and Resource consulting

Group, Inc., “Alternative Procedures for Managing the Leasing of

Nonprospective OCS Acreage, report to the Department of Energy

fJan. 29, 1981).

47W. J. Mead et. al., ‘ ‘Additional Studies of Competition and Performance in OCS Lease Sales, 1954 -1975,” report to the U.S. Geological Survey (1980).

payments may be a deterrent to comprehensive

exploration of frontier areas. Alternative arrangements and even government incentives may be

needed at some point to encourage continuing exploration in high-risk deepwater and Arctic regions.

In addition, the low profit margins in frontier areas

may cause fixed royalties (which are levied on gross

income) to overtax small or marginal fields and lead

to non-development of resources (see economic

analysis in chapter 5). Even the lower 1/8 royalty

rate may be too burdensome on some Arctic and

deepwater fields.

Other countries, including the United Kingdom,

Norway, and Canada, have generally used work

commitment systems rather than cash bonus bidding for offshore leasing in frontier areas. This system is discussed in the appendix to this study.

Under this system, firms agree to carry out a preplanned exploration program, drill a specified number of wells, or make a minimum expenditure in

exploring a lease area. Firms which fail to carry

out the terms of the work program can lose lease

rights or any collateral paid to the government. In

countries which use work commitment systems,

lease tracts are far larger than those in the United

States. In addition, the contract generally contains

relinquishment provisions for returning portions of

acreage to the government at a specified time. The

work program, large size of the lease area, and turnback requirements jointly provide incentives for

rapid exploration of vast offshore areas. Work programs also can be used to encourage firms to assess

nonprospective offshore regions or to reassess relinquished acreage.

Other types of bidding systems which do not require initial cash payments for exploration rights

may also provide more incentives to high-risk ventures in offshore frontier areas. Deferred bonus payments or cash bonuses payable only on commercial discoveries of oil would increase government/

industry risk-sharing. These systems would retain

the cash bonus bid variable and the financial competition which have been the basis of our leasing

system.

Bidding systems with other types of downstream

payments, such as sliding scale royalties, net profit

shares, or even zero royalties, may be more effective in providing economic incentives for developing marginal oil and gas discoveries in offshore fron-
Ch. 6—Federal Leasing Policies ● 157

tier areas. Under the sliding scale royalty system,

the royalty rate increases with the production rate

and government and industry shares of income are

based partially on the productivity of the tract.

Marginal resources and declining fields may be

more likely to be produced because of the lower

royalty rate attached to this production. At present,

the primary disadvantage of the sliding scale royalty

bidding system is that the royalty rate does not slide

below the legal minimum of 121⁄2 percent and won’t

greatly improve the profitability of small or marginal fields over the 121⁄2 percent fixed royalty now

in use. Sliding scale royalties that slide to zero percent may be needed to encourage the development

of resources in frontier areas.

Economic theory and empirical economic models,

including the OTA computer simulation, indicate

that net profit share payments also may be well-

-suited to offshore frontier areas. 48 Under this Sys -

tem, firms share the net income from tract development with the government at a specified profit

share rate, fixed by law at no less than 30 percent.

Of the several types of profit-sharing systems (e. g.,

investment account, rate-of-return, annuity-capital

recovery), the United States has used the fixedcapital recovery system. Firms are allowed to recover their initial investment, plus a return on the

investment, before sharing profits from oil and gas

development with the government. Because this

system takes into account the high costs, long leadtimes, and other features characteristic of frontier

areas, it provides for greater government risksharing. Small and marginal fields may not be as

highly taxed and, therefore, are more likely to be

developed.

Although work commitments, profit-sharing,

and other leasing approaches have generally been

accepted abroad, these bidding systems may be difficult to implement in the United States. Offshore

leasing in the United States has always been based

on competition between companies. Any leasing

system used in the United States has to award lease

rights on the basis of defined, objective criteria. In

other countries, leasing conditions are often nego4’R. J, Kalter, W. E. Tymer, and D. W, Hughes, “Alternative

Energy Leasing Strategies and Schedules for the Outer Continental

Shelf (Cornell University, Dept. of Agricultural Economics, December 1975).

tiated directly between private firms and the government,

In addition, effective design and administration

of alternative bidding systems would require extensive testing and increased funding. The design

of sliding scale royalty and profit-sharing systems

is based on certain types of tract-specific information and calibration that is difficult for the government to achieve.49 Post-production accounting in

these systems often involves complex procedures

for verifying costs, profits, and/or flow rates associated with individual leases. Work commitment

bidding systems have administrative costs in negotiating terms and conditions and monitoring industry compliance. There has also been concern

about potential government intervention into industry accounting and operational practices in the

implementation of these bidding systems.

Because of the inconclusive results of the 5-year

testing of the alternative bidding systems specifed

in the OCS Lands Act Amendments, the General

Accounting Office (GAO) has recommended that

the requirement to test alternative bidding systems

in offshore leasing be extended by Congress .50 Further testing of alternative bidding systems, including some approaches not specified in the OCS

Lands Act Amendments, is especially needed in offshore frontier areas. The effect of bidding systems

on the level of competition is not particularly germane in the Arctic and deepwater, where competition will automatically be limited by the high-cost

and high-risk nature of the tracts. But the effect of

bidding systems on the rate of exploration and development in the frontiers is crucial in view of the

need to assess and develop the resource potential

of these areas.

The OCS Lands Act Amendments now gives the

Secretary of the Interior great flexibility in designing bidding systems, which may consist of ‘‘ any

other system of bid variables, terms, and conditions . . . except that no such bidding system or

modification shall have more than one bid vari4gD, R. Siegel and J. L. Smith, ‘ ‘Does Profit-Sharing Leasing for

Outer Continental Shelf Leases Need Finer Tuning?’ Oil and Gas

Journal (May 7, 1974), pp. 144-152,

sOGenera] Accounting Office, ‘ ‘Congress Should Extend Mandate

to Experiment With Alternative 13idding Systems in Leasing Offshore

Lands, ” (May 27, 1983).
158 • Oil and Gas Technologies for the Arctic and Deepwater

able.” 51 As leasing and exploration proceed in offshore frontier areas, new approaches and modifications of lease conditions may be necessary to sustain

the search for oil and gas resources. Other countries, such as the United Kingdom, have found it

necessary to adjust lease payments and taxes in later

stages of offshore activity to extend exploration and

to encourage development of marginal resources.

Through testing, the Department of the Interior

could assess the advantages and disadvantages of

alternative bidding systems in promoting exploration and development in frontier areas. It could also

refine different bidding approaches and would be

prepared to implement them on a more widespread

basis if needed as an incentive to a second-round

of leasing and development in the offshore frontiers.

Lease Terms

Other lease conditions may also need to be modified to encourage oil and gas activity in offshore

frontier areas. For example, longer lease terms and

larger tracts coupled with relinquishment provisions

may be appropriate to frontier areas in conjunction with or apart from the implementation of new

bidding systems.

As leasing in offshore frontier areas has increased, a greater number of OCS tracts have been

offered and leased with 10-year rather than 5-year

lease terms. The OCS Lands Act, as amended, provides for longer lease terms as an incentive to exploration and development in areas of unusually

deepwater or difficult operating conditions. The

longer lease terms have been offered for tracts in

the Alaskan offshore, where weather and ice conditions may be severe, and for deepwater tracts in

the Atlantic, Pacific, and Gulf of Mexico regions.

The first tracts with 10-year lease terms were offered in the 1979 joint Federal/State lease sale in

the Beaufort Sea. This was the first Federal lease

sale held in Arctic waters, and it resulted in the leasing of 24 Federal tracts which expire in 1990. Since

that time, most of the lease sales held in the Alaskan

planning areas have included tracts with 10-year

leases. In 1984, the Navarin Basin sale (Lease Sale

83) and the Diapir Field sale (Lease Sale 87)

featured some of the most remote tracts yet offered

~lScCtiOn B(a), Supra note 1‘

in U.S. waters and the most tracts leased with 10-

year terms in single lease sales. About 70 percent

of the tracts leased with longer lease terms have

been in the Alaskan planning areas.

Ten-year lease terms also have been used for

deepwater tracts in the lower 48 states, although

the deepwater criteria have varied. The first truly

deepwater OCS sales were held in 1981 in the Atlantic, where all tracts in water over 400 meters deep

were offered with 10-year leases. However, a 900-

meter criterion was used for Southern California

Lease Sale 68 in June 1982, and 900 meters subsequently became the deepwater marker for tracts

leased in the Pacific, Atlantic, and the Gulf of Mexico.

In December 1983, the Department of the Interior proposed increasing the acreage offered with

10-year lease terms by reestablishing 400 meters

as the deepwater criterion and making 10-year lease

terms automatic for all tracts in 400 meters of water

or deeper.52 The revision of the definition of deepwater from 900 meters to 400 meters is based on

the increased amount of time needed to explore and

develop energy resources in these water depths as

compared to nearshore tracts. Lease terms are now

decided on a sale-by-sale basis, but an automatic

10-year term tied to water depth could facilitate industry and government planning.

Critics of the longer lease terms believe they allow

companies to delay exploration and development

in offshore areas. At present, the 5-year lease term

ensures that tracts are explored and developed in

a timely manner, as leases are forfeited at the end

of 5 years if they have not been drilled or declared

prospective. Extensions of lease terms or ‘ ‘suspensions of operations’ (SOPS) are available under

special conditions. Critics of 10-year lease terms

believe that the standard 5-year term and SOPS

should be continued to be used in Alaskan and

deepwater areas. However, SOPS are subject to

changing policy interpretations or regulations and

create greater uncertainty for the industry in

frontier-area leasing.

Exploration diligence generally has been promoted by the requirement that lessees submit exploration plans and follow them. Holders of 5-year

52 Fe~er.d ~egister, (Dec. 20, 1983), 48 (245): 56279-56281.
Ch. 6—Federal Leasing Policies ● 159

leases are required to submit exploration plans or

statements of intentions to explore by the end of

the fourth year of the lease term. However, holders

of 10-year leases have not been required to submit

these plans at a specified time, except as outlined

in the lease offering. This often has been as late

as the eighth or ninth year of the lease term. The

Department of the Interior is now considering a

requirement that exploration plans be filed within

a set time on 10-year leases, although a milestone

year has not been proposed. A requirement for

earlier submission of exploration plans on 10-year

leases could promote diligent exploration efforts

while reducing the risks of the shorter lease term

for the industry.

Tract Size

In addition to lengthening the lease terms,

another proposal to improve the efficiency of exploration and development in offshore frontier areas

is to increase the size of offshore lease tracts or

blocks. The OCS Lands Act limits lease tracts to

an area of nine square miles or 5,760 acres, unless

it is determined that a larger area is necessary to

comprise a reasonable economic unit. An option

in frontier areas is to increase the average size of

the tracts and to combine the larger tracts with

relinquishment provisions. 53 This is standard practice in countries such as the United Kingdom, Norway, and Canada, where the average size of the

tracts ranges from 90 square miles to 700 square

miles.

Leasing larger tracts in offshore frontier areas

can promote more rapid and efficient exploration

strategies. Firms may be more willing to bid on

large areas, which increase the probability that oil

discovered by the lessee would be contained within

its tract rather than on an adjoining lease. Firms

would have less incentive to delay exploration in

hopes that information from nearby drilling efforts

reduces uncertainty about the value of a tract. In

general, larger tracts increase the likelihood that

owners will fully benefit from drilling information

and thus may induce increased investment and exploratory activity.

SsResource planning Associates, Inc. and Resource Consulting

Group, Inc., Report to the Department of Energy, “Alternative Procedures for Managing the Leasing of Nonprospective OCS Acreage,

report to the Department of Energy (Jan. 29, 1981), p. 3-16,

In offshore frontier areas, increased tract size can

provide for the surveying of vast amounts of acreage and the selection of prospective areas for

drilling. The addition of relinquishment or turnback requirements could help assure the early identification of high quality acreage. Under this system, firms would relinquish a percentage of their

acreage with exploration information at a specified

time to the government, which could then lease the

land again in smaller tract sizes. The United

Kingdom, Norway, and Canada require that firms

relinquish 50 to 65 percent of the lease tract after

3 to 5 years of exploration. The government benefits from the information generated by the broadscale exploration efforts.

Joint Bidding

The extremely high costs of exploration in frontier areas may prompt a need to allow joint bidding by the major oil companies on offshore leases.

In October 1975, the Department of the Interior

banned oil companies with worldwide production

in excess of 1.6 million barrels per day of oil

equivalent from participating in the same joint bidding group for offshore leases. This restriction became law with the enactment of the Energy Policy

and Conservation Act of 1975, The OCS Lands

Act Amendments modified the ban by allowing the

Secretary of the Interior to authorize joint bidding

by the majors on lands with extremely high exploration costs or where activity might not occur otherwise. The joint bidding ban so far has not been

lifted for any sale,

Joint bidding has played a key role in OCS lease

sales since the start of leasing in 1954. In the 35

pre-ban lease sales, about 10 percent of the bids

were joint bids among the seven or eight largest

oil companies. Recently, the majors not affected

by the ban have frequently bid together on the more

attractive and expensive tracts. The list of U.S.

companies affected by the ban is updated every 6

months by the Department of the Interior and has

included such firms as Exxon, Texaco, Mobil,

Shell, Standard Oil of California, and Chevron.

A variety of concerns has prompted the continuance of the ban on joint bidding and even initiated political pressures in the early 1980s for extension of the ban to the 16 largest U.S. oil and
160 . Oil and Gas Technologies for the Arctic and Deepwater

gas companies. A major purpose of the ban is to

facilitate the participation of smaller firms in offshore lease sales. Joint ventures among the majors

might preclude their bidding with smaller firms,

who would otherwise not gain entry to OCS activity. Joint bidding by the majors may also be a substitute for individual participation and reduce the

number of competitors for OCS tracts and government cash bonus revenues. Greater competition

and diversification of tract ownership are believed

to provide for increased capital availability and

more efficient exploration.

Joint bidding by the majors also prompts fears

of collusion in other offshore areas and markets.

At joint bidders’ conferences, the majors may

discern tracts on which other firms are not planning to bid, allowing them to lower their bids on

these tracts. Joint ventures by the majors on OCS

leases might also foster collusion in refining, processing, or related markets and increase their downstream market power.

A number of statistical analyses of OCS bidding

and leasing data have tested the various hypotheses concerning the effects of the joint bidding ban.

It is argued that the joint bidding ban itself is anticompetitive because the average number of bids

per tract has actually decreased since the imposition of the ban.54 Similarly, it has been shown that

stB~ian Sul]ivan and Paul Kobrin. “The Joint Bidding Ban: Proand Anti-Competitive Theories of Joint Bidding in OCS Lease Sales,

Journa/ of Economics and Business (fall 1980), pp. 1-2.

the size of the cash bonuses statistically increases

as the concentration of joint bids increases and that

the ban results in government revenue losses.55

However, the percentage of offshore leases won by

non-major oil companies and the number of successful bidders in offshore lease sales have increased

since the ban was put in place.56 All of these effects could be due to causes other than the joint bidding ban. In general, it is difficult to draw any

strong conclusions based on these studies about the

effect of the ban on OCS participation rates, bidding rates, or government revenues.

Removing the ban on joint bidding by the major oil companies would allow them to share the

financial burdens and risks of investments in offshore frontier areas and might provide an additional

incentive to exploration and development. The

competitive effects of the joint bidding ban are less

significant in Arctic and deepwater areas, where

the number of firms which may participate is

limited by the high costs of exploration. The joint

bidding ban eventually may have unwanted negative effects in frontier areas in discouraging participation and in lowering bids.

55Alan Rockwood, “The Impact of Joint Ventures on the Market

for OCS Oil and Gas Leases, ‘Journal of Znc/ustria/ Economics (June

1983), pp. 453-468.

sGLes]ie Grayson et. ~., ‘ ‘Issues of Competition on the Outer Continental Shelf, ” Journal of Natural Resources Law, (spring 1983),

p. 97,
Chapter 7

Environmental Considerations
Contents

Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163

Environmental Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

Types of Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

Trends in the Environmental Studies Program. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170

Biological Resources. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173

Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173

Affected Species . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174

Bowhead Whales: A Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176

Oil Spills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185

Limits to Effective Countermeasures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186

Countermeasures Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188

Government/Industry Responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197

Technology Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200

TABLES

Table No. Page

7-1. Use of Environmental Information in Leasing Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 166

7-2. Oil Spill Probabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185

7-3. Oil Spill Technology Research Needs. . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . 201

FIGURES

Figure No. Page

7-1. Expenditures for Environmental Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167

7-2. Expenditures for Environmental Studies by Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167

7-3. Recent Trends in Environmental Studies Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

7-4. Funding for Alaskan Environmental Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

7-5. Funding for Alaskan Environmental Studies by Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169
Chapter 7

Environmental Considerations

OVERVIEW

The development of petroleum resources in frontier areas of the Outer Continental Shelf (OCS) has

become an important strategy in meeting the Nation’s future energy needs. At the same time, a national consensus exists that protecting the environment from the effects of OCS development is

equally important. Several laws are in force which

address the potentially conflicting goals of environmental protection and resource development:

● The Outer Continental Shelf Lands Act (OCS

Lands Act) of 1953 (amended in 1978) mandates, among other things, that environmental

studies be done ‘ ‘in order to establish informat ion needed for assessment and management of environmental impacts on the human,

marine, and coastal environments of the Outer

Continental Shelf and the coastal areas which

may be affected by oil and gas development.”1

● The National Environmental Policy Act

(NEPA) of 1969 requires that all Federal agencies ‘‘utilize a systematic, interdisciplinary approach which will insure the integrated use of

the natural and social sciences and the environmental design arts in planning and in decisionmaking which may have an impact upon

man’s environment. The NEPA requires

that an Environmental Impact Statement be

prepared for major Federal actions.

● The Marine Protection, Research and Sanctuaries Act prohibits the unregulated dumping of waste materials into coastal and ocean

waters and authorizes the Secretary of Commerce to designate offshore marine sanctuaries. 3

‘Public Law 83-212, 67 Stat. 462 (1953), 43 USC 1331-1356, as

amended by Pub. Law 93-627, 88 Stat. 2126 ( 1975), and Pub, Law.

95-372, 92 Stat. 629 (1978). Seccion 20 (a)(l),

‘Public Law 91-90, 83 Stat. 852 ( 1970), 42 USC 4321-4347, as

amended by Pub. Law 94-52, 89 Stat. 258 ( 1975) and Pub. Law 94-

83, 89 Stat. 424 (1975). Section 102 (2)(A).

3Public Law 92-532, 86 Stat, 1052 (1972), 33 USC 1401- 1444; 16

USC 1431-1434, as amended by Public Laws 93-254 (1974), 93-472

(1974), 94-62 (1975), 94-326 (1976), and 95-153 (1977).

●

●

●

●

The Endangered Species Act requires that endangered and threatened species of fish, wildlife, and plants (and the ecosystems on which

they depend) be determined and conserved,

and it authorizes issuance of regulations necessary for protection of these species.4

The Marine Mammal Protection Act provides

for the conservation and management of

marine mammals.5

The Coastal Zone Management Act (CZMA)

provides for management and protection of the

coastal zone in cooperation with states. b Under

the CZMA Federal actions must be consistent with approved state coastal zone management programs.

The Federal Water Pollution Control Act

(FWPCA) provides for the restoration and

maintenance of the quality of the Nation’s

waters. 7 Among other things, the FWPCA requires discharge permits for OCS activities.

Several important environmental concerns are

related to oil and gas development in frontier areas.

If OCS exploration and development is to proceed

with due regard for environmental protection and

if sound lease management decisions are to be

made, a large quantity of environmental information is needed. This is particularly true in Arctic

frontier areas where relatively less is known about

marine ecosystems and the manner in which they

may be affected by OCS activities. Given funding

constraints for environmental research, it is particularly important that such information be based

on sound scientific procedures, provided in a timely

manner, available to all interested parties, and rele4Public Law 93-205, 87 Stat. 884 ( 1973), 16 USC 1531-1543, as

amended by Public Laws 94-325 (1976), 94-359 (1 976), 95-212 ( 1977),

95-632 (1978), and 96-159 (1979).

5Public Law 92-522, 86 Stat. 1027 (1 972), 16 USC 1361-1407, as

amended by Public Laws 93-205 (1973), 94-265 (1976), 95- 136( 1977),

and 95-316 ( 1978).

bPublic Law 92-583, 86 Stat. 1280 ( 1972), as amended by Public

Laws 93-612 (1975), 94-370 (1976), and 95-372 (1978).

‘Public Law 845, 62 Stat. 1155 ( 1948), 33 USC 1251-1367, as

amended.

163
164 ● Oil and Gas Technologies for the Arctic and Deepwater

vant to the pre-and post-lease decisions that must

be made. The major program for developing the

information necessary for predicting, assessing, and

managing the effects of OCS development is the

Department of the Interior’s Environmental Studies

Program (ESP).

It is beyond the scope of this assessment to do

an exhaustive study of all biological resources that

potentially may be affected by OCS oil and gas development. Some endangered species and some species of commercial importance which may be affected by oil and gas activities in Arctic areas are

briefly considered. In lieu of a thorough analysis

of all species, a detailed case study of bowhead

whales is presented. Although not the only Arctic

marine mammal listed as endangered, this species

has received considerable attention in recent years.

The possible vulnerability of bowhead whales to oil

and gas activities has been the subject of intense

debate among groups with different values and different objectives for Arctic development. Organizations including the Minerals Management Service (MMS), the National Marine Fisheries Service

(NMFS), the Alaska Eskimo Whaling Commission,

and the oil and gas industry have funded bowhead

whale research in an effort to better understand the

life history of the species and to determine the potential effects of OCS oil and gas activities on the

species’ behavior, survival, and reproduction.

Technology and techniques for oil spill containment and clean up in frontier areas are an important environmental consideration. While the oil and

gas industry is genuinely concerned with preventing oil spills, the industry’s capability to contain

and clean up spilled oil in hostile environments has

not been proven under actual conditions. This

assessment focuses on the evaluation of the stateof-the-art of Arctic oil spill countermeasures. Less

attention is given to deepwater spills. Although

some deepwater oil spills may occur as the oil and

gas industry moves further offshore, and although

current capability to clean up such spills is limited,

the equipment and methods for combating deepwater spills are essentially no different than those

used for nearshore areas. Most deepwater spills will

likely be of less concern than shallow water, nearshore spills because: 1 ) they generally occur in less

biologically sensitive areas; 2) natural processes may

often work to dissipate and degrade deepwater spills

before significant damage can be done; and 3)

greater distance from shore allows more lead time

in which to consider what (if anything) is to be

done.

ENVIRONMENTAL INFORMATION

Overview

The Department of the Interior (DOI) is responsible for leasing and managing OCS lands. As manager of the OCS leasing program, it is DOI's

responsibility to ensure that environmental safeguards are employed. Specifically, DOI must

ensure that OCS operations are

. . . conducted in a safe manner by well-trained

personnel using technology, precautions and techniques sufficient to prevent or minimize the

liklihood of blowouts, loss of well control, fires,

spillages, physical obstruction to other users of the

waters or subsoil and seabed, or other occurrences

which may cause damage to the environment or

property, or endanger life or health.8

8Section 3(6), Supra note 1.

In order to meet this responsibility, DOI must

be able to assess the environmental impacts of

proposed offshore development, to delineate sensitive and unique areas, and to determine environmental hazards. The need for scientific information

to accomplish these tasks led to the establishment

of the Environmental Studies Program in 1973.

This is the major scientific program designed to

acquire information for OCS leasing.

ESP was initially administered by the Bureau of

Land Management (BLM). However, in 1982,

then Secretary of the Interior James Watt created

MMS in order to streamline the administration of

the leasing process, and the responsibility for the

ESP was transferred to MMS. The environmental

information generated by ESP research projects is

used by the Secretary of the Interior and by the
Ch. 7—Environmental Considerations . 165

environmental assessment and leasing management

divisions of the MMS in order to carry out their

responsibilities under the NEPA and the OCS

Lands Act. The Secretary of the Interior uses ESP

information (as presented in NEPA documents and

in the Secretarial Issue Document for each sale) for

sale-related decisions.

The studies program is divided among the four

MMS regional offices—the Alaska, the Atlantic,

the Gulf of Mexico, and the Pacific regions—and

the headquarters office. Alaska studies have received the most attention because the Alaska OCS

is the largest OCS area (comprising about 74 percent of OCS lands) as well as the least explored and

least studied area.

Relatively little information was available prior

to 1973 to assess the potential impacts of oil and

gas development, and data gaps were especially

large for the Alaskan OCS. Moreover, BLM—

primarily a western land management agency—

initially did not have the inhouse capability to

extend its environmental studies program to the

Alaskan OCS. Therefore, in 1974, BLM contracted

with the National Oceanic and Atmospheric Administration (NOAA) to design and manage an

environmental studies program for the Alaskan region. NOAA initiated the Outer Continental Shelf

Environmental Assessment Program (OCSEAP)

for Alaskan studies, OCSEAP has become one of

the most comprehensive programs for the collection

and evaluation of Arctic environmental information. It is also the largest single segment of the environmental studies programs funded by the MMS.

MMS directly manages all environmental studies

in the Atlantic, Gulf, and Pacific OCS regions and

some of the Alaskan OCS studies (including some

transport studies and endangered species and monitoring studies). MMS also manages the Alaska

Social and Economic Studies Program. This program, begun in 1976, funds studies which investigate the impact of offshore oil and gas development

on economic, social, and cultural systems of coastal

residents, communities, and regions. Seventy-five

percent of MMS funds for social and economic

studies have been spent in Alaska.

The assessment of environmental information

needs and the development of environmental

studies occur annually through the MMS Regional

Studies Plans. Assistance in developing Regional

Studies Plans is given by Regional Technical

Working Groups in each OCS area. In the Alaska

region, this group is composed of representatives

from the MMS, the State of Alaska, the Fish and

Wildlife Service, the NMFS, the U.S. Coas t

Guard, the Environmental Protection Agency, industry, and private groups. The OCS Advisory

Board Scientific Committee also comments on the

plans during development.

Studies are ranked according to: 1) the importance of the research to decision-makers; 2) the date

of the decision for which the study results are to

be used; 3) the generic applicability of results or

techniques from the study; 4) the availability and

completeness of existing information; and 5) the

applicability of the information to issues of regional

or programmatic concern. 9

With respect to the Alaskan OCS, information

needs identified by MMS are utilized by NOAA

to prepare an annual Technical Development Plan

for OCSEAP research. 10 OCSEAP research is performed at universities, State and Federal agencies,

private firms, and research institutions. Private

firms currently receive the greatest proportion of

ESP funding in Alaska, and that proportion has

been increasing.

The results of research projects are utilized in

the OCS leasing decision process at various stages.

The steps in which scientific information is incorporated into leasing decisions are described in table

7-1. Results from the studies program and other

scientific information are also utilized in post-lease

permitting, post-lease environmental analyses, and

(if necessary) development environmental impact

statements.

Expenditures

MMS spent approximately $370 million on the

ESP between 1973, the year in which the program

was initiated, and 1984, the latest year for which

data are available (see figure 7-l). About half of

‘Minerals Management Service, Alaska Outer Continental Shelf

Region, FY1985 Alaska Regional Studies Plan: Final (October 1983),

lo~ation~ Oceanic and Atmospheric Administration, Outer Continental Shelf En\’ironmental Assessment Program: FY 84 Technical

Development Plan (August 1983).
166 . Oil and Gas Technologies for the Arctic and Deepwater

Table 7-1 .—Use of Environmental Information in Leasing Process

Area Identification MMS Scoping Meeting

MMS analyzes recommendations based on Issues concerning proposed lease areas identified.

environmental information from FWS, DOI, the public,

and affected States. oil and gas industry, environmental groups, a-rid citizen

representatives.

MMS/OCSEAP Synthesis Meeting Synthesis Report

Primary management tool for incorporation of scien- Synthesis Report prepared by NOAA (for Alaska OCS

tific results into OCS leasing process. Scientists and

science managers discuss research results, identify Environmental Impact Statement (DEIS).

data gaps, determine how results answered OCS

management questions. Full synthesis meeting now

held only for first generation lease sales. Smaller

meetings held for second or third sales in an area,

Draft Environmental Impact Statement Endangered Species Consultation

MMS prepares the Draft Environmental Impact Statement based upon available research results from a biological opinion.

variety of sources, including, when applicable, the

OCSEAP Synthesis Report (or results from the

Synthesis Meeting if report not yet available). DEIS

must address major issues related to the proposed

Secretarial Issue Document

action.

Final Environmental Impact Statement

Required to address proposed alternatives discussed

in DEIS; incorporates public comment received on

DEIS. lease tract sale decision.

Final Notice of Sale

Decision to lease, approved by Secretary of Interior.

Any changes in bidding systems, lease stipulations,

lease blocks incorporated here.

Addresses economic, industry, social, and environSOURCE: Office of Technology Assessment.

these funds have been expended in the Alaska OCS office. Program expenditures increased dramatically

region (see figures 7-2). The other half of the budget in 1975 and doubled again in 1976, in response to

has funded studies in the Atlantic, Gulf, and Pa- the decision to lease offshore areas for oil and gas

cific regions and in the Washington headquarters exploration in Alaska.
Ch. 7—Environmental Considerations . 167

Figure 7-1 .—Expenditures for Environmental Studies

(1973-84)

— — — — — — —

1974 1976 1978 1980 1982 1984

Year Branch of Environmental Studies. SOURCE: Minerals Management Service,

Figure 7-2.— Expenditures for Environmental Studies

by Region (1973-84) (millions of dollars)

Pacific

$185

Alaska

(50°10)

However, since 1980, when expenditures for

environmental studies totaled more than $45 million, budgets for the program have declined, and,

in 1984, yearly funding dropped below $30 million

(without accounting for inflation) for the first time

since 1975. This trend is consistent with reduced

non-defense spending throughout government

under the 1981 through 1984 budgets.

Since 1980, ESP funds for the Alaska region have

decreased more rapidly than funding for studies in

other areas (see figure 7-3). Although the Alaska

region budget is still the largest, it has decreased

from 55 percent of the budget in 1980 to 45 percent in 1984, Funds for Alaska OCS studies have

been reduced some 49 percent since 1980, from

$25.3 million to $12.9 million in 1984 (see figure

7-4). Funding for Gulf of Mexico studies has also

decreased, from 19 percent of the budget in 1980

to less than 14 percent in 1984. The proportion of

the total budget spent for Atlantic and Pacific region studies has increased since 1980, although total

dollar amounts have declined. Funding for the

Washington, D.C. headquarters office also increased in this period, and in 1984 accounted for

5.3 percent of the total ESP budget.

Over the 1 l-year period from 1973 through 1983

about 86 percent ($148 million) of Alaska environmental studies funds have been used for NOAA/

OCSEAP studies. The relationship between NOAA

and MMS has changed in recent years. MMS has

gradually upgraded its technical capabilities which

it lacked in the early years of the program, and has

assumed more responsibility for managing Alaskan

environmental research. The budget for MMS

(non-OCSEAP) Alaskan studies has increased–

but not dramatically— since 1980, but funding for

OCSEAP studies has decreased more than 50 percent, from just over $21 million in 1980 to less than

$8 million in 1984. Thus, the relative importance

of MMS inhouse and directly contracted environmental studies has increased significantly.

SOURCE: Minerals Management Service, Branch of Environmental Studies
168 ● Oil and Gas Technologies for the Arctic and Deepwater

Figure 7-3.—Recent Trends in Environmental Studies Figure 7-4.—Funding for Alaskan Environmental

Funding (1980-84) Studies

45

40

35

30

25

20

15

10

5

0

— —

1980

Legend:

1981 1982 1983 1984

Year

Atlantic

Gulf of Mexico

Pacific

1 1 Alaska

SOURCE: Minerals Management Service, Branch of Environmental Studies. — —

1974 1976 1978 1980 1982 1984

Year

SOURCE: Minerals Management Service, Branch of Environmental Studies.

Hazards Studies

Environmental hazards studies encompassed investigation of seismicity and volcanicity; determination of the character of bottom sediments and

subsea permafrost; quantification of the nature, intensity, and frequency of sea ice hazards; and determination of wave heights. The objective of these

studies has been to acquire information useful for

determining hazards to drill ships, platforms, and

pipelines, and for determining the probability of

accidents caused by environmental hazards.

Transport Mechanisms

The objective of transport studies has been to determine the mechanisms involved in transport,

weathering, and dispersion of spilled oil, oiled

sediments, and other contaminants. A major part

of this program has involved physical oceanography studies, including development of a sophistiTypes of Studies

ESP and OCSEAP studies maybe classified into

seven categories. These are:

Contaminant Distribution Baseline Studies

These studies were designed to learn more about

the background levels of hydrocarbons and heavy

metals in the Alaskan OCS in order to establish

a baseline for predicting changes if these kinds of

contaminants were released during oil and gas development. Funding for baseline studies in the

Alaska region was greatest in 1976, 1977, and 1978

(see figure 7-5).

Biological Studies

Biological studies have investigated the distribution and population dynamics of birds, mammals,

fish, littoral biota, benthic biota, and plankton.

These studies have received the largest total amount

of funding since the inception of the program.
Ch. 7—Environmental Considerations . 169

30

28

26

24

22

20

18

16

14

12

10

8

6

4

2

0

Figure 7-5.—Funding for Alaskan Environmental Studies by Type (1973-83)

species

1973 1975 1977

SOURCE Minerals Management Service, Branch of Environmental Studies.

cated oceanic circulation model, a simplified version of which the MMS now uses for risk analysis.

Such models are important because they help to

focus impact assessment on identified vulnerable

coastlines and marine biological resources at risk.

They also can lead to local site-specific models

which could allow assessment of OCS activities

affecting circulation patterns, or whose impact is

distributed regionally by circulation (e. g., causeway

construction, sand and gravel extraction, hydrocarbon production byproducts, and marine construction siting).

Effects Studies

Effects studies investigate the interactions of

spilled oil and other contaminants on individual

species and ecosystems. For example, effects studies

have been done for salmon, herring, and king and

tanner crabs.

1979 1981 1983

Year

Ecosystem Processes

The purpose of process studies is to investigate

and understand aspects of community structure and

function. Although some biological process studies

have been undertaken in specific ecosystems, there

are still other ecosystems for which processes need

to be better understood. Studies of ecosystem structure and processes tend to involve many scientists

in different disciplines, all collecting field data concurrently. Thus, these studies are expensive and

site specific. Ecosystem studies have been conducted

at Simpson Lagoon and Pearl Bay, and studies of

the Yukon Delta and the North Aleutian Shelf are

in progress.

Socioeconomic Studies

The objective of these studies is to assess the

social costs of OCS operations, e.g. , the impacts
170 ● Oil and Gas Technologies for the Arctic and Deepwater

of coastal development, tanker traffic, and marine

pollution associated with OCS development; effects

on local cultural systems; damages to personal property and property values; and costs to recreational

and/or subsistence uses.

Trends in the Environmental

Studies Program

Scope and Direction

Baseline studies. Baseline characteristics and contaminants in Arctic regions have been extensively

studied. However, this class of background study

was criticized by scientists in the 1978 National Research Council ESP review because the natural geographic and temporal variability of the marine environment is so great, both in space and time, that

useful baselines could not be established without

prior information on the types and specific locations of the development to be undertaken. Thus,

the studies would be of little use either for predicting changes or for quantifying change during and

after development. Consequently, funding for these

studies was cut significantly in 1979, and, beginning in 1982, no funds were allocated for baseline

studies. Now that development in specific Arctic

OCS areas may occur, concern about monitoring

the effects of OCS activities has increased, and more

site-specific work will be necessary.

Biological studies. Funding for biological studies

has decreased in the last several years by a greater

proportion than decreases for the ESP as a whole.

Basic information about Arctic biota is now relatively well known. However, data are still lacking

for many geographic and subject areas (e. g., areas

outside the fast ice zone in the Beaufort Sea). The

Interagency Committee on Ocean Pollution Research, Development, and Monitoring considers

the Beaufort Sea living resources studies important

because they are process oriented. ” These studies

have proven more effective than studies which

simply enumerate and catalog biota. For example,

the results of ecological process studies in Simpson

Lagoon provided the nucleus for biological stipulations attached to the joint State/Federal Beaufort

Sea lease sale in 1979 and for other lease sales.

111~teragency Cornrn it[cc on Ocean Pollution Research, Development, and Monitoring, Marine Oil Pollution: Federzd Program Review (April 1981 ).

Funding for endangered species studies has increased significantly since the beginning of the ESP.

In fiscal years 1982 and 1983, endangered species

studies accounted for the largest percentage (about

35 percent) of Alaska ESP expenditures. The endangered species most studied have been bowhead

and gray whales. The Endangered Species Act is

a major reason that studies of endangered whales

have been emphasized. Federal agencies must

ensure that actions which they authorize, fund, or

carry out are not likely to jeopardize the existence

of any endangered “or threatened species. The emphasis on bowhead whale studies, in particular, is

also motivated by regional political concerns. Several interest groups have important, but not necessarily compatible, interests concerning the

species.

Hazards studies. In the early stages of the ESP,

there was a large geological hazards assessment

program. Funding for environmental hazards

studies peaked in 1980 at $12.6 million per year

(of which two-thirds was allocated to Alaska OCS

studies). Since then, funding has been reduced significantly. In 1983, total ESP funding amounted

to only $1.4 million. The decrease in funding has

corresponded to an evolution in DOI policy concerning the appropriate scope of the Federal Government’s research responsibilities relative to those

expected of the private sector. It is the MMS

position that most hazards studies should be undertaken by industry. In particular, industry must

undertake site-specific hazards studies in order to

properly design offshore structures, pipelines, etc.,

and must provide the data to the MMS Offshore

Field Operations for exploration plan and permit

approvals.

Reduced ESP funding for geological hazards

studies has been controversial. Some groups believe

that the government should have an independently

acquired, public body of information in order to

properly perform its oversight role of assessing the

performance of the industry in their proposed future

OCS activities, and that the current program does

not provide the government with this capability.

Thus, it is contended that government needs a

stronger capability to evaluate offshore hazards and

the measures that industry is developing to respond

to them. This would require more Federal involvement in hazards studies and more funding.
Ch. 7—Environmental Considerations ● 171

Transport mechanism studies. Transport studies

generally have been of high quality, especially in

Alaska where relatively less was known. Nevertheless, regional gaps remain, such as the need for

better information about sediment transport in the

Bering Sea (e. g., for designing gathering pipelines

and subsea completions) and the need for weather

and ice data in the Bering and Chukchi Seas. Most

transport studies require data acquisition over periods of years, requiring many instruments and

repetitive surveys. However, risk analysis is conducted using simulation models which project probable transport based on physical and chemical properties and available field data.

Effects studies. Although research needs remain,

funding for effects studies has decreased by more

than 50 percent since 1980. Knowledge of effects

of offshore development (e. g., the effects of oil spills,

the effects of artificial structures on living organisms, the effects of coastal modifications on the

natural movement of fishes, and the effects of noise)

is currently deemed by some to be inadequate,

Others take the view that such effects (with the possible exception of noise) would be too localized to

play a major part in formulating large-scale research

policy. Several effects studies have been completed

or are underway.

Socioeconomic studies. In comparison to other

studies areas, relatively little money has been spent

by MMS on socioeconomic studies (e. g., $2.0 million in 1983), Social and economic studies are often

less expensive than equipment-intensive environmental studies. Hence, although less money has

been spent, the number of socioeconomic studies

funded through 1983 (133) is large relative to the

numbers of studies funded in other categories. Most

of these funds have been spent in Alaska. On the

other hand, the 1981 report of the Interagency

Committee on Ocean Pollution Research, Development, and Monitoring notes that higher priority

is generally assigned to studies which are legally

mandated or which are designed to avoid lawsuits

or to accommodate political concerns. Thus, studies

addressing economic and social issues may have

greater difficulty meeting the criteria for funding.

Management

Funds allocated to the OCSEAP program have

decreased since 1980, and MMS has increased its

capability to manage environmental studies. The

relationship between OCSEAP and MMS is changing, and some critics have argued that the larger

role for MMS in directly managing Alaskan environmental studies may not be the optimum situation. The argument against MMS’s involvement

is that the agency responsible for OCS leasing

should not also be in charge of determining what

environmental research is necessary and of supervising subsequent research efforts. Thus, a continuing OCSEAP role is seen by some as desirable in

order to help ensure that scientific knowledge is produced which is needed to achieve a balance between

offshore oil and gas development and environmental protection, thus safeguarding the public interest. Conversely, the OCSEAP program has

always been supported by interagency transfer of

BLM/MMS funds, and OCSEAP managers have

worked under the guidance of the MMS. MMS

is legally required by the OCS Lands Act and

NEPA to acquire information relevant to potential environmental impacts, and is increasing its capability to do this itself.

In 1978, a National Research Council review of

the ESP concluded that the program at that time

did not effectively contribute to leasing decisions

or to the accrual of sound scientific information adequate for OCS management. The National Research Council cited several reasons for poor program design, including low priority within DOI and

the paucity of professional experience within the

staff. 12 Many of the important issues raised by the

NRC have been addressed, and, in particular, the

creation of MMS, improvements in staff, and redesign of the program have produced information

more directly related to the management of OCS

activity. However, despite the fact that MMS is

now conducting the post-lease monitoring required

by the OCS Lands Act, MMS’s research efforts—

given its leasing mission—have mostly been focused

on immediate rather than long-range information

needs. Approaches should be considered that help

ensure that important longer term studies, not

motivated by near-term leasing decisions, are

undertaken.

1 ZNationa] Research Council, OCS Oil and Gas: An Assessment

of the Department of the Interior Environmental Studies Program

(Washington, DC: National Academy of Science, 1978).
172 ● Oil and Gas Technologies for the Arctic and Deepwater

Funding

Each year less money is available for environmental studies, and fewer such studies are funded.

This raises the fundamental question of what level

of funding is adequate for OCS decision making

and management, and, related to this, what information base is adequate for decision making. On

the one hand, a large body of OCS environmental

information has been acquired in the past 10 years.

The current information base is increasingly sufficient for most pre-lease decisions in all OCS regions. This is a major reason why MMS is now

shifting the focus of environmental studies toward

research designed to answer operational questions.

Nevertheless, the stated national objective is to

increase reliance upon domestic petroleum resources, and at the same time minimize environmental disturbance. To do this properly, a significant research effort is still required—particularly

for post-lease studies and in Arctic and deepwater

areas—and research in OCS frontier areas is expensive. Adding to the expense of Arctic and deepwater studies is the fact that opportunities for conducting research are constrained by weather and

other variables.

The Federal budget is under scrutiny, and it may

be difficult to increase funding for OCS environmental studies. However, the size of the Alaskan

OCS and the amount of estimated oil and gas reserves, the frontier character of the Alaska region,

and the high costs of logistics and support operations may warrant the continued emphasis on funding for this area relative to the other OCS areas.

It is not necessary, however, to rely entirely on research funded by the ESP/OCSEAP program to

answer all important research questions. Some results from other research programs, both Arctic and

non-Arctic (e. g., the National Science Foundation’s

Arctic Research Program, MMS’s Technology

Assessment and Research Program, etc. ) may be

useful.

Emphasis

The main thrust of the ESP, until recently, has

been to gather information useful primarily for the

leasing decision itself. In 1978, the National Research Council criticized BLM’s (now MMS) inadequate program design for post-lease environmental studies. Increasing emphasis is now being

placed on post-lease management and monitoring

studies. For instance, in 1984, MMS implemented

a long-term monitoring program for the Beaufort

Sea to determine if any trends can be observed in

concentrations of heavy metals and other contaminants. Such studies are expensive and require continuous funding.

Both the MMS and NOAA are chartered to do

ocean monitoring studies. MMS is specifically

charged with monitoring the effects of OCS operations while NOAA has a more general mandate

to study long-range effects of pollution and maninduced changes of ocean ecosystems. This overlap

of responsibilities is sometimes confusing and has

fostered occasional competition between MMS and

NOAA. In this regard, the Biological Task Forces

that have been organized for the Bering and

Beaufort Seas may be able to play a larger role in

fostering coordination and cooperation among the

Federal environmental monitoring programs.

These task forces are composed of agency representatives from MMS, the Environmental Protection Agency (EPA), Fish and Wildlife Service, and

NMFS (State and local observers participate as well

in Alaska). They were created to give these agencies an opportunity to advise MMS’s Regional

Supervisor of Field Operations on the biological

aspects of the lessee’s proposed activities and to recommend appropriate actions for protecting biological resources.

Public Participation

Environmental groups are concerned that public input to the decisionmaking process has decreased since 1981. Environmentalists perceive that

less scientific information related to the oil and gas

leasing program is being disseminated, and that the

public is therefore less informed than it was immediately after the OCS Lands Act Amendments were

implemented in 1978. For example, environmentalists contend that Synthesis Reports, which are

helpful to the public in evaluating environmental

impact statements, are not available sufficiently in

advance of lease sales. DOI is attempting to respond

to the criticisms of the environmental groups with

regard to dissemination of study results. Beginning

in July, 1984, for instance, DOI began publishing

a list of offshore scientific and technical publica-
Ch. 7—Environmental Considerations • 173

tions available to the public. A list of OCSEAPsupported publications has been available since

1980, In addition, the ESP has begun a project to

make available abstracts of most prior environmental studies, and MMS now conducts annual

Information Transfer meetings to help disseminate

the results of studies. Nevertheless, funding for publication of research results has declined, and it does

take longer to get information published.

Public participation and input to the process of

determining research needs has also decreased,

according to environmental groups monitoring

DOI’s OCS program, and it has thus become more

difficult for the public to participate in framing the

research questions to be addressed by the environmental studies program. The MMS argues that

there are ample opportunities for public participation, including Scoping Meetings, which are held

at an early stage in the lease process to give citizens

a chance to express their concerns. However,

another useful forum for involving the public at an

early stage of the research planning process, the

OCSEAP Users Panel, no longer exists, and the

Regional Technical Working Group in Alaska has

been meeting less frequently.

BIOLOGICAL RESOURCES

Overview

Since the Torrey Canyon and Santa Barbara oil

spills in 1967 and 1969, the effects of oil spill accidents have been studied intensively.13 Despite this

study, there is still a great deal of controversy regarding the effects of oil in the marine environment.

A major problem in assessing the effects of pollution is that natural variation of biological populations and water quality in the ocean is very great

and poorly understood. It is difficult to detect

changes and to relate these changes to a specific

pollution event. MMS has made some attempt to

rank the OCS planning areas in terms of their potential vulnerability to spilled oil (see box).

There have been few documented effects of oil

in the water column, even from such massive spills

as Amoco Cadiz and Ixtoc I. On the other hand,

oil regularly reaches bottom sediments after a spill,

and may persist in these sediments for years. When

fresh oil reaches the bottom, effects including death

among sensitive benthic species may occur. Sublethal contamination of zooplankton and benthic

invertebrates is common. Studies have shown (e. g.,

of the Arrow spill off the coast of Nova Scotia) that

J

1 J ~hn M, ‘red ~~d Robert M. Howarth, ‘‘oi] spill Studies: A

Review of Ecological Effects, ” Environmental Management (1984),

8(1 ):27-44.

Relative Environmental Sensitivity of

the OCS Planning Areasa

Overall total

Planning area score

● . . . . . . . . . . . . . . . . 345

● ..............,,,. . 307

. . * . * . . . . . . . . . . . . . . . . . . . . . 303

Kodiak . . . . . . . . . . . . . . . . . . . . . . .

Gulf of Alaska . . . . . . . . . . . . . . . . . . . 283

St. George Basin . . . . . . . . . . . . . . . . . 278

. . . . . . . . . . . . . . . . . . . . . 278

North Aleutian Basin . . . . . . . . . . . . . 264

Cook lnlet. . . . . . . . . . . . . . . . . . . . . . . 255

Central Gulf of Mexico . . . . . . . . . . . . 253

North Atlantic . . . . . . . . . . . . . . . . . . . 245

Central California . . . . . . . . . . . . . . . . 244

Northern California . . . . . . . . . . . . . . . 234

 Hope Basin . . . . . . . . . . . . . . . 231

Southern California . . . . . . . . . . . . . . . 222

Chukchi Sea. . . . . . . . . . . . . . . . . . . . . 212

 South Atlantic . ● . . . . . ● . . . . . . . . . . . 208

Eastern Gulf of Mexic o . . . . . . . . . . .

Washington-Oregon . ● . . . 203

. . . . . . . . . . .

Mid-Atlantic. . . . . . . . . . . . . . . . . 185

Beaufort Sea . . . . . . . . . . . . . . . . 183

 Navarin Basin. . . . . . . . . . . . . . . . . . . .

Aleutian Basin . .. . . . . . . 

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174 • Oil and Gas Technologies for the Arctic and Deepwater

oil contamination can decrease the abundance of

organisms and the diversity of species of benthic

communities. However, there are striking differences in sensitivities among these species. Persistent effects have been found in soft sediments in

shallow, protected waters, where natural recovery

may take 6 to 12 years or more. Rocky headlands

are much more quickly cleansed, and generally recover within a few years, at least to the extent of

recolonization of the substrate. Where initial

recolonization is not by the normal dominant species, however, time for return to initial conditions

through succession may be much greater.

Affected Species

Fish

The commercial fish stocks of the Bering Sea and

Georges Bank are world-renowned. Important

commercial fisheries exist in most other U.S. OCS

areas as well, and subsistence fishing is important

in the Beaufort, Chukchi, and Bering Seas and the

Gulf of Alaska. In the Bering Sea, for example,

lease sales have been held or are being planned in

such productive fishing grounds as the North Aleutian Shelf, St. George Basin, and Navarin Basin.

Important commercial fish species in these areas

include: sockeye, chinook, chum, Pacific, pink, and

coho salmon; Tanner and king crabs; Pacific herring; Pacific halibut; yellowfin, flathead, and rock

sole; walleye pollack; Pacific cod; Greenland turbot; sablefish; Pacific Ocean perch; atka mackerel;

arrowtooth flounder; sidestripe, pink, and humpy

shrimp; and Alaska plaice. In addition to the

United States, Japan, the Soviet Union, South Korea and several other nations regularly fish these

waters. The 1983 ex-vessel (before processing) commercial value of the Bering Sea catch was about

$409 million dollars.

The regional effects of oil spills on most species

of fish are likely to be minor. It has been noted that:

. . . although there is a widespread public perception of impending environmental degradation and

resulting loss to harvestable populations coinciding

with possible oil spills, this does not appear to be

justified for relatively small oil spills . . . [b]ecause

most species are widely dispersed in the Bering

Sea and because stocks exhibit high annual variability in year class strengths. [E]ven the largest

estimated oil-induced mortalities from spills occurring under open-water conditions would probably

be undetectable in regional fisheries.14

However, species which spawn in nearshore areas

in relatively few locations—for example, salmon,

herring, capelin—could be particularly vulnerable

to a large spill. A large oil spill in Bristol Bay, for

instance, during a period in which salmon were

migrating to their spawning grounds could have

substantial effects on a large portion of a year class.

Kills of adult fish probably pose less of a threat to

commercial fisheries than do damage to eggs and

larvae, or changes in the ecosystem supporting the

fishery. The greatest potential effect on fish populations would probably occur if oil were spilled in

spawning or nursery areas where larvae and eggs

were abundant, or if local populations of food species of adults, juveniles, or larvae were reduced or

eliminated.

Birds

Birds are particularly susceptible to the effects

of oil spills and human interference. Depending on

the time of year, large numbers may be present in

Arctic areas. For example, at least six million

marine birds breed on the Pribilof Islands and on

St. Matthew and St. Lawrence Islands adjacent to

the Navarin Basin.

Birds most vulnerable to oiling are those which

are gregarious, spend much of their time on the

surface, and dive rather than fly when disturbed.

These include murres, puffins, and diving ducks

such as eiders, scoters, and oldsquaws. Oiling of

plumage may cause death from hypothermia,

shock, or drowning. In addition, death of embryos

may result from the transfer of oil on feathers to

eggs. The physiological stress accompanying migration may reduce birds’ ability to survive the additional stress resulting from oiling. Oil ingestion

through preening could possibly reduce reproduction in some birds and causes various pathological

conditions.

l+ Fredrik V. Thorsteinson and Lyman K. Thorsteinson, ‘‘Fishery

Resources, ‘‘ in Lyman K. Thorsteinson, Ed., Proceedings ofa Synthesis Meeting: The North Aleutian Shelf Environment and Possible

Consequences of Offshore Oil and Gas Development (Juneau, Alaska:

Outer Continental Shelf Environment Assessment Program, March

1984), p. 153.
Ch. 7—Environmental Considerations • 175

Oil spills occurring near colonies or along migration corridors could have substantial effects on

seabirds and waterfowl. Oil reaching coastal wetlands could persist for a long period of time, and

large numbers of birds could be contaminated. The

MMS estimates, for instance, that important regional seabird populations on St. Matthew and adjacent islands could sustain major losses if spills occur in the area during the breeding season. MMS

estimates that seabirds and waterfowl wintering in

the Navarin Basin lease area may sustain losses of

10,000 or more birds in each of the several spills

projected over the life of the field.15 A tanker spill

in Unimak Pass, one of the major migration corridors for bird and mammal populations entering

and leaving the Bering Sea, could be particularly

serious, since oil could potentially affect major portions of regional populations of both birds and

marine mammals. However, long-term population

responses of sea-birds to oil-induced mortalities are

uncertain due to incomplete data. For example,

Great Britain’s seabird populations appear to be

increasing in spite of incremental mortalities induced by OCS oil and gas operations in the North

Sea. 16

Marine Mammals

Impacts of potential oil spills on marine mammals have received considerable attention. Effects

could include coating of animals with oil, ingestion

of oil, and irritation of eyes. Contact with oil may

also contribute to or alter susceptibility to existing

physiological and/or behavioral stresses. However,

‘‘unequivocal evidence for mortality of marine

mammals caused by oiling in the wild has not been

observed.” 17 The potential for adverse effects on

most marine mammals from large and small oil

spills is perceived to be low. Adverse effects in the

immediate vicinity of a spill would be unavoidable,

but, given the mobility and widespread distribution of most species, the low occurrence rate of large

spills, the relatively small areas affected by spills,

fs M i~~r~s Management service, Navarin Basin Lease Offering:

Final Ent’ironmentaf Impact Statement (November 1983).

16 Laurie jamela, Lyman ThOrsteinsOn, and Mauri pelto, ‘ ‘Oil and

Gas Development and Related Issues, ” in Laurie Jarvela, Ed., The

Nat’arin Basin Environment and Possible Consequences of Planned

Offshore Oil and Gas Development (Juneau, Alaska: Outer Continental Shelf Environmental Assessment Program, May 1984).

1 TM inera]s Management service, Navarin Basin Lease Offering:

Final En\’ironmental Impact Statement (November 1983), p. IV-37.

and the rapid dispersion and dilution of small spills,

significant population losses of most species are

unlikely.

Some species are probably more vulnerable than

others, and some species may be particularly vulnerable at certain times of the year or while occupying certain habitats. Research to date suggests

that the animals most at risk are those vulnerable

to oiling of fur, such as furred seals, sea otters, and

polar bears. A number of endangered and threatened species occur in prospective OCS development

areas. Other cetaceans inhabiting subarctic seas

during all or part of the year include right, fin, sei,

blue, humpback, gray, and sperm whales. Some

of these whales (for example, gray whales) migrate

considerable distances, and may potentially come

in contact with oil in several OCS regions.

Several examples of areas where marine mammals would be particularly vulnerable include:

St. Matthew Island. In addition to large seasonal

concentrations of nesting birds, St. Matthew Island

(and nearby Hall Island), is the location of numerous haulout sites for Stellar sea lions, spotted seals,

and walruses. Several species of endangered whales

also inhabit the vicinity. A support facility for

Navarin Basin exploration and development has

been proposed for this Bering Sea island; however,

recent court action denied the facility. In addition

to the possible impact of oil spills, marine mammals and birds in the area may be exposed to frePhoto credit: American Petroleum Institute

Offshore energy production must be balanced with

protection of seals and other wildlife
176 ● Oil and Gas Technologies for the Arctic and Deepwater

quent vessel movements, helicopter flights, and construction activities.

The Prihilof Islands. In addition to their importance to nesting birds, from May through August

the Pribilof Islands are home to over 70 percent of

the world’s population of northern fur seals, which

breed and bear their pups there. Fur seals may be

particularly sensitive to oiling since they rely on

their fur for thermal protection, and oil can destroy

its insulative properties. Oil spill trajectory models

indicate that a St. George Basin spill could possibly reach the Pribilof Islands.18

Unimak Pass. Unimak Pass through the Aleutian Islands is a major migration corridor for endangered gray, fin, and humpback whales, northern fur seals, and several species of birds (e. g.,

shearwaters and tufted puffins). Although it is predicted that strong currents would likely rapidly wash

away spilled oil, a spill large enough to significantly

oil the pass in early spring or late fall could expose

great numbers of whales, birds, and fur seals to

hydrocarbons, and could seriously impact regional

populations. In the event of oil and gas discoveries

in the Bering Sea, increased vessel traffic (including

tankers) is expected through the Pass.

Bowhead Whales: A Case Study

Introduction

Bowhead whales are listed as an endangered species and could be adversely affected by offshore oil

and gas operations in the Arctic. The degree of their

vulnerability remains uncertain at this time; however, bowheads are a subject of concern and the

target of several expensive research projects. As a

consequence of their endangered status, the Endangered Species Act places specific legal constraints on all Federal agency activity affecting the

species. Thus, the potential impacts of offshore oil

and gas activities on the bowhead population must

be considered fully. If these activities are found to

jeopardize the continued existence of bowheads or

other endangered species, the law requires that actions be taken to ensure their preservation. Actions

] 8H, w. Braham et. al. , ‘‘Marine Mammals, ‘‘ in M. J. Hameedi,

Ed., Proceedings of a Synthesis Meeting: The St. George Basin Environment and Possible Consequences of Planned Offshore Oil and Gas

llevek~prnent (Juneau, Alaska: Outer Continental Shelf Environmental

Assessment Program, March 1982).

to protect bowhead whales could take the form of

restrictions on or curtailment of Arctic oil and gas

development. Thus, the potential for conflict exists between the competing national objectives of

energy production and the preservation of an endangered species.

Bowhead whales are also highly prized by the indigenous people of the Arctic (the Inuit) as a supplementary source of food and as a part of their

cultural heritage. Activities which threaten bowhead

whales are considered by the Inuit to be a threat

to their culture and their subsistence lifestyle. At

the same time, the annual bowhead harvest by Inuit whalers may also be a threat to the existence

of the species. The national effort to protect endangered marine mammals competes, to some degree, with the local interest in Arctic subsistence

hunting. Protection of bowhead whales is thus complicated by competing national interests in the production of domestic energy and the desire to protect endangered species as well as by the interests

of Native Alaskans to pursue their traditional

lifestyle. The debate surrounding the bowhead

whale involves complex scientific, political, and

socioeconomic issues for which there are no totally

satisfying answers.

Compared to a pre-exploitation whaling stock

(estimated by the International Whaling Commission to be approximately 20,000 animals during the

1800s), the minimum population is now believed

to be about 3,900, Census taking has improved in

recent years, so that this number is larger than the

number of whales believed to exist in 1977 (between

800 and 1,200 animals), but the figure is still imprecise. For hundreds of years, until about the turn

of the century, bowheads were one of the most important commercial whale species. Commercial exploitation of bowheads has ceased, but whaling in

several coastal Arctic native communities is still an

important cultural activity.

Bowhead whales winter in the Bering Sea, generally south and west of St. Lawrence Island (the

full extent of the area they use is unknown). In

March and April they begin their northward migration, using the lead systems that develop in the ice

cover. The whales follow nearshore open leads past

Point Hope, Cape Lisburne, and Point Barrow and

then move further offshore en route to their summer range in the eastern Beaufort Sea off Canada.
Ch. 7—Environmental Considerations . 177

After about mid-September the whales begin their

return migration to the Bering Sea. The migration

corridor is bounded on its landward side by approximately the 20-meter isobath and extends on its

seaward side to at least the 50-meter isobath. It is

during the migration periods when the whales are

closest to the coast that they are hunted by Inuit

(Eskimo) whalers and, at the same time, may be

most vulnerable to potential disturbance by the

activities of the oil and gas industry.

Concerned Groups

Among the groups with a stake in the future of

the bowhead whale are the indigenous people of the

Arctic (the Inuit Eskimos of Alaska), environmentalists, industry, the Federal Government, and the

State of Alaska.

Inuit. For the Inuit, the bowhead whale is an important element of cultural identity. Despite the

ongoing changes occuring in Alaska whaling

villages, many traditional activities remain important, and the annual hunting cycle remains essentially the same as practiced for generations. Currently, ten Inuit villages participate in bowhead

hunting. Eight of these ten villages take part in the

spring hunt, and three participate in the fall hunt.

Barrow, given its strategic location, is the only

village to participate in both hunting seasons.

A recent survey indicates that most Inuit continue to value hunting and fishing highly and to

view these activities as an important source of

food. 19 Data from the same survey also suggest that

Inuit still prefer locally harvested foods (especially

whale meat, although seal and walrus are probably

consumed in greater quantity) despite the influence

of western culture. Inuit maintain that the ‘Eskimo

way of life’ would be severely jeopardized if they

could no longer hunt bowhead whales. In addition

to the food that the whales provide (which is shared

among the members of the community), a successful hunt is an occasion for celebration, a symbol of initiation into manhood, and brings prestige

to successful whalers.

Inuit are concerned about potential adverse impacts that offshore oil and gas activities could have

1 gAlaska Consultants, inc. , Subsistence Study of Alaska Eskimo

Whaling Villages report prepared for the U.S. Department of the Interior (’January 1984).

Photo credit: National Marine Fisheries Service

The endangered bowhead whale is important to the

Inuit culture

on bowhead whales. They are concerned about

maintaining a pollution-free marine environment,

about protecting bowhead feeding and nursery

areas, and about preventing seismic survey and

other noise-making activities that may interfere with

the annual hunt or with the health of the species.

Increasing industrial activity in the Arctic highlights

the fact that whale hunting now must compete with

national, and even international, interests. These

concerns have stimulated an active Inuit-sponsored

research program to learn more about the factors

which affect bowhead whales. This research focuses

on bowhead population dynamics (size and growth

rates) and on the possible susceptibility to disturbance from various industrial activities.

Environmentalists. The primary concern of enviromentalists is for the protection and stewardship

of an endangered species and its marine habitat.

Environmentalists are particularly concerned that

the projected increase in offshore oil and gas activities may be detrimental to the bowhead whale population. Offshore exploration and development introduces increased levels of industrial noise into the

marine environment and raises the potential for

marine oil pollution, both of which may be harmful to whales. Environmentalists assert that the effects of noise (particularly noise generated by

marine seismic exploration) and of oil pollution on

bowhead whales should be fully studied, and that

steps should be taken to reduce impacts as much

as possible.
178 ● Oil and Gas Technologies for the Arctic and Deepwater

Most environmental groups are not enthusiastic

about subsistence whaling, but tend to view it as

a legitimate activity so long as vigilant oversight

of bowhead stocks is maintained and traditional

methods are used. A few groups have advocated

the complete prohibition of native whaling of endangered whales. These groups contend that the

result is the same whether the whale is taken by

commercial whalers or native whalers. If the species is endangered, they reason, no whaling should

be allowed.

Between 1970 and 1977, there was about a threefold increase in the bowhead whale harvest. In

1977, the International Whaling Commission noted

this trend with alarm, and established a quota for

native whalers which has been in effect since the

1978 harvests, reducing the hunt to approximate

historic levels. This quota system is considered an

important management tool by environmentalists

and by the Federal Government.

Industry. The oil and gas industry acknowledges

that under certain circumstances bowhead whales

do respond to offshore hydrocarbon activities, but

does not believe that normal operational activities

constitute a major problem for the health of the

whale stock. Even if some limited, localized, shortterm impacts (e. g., flight response to nearby seismic

activities) are unavoidable, the industry does not

believe that long-term effects from oil and gas activities will be significant.

Seasonal drilling restrictions have been imposed

and protective buffer zones established to mitigate

the possible adverse impacts to bowhead whales.

Industry’s consistent opposition to these costly

restrictions that reduce operating efficiency is based

on their belief that they are not warranted by the

scientific evidence. However, industry wishes to

avoid unnecessary interruptions in its long-term

operations, and has therefore participated in some

bowhead research projects (for instance, by dedicating geophysical ship time to assess seismic impacts on bowhead whales).

The industry is convinced that, given current

technology and personnel training, the possibility

of a major blowout in the Arctic is remote, and that

even if such an accident were to occur, the capability to recover most spilled oil and thus to avoid

harm to whales, is adequate. Since the first stipulations attached to the 1979 joint Federal/State lease

sale in the Beaufort Sea, lease stipulations inside

the barrier islands have become less stringent. However, industry is still unhappy with seasonal drilling

restrictions.

The Federal Government. The Federal Government is responsible for promoting OCS development, protecting endangered species, and ensuring that Native interests are considered. The desire

to stimulate domestic petroleum production was the

primary reason for the Administration’s decision

to accelerate leasing of OCS lands. In addition, the

sale of leases for OCS energy exploitation is the

second-ranked source of Federal revenues, and

OCS resources are seen as insurance against potential international energy supply disruptions.

Federal development and protection objectives

are potentially in conflict, particularly since leasing is now taking place at a faster pace in Alaskan

offshore areas. However, several Federal laws provide for the protection and management of bowhead whales. The Endangered Species Act of 1973

prohibits the taking, harassing, importing, exporting, or interstate trading of any endangered species, their parts or products. However, the take by

Alaska natives is exempted. The Marine Mammal

Protection Act of 1972 protects all marine mammals from any undue influence or exploitation by

U.S. nationals and forbids importation of any

marine mammal products into the country. ‘‘Subsistence’ hunting is permitted as long as the stocks

can support the harvest, and specific conditions are

met.

The Endangered Species Act specifies that it is

the responsibility of all Federal agencies to conserve

endangered species. Each Federal agency is required to ensure, in consultation with the Fish and

Wildlife Service or the NMFS (as appropriate, for

species under their respective jurisdictions), that

any action it authorizes, funds, or conducts is not

likely to jeopardize the continued existence of an

endangered or threatened species or result in the

adverse modification of its critical habitat. Thus,

MMS must consult with the NMFS on the probable impacts to bowhead whales that might result

from many OCS activities for which it issues permits. NMFS then issues a biological opinion concerning the likelihood that these impacts will jeop-
Ch. 7—Environmental Considerations • 179

ardize the survival of the species. If so, NMFS also

describes ‘‘reasonable and prudent alternatives’

to the activity that would avoid jeopardy.

In practice, NMFS also includes in its biological opinions recommendations and suggestions that

it feels would help conserve the species, although

the Act does not require that they be included.

MMS is not legally required to adopt these recommendations, suggestions or alternatives to avoid

jeopardy so long as the mitigating measures it does

adopt are consistent with the alternatives, would

effectively preclude jeopardy, and satisfy the intent

of the law.

Some dispute the right of the MMS not to accept all parts of biological opinions. DOI's ‘veto

power’ has been criticized by those who contend

that NMFS recommendations should be binding.

However, biological opinions carry weight in the

courts, so DOI must have good reasons for not implementing every NMFS recommendation or risk

being litigated. The biological opinion process has

evolved over the years, and NMFS recommendations for avoiding jeopardy to the species are less

specific than they once were.

In 1981, the NOAA and the Alaska Eskimo

Whaling Commission signed a cooperative agreement to implement the limited bowhead quota

allowed by the International Whaling Commission

(IWC). For calendar years 1981, 1982, and 1983,

a quota was established by the IWC for the Bering/Beaufort/Chukchi Sea stock of 45 bowheads

landed and 65 struck, with a maximum of 17 to

be landed in any one year.20 (65 whales were struck,

and, of these, 34 were landed). For 1984 and 1985,

43 strikes have been allowed (0.55 percent of the

estimated population per year), but no more than

27 can be made in either year. The agreement

specifies whaling techniques, monitoring procedures, and division of responsibilities.

Alaska. The State must consider the welfare of

its citizens, and, in this particular case, the welfare of those engaged in native whaling. Similarly,

the State is concerned with environmental protection. Moreover, since the State derives a major proportion of its revenues from the oil and gas indusZowl]]iam F. Gu5ey, ~ow~ea~ (Houston, Texas: Shell Oil Company, June 1983), p. 87.

try (although none at the present time from Federal

OCS leases), it has a major stake in fostering responsible oil and gas development. These interests

may be conflicting if oil spills or industrial noise

associated with development adversely affect the

environment or Native hunting.

The State believes that further research should

be undertaken. The State also is concerned about

the capability of industry to clean up oil spills and

about the effects of such spills on bowhead whales.

For these reasons, in responding to the Draft Environmental Impact Statement for the 1984 Diapir

Field Sale No. 87, the State of Alaska recommended

that sensitive blocks in the eastern and western parts

of the sale area be deleted and that all proposed

stipulations in the DEIS be adopted. In general,

the State believes that mitigating measures are

preferable to tract deletions if adequate scientific

information is available or if existing technological capabilities are adequate; however, it was not

felt at that time that these concerns had been adequately studied.

More recently, the State’s position regarding

bowhead whales was addressed in its decision to

allow exploratory drilling in the Beaufort Sea where

the capability to clean up oil spills in broken ice

can be demonstrated. However, in reaching its

decision to allow longer drilling periods in certain

circumstances, the State reviewed existing bowhead

whale and related knowledge and concluded that:

1) the likelihood of a large oil spill from exploratory

drilling was small; 2) the probability that migrating

bowhead whales would encounter spilled oil was

also small; 3) oil spill countermeasures for combating spills from artificial islands are now adequate; and 4) prohibition of exploratory drilling and

other downhole activity during whale migrations

is an adequate measure to ensure that bowheads

are not unduly disturbed by industrial noise. The

State recognizes that information gaps still exist and

that its decision was based on a large amount of

probabilistic data, but it is satisfied that exploratory

activities in nearshore areas can be conducted without significant impacts on bowhead whales.

Potential Impacts

The June 1984 Diapir Field Final Environmental

Impact Statement for Sale No. 87 and accompanying comments on the Draft Environmental Im-
180 . Oil and Gas Technologies for the Arctic and Deepwater

pact Statement provide an overview of the current

state of knowledge concerning the impacts of oil and

gas development on the bowhead whale.

Noise. Bowheads may react to noise associated

with offshore activities. The ocean is naturally noisy

owing to sounds created by rain, wind, ice, and

the animals themselves. However, noise pollution

has been of concern in recent years because some

marine mammal species seem to rely heavily upon

sound for communications with one another and

for acquiring information about their surroundings.

Since many offshore industrial activities create intense sounds, there has been concern that such

sounds may disturb marine mammals and also

mask the ‘‘natural’ sounds that are apparently important to these mammals. In evaluating the potential effects of noise from industrial operations,

it is important to consider ambient noise levels, the

characteristics of noise from industry sources and

from marine mammals, the propagation of sound

in water, hearing by marine mammals, the ‘ ‘zone

of influence’ of noise from industry sources, and

documented reactions of marine mammals to industrial noise.21

Sound can be generated by passing boats and

ships, by open-water geophysical seismic exploration, and by on-ice activities or onshore installations. The intermittent sound generated by seismic

surveys is the most intense type of sound. Shortterm behavioral reactions to seismic activity and

vessels may include flight from the area, changes

in surfacing and dive times, and temporary changes

in direction. However, responses of bowheads to

seismic activity have been much less clear-cut than

responses of bowheads to moving vessels.

Evidence demonstrates that bowheads react to

low-flying aircraft by diving suddenly and thus are

sensitive to aircraft disturbance. Other sources of

noise include drilling activities and dredging and

gravel island construction, none of which is expected to be as disturbing to whales as vessel noise.

Adding the small effects of all these noise disturbances together, MMS has concluded that during

the spring and fall migratory period, noise from

seismic activity on leased tracts or from vessels or

“W. J. Richardson et. al., Effects of Offshore Petroleum Operations on Cold Water Marine Mammals (American Petroleum Institute, October 1983).

aircraft could have moderate impacts on bowheads.

That is, a portion of the regional population could

change in abundance and/or distribution over more

than one generation, but is unlikely to affect the

regional population. The North Slope Borough and

many environmental groups disagree with this overall conclusion, and believe that MMS has tended

to downplay evidence suggesting greater effects.

Oil pollution. Few observations of the responses

of bowhead and other whales to oil spills have been

made. It is unknown whether or not large cetaceans

are able to detect hydrocarbon pollution. Dolphins,

however, have shown an ability to detect and avoid

oil. The rough nature of bowhead whale skin suggests that bowheads maybe more vulnerable to affects of surface contact with oil than most cetaceans.

Concern has also been expressed that bowhead skin

and eyes may be sensitive to oil contact, but it is

unknown whether contact would be harmful. Inhalation of toxic substances and plugging of blowholes by oil have also been cited as possible, but

unlikely, threats.

The potential effect of oil on bowhead feeding

is another type of adverse impact. Bowheads may

not be able to differentiate between hydrocarboncontaminated and uncontaminated food. If the

baleen plates of bowhead whales become fouled by

oil, feeding efficiency is decreased, although recent

experiments have shown only minor and short-lived

reductions in efficiency. Indirectly, bowheads may

be adversely affected if food sources are reduced

by acute or chronic hydrocarbon pollution, but such

pollution would have to be very widespread in order to have a serious effect.

The impact of an oil spill on the bowhead whale

population would vary depending upon the volume

of oil spilled, the amount of oil in the water column, the extent of weathering of the oil, the proportions of habitat affected, the numbers of whales

present, and other factors. The MMS considers the

probability that oil from an accidental spill will

come in contact with whales in the offshore leads

to be very low, particularly “since whales are not

present in the lease offerings at all times, and if certain tracts are deleted from lease consideration. ’22

ZZMiner~s Management &rvice, Diapir Field Lease Offering: Find

En\’ironmental Impact Statement (March 1984), p, IV-1OO.
Ch. 7—Environmental Considerations . 181

MMS concedes that localized effects of spills could

occur, but believes that the probable degree of regional impact from oilspills within the lease area

will be minor. Other groups believe the impact

could be severe in the case of a major oil spill, and

the NMFS, as noted above, has concluded that an

uncontrolled blowout or major oil spill could jeopardize the continued existence of the species if

whales are present and encounter spilled oil.

In the Final Environmental Impact Statement

for the August 1984 Diapir Field lease sale, MMS

concluded that the overall regional impact of the

combined effects of noise and oilspills resulting from

the original proposal was not expected to exceed

‘‘moderate. Moreover, if sensitive tracts in the

western and eastern portions of the Diapir Field

sale area were deleted, the combined potential

adverse effects on bowhead whales were expected

by MMS to be minor. Both the State of Alaska and

the North Slope Borough supported these tract deletions in order to reduce potential disturbances to

the whales in the spring ice lead system and during the fall migration offshore of Point Barrow. As

a result, a 20-mile buffer zone was established

around Barrow, where the Inuit conduct their hunt;

and, although no tracts were deleted in the eastern Beaufort Sea, a study has been initiated to determine whether this area is an important habitat

where oil and gas exploitation should be restricted.

Borough residents believe this is a major improvement over the original lease plan. 23

While the MMS bases its conclusions on the best

available information, there are still gaps in knowledge about bowhead whales. Hence, despite the fact

that bowhead whales have been one of the most

studied of the endangered species, there is still

disagreement concerning the probable effects of oil,

noise, and other aspects of human intervention on

the behavior, survival, and reproduction of individuals and populations.24

23’ ‘Plans for Oil Leases Would Protect Whales, The New York

Times (August 5, 1984), p. 27.

Z4L, Lee Eberhardt and R. J. Hofman, ‘‘Existing Programs, Technology, and Requirements Relati~.e to the Conservation and Protection of Marine Mammals in the U, S. Fishery Conservation Zone

and in the Southern Ocean, in Technology and Oceanography,

(Washington, DC: Office of Technology Assessment, 1981).

Research Priorities

Four general areas for future research appear to

be especially important.

Population studies. There is a continuing need

for more precise information about the status of the

bowhead whale population. Shore-based censuses,

aerial surveys, and/or acoustical detection methods have been employed in bowhead whale population studies for about 8 years, yet scientists still

have not satisfactorily defined population parameters. Reliable information is needed about the current and the historic distribution, abundance, and

productivity of the population. Currently, it is

believed that calves account for at least 7 percent

of the population, and that the distribution among

age classes is about normal. However, it is not yet

known whether the bowhead population is growing, stabilized, or decreasing or what the natural

mortality rate is. Such information is important in

order to determine population status and trends to

aid in conserving the species. It is also important

to facilitate setting quotas for Native whalers. Thus,

if the yearly increment in the bowhead population

can be accurately determined, it will be possible

to allocate, with a much larger degree of confidence,

a portion (e. g., one-half) of this increment to native

hunters.

One hypothesis that has been put forth recently

is that the Beaufort Sea bowhead whale population

may be a distinct sub-population or feeding group.

While feeding groups in the Chukchi and Bering

Seas have been decimated, the Beaufort Sea stock

may, in fact, be healthy and possibly as numerous

as before commercial whaling began. This hypothesis will be difficult to test; however, historical data

make it clear that large numbers of bowheads once

existed in the Bering and Chukchi Seas in June,

July and August. Thus, of an original western Arctic bowhead population of perhaps 20,000 animals,

it has been suggested that only one-quarter to onethird of these animals comprised the Beaufort Sea

sub-population. Since there are now known to be

a minimum of 3,900 bowhead whales, the present

stock may be very near historical levels. Thus, as

a corollary of this hypothesis, until the Bering and

Chukchi stocks can be repopulated, one cannot expect the bowhead population to recover, because

it involves distinct sub-populations. If this hypo-
182 ● Oil and Gas Technologies for the Arctic and Deepwater

thesis can be proven, rethinking of bowhead whale

stock management would be in order.

Effects of noise. Better understanding of these

effects will aid in establishing appropriate ‘‘zones

of influence, thereby enabling better protection

of the whales from noise associated with industrial

activities. If one knows the noise levels of an industrial activity and the propagation characteristics of the surrounding waters, then it is possible

to determine how far the sound travels and its level

of impact at various distances from the source. It

is much more difficult to determine the effect of

noise on the whale, in large part because it is difficult to control all aspects of experiments. Results

from the most recent study have shown that whales

do not exhibit avoidance behavior beyond four

miles from seismic activities, and that behavioral

changes between about 2 and 4 miles are only temporary. 25 Although the presence of whales in the

vicinity of industrial activities in the Canadian

Beaufort has declined since 1980, evidence proving a cause and effect relationship between industrial activities and the decline has not been established. Canadian efforts to address this question are

currently underway.

If bowhead whales have a threshold level above

which noise causes detrimental effects, then a zone

of influence—generally delimited by a circle—can

be calculated. The zone delimits the area within

which activities (e. g., seismic activity) may be restricted when whales are present. Several zones may

be postulated, the size of which vary according to

the level of sound and/or the degree of disturbance;

however, with currently available information,

determining zones of influence may be a theoretical exercise. MMS has established a 5-mile zone

of influence, pending receipt of new data. The

NMFS concurs with this decision. Both agencies

feel that more information is necessary, however,

and MMS has established an experimental program

with cooperating oil and geophysical exploration

companies to obtain more data concerning whale

reactions to seismic activities.

Cumulative effects of industrial activities. Such

effects are extremely difficult to assess, particularly

in the absence of development. However, it is imZsMiner~S Mmagernent service, “Observations on the Behavior

of Bowhead Whales in the Presence of Operating Seismic Exploration Vessels in the Alaskan Beaufort Sea” (Technical Report, 1985).

portant to know whether whales are likely to permanently vacate oil and gas development areas or

whether they might, in fact, become accustomed

to development activities as seems to be the case

with gray whales in Southern California. In addition, as offshore Arctic development increases,

whales are likely to encounter more industrial activity. Thus, it is possible that noise and pollution effects, which, in isolation, may not be detrimental,

may have a cumulative impact as whales encounter

these effects along their migratory route.

Identification of sensitive habitats, including primary feeding areas and nursery areas within U.S.

and Canadian waters. Migrating bowheads in

spring do not feed extensively. However, there is

new, but as yet unsubstantiated evidence that the

area between Barter Island and the Canadian border is an important habitat area where bowhead

whales feed on their westward fall migration. Concern has been expressed by the North Slope Borough and other groups that seismic and oil activities in this area may adversely affect bowhead

feeding at a critical time and, hence, that the

bowhead population may be affected. Scientists

would like to be able to correlate the distribution

of organisms in these areas with whale feeding

habits. In 1985, MMS plans to study the importance of the area east of Barter Island to bowhead

whale feeding. Better knowledge of feeding areas

will aid understanding of migratory patterns and

in conservation of the whale’s ecosystem.

Some specific tasks have been identified by the

Interorganization Bowhead Whale Research Planning and Technical Coordination Group.26 The

group agreed that the highest priority short-term

(1983) research needs included:

●

●

●

Continuation of studies of recruitment using

photography.

Completion of the evaluation of the sources

of bias in census taking and improvement of

the accuracy of the census count (at Point

Barrow).

Study of the distribution of bowheads in summer to facilitate estimating total abundance

and migratory behavior.

zbNation~ Marine Fisheries Service, ‘‘Report of the Second Interorganization Bowhead Whale Research Planning and Technical

Coordination Meeting” (Washington, DC: NOAA Technical Memorandum, April 1983).
Ch. 7—Environmental Considerations Ž 183

●

●

●

Identification and evaluation of possible

feeding areas in the Beaufort Sea in summer

and autumn.

Determination of the effects of seismic operations (through a boat-whale interaction study).

Initiation of a review of the state-of-the-art of

bowhead knowledge.

This last task is important because there has been

a rapid accumulation of information in the past few

years, but a much slower rate of synthesis. Moreover, it could be a very useful exercise in order to

reach a scientific consensus on the key issues. Other

important but less pressing studies were also identified by the group.

Current Research

Research on bowhead whales is conducted by

several organizations, but primarily MMS. MMS

is conducting surveys to detect when whales are

present in areas where they could be disturbed by

seismic activities. They are also doing basic

behavior and perturbation studies, and, in the Bering Sea, distribution and abundance studies. Since

1980, MMS has funded four studies related totally

or in part to the effects of noise on endangered

whales. The funding for these studies through 1983

was about $4.3 million.

NMFS is responsible for the management of

bowhead whales. The National Marine Mammal

Laboratory in Seattle, Washington, is involved in

bowhead whale research. NMFS research focuses

on understanding the life history and population

dynamics of bowhead whales. During the spring

migrations, bowheads are counted from ice camps,

and during the summer photo-identification surveys are conducted.

The North Slope Borough and Alaska Eskimo

Whaling Commission receive much of their research funds from the Alaska Legislature. Their research focuses on biological studies of animals taken

in harvest. They have also conducted population

counts of bowheads as they move north in the

spring. Recently, hydrophones have been used at

the counting stations to try to account for the whales

which pass beyond the view of visual counters or

travel when the leads are closed. The North Slope

Borough has organized and convened several

bowhead whale symposia.

The oil industry also has contributed to the

bowhead whale research effort. Particularly valuable was the large research effort undertaken in

1981 which led to the discovery of a better means

to estimate the rate of calf production.

In comparison to the funds spent on other endangered species, a large proportion of available

money has been spent on bowhead research. In

large part, this is due to expensive logistical requirements, and to the necessity of using ships and airplanes. Despite the large sums of money that have

been spent, most scientists are reluctant to make

unqualified statements concerning bowhead whale

population, reproduction, or the effects of noise and

oil contamination.

The reasons for large bowhead whale research

budgets are at least in part political. Native Alaskans hope that research results will help them both

to justify a continued, if not expanded, whale hunt

and to protect the health of the species. The oil industry hopes that research results may lead to less

restrictive stipulations, and the Federal Government must try to balance competing national and

international objectives. In addition, the special

status of bowhead whale research stems in part from

the legal mandate granted by the 1973 Endangered

Species Act and the 1972 Marine Mammal Protection Act.

Operational Restrictions

MMS can mitigate potential adverse impacts that

oil and gas activities may have on bowheads by

deleting tracts or by specifying lease stipulations

and conditions in operating permits, some of which

NMFS suggests in its biological opinion. These may

take the form of drilling restrictions during migration or broken ice periods, restrictions on seismic

activities when whales are within the vicinity (e. g.,

within a 5-mile zone of influence), and/or directions to vessel operators on how to comport themselves in the presence of whales. For instance, in

the 1979 Federal/State Beaufort Sea Lease Sale the

recommendations of scientists were followed and

a 7-month seasonal drilling closure effective for 2

years was proclaimed. In the 1982 Diapir Field lease

sale, drilling restrictions were reduced so as to apply

only to specified tracts and only during the 2-month

fall whale migration. Moreover, MMS did not

38-749 0 - 85 - 7
184 ● Oil and Gas Technologies for the Arctic and Deepwater

adopt NMFS’s recommendations in its biological

opinion calling for drilling restriction periods to be

extended so as to ensure that areas occupied by

migrating whales are free of oil by the time the

whales arrive. MMS did not believe that the low

level of risk of a major oil blowout or spill during

exploration justified such a precaution. In the 1984

sale, drilling and other downhole activity has been

restricted in the periods of April 15 through June

15 and September 1 through October 31 in the

western blocks and between August 1 and October

31 in the eastern blocks,

MMS may also publish a “notice to lesees and

operators. This is advisory and applies to those

activities which take place after the lease sale but

before development or production plans are submitted. For instance, MMS may advise lessees to

use aircraft to ensure that no bowhead whales are

within 5 miles of seismic operations.

The findings of bowhead whale researchers have

influenced Federal OCS lease decisions and stipulations in the past. Differences of opinion exist, however, concerning whether science or political considerations are more important in determining

mitigating measures. Some scientists have suggested that “political issues and [especially] the desire to accelerate development on the OCS predominated over scientific considerations in the

[1982] sale. ”27 For instance, bowhead whale migration data were collected between 1979 and 1982,

but, in the view of these scientists, the new data

did not justify relaxing the seasonal drilling restriction. Conversely, much more data were available

by 1982—it was clear by then, for instance, that

the spring migration takes places well offshore and

that the fall migration corridor lies in water from

20 to 50 meters deep—and restrictions were reduced in light of this new information.

27JaCqUeline G’ebrneie’, “The Role of Science in the Alaskan Outer

Continental Shelf Oil and Gas Leasing Decision Process’ (Master’s

Thesis, Institute for Marine Studies, University of Washington, August

1983).

Stipulations currently in place to mitigate impacts

on bowhead whales are operational in nature, i.e.,

they affect operating procedures. Alternatively, one

might consider stipulations requiring the design of

offshore structures and ships aimed at reducing industrial noise to an acceptable level. Rather than

being required to curtail activities in the presence

of whales, industry could be offered an opportunity

to design, for example, quieter ships. This regulatory approach is favored by some environmentalists, but they admit that far too little information

is currently available for designing appropriately

quiet technology, particularly given the lack of

knowledge on the effects of noise on marine mammals. Moreover, designation of this type of stipulation would probably be beyond the current authority of the MMS. However, if such design

regulations proved to be less costly to the oil industry than operating restrictions, industry may be

receptive.

Current policies regarding protection of bowhead

whales from the impacts of oil and gas activities and

native whaling include limited and closely controlled Inuit hunting, stipulations controlling

drilling and other activities during specified periods, and continuation of relevant scientific research.

The aim of these policies has been to balance competing national interests. However, differences of

opinion persist concerning their adequacy. Both the

North Slope Borough and the environmentalists

have pushed for greater bowhead whale protection,

while the oil and gas industry believes drilling

restrictions to be unwarranted based on the information available concerning whale migrations and

on the safety record of OCS operations. Some

alteration and/or finetuning of existing policies

(e.g., alteration of whale quotas, changes in the radius of the zone of influence, or further tract deletions) may be necessary, depending upon the results of further scientific research. However, no

significant changes of policy are likely to be necessary in the near term.
Ch. 7—Environmental Considerations . 185

OIL SPILLS

Introduction

As the U.S. oil and gas industry begins exploration of deepwater and Arctic OCS areas, questions

are being raised concerning the effectiveness of techniques and equipment for combatting oil spills in

frontier areas. Industry argues that it is prepared

for the possibility of spills in both Arctic and deepwater areas, and that the risk of catastrophic spills

is very low. Although the petroleum industry has

not had a drilling or production-related oil spill in

U.S. waters as large as the Santa Barbara blowout

since 1969, major spills in other parts of the world

(for example the 1979 Ixtoc 1 blowout in the Gulf

of Mexico) and a number of sizeable tanker casualties have heightened the public’s awareness of the

risks and consequences of oil spills.

The offshore oil and gas industry has a good oil

spill prevention record. However, the industry has

little experience producing oil in Arctic and deepwater frontier areas. With the exception of Canadian and North Sea operations and Cook Inlet operations in State waters in Southern Alaska, the

industry’s offshore operating experience and oil spill

data are derived largely from operations in temperate regions, such as the Gulf of Mexico and California. Notwithstanding the oil and gas industry’s

plans and preparations for oil spills, it is still uncertain whether the industry will be able to make

effective use of currently available equipment and

countermeasure strategies to recover significant

amounts of spilled oil in frontier areas. Although

industry has equipment on hand and can airlift additional equipment to a spill site if necessary, this

equipment has never been proven under realistic,

at-sea conditions.

Most oil spill containment and cleanup technology has been developed for nearshore and temperate regions and may be unsuitable for Arctic or

deepwater areas. Arctic oil spill countermeasures

may be complicated by extremely cold temperatures, the presence of ice, long periods of darkness,

intense storms, and lack of support facilities in most

areas. Hence, the risk of oil spills in the Arctic may

sometimes be greater than the risk in temperate

areas. At least partially offsetting this factor, however, is the higher level of engineering in the Arctic and the significant attention paid to safety factors. Risks have been analyzed and are carefully

considered in the planning process, but there is little

offshore Arctic operating experience on which to

base risk estimates. In deepwater areas, high seastates may be encountered, and the greater distance

from shore may create logistical problems for oil

spill cleanup. Existing cleanup technologies have

proven effective only in placid, protected waters.

The number of frontier area spills that may occur, and, therefore, the total amount of oil that may

be spilled is related to the amount of oil that will

be found and produced. Predictions concerning the

amount of oil frontier areas will yield are considered highly speculative, and thus the possible danger of oil spills is also uncertain. MMS uses oil spill

risk analyses to estimate the probability of oil spills

occurring in offshore areas it proposes to lease.

Based on historic data from the U.S. OCS, MMS

has determined that 3.9 spills of 1,000 barrels or

greater and 1.8 spills of 10,000 barrels or greater

can be expected for each billion barrels of oil produced and transported. Predicted spill types and

corresponding rates are shown in table 7-2. Although no oil has yet been produced from the Federal Arctic OCS, and the United States has only

recently begun production from areas of about

1,000-foot water depths, the probability that one

or more spills of both 1,000 barrels or greater and

10,000 barrels or greater will occur over the productive life of each lease sale area is considered to

be very high, based on past statistics.28

laMlne~~S Management service, Natrarin Basin Lease Offering:

Final Environrnentd Impact Statement (November 1983), p. IV-4.

Table 7-2.—Oil Spill Probabilities

(predicted spills per billion barrels of oil produced)

1,000-barrel 10,000-barrel

Source of spills oil spills oil spills

Platforms . . . . . . . . . . . . . . . 1.0 0.44

Pipelines . . . . . . . . . . . . . . . . 1.6 0.67

Tankers at sea . . . . . . . . . . . 0.9 0.50

Tankers in port . . . . . . . . . . 0.4 0.15

Total . . . . . . . . . . . . . . . . . 3.9 1.76

SOURCE: Minerals Management Service, Navadrr 6as/n Lease Offering: final Errvirorrrnenta/ hrrpact Statement, November 1983
186 ● Oil and Gas Technologies for the Arctic and Deepwater

Industry’s capability to effectively deal with

spilled oil in the frontier regions depends on two

factors: 1) preparedness with regard to countermeasures strategies, logistical support, equipment

availability, and planning; and 2) performance, effectiveness, and suitability of the containment and

cleanup equipment. Industry has met current State

and Federal requirements for pre-spill preparation.

The major uncertainty, however, is how equipment

which is currently available will actually perform

under the conditions commonly encountered in

Arctic and deepwater areas. Although the state-ofthe-art of cleanup technology has advanced in recent years, for the most part, only rough qualitative

measures of its effectiveness exist. Little quantitative

data about equipment performance exists, and most

of that which does exist is derived from relatively

inexpensive and easily controllable simulations and

small-scale tank tests rather than from expensive

testing under real-life conditions. In many instances, the manufacturer’s claims and the vendor’s

specifications are all the information available to

gauge the effectiveness of the equipment.

There are two major types of oil spills: blowouts

and tanker spills. The sudden, uncontrolled escape

of hydrocarbons from a well is known as a blowout. Oil well blowouts differ from tanker spills in

that the discharge rate of a blowout is often slower

and usually occurs over a longer period of time.

Tanker spills could involve the release of a large

amount of oil over a relatively short period of time.

The behavior of the discharge, countermeasures

strategies, and the potential impact of a blowout

spill are thus different than for tanker spills.

Countermeasures strategies vary for blowouts depending upon the depth of the blowout (e. g.,

whether it is a surface blowout from an artificial

island or a shallow or deepwater blowout resulting

from a drillship accident), the amount and stability

of ice cover (e. g., moving pack ice, broken ice, or

open water), and the sea state.

If a blowout cannot be controlled quickly, large

quantities of oil and gas may be released. If the

blowout occurs on the sea floor, the difficulties of

control are compounded; and if it occurs underwater and under moving ice, it can be extremely

difficult to control. It has been estimated that an

uncontrolled sub-sea blowout in the Beaufort Sea

lasting one year (although improbable) could release about 500,000 barrels of oil.

Some characteristics of blowouts make them

easier to handle than tanker spills. First, potential

spill locations are known; thus, spill containment

and cleanup equipment can be prepositioned and

variables affecting the spill’s behavior (currents,

wind patterns, etc. ) can be studied before the event.

Second, the release rates of blowouts are generally

lower than release rates of tanker spills. If a blowout can be quickly controlled, relatively less equipment may be needed to clean up this type of spill.

And third, oil from a blowout is often initially in

a fresh, fluid state. This characteristic makes

cleanup easier. However, the oil does not remain

fresh for long, and once it has weathered, it is more

difficult to recover.29

There have been several proposals to transport

Arctic hydrocarbons by ice-strengthened or icebreaking tankers. The proponents of these proposals

(e.g., Dome Petroleum) have designed tankers to

minimize the risk of a spill. Nevertheless, the possibility of a tanker spill in the Arctic—if and when

tankering becomes viable—cannot be discounted.

It is impossible to predict the exact location of

tanker spills. Equipment cannot be positioned in

advance, and it is therefore very difficult to implement a fast response before extensive oil spreading

and weathering occurs. Tanker spills may result in

the release of a large amount of oil during a short

period of time. Responses to such spills would require a large amount of equipment and manpower.

Limits to Effective Countermeasures

Environmental Variables

Whether a spill is from a blowout or a tanker accident, a number of environmental variables will

affect the response effort. One of the most important is the amount of ice present. Spills may occur

either in open water, under conditions of partial

ice coverage, or in solid landfast or pack ice. Those

which occur in complete ice cover are probably the

easiest to control. In such instances, the most practical countermeasures technique currently available

Zgsee S, L, Ross EnVirOnrnent~ Research Limited, Potentia/ Large

Oil Spills Offshore Canada and Possible Response Strate~”es (Environment Canada, March 1982), oil Spill Countermeasures: The

Beaufort Sea and the Search for Oil (Canadian Department of Fisheries and the Environment, 1977), and Evaluation of Industry Oil

Spill Countermeasures Capability in Broken Ice Conditions in the

Alaskan Beaufort Sea (Alaskan Department of Environmental Conservation, September 1983).
Ch. 7—Environmental Considerations ● 187

probably is to burn the oil on the surface of the ice

or, if spilled under the ice, to burn it as it accumulates in melt pools during the spring breakup.

Open water spills, particularly in the high sea states

common in the Bering Sea, are much more difficult to clean up. For instance, contamination from

a summer tanker spill is not likely to be significantly

reduced using currently available cleanup technology. High sea states would, however, promote natural dispersion.

In many ways, however, the most difficult spills

to clean up may be those which occur in partial ice

cover. Most oil spill containment and cleanup technology has been developed for temperate region

spills and may not be sufficiently effective when

used in partial (or broken) ice. Some promising

techniques have been developed recently, but all

require further development, testing, and integration into an overall response strategy. The brokenice period varies by year and by location. In the

Beaufort Sea and Chukchi Seas, this period lasts

approximately 3 to 7 weeks during breakup and 3

to 6 weeks during freezeup. Thus, the most difficult conditions in which to clean up spilled oil last

from 6 to 13 weeks each year. A generalization

about the Bering Sea is not possible since the Bering varies in climate from north to south. Some

areas of the Bering Sea may have broken ice at any

time of the year.

Other environmental variables also affect the performance and efficiency of equipment and the overall response effort. The velocity of the ice is important, since it is much more difficult to operate

in moving ice than in stationary (or landfast) ice.

The characteristics of the ice are also important.

Solid ice, for instance, provides an excellent platform from which to stage countermeasures, but it

is extremely difficult to maneuver equipment (such

as barges or skimmers) when ice coverage is extensive, Conversely, the operation of equipment in

old ‘‘rotten ice or in thin, early season ‘‘grease’

ice is probably easier than in solid ice, but these

types of ice cannot be used as a countermeasures

platform.

Inasmuch as the wind speed, sea state, and current strength affect both the rate at which oil is

dispersed and the deployment and operation of

countermeasures equipment, cleanup efficiency is

also influenced by these variables. Water temperature also plays a role because colder temperatures

increase the viscosity of the oil, thus reducing

spreading. However, in very viscous oil mechanical cleanup is difficult, and the effectiveness of

chemical dispersants is reduced.

Lack of Support Facilities

The absence of roads and support facilities

throughout much of the North Slope and Western

Alaska will make oil spill countermeasures difficult

even if appropriate cleanup technology is available.

There are few roads in these areas. Thus, land access to staging areas for offshore spills and/or threatened shorelines is rarely possible, and extensive use

of aircraft is required. In addition there are no

refineries, little manpower, few housing facilities,

and few disposal sites. Some of the resources which

could be mobilized in more populated areas in the

event of a major spill simply do not exist in the Arctic. Conversely, industry argues that because Arctic areas are so remote, they must be self-sufficient.

Located in the Prudhoe Bay area are fixed wing

aircraft, helicopters, air cushion vehicles, roligons,

trucks, boats, barges and personnel which could be

mobilized rapidly in a local emergency.

Difficult Working Conditions

Difficult working conditions pose a general

limitation on the capability of industry to clean up

offshore Arctic oil spills. Although techniques,

equipment, and clothing have been developed to

minimize the effects of intense cold, and personnel have received specialized training, human efficiency is reduced in cold climates, and safety is correspondingly more difficult to ensure. Even with

the best of protection, it is not possible to work outside for long periods of time. Generally, responses

to accidents in cold environments take more time

and equipment problems are greater, although little reliable data exists concerning the precise effects

of cold on either human or equipment efficiency.

The possibility that a spill may occur during the

long Arctic night or during times of persistent fog

also poses problems of efficiency industry will be

able to make effective use of currently available

equipment and countermeasure strategies to re-
188 . Oil and Gas Technologies for the Arctic and Deepwater

cover significant amounts of spilled oil in frontier

areas.

Response Time

Of all the difficulties associated with containing

and cleaning up spilled oil in the Arctic, two appear to be especially troublesome. The first is the

problem of response time. Although inventories of

oil spill cleanup equipment are located at Prudhoe

Bay and at Dutch Harbor, response time is a problem because Arctic spills may occur in remote areas

and because human efficiency is less in cold environments. If response to a spill is not prompt, the

effectiveness of countermeasures is reduced, sometimes markedly. The response time problem will

be particularly difficult in the case of tanker spills,

since a spill may occur anywhere. Although tankers

are not currently being utilized, their use in the Bering Sea can be foreseen, and their future use in the

Beaufort and Chukchi Seas is being considered. It

has been suggested that the major countermeasures

question in the case of open water spills is how to

deliver the technologies to the spill site prior to the

oil’s spreading and weathering beyond control.

In the Bering Sea, a distressed ship could be 400

or more miles from any point in Alaska and a much

greater distance from a base that could support a

spill response effort. For instance, it would take a

Coast Guard icebreaker stationed at Kodiak Island

at least 4 days to reach the site of a Bering Sea spill.

It may be possible, if the safety of the crew is not

at risk, to use the tanker itself as a working platform for countermeasures operations. A portable

response system may be developed to be carried

on tankers that would include booms that could be

deployed by a small boat, skimmers that could be

operated remotely or from the ship, and some kind

of vehicle capable of operating in the water and on

all kinds of ice. The United States has no requirement at this time that ships be equipped for countermeasures activities.

While the response time problem for remote

tanker spills is of particular concern, responses to

all Arctic spills will, on average, take more time

than responses to temperate spills. The difficulty

of detecting oil spills compounds the problem.

Detection is most difficult for spills which occur

under the ice or in broken ice, but it can also be

a problem in more controllable situations, such as

in the June 1981 Challenge Island oil spill in the

Beaufort Sea. In this case a spill of approximately

3,000 gallons went undetected for an indeterminate

length of time because of sustained inclement

weather conditions .30

The industry treats the response problem seriously. Individual oil companies as well as industry cooperatives have stockpiled spill countermeasures equipment as required by the MMS. The

companies prepare oil spill contingency plans for

all exploration activities, and they conduct periodic

drills to improve their response capability. In addition, the U.S. Coast Guard has established a national strike force equipped to respond to spills on

short notice.

The broader countermeasures challenge is to develop a comprehensive and integrated spill response

system. Such a system is composed of many components, including detection and surveillance, logistics operations, containment, recovery, storage,

and disposal. In addition, the response operation

depends upon timely weather and ice information

and on other contingency plans (e. g., when conditions become hazardous, evacuation of personnel must be provided). If attention to any of the

system components is less than adequate, the effectiveness of the overall response is likely to be

limited. Thus, even with the best recovery technology, the response may be ineffective if the equipment can not be transported to the site fast enough

or if recovery efforts must be terminated due to

safe conditions.

Countermeasures Technology

Mechanical Recovery

unIn some Arctic spill situations oil can be removed

from the surface of the water by mechanical skimming devices. Many different types of skimmers

have been developed, but few of these have been

designed specifically to recover oil from Arctic

waters. Moreover, although mechanical oil skimming technology continues to advance, little testing

has been done under at-sea Arctic conditions. Even

gosohio Alaska petro]eum Company, Challenge zd~d SPJ1 Repofl

(March 1982).
Ch. 7—Environmental Considerations ● 189

the most effective skimmers have limited capacities for recovering oil in stormy and/or ice-covered

Arctic waters. Considering the relatively low percentage of spilled oil they may be able to recover

in most Arctic spill scenarios, skimmers are seen

by some to be a second-order countermeasure

technique.

The effectiveness of skimming devices depends

upon a number of different variables. For one, the

thickness of the oil layer to be recovered affects

cleanup efficiency. Thus, skimmers are usually used

in conjunction with booms which prevent the oil

from spreading and becoming too thin to recover.

In this respect, ice may sometimes be used to

advantage. If ice is present, but not extensive

enough to limit skimmer deployment, it may serve

as a natural barrier to spreading and thinning. The

viscosity of the oil is a second important variable.

The mechanical recovery of viscous oil, which may

quickly form in cold Arctic waters, is a problem

requiring specialized equipment. Skimmer performance is also reduced by high sea states, strong

currents, and the presence of debris and/or ice.

Skimmers for Arctic spills must be easily maintainable, easy to transport to the spill site, and simple to operate. Skimmer designs which may be

useful in certain Arctic spill situations include weir,

suction, and sorbent surface devices. Each type of

device is available in the Arctic.

Weir skimmers. Weir type skimmers depend on

gravity to drain oil off the surface of the water. They

operate by allowing the oil to fall over a lip suspended at the surface of the water into a sump

placed in the slick. The oil is then pumped out of

the sump to a storage facility. The main advantages

of this type of skimmer are portability and simplicity. They have proven most useful for recovering light oil in calm water. They are not useful in

waves because large volumes of water will enter the

sump with the oil (a ratio of 10 percent oil recovery to 90 percent water is not atypical). In larger

waves, smaller weir skimmers may be swamped.

Weir skimmers can be used in calm, open water

Arctic spill situations; however, the presence of ice

or other debris may clog the weir openings and render the equipment temporarily inoperative.

Suction devices. Suction devices, if mounted on

a suitable operating platform and if used with

suitably powerful positive displacement pumps,

may prove to be useful in some instances. Since

low ambient temperatures predominate in the Arctic, spilled oil is likely to become very viscous;

water-in-oil emulsions also may be formed. The

main advantage of suction skimmers is their ability

to vacuum heavier oil. Even suction pumps, however, will have problems recovering semi-solid oil.

Other types of skimmers have difficulty efficiently

recovering viscous oil because the oil will not readily

flow toward the equipment.

Disc skimmers and rope mops. Sorbent surface

devices, including rotating disc skimmers and rope

mops, seem to hold promise for efficient operation

where small amounts of ice are present. The disc

type skimmer collects oil on rotating oleophilic

discs. The oil is scraped from the discs, transfered

to a screw auger at the axis of the discs, and pumped

to storage containers. The advantages of this type

of skimmer for Arctic use are its ability to pick up

viscous oil and to function amidst limited ice, debris, and waves. However, disc skimmers may become quickly overloaded in heavy oil.

Rope mop skimmers use continuously moving,

absorbent, polypropylene ropes to sop up oil. This

type of device has relatively good potential as a secondary collection system in broken ice conditions.

Rope mop skimmers range in size from very small

portable units capable of being mounted on icestrengthened barges or other platforms to large

boats specially designed for skimming operations.

The ARCAT. The largest and most important

rope mop skimmer currently on hand in the Arctic is the ARCAT, a 65-foot catamaran dedicated

Photo credit: EPA OHMSETT facility

Testing the effectiveness of a rope mop skimmer in

cleaning up oil spills in broken ice
190 . Oil and Gas Technologies for the Arctic and Deepwater

to spill cleanup in the Beaufort Sea and operated

by Alaska Clean Seas. A distance of 6 feet separates the ARCAT’s two hulls. However, using

diversionary booms and support from two small tow

boats, the ARCAT can increase its swath width and

thus its oil encounter rate by a factor of 20 or more.

By offloading recovered oil into auxiliary oil storage containers, it is hoped that ARCAT will be able

to operate continuously for days or even weeks at

a time, recovering oil at the average rate of 5 to

30 barrels per hour. Other features of the ARCAT

include oil dispersant booms, oil storage capacity,

and equipment to break down recovered emulsions. 31

The maneuverability of the ARCAT has been

evaluated in broken ice coverage up to 7 oktas (an

okta is equivalent to 12.5 percent—one-eight—

coverage). In 2 oktas (25 percent) or less ice coverage, it is able to maneuver through broken ice

at speeds of from 5 to 7 knots. In 3 to 5 oktas its

speed is reduced to one to 2.5 knots, and, in 6 to

7 oktas to about one-half knot. Industry is satisfied

that the ARCAT has been sufficiently tested to

demonstrate its utility for recovering oil in broken

ice conditions. Industry argues that further testing

is not necessary since other skimmers very similar

to the ARCAT have been tested with good results

in oil, and it is reasonable to conclude that ARCAT mops will behave in the same way. Others

are not so sure, since it has not been tested in oil

and ice, and believe that the device should be put

to the test recovering the type of oil that it will most

likely encounter—viscous crude that has weathered

for about 3 days in water at 0°C. Even if ARCAT

can handle these tests, special operating procedures

may have to be developed. Tests may indicate that

different types of mops are necessary, or that it may

be necessary to adjust wringer speed, rope speed,

or even the vessel speed. These operating procedures could be tested and developed before a spill

occurs.

The Force Seven type mop. The Force Seven

type rope mop has also been considered in connection with Arctic spill response. This system uses a

series of mops deployed from the stern of a vessel.

31R. E, Wi]]iams, s. J. Bowen, and D. H. Glenn, ‘‘Field Trials

of the ARCAT 11 in Prudhoe Bay, Proceedings of the Seventh annual Arctic Marine Oilspill Technical Seminar (Edmonton, Alberta,

June 1984).

It is attractive because: 1) the area covered can be

increased by increasing the number of mops; 2) the

device is likely to have some utility in broken ice

since the mops are drawn over the surface of the

ice; 3) there is no problem of a catamaran hull becoming jammed with ice; and 4) the device can be

quickly installed on the stern of any available vessel.

This last feature is particularly important. The ARCAT is an expensive vessel, and although it may

be used for other purposes, it is dedicated solely

to oil spill response. When it isn’t recovering oil,

it sits unused. As a result, only one ARCAT has

been built and deployed to date. If a large spill does

occur, however, the use of as many vessels as are

available probably will be required if a significant

amount of oil is to be recovered. Therefore, availability of equipment that can be mounted on vessels

of opportunity probably will be more feasible than

dedicated single-purpose vessels.

Few skimmers have been independently tested

to evaluate how well they perform in broken ice

conditions. In most cases it is simply not known

how well they will operate in the different ice conditions which could be encountered. Manufacturers

have made optimistic statements about the efficiency of their skimmers for Arctic conditions, but

what little independent testing has been done has

shown many of these claims to be overstated.

Industry has been using conventional barges and

tugs for some time for supporting offshore and nearshore oil spill cleanup operations. One innovation

would be an icebreaking barge. Barges provide

mobile and stable platforms from which to conduct

countermeasures operations. Recent industry demonstrations have shown that rope mop skimmers

can be effectively deployed from barges in deteriorating heavy pack ice. The recovery capability of

barge-mounted skimmers, however, has not been

demonstrated. The oil-encounter rate for these

skimmers may not be high; nevertheless, this approach constitutes one more countermeasures tool

that may be useful in some situations.

Booms. Booms are used to contain oil. They may

either be employed in conjunction with skimming

operations (in which case their function is to capture and concentrate oil slicks so that recovery can

be as efficient as possible) or for deflecting or excluding oil from particularly sensitive areas. Booms

work best in calm water, free of ice or other de-
Ch. 7—Environmental Considerations ● 191

bris. However, in strong currents (above one knot)

and high sea states, the efficiency of containment

booms is impaired. In heavy sea states, for instance,

oil may either splash over the top of the boom or

escape under the skirt. In addition, scattered ice

can cause boom damage. In general, booms do not

yet seem to have the endurance necessary for continuing performance during a long-term cleanup

operation, and booms used in open ocean conditions have not proved to be very effective. In rough

environments, the use of booms and skimmers

probably would not make a significant difference

in the ultimate environmental impact of a spill.

MMS recommends that booms be able to perform in wave heights of 8 to 10 feet. These performance guidelines have not been met. However,

it is still unclear what constitutes adequate boom

performance under real conditions, and under high

wave conditions, oil will usually be quickly dispersed, Although booms are an indispensable

countermeasures tool, their use is clearly limited.

A promising addition to containment technology

is the high pressure water jet barrier, which currently is being developed. It is used for the same

purposes as conventional booms. The water jet system is designed to herd oil in waves, ice, and marsh

areas, and can be mounted on and used in conjunction with skimming devices. It has not yet been

evaluated in high sea states, however. In addition,

the jets create a considerable amount of fine mist.

In subfreezing air temperatures, the resulting ice

mist could be a health and safety hazard.

Disposal. The ultimate disposal of recovered oil

or oiled debris generally takes the form of either

landfilling or incinerating the material. Both of

these alternatives have drawbacks in a northern application.

The burial or landfilling of oil and oiled debris

is possible only if suitable sites are available to construct either subsurface pits or above-grade berms

to contain the material. Such sites are not plentiful

in the Arctic; where available, they may be difficult to access due to the complete absence of roads

and the presence of shallow water at the shore. Icerich soils, common in the Arctic, also pose a problem in summer operations since excavation in permafrost can create sloppy, unworkable conditions.

Landfilling operations also require the use of heavy

equipment which is not plentiful in the North and

which would be difficult to transport to specific disposal sites. The major advantage of land filling in

the Arctic is the ability to permanently encapsulate

the oil and debris in a frozen surrounding.

The state-of-the-art for oil spill disposal by incineration has advanced from earlier attempts at

burning oil and debris in oil drums or open pits

to a technology including air-transportable incinerators and reciprocating kiln beach cleaners.

A transportable flare burner capable of burning

6,000 barrels of light oil per day and 3,000 barrels

of heavy oil per day is available in Anchorage. The

industry on the North Slope has access to a rental

burner that is theoretically capable of incinerating

13,000 barrels of oil per day.32

Oiled beach materials such as sand and rock

could be cleaned in simple reciprocating kiln devices but such equipment at present has a very low

throughput. A larger number of these kilns, along

with their manpower and logistical support, would

therefore be required to carry out an extensive

beach cleaning. It is also apparent that any proposed landfill operation would involve serious

logistical problems. This is also the case for any proposed labor-intensive spill control operation in the

North, either beach cleaning or debris disposal.

The disposal problem is mainly of concern for

large spills. Small spills can be stored until adequate

disposal is available. For the Beaufort Sea, the industry points out that it would be technically feasible to transport skimmed oil by barge or possibly over ice to Prudhoe Bay where it could be

offloaded into a ‘‘slop tank’ at one of the flow stations of the Prudhoe Bay Unit. These flow stations

have the capability to treat skimmed oil to Trans

Alaska Pipeline specifications. Likewise, in the Bering Sea, it may be technically possible to transport

skimmed oil in a large oceangoing barge to Kenai,

Alaska or Seattle, Washington for deposit into a

refinery slop tank.

In Situ Burning

For many Arctic marine oil spills, in situ burning is considered to be one of the most practical

methods available for removing oil from the envi-

——

jzshell oil Company, Sohio Alaska Petroleum Company, Exxon

Company, and Amoco Production Company, Oil Spill Response in

the Arctic (Three parts, April 1984).
192 ● Oil and Gas Technologies for the Arctic and Deepwater

ronment. This countermeasure method may be

used in combination with other techniques to reduce water pollution. The oil that escapes combustion, either as residue or as a partially burned oil

layer, might be recovered downstream with skimmers. When burning can be used as an oil spill

countermeasure, the problems of disposal encountered with mechanical recovery techniques

may be reduced.

In situ burning may be practical for both contained and uncontained spills. In an uncontained

slick, such as one from a tanker spill in open water,

burning may be the only feasible method of significantly reducing the amount of oil in the water.

Even if mechanical recovery equipment could be

deployed to a remote spill site, it probably could

not be expected to remove more than a small fraction of the oil from a large batch spill, and the problem of disposal of recovered oil would remain.

Dispersants might be used to counteract some of

the adverse effects of uncontained spills, but their

effectiveness may be reduced in cold environments.

If spilled oil can be contained, in situ burning

may be the most efficient removal technique. Oil

may be contained naturally or by man-made, fire

resistant booms. Winter tanker accidents or winter subsea blowouts are two situations in which

spilled oil would be naturally contained and in

which in situ burning may be successfully used. In

either situation, most of the spilled oil would be

trapped under the ice for the duration of the winter, and no countermeasures would be possible until

breakup begins. Within a very short time, the oil

would be encapsulated in the growing ice sheet. If

the spill were in the landfast ice zone, the oil would

not likely travel very far. However, if the spill were

beyond this zone in the moving pack ice, the oil

could eventually be spread along a narrow track

under the ice for many miles. As the ice begins to

decay, the oil would migrate to the surface (where

it would emerge in a relatively fresh and unweathered state) and collect in melt pools. Depending

upon the size and type of the spill, thousands if not

tens of thousands of separate oiled pools could appear. Like spills resulting from open-water tanker

accidents, there may be no practical solution other

than burning for spills resulting from either winter tanker accidents or winter subsea blowouts.

Photo credit: EPA OHMSETT facility

Testing the effectiveness of in situ burning as an

oil spill countermeasure

Spills which occur during the broken ice period

can also be contained naturally for in situ burning, if the ice coverage is adequate (the ice edges

tend to limit the spreading tendency of the oil). For

some open water or broken ice situations, fire resistant containment booms, although still in the development stage, may provide a way for reducing

marine oil pollution.

The major technical issue associated with in situ

burning is the problem of igniting the oil and keeping it burning. When oil is allowed to spread and

thin, it is difficult to burn efficiently. Oil which is

thicker than about 2 or 3 millimeters can be ignited

and burned. Since oil thins as it spreads, undue

delays in ignition result in reduced burn efficiencies. Moderate wind may be helpful if it works to

herd the oil against an ice barrier. However, lower

burn efficiencies can normally be expected in high

wind and low ice concentrations. Weathered oil

which has remained in the water is likely to be unburnable because the lighter fractions quickly

evaporate, and the remaining oil breaks into windrows. Minimum conditions for burning are currently unknown.

For in situ burning of uncontained slicks to be

effective, the spreading of the flame must keep up

with the spread of the oil itself. The flame spreading

velocity is related to the type of oil burned, wind

speed, and water temperature. Recent laboratory

and test-tank oil burn tests have shown that in most

cases the flame spreads as rapidly as the burning
Ch. 7—Environmental Considerations • 193

oil until the thickness of the leading edge of the slick

drops below that necessary to support combustion.

Beyond this point, only the thick portions of the

slick burn, However, certain ignition patterns, such

as igniting the circumference of the slick, may be

able to overcome this problem. Combustion efficiencies vary proportionally with spill size, wind

speed, amount of ice, water temperature, oil type,

ignition delay, and pattern of ignition. Efficiencies

of up to 80 percent by volume can be achieved, with

lower efficiencies expected, for instance, in high

winds and low ice concentrations. If adverse conditions persist, cleanup efficiencies could drop below

20 percent.

The 1983 Alaskan Tier 2 field demonstrations

of industry’s ability to clean up oil in broken ice

included industry demonstrations of in situ burning. Task 1 consisted of a series of burns of oil in

grounded and floating ice. Although the demonstrations were less successful when the ice was

floating rather than grounded, they clearly showed

that burning is an important component of Arctic

oil spill response and cleanup if the oil enters moving broken ice. In its evaluation of the demonstration, the State of Alaska noted that the relatively

high efficiency of in situ burning depended on the

crucial assumption that burning must take place

close to the spill source while the oil layer is relatively thick and easily combustible. In many situat ions, however, a safe burn near the source of a

blowout may be impossible, and therefore the burn

efficiency will be significantly reduced. It is suggested that more work on the ignition and in situ

burning of crude oil among 3 to 5 oktas of moving

ice is necessary to determine the limits of this

countermeasure approach with respect to oil weathering, thickness, and environmental conditions.

Wellhead ignition. When in situ burning and

other countermeasures techniques are not feasible,

wellhead ignition is another possibility. This technique has been considered for dealing with blowouts

from gravel islands. Combustion and skimming

techniques employed in the vicinity of an unignited

blowout can be dangerous and countermeasures

taken far downstream of a blowout may not be very

effective, Therefore, well ignition may be the only

way that artificial island blowouts can be rapidly

and effectively controlled. It has been roughly estimated that if the wellhead is ignited, approximately

95 percent of the oil would be burned immediately

and another three percent could be removed by

other cleanup processes, regardless of whether the

blowout occurred in broken ice, landfast ice or open

water.

However, there are some important unanswered

questions concerning the feasibility of wellhead ignition as an oil spill countermeasures technique.

Oil companies may be reluctant to ignite blowouts

and thus destroy their wells unless there is no alternative. When possible, rapid control of the well may

be more effective in minimizing pollution than early

ignition of the blowout. Wellhead ignition prevents

the use of equipment which could otherwise be used

to reduce the flow.

If a blowout were to occur, wellhead ignition

would probably not be ordered immediately. There

would inevitably be some delay as experts evaluated

the best course of action to take, during which time

oil would continue to flow. It has been suggested

that 24 to 48 hours would be required to analyze

the blowout situation. If experts determined that

the well could be brought under control within a

‘ ‘reasonable’ time period, the well would not be

purposely ignited, and alternative well control efforts would commence. The decision would depend

on the rate of flow, the likely damage to the rig and

equipment if the well were purposely ignited, the

potential environmental damage with and without

well ignition, and the safety, cost, and efficiency

of cleanup options.

The State of Alaska’s decision to grant yearround exploratory drilling on and inside the barrier islands to qualified lessees (the Tier 2 decision),

was based, in part, on the viability of wellhead ignition as a countermeasures option. A major question, however, is whether government authorities

(either the Alaska Department of Environmental

Conservation or the United States Coast Guard)

would be willing to order a blowout ignited, recognizing the possible legal problems which might

ensue if industry claimed that the well could have

been saved and that other techniques could have

been used. If ignition is ordered by these authorities, it is not altogether clear who would pay for

the damage to equipment. There is also some concern about the safety of ignition. On offshore structures, for instance, it is possible that igniting a blow-
194 . Oil and Gas Technologies for the Arctic and Deepwater

out could destroy blowout preventers which might

be used to bring the blowout under control. In this

situation, the capability to drill a relief well becomes

very important. Depending upon the area in question and the availability of rigs, a relief well could

take from one to three months to drill. Hence, a

buffer period would be required so that relief well

drilling could be completed before the fall freezeup.

Wellhead ignition should probably not be considered a preferred countermeasure, but rather as a

last resort to use in the absence of any better

technique.

Ah--deployable igniters. Any approach to dealing with spills beneath ice must take into account

that the size of the area that might have to be

cleaned could be extremely large, that there could

be numerous unconnected pools of oil to clean up,

and that putting cleanup personnel on the ice surface is potentially unsafe. To overcome these problems, a considerable amount of effort has gone into

developing igniters which are inexpensive and safe

for use from helicopters. One of the requirements

specified by Alaska’s Department of Environmental

Conservation in order for a lessee to obtain approval of its contingency plan is that the lessee must

be able to obtain 500 in situ igniters within 6 hours

of a spill and an additional 1,000 igniters within

48 hours of a spill. Still, this number of igniters

might be inadequate for certain types of spills. It

has been estimated, for instance, that up to 30,000

igniters could be needed to ignite the oil from a

large spill from a tanker. Research is continuing

on developing more efficient igniters, and one of

the more promising techniques currently under investigation is that of airborne laser ignition. 33

Collection and disposal of residue. Although in

situ burning is considered the most practical

countermeasure for oil spills on solid or in broken

ice, little attention has been given to collection and

disposal of the residue from a burn, which could

be as much as 35 percent of the volume of the oil

spilled. Such residue will be viscous and difficult

to handle. While flare burners could be used to dispose of oil and oil/water mixtures recovered by mechanical devices, residue from in situ burning may

331. A. BuiSt, R. c. llelore, and L. B. Solsberg, ‘‘Countermeasures

for a Major Oil Spill from a Tanker in Arctic Waters, ‘Proceedings

of the Seventh Annual Arctic Marine Oilspill Technical Seminar (Edmonton, Alberta, June 1984).

be too viscous to burn. Field tests have shown that

burn residue can be removed using sorbents. However, burn residue and sorbent material must first

be collected and then transported to an incineration site, which may not be an easy task if the spill

is distant from onshore facilities.

Air pollution. In situ burning in many places in

the United States would be considered unacceptable because of the smoke and products of combustion. On the North Slope it may be less objectionable because it is remote from populated areas.

Environment Canada conducted a brief study of

the characteristics of atmospheric emissions from

in situ burning in 1979 and concluded that ‘‘in the

immediate vicinity of the fire, the concentration of

particulate (soot) will be undesirably high and such

areas should be avoided. The concentrations at distances of 10 to 40 km and beyond are judged to

be sufficiently low that no adverse air quality problem exists. ’34 The study further notes that poly -

nuclear aromatic hydrocarbons in the oil soot have

been established as potent carcinogens and are

regarded as being only slowly biodegradable. The

toxicity of the amounts of these substances likely

to be present in the soot has not yet been established, but the Canadian report recommends that

it is prudent to minimize human exposure to these

substances. This could probably be accomplished

by careful planning of the burning operations, taking into account short range weather forecasts.

More recently, the Alaska Department of Environmental Conservation and the Alaska Department of Natural Resources have noted that it is

unlikely, given the remoteness from population

centers of Arctic oil and gas activities, that concentrations of the byproducts of in situ burning of oil

will reach levels in which a hazard to humans and

wildlife will be present. They plan to use a dispersion model to analyze the air quality impact before

deciding to order a blowout ignited or burn large

quantities of oil in situ. Despite possible air contamination, it is generally believed that in balance

it may be more advantageous to burn the oil rather

than allow it to remain in the marine environment.

t+Tom Day, et. ~., characteristics of Atmospheric Emissions from

an In-Situ Crude Oil Fire (Ottawa: Environment Canada, October

1979), p. 58.
Ch. 7—Environmental Considerations Ž 195

Finally, although it will be possible to burn oil

that surfaces in melt pools in the spring, if large

quantities of oil are involved, it may be desirable

to take action sooner. The Alaskan Beaufort Sea

Oilspill Response Body (ABSORB) has sponsored

research investigating the possibility of drilling

through the ice to reach oil pooled beneath. Since

oil from a winter subsea blowout would be trapped in cavities under the ice, it may be possible to

put personnel and heavy equipment on the ice in

winter to drill down to oil trapped in the larger

pools—if it can be located—and pump it out. This

approach would not require developing any new

equipment.

Dispersants

Dispersants are chemical agents used to eliminate oil from the surface of the water and distribute it though the upper few meters of the water

column. Used on an oil slick, dispersants decrease

the interracial tension between oil and water, thus

reducing the cohesiveness of the slick and promoting the formation of small droplets, which, with the

aid of wind and waves, move downward into the

water column. Natural degradation by oil consuming bacteria and other processes eventually takes

place. The use of dispersants as an oil spill countermeasure may be appropriate if: 1 ) sea conditions

are too rough for deployment and/or efficient operation of collection and recovery equipment; 2) the

spill is too large; 3) the spill site is too remote for

efficient mechanical recovery or in situ burning;

4) it is necessary to stop the movement of a slick

toward shore; 5) the oil slick presents a fire hazard; or 6) the probability of contaminating wildfowl

is high. 35

There are several problems associated with the

use of dispersants. For one, dispersants may adversely affect marine organisms. The first dispersants used for oil spills were hydrocarbon-base

solvents. In response to the Torrey Canyon spill

it was found that, when applied in large doses, these

first-generation dispersants were lethal to marine

organisms. Dispersants thus acquired the reputation of being compounds too harmful to marine life

to be used as an oil spill countermeasure. More

tsAmeric~ petroleum Institute, Oil Spilf Cleanup: A Primer (Washington, DC, 1982).

recently, “third-generation" dispersants have been

developed. For these dispersants, the water on

which the oil is floating serves as the reactant in

the dispersing process. This eliminates the need for

hydrocarbon solvents, and greatly reduces the biological toxicity. The most effective dispersants are

those which maximize dispersal of oil at sea but

have a minimal impact on key organisms living in

the water column and sediments. Although the most

recent generation of dispersants are relatively nontoxic, there may still be problems associated with

placing dissolved and particulate oil in the water

column. It is believed that sub-lethal effects (e. g.,

tainting of marine species) are the main biological

concern.

The decision to use or not to use chemical dispersants relates to the expected severity of oil spill impacts on wildfowl, beaches, or wildlife. The safe

use of dispersants requires an understanding of the

fate, behavior, and effects of treated and untreated

oil spills. Since the potential exists for improper use,

dispersants must be thoroughly tested before being placed on the EPA approved list.

A second problem concerns the effectiveness of

dispersants in cold climates. Dispersants formulated

for use in temperate regions may not be well-suited

for use in the Arctic, since cold temperatures increase the oil’s viscosity, thereby reducing the

ability of the dispersant to break down the slick.

Since dispersants require relatively high surface

mixing, their use would probably not be effective

in broken ice conditions. Currently available dispersants are less effective in acting on water-in-oil

emulsions. Another temperature-related problem

is the potential for the dispersant to separate, freeze,

or gel at low temperatures which might cause problems in spraying. Also, the amount of mixing, the

degree of weathering of the oil, the dispersant-tooil ratio, uniformity of coverage, the size of the oil

droplets (they must be small enough to create a

permanent dispersion), the presence of slush ice,

and the degree of salinity affect dispersion. For

instance, dispersants require mixing to be effective,

and sufficient wave energy is often not present off

the North Slope. In addition, since current oil and

gas operations in the Alaskan Beaufort Sea are in

very shallow water, the use of dispersants may not

be an effective way to degrade the oil and may not

be desirable from an environmental point of view.
196 ● Oil and Gas Technologies for the Arctic and Deepwater

On the other hand, dispersants could be effective

in the Navarin Basin, where there is more wave

energy and deeper water, and where marine life

and wildfowl are more dispersed.

Dispersants have been developed in the last few

years which apparently require little mixing i n

addition to normal wave action, and this development has stimulated research and development in

aerial application techniques. Dispersant effectiveness, toxicity, and logistics support requirements

probably should be examined in light of the much

greater slick thicknesses associated with fresh oil

films in the Arctic. Ultimately, it could be possible to rank dispersants according to their effectiveness in specific types of situations.

The effectiveness of dispersants as a countermeasure in Arctic waters has yet to be adequately

demonstrated under cold marine conditions. Questions remain, for instance, about whether aerially

applied dispersants work the way they are supposed

to or merely ‘herd’ the oil to either side of the spray

path. The two largest dispersant manufacturers,

British Petroleum and Exxon, are actively involved

in developing chemical dispersants that will be more

effective in treating Arctic oil spills, or other viscous

spills.

Logistics problems and high costs of using dispersants as a countermeasure for large, remote Arctic spills may ultimately prove to be the factors most

limiting their use. Since dispersants must be applied

from either ships or aircraft, their use depends upon

the availability of expensive equipment. Moreover,

for major spills, large quantities of dispersants will

be required. Long distances require large amounts

of fuel. However, aerial dispersant operations could

be carried out in all Alaska OCS areas from existing

aircraft landing facilities.

For use in remote Arctic locations (e. g., to apply

to oil from a tanker spill), aircraft may be the only

practical means of delivery, because for dispersants

to be effective, they must be applied as soon as possible after a spill. It has been estimated that a response effort for remote spills could require three

to four days to mount. By this time, however, the

increased viscosity of the oil would make currently

available dispersants much less effective. Thus, until more effective dispersants are developed, aerial

applications will not likely be a useful countermeasures technique for remote tanker spills. Moreover, expensive stockpiling of sufficient quantities

of dispersants at strategic locations and a wellrehearsed logistics plan for delivering the chemical to the spill site probably will be crucial if future

applications are to be successful. More promising,

perhaps, is the use of dispersants to combat oil from

blowouts which is thin and fresh, and for fresh spills

in choppy seas which can be reached quickly. Other

applications might include small batch spills and

protection of nearshore areas.

Shoreline Cleanup

Conventional shoreline cleanup in the south involves the containment of oil at shore, the removal

of oil and oiled debris by manual and mechanized

means, and the cleaning of rocks and man-made

structures by high-pressure water and steam.

Northern cleanup and restoration operations will

utilize techniques and equipment much as in the

south. The northern shoreline cleanup operation

will, however, likely be complicated by several

factors.

Outside the Prudhoe Bay area, a large work force

is not available in the Arctic. Since many cleanup

steps require manual labor, responses to northern

spills may face labor shortages. Heavy equipment

will have to be used sparingly due to the sensitive

nature of the northern shorelines and their slow

recuperative abilities. In many instances, beach material will not support heavy loads. In addition, the

presence of boulders and other irregular features

on the surface preclude the use of any large mechanized vehicle. The lack of road access in the Arctic means personnel and equipment will have to be

transported to the spill site by water or air. Cold

temperatures much of the year and periods of prolonged darkness will also complicate northern

shoreline cleanup operations. While all of the southern shoreline cleanup techniques are generally

applicable to the Arctic study area, the remote

nature and harsh but fragile environment of the

North will make their application more difficult and

less efficient. In most cases, beaches and shorelines

will likely be left to regenerate by natural means.

Conversely, shoreline response may not be as

time sensitive as offshore or nearshore cleanup;

thus, there would be more time to import additional
Ch. 7—Environmental Considerations • 197

labor from Fairbanks, Anchorage, or elsewhere. In

the northernmost areas, the shoreline would be in

a frozen or semi-frozen condition most of the year,

which would limit the amount of oil that would

penetrate the surface. Industry expects that most

shoreline cleanup operations would take place during the summer when there is much more daylight

than in the lower latitudes.

Monitoring and Surveillance

The effectiveness of many control operations depends on the ability to monitor the position, direction of drift, and size of oil slicks. The vast areas

and remoteness of the Arctic, as well as long periods of darkness, complicate this task. The most obvious method of tracking the oil is by visual observation from aircraft. In many cases this will not

be possible in the Arctic because of prolonged periods of poor visibility due to either weather or seasonal daylight conditions. Many other methods

have been developed for this purpose which will improve surveillance under northern conditions.

Radio tracking buoys monitored from land, ships

or aircraft have been constructed to simulate the

behavior of specific oil types. Tracking distances

of 15 kilometers from the water and 45 kilometers

from the air for periods of up to three weeks are

possible with the present equipment.

The use of both passive and active airborne

remote-sensing packages for tracking and locating

purposes has been advanced in recent years. Pictures of spill extent and location can be made

through color or filtered black and white photographs. Low-light television systems can differentiate oil slicks from wind and wave patterns but are

ineffective in the dark and are unable to discriminate oil from foam, slush ice or brash ice, A day

or night system—the laser fluorosensor-is able to

detect oil on water, on ice, and in ice-infested conditions. It is limited to the detection of oil at, or

very near the surface of the water or ice. Dual, infrared/ultraviolet, line scanners have been successful in locating oil on a real-time basis during

the day. Side Looking Airborne Radar (SLAR) is

able to cover a larger area in one pass from an airplane or satellite. These SLAR systems are effective, day or night, in detecting oil only in ice-free

waters. None of the sensors currently available have

been proven to detect oil in broken ice, with the

exception of the laser fluorsensor, which is still being tested.

Satellite imagery is another means of locating and

tracking oil slicks during daylight hours. Currently,

the LANDSAT series of satellites scan the Arctic

with sensors in the red, green, and near infrared.

This information can be used to identify the position and extent of an oil slick. Plans to mount improved sensors in these orbiting stations will undoubtedly enhance the use of satellites for future

monitoring.

Government/Industry

Responsibilities

Primary responsibility to cleanup oil spills rests

with industry, and, although industry has treated

the oil spill issue seriously, it has developed only

limited capability to contain or clean up a spill in

the Arctic. It is the responsibility of Federal and

State governments to ensure that industry is adequately prepared to respond to oil spills and to provide backup assistance when necessary.

Federal Government

Since the Santa Barbara blowout, improvements

in the regulations governing OCS oil and gas exploration and development have been made by the

Department of the Interior. New regulations regarding subsea blowout preventers, worker training programs, oil spill contingency plans, and inspections have been implemented since 1970. In

addition, several laws establish penalties for spilling oil and assess liability for polluters. For example, amendments to the FWPCA in 1972, 1977,

and 1978 have increased civil and criminal penalties

that may be incurred for polluting. Polluters may

now be fined up to $10,000 for failure to report an

incident, and up to $50,000 for each offense (and

more if willful misconduct or negligence can be

proved). Under the FWPCA, vessel owners are liable for cleanup costs of up to $150 per gross ton

and owners of offshore facilities may be liable for

cleanup costs up to $50 million. The Administration supported recent congressional attempts to further increase pollution penalties and liability limits.
198 ● Oil and Gas Technologies for the Arctic and Deepwater

Federal responsibilities in the event of offshore

oil spills are specified in the National Oil and Hazardous Substances Pollution Contingency Plan, developed in response to the FWPCA. The plan designates the Coast Guard and the MMS as the lead

government agencies with responsibilities for offshore oil spill mitigation and cleanup. The respective responsibilities of these two agencies have been

clarified in several memoranda of understanding.

In general, the Coast Guard is responsible for

coordinating and directing measures to contain and

remove pollutants from the water, while the MMS

is responsible for coordinating and directing measures to abate the source of the pollution. In the

Alaska coastal region, responsibilities are further

delineated by the Alaska Coastal Region MultiAgency Oil and Hazardous Substances Pollution

Contingency Plan. Although the primary responsibility for pollution response lies with the Coast

Guard, the MMS does have the authority to suspend response operations within a 500-meter radius of the pollution source to facilitate abatement

measures.

Supervising and monitoring is the Coast Guard’s

normal role in managing a cleanup operation. It

is Coast Guard policy to encourage the responsible operator to undertake proper removal actions.

However, the Coast Guard is prepared to direct

the response if the responsible operator is either unknown or not taking satisfactory action. When the

Coast Guard is simply monitoring the cleanup operation, removal is done by commercial cleanup contractors and industry cooperatives. Historically, the

Coast Guard has been directly involved in only one

out of five removal operations. When this happens,

the Coast Guard uses its pollution revolving fund

($35 million, established by the FWPCA).36

In the event of an offshore spill, the Coast Guard

provides an On-Scene Coordinator (OSC) (the

Captain of the Port within a specific area of the

coastal zone). The OSC coordinates or directs the

Federal response to actual or potential pollution incidents. If the OSC decides that cleanup is indequate or cannot find anyone to immediately assume

responsibility for directing an action which is considered necessary, he or she will declare a Federal

B6Coast Guard capabilities for Oilspill Cleanup, Hearing before

the House Committee on Government Operations (August 26, 1982).

response and take over actual management of the

cleanup. Commercial contractors are used whenever possible, since it is the Coast Guard’s policy

not to compete with private industry. However, the

Coast Guard has developed a modest inventory of

equipment for use where commercial sources are

either not available or do not have the necessary

amount or type of equipment. Much of the Coast

Guard’s equipment is for use to combat open water

spills and was designed specifically for its use, since

there are fewer commercial sources for this type of

equipment.

The OSC has a number of resources available

to expand the amount of equipment, personnel, and

expertise available. The Regional Response Team

(RRT) can be convened at the request of the OSC

for advice or assistance in obtaining equipment or

other support. The RRT is also responsible for

planning and preparedness prior to spills. The team

consists of regional representatives of the Departments of Agriculture, Commerce (NOAA), Defense, Energy, Health and Human Services, Interior, Justice, Labor, State, and Transportation,

EPA, the Federal Emergency Management Agency,

and representatives of State governments. The National Response Team (NRT), composed of Federal agency representatives at the national level, is

also available to assist the OSC. The NRT is consulted for major policy decisions or when large scale

or specialized support not available to the RRT is

needed.

The National Strike Force (NSF) is a key Coast

Guard resource available to the OSC. When commercial resources are not adequate, the NSF is

employed. The Strike Force consists of several

teams specially trained and equipped to respond

to oil spills. The Pacific Strike Team of the NSF,

located in Marin County, California, is the unit

charged with responding to spills in the Arctic. The

NSF maintains a stock of specialized equipment

that can be deployed anywhere in nation. It is also

involved in testing and evaluation of equipment and

response methods. Other resources upon which the

OSC can draw are the Scientific Support Coordinator provided by NOAA, EPA, State and local

governments, and the academic community.

The Coast Guard has developed regional and

local contingency plans in preparation for spills.

These plans include data on possible pollution
Ch. 7—Environmental Considerations ● 199

sources, location of environmentally sensitive areas,

available contractors/cooperatives and their equipment, and plans for protecting vulnerable resources

within the area. An Environmental Atlas for the

Alaskan Beaufort Sea, which contains information

concerning general oceanography, meteorology,

ice, and climatology recently has been compiled for

use by the OSC. By compiling available information on environmental conditions and variables, the

OSC is better able to understand the environmental

conditions one could expect to encounter in the

event of a spill. If the atlas proves useful, the Coast

Guard plans to develop atlases for other lease sale

areas of the Alaskan OCS.

Industry

The offshore oil and gas industry must comply

with OCS regulations and orders. Regulations are

general rules applicable to OCS operations everywhere. OCS orders are published by the MMS and

refer to particular areas. These orders expand upon

the regulations and provide more detailed guidance

on regulatory requirements. OCS Order No. 7

stipulates the pollution prevention and control

measures required of industry. This order specifies

that lessees shall submit a description of procedures,

personnel, and equipment to be used in reporting,

cleaning up, and preventing oil spills which may

occur during exploration or development activities.

The order also requires lessees to maintain (or to

have readily available) pollution control equipment,

including booms, skimmers, cleanup materials, and

chemical agents. In addition, requirements for drills

and training procedures are also stipulated.

In addition to other requirements, OCS Order

No. 7 requires that all companies that propose to

do work in the Arctic submit an oil spill contingency

plan. Contingency plans are reviewed annually and

must contain information concerning: 1 ) amount,

type, and location of all countermeasures equipment and time required for its deployment; 2) alternative responses for spills of varying severity; 3)

plans for protection of areas of special biological

sensitivity; 4) procedures for early detection and

timely notification of an oil spill, including names

and telephone numbers of people to notify; and 5)

the necessary steps to be taken to assess the seriousness of the spill, plan the response, and begin

cleanup actions. Oil companies must specify an oil

spill response operating team consisting of trained,

prepared, and available operating personnel; an oil

spill response coordinator; a response operations

center and reliable communications system for coordinating the response; and provisions for disposal

of recovered spill materials.

The Coast Guard reviews and advises the MMS

as to the adequacy of industry oil spill contingency

plans submitted to MMS. Criteria for evaluating

plans have been defined jointly by the two agencies. The Coast Guard and MMS consider: 1) the

adequacy of the risk analysis; 2) the adequacy of

recovery equipment; 3) equipment availability; 4)

the estimated response time; 5) provisions for periodic practice drills; 6) adequacy of support vessels;

7) dispersant equipment; 8) decision procedure for

ordering ignition of an uncontrollable well; 9) disposal methods and sites; and 10) detection and

monitoring provisions.

Oil spill contingency planning efforts of individual companies are supplemented by a statewide cooperative organization, Alaska Clean Seas (ACS).

ACS has been organized to assist member companies in dealing with the possibility of a major spill.

ACS maintains spill response equipment and supplies, provides staff assistance for contingency planning and training, and conducts research and development projects to advance the state of the art

of oil spill containment and cleanup. ACS is divided

into five cost-participation areas: the Beaufort Sea,

Norton Sound, St. George Basin, the Gulf of

Alaska, and the Navarin Basin. In all, sixteen companies have joined ACS, although memberships of

each area vary according to company interests.

ABSORB, the Alaskan Beaufort Sea Oilspill Response Body, is under the ACS umbrella, and is

the regional response organization for the Beaufort

Sea. Equipment for use by members has been

stockpiled at ABSORB’s main warehouse in

Prudhoe Bay. As far as equipment staging is concerned, industry preparations seem to be very good.

In addition to providing supplemental equipment

and expertise, ABSORB has studied the biology

and shoreline characteristics of the Beaufort Sea,

and has recently assembled an oil spill response considerations manual which synthesizes knowledge of

the biological resources of the area. Industry points

out, with some pride, that it has not yet been necessary to use ABSORB equipment. However, since
200 ● Oil and Gas Technologies for the Arctic and Deepwater

there have not been any spill incidents, the capability of personnel to respond to spills under realistic conditions, remains unknown. Moreover, for

large Arctic spills, it is likely that contractors from

outside the region would have to be used. The Cook

Inlet Response Organization could possibly also

provide support for spills in the Arctic.

The Alaska Cooperative Oilspill Response Planning Committee functions in addition to the industry cooperative organizations. It consists of both

industry (ACS) and government (State and Federal) representatives. Its purpose is to foster sharing of resources and technical expertise and to facilitate cooperative oil spill response.

State of Alaska

The Alaskan Department of Environmental

Conservation requires that an oil spill contingency

plan be approved (and renewed at least once every

three years) for operations within State waters.

Moreover, concurrence of the State in the adequacy

of oil spill contingency plans must be obtained to

the extent required the CZMA. Like the Coast

Guard, if the State determines that containment

and cleanup activities are not adequate, the department may undertake cleanup itself and/or may issue

a contract for the cleanup. Where the Coast Guard

has primary authority, the State may still authorize supplemental cleanup or containment efforts.

State contingency plans are similar in most

respects to Federal requirements. Of special note,

for Tier 2 approval the State requires that 500 in

situ igniters be available within 6 hours of a spill,

and that an additional 1,000 be obtainable within

48 hours of spill. The state also requires that 1,000

feet of fire resistent boom be stored on site, and

that an additional 2,500 feet be available within six

hours. In addition, plans must be submitted for

drilling a relief well, and the decision process necessary to ignite a well must be outlined .37

sTAlaska Departments of Environmental Conservation and Natural Resources, ‘ ‘Final Finding and Decision of the Commissioners

Regarding the Oil Industry’s Capability to Clean Up Spilled Oil During Broken Ice Periods in the Alaskan Beaufort Sea’ (June 1984).

Technology Development

Under the OCS Lands Act, the Federal government requires that the oil industry use the best

available and safest technologies (BAST) in their

drilling and production operations. Criteria exist

for evaluating the adequacy of most equipment or

processes, but there are as yet no standards for

evaluating offshore oil spill cleanup technology.

One problem is that it is difficult to determine what

proportion of spilled oil is “adequate” to clean up

or how much can reasonably be expected to be

cleaned up in spill situations. The definition of

‘‘adequacy ‘‘ is as much a political issue as a technological one. Neither the government nor the oil

and gas industry is currently required to demonstrate which oil spill technology is best.

Three Federal agencies have small inhouse oil

spill research and development programs: the

MMS, the Coast Guard, and EPA. Total Federal

funding for oil spill technology research has averaged less than $1 million per year over the past five

years, One million dollars per year is considered

small in view of: a) the unknown and/or inadequate

capabilities of oil spill containment and cleanup

technologies for frontier areas; b) the Administration’s objective of accelerating OCS development;

and c) the fact that the total economic costs of major spills may reach several hundred million dollars.

Suggestions of the kinds of oil spill technology research needed are given in table 7-3.

Representatives from the U.S. agencies, along

with the U.S. Navy and the Environmental Protection Service (EPS) of Canada, comprise the

OHMSETT (Oil and Hazardous Materials Simulated Environmental Test Tank) Interagency Technical Committee (OITC). Although the Coast

Guard has funded some Arctic and offshore spill

technology research since the early 1970s, the

OITC did not become involved in Arctic or offshore oil spill technology research until 1984. The

objective of the OITC program is to evaluate oil

spill countermeasures equipment and methods for

OCS conditions. The OHMSETT test tank, located in Leonardo, New Jersey, has been used to

evaluate Arctic oil spill technology. However, because this program is new and because there have
Ch. 7—Environmental Considerations ● 201

Table 7-3.—Oil Spill Technology Research Needs

Assessment of capabilities of existing oil spill equipment

and techniques under realistic conditions

Field or large-scale tank tests of behavior of North Slope

crude oil in cold water and in ice

Assessment of behavior of oil in a moving, broken ice

field

Development of a portable oil spill response system to

be used on tankers

Development of a containment boom that can be used in

broken ice conditions

Development of better techniques for oil spill cleanup in

shallow, nearshore waters

Development of better techniques for containing oil in

scattered ice floes outside the protection of the barrier

islands

Development of more effective igniters

Development of an oil spill recovery system that can be

used on vessels-of-opportunity (vessels used to supply

offshore operations)

Determine and record the properties of air and waterborne residues of in situ burning

Determine minimum boundary conditions for effective in

situ burning (thickness, degree of weathering,

containment requirements)

Refine fire resistant containment booms

Review dispersants for cold and open water applications

SOURCE: Office of Technology Assessment

been funding limitations, little testing of equipment

for use in Arctic or deepwater areas has been accomplished to date.

The OITC has recently proposed a 5-year program for testing OCS booms and skimmers. This

program would consist of three phases: 1) tank

testing; 2) assessment of equipment capability at

sea for seakeeping and durability (in accordance

with a rigorous, pre-determined test protocol); and

3) exposure of the equipment under OCS conditions to intentional oil spills. The OITC also proposes to continue tests, begun in 1984, on the potential for mechanical recovery and in situ burning

of oil in broken ice as a mitigation measure; to continue investigation of new technologies; and to take

advantage, when possible, of spills-of-opportunity

to gather equipment performance data.

The OITC program has been level-funded at

$400,000 per year with the MMS, Coast Guard,

and EPA each contributing about $125,000, and

EPS contributing about $25,000. Continued funding at this level is considered unlikely in light of

the budget constraints of the participating agencies.

EPS participation is considered very important,

since the Canadian agency also conducts spill research, the results of which are available to the

OITC. The Coast Guard also contributes logistical

support. Although the MMS has spent about $372

million (or an average of approximately $31 million per year) for OCS environmental studies since

1973, none of this money has been allocated for oil

spill equipment research.

Since the 1970s, little industry or government

effort has been given to developing technology or

methods for the specific purpose of combatting oil

spills in deepwater. As oil and gas activities increase

in deeper and more distant waters, the continued

use of conventional recovery equipment in these

areas may need further analysis. In particular, technologies for open-ocean rough sea recovery and

deepwater sea floor containment may need further

development. However, the major difference between countermeasures problems in deepwater and

spill problems nearshore is logistical rather than

technological. Logistical concerns include how to

transport the equipment needed to contain, recover,

store, and dispose of oil to the spill site in a timely

way.

The MMS is currently funding two engineering

studies to deal specifically with deepwater subsea

blowouts: 1) the feasibility of deploying a large selfcontained collection ship capable of remaining onstation while collecting oil and gas from a blowing

well using a subsea collector similar to that used

in the Ixtoc 1 blowout (the ‘ ‘sombrero’ ‘); and 2)

the feasibility of deploying a collection ship equipped

with skimming booms to collect and separate oil

in close proximity to a blowing well. Such a ship

would have to be large enough to remain on-station

in heavy weather and to store two to three weeks

of recovered oil. The availability of such selfcontained ships could possibly overcome many of

the logistics problems related to deepwater spills;

however, costs may be extremely high.
Appendixes
Appendix A

Offshore Leasing Systems

U.S. Federal Leasing System for

Offshore Areas

Description

Federal offshore leasing is conducted according to the

guidelines contained in the Outer Continental Shelf

(OCS) Lands Act of 1953, as amended in 1978, which

authorizes the Secretary of the Interior to grant mineral

leases for OCS lands and to prescribe any necessary regulations. Currently, the Minerals Management Service (MMS) within the Department of the Interior is responsible for implementing the offshore leasing system

and the operating regulations.

In general, the Interior Department identifies an area

for leasing in accordance with a pre-set lease schedule.

It surveys the hydrocarbon potential, calls for information, and prepares a draft environmental impact statement. After filing a final environmental impact statement with the Environmental Protection Agency, the

lease sale is announced and comments are solicited from

the States and other interested parties. With appropriate modifications, the lease sale takes place and firms

are awarded offshore tracts according to a competitive

bidding process. In the post-lease phase, companies

must submit extensive safety and environmental protection plans with each stage of exploration, development, and production. The post-lease management

functions of the Department of the Interior involve approval and enforcement of the plans and collection of

government revenues. The pre-lease and post-lease steps

of the leasing process are outlined in table A-1 and figure A-1.

LEASE SCHEDULE

Prior to the enactment of the OCS Lands Act Amendments of 1978, the Department of the Interior was not

required to develop a prospective leasing program or

plan. Between the start of leasing in 1954 and 1967,

nearly all offshore tracts nominated by the industry were

offered for leasing. However, in 1967, the Department

of the Interior instituted a formal nomination and selection system that required a resource evaluation and

determination of industry interest before tracts were offered for sale. Subsequent to the passage of the OCS

Lands Act Amendments of 1978, leasing programs have

been developed in accordance with Section 18 of the Act,

which requires that the Secretary of the Interior prepare and periodically review a 5-year leasing schedule

which is consistent with the principles of the Act.

The selection of areas to be included in the lease

schedule is influenced by initial assessments of oil and

gas potential, environmental concerns, economic conditions, location of commercial fisheries, availability of

technology, and other factors. Geological and environmental information on the Outer Continental Shelf is

collected and evaluated by the Department of the Interior. Companies may obtain permits for preliminary

offshore exploratory activity, including broad area

reconnaissance to identify promising geologic formations

and requirements for more detailed seismic surveys. In

certain circumstances, permits may be granted to firms

to take bottom samples or cores (COST wells) to obtain additional geologic information. The government

may request the submission of all pre-lease geological

and geophysical data and information.

Final approval of the 5-year OCS leasing program

takes approximately 2 years. Comments are solicited

from the States, industry, Federal agencies, and other

interested parties at several points in the development

of the plan. After comments are received and appropriate modifications are made, the final schedule is submitted to the President and Congress for review.

CALL FOR INFORMATION

The initiation of individual lease sales begins with the

identification of areas of hydrocarbon potential by the

Department of the Interior. A Call for Information is

issued for a large area, usually consisting of several million acres, and is published in the Federal Register with

a 45-day comment period. Potential bidders are asked

to identify areas they wish to have offered for lease.

States and other interested parties may identify and recommend areas which should be excluded from oil and

gas leasing or only leased under special conditions because of conflicting resource values or environmental

concerns. At the same time, a Notice of Intent to prepare an Environmental Impact Statement (EIS) is published, which invites public assistance in determining

significant issues. The information received from the

public, as well as the resource, environmental, and technical information collected by the Department of the Interior, are used to identify an area for further analysis

in the EIS.

In the proposed 1986-91 5-year leasing schedule, an

additional lease sale step has been added for selected

frontier-area sales. A Request for Interest will be made

four months prior to the Call for Information. This request will help determine industry interest in leasing in

these areas and whether the 2-year sale process should

205
206 ● Oil and Gas Technologies for the Arctic and Deepwater

Table A-1.–Steps in Offshore Leasing (1984)

Timeframe: month

Activity Lower 48 Alaska Action

Pre-lease phase:

Five-Year

Leasing Program

Identify area of

Hydrocarbon Potential

Call for Information;

Publish Notice of

Intent to Prepare EIS

Area Identification

Draft Environmental

Impact Statement

Final Environmental

Impact Statement

Proposed Notice of

Lease Sale

Final Notice of

Lease Sale

Lease Sale

Leases Issued

Post-lease phase:

Exploration Plan

Environmental

Analysis

Exploration

Drilling

Development and

Production Plan

Environmental

Analysis

Development

Drilling

Pipeline

Permits

Production

Relinquishment

2-5 years prior to

to call

At least 2 months

prior to call

1 1

4 4

12 15

18 21

19 22

22 25

23 26

25 28

Within 4 years of

lease issue (for

5-year terms)

For all exploration

wells

Within 5 years of

lease issue/or

receives SOP

For all exploration

wells

For duation of

production

Cancellation or

shutdown

Prepare schedule of proposed lease

sales, to be revised annually.

Industry, states, and other parties

comment prior to final approval.

Identify area of hydrocarbon potential

(AHP) for upcoming sale.

Request bidders to indicate areas

of interest and solicit comments from

all interested parties. Due in 45 days.

Also announce initiation of EIS

scoping.

Identify areas for detailed environment analysis.

Draft EIS issued for planning area

and notice published in Federal

Register. Comments requested and

hearings held during 60-day comment

period.

Revised EIS submitted to EPA for

review and made available to public.

Proposed notice of sale, with terms

and conditions, sent to States for

comment for a 60-day period.

Final notice of sale published in

Federal Register at least 30 days

prior to sale.

Regional office holds public opening

and reading of sealed bids.

Leases issued not later than 90 days

later, after bid review and anti-trust

review.

Lessee submits exploration plan and

environmental report. States evaluate

for CZM consistency.

MMS conducts environmental analysis,

prepares EIS if necessary, and

approves or rejects plan.

Lessee submits application to drill

(APD) and applies for permits from

other agencies. After analysis, MMS

approves or rejects.

Lessee submits development and

production plan and environmental

report. States review for CZM

consistency.

MMS conducts environmental analysis,

prepares EIS if necessary, and

approves or rejects plan.

Lessee submits APO and required

permits, State CZM ruling, and platform verification and certification.

MMS approves or rejects.

Lessee applies for pipeline permits

from MMS and other relevant

agencies.

Lessee submits monthly production

reports and royalty payments.

Wellheads plugged and equipment

removed.

SOURCE: Office of Technology Assessment.
App. A—Offshore Leasing Systems • 207

Figure A-1 .—Offshore Leasing Process: Pre-Lease

Other

Federal

Public Industry States agencies I FWS/NPS MMS Secretary

Federal

Register

Input

Federal

Register

Hearinqs

Federal

Register

Federal

Register

Federal

Register

●

5-year OCS Oil-and-gas leasing schedule

Input Geology and

resource reports

1

[

Defin area of

hydrocarbon potential Approve

Call for reformation

Notice of intent to 45-day comment period prepare EIS 4 Step 1

Approve

Call closes

– Evaluate comments

– Evaluate multiple uses

in EIS process

Area Identification

Step 2

Approve

—— .— — Draft EIS

(regional office)

60 day comment period

●- ~

Final EIS

Governors — — Secretarial issue document

sale

decision

*

Governors

Governors 60 day comment period on proposed notice of sale Dec ision ● meeting on

areas terms

Conditions

Publi shed 30 days prior 10 sale

— Final notice of sale Step $ Approve

Bids ● sale

Just Ice

Department/

Federal Trade

Commission review

[

Sale results I

Bid acceptance decisions

Lessee — — Lease Issuance

J

SOURCE Minerals Management Service
208 . Oil and Gas Technologies for the Arctic and Deepwater

—Offshore Leasing Process: Post-Lease

Public

Federal

register

Public hear

Federal

register

Public hearing

I

I

I

● Regs Corps

● construction

Pipeline I

permit I I

I construction I I

Monthly

prod reports ●

& royalties

Product Ion

1 1 1

I I I

1 1 Official record

title actions

Secretary

Cancellation

SOURCE: Minerals Management Service
App. A—Offshore Leasing Systems ● 209

proceed. The Request for Interest will be made for the

following Alaska sales: Gulf of Alaska (1988); Cook Inlet (1990); Shumagin (1990); Hope Basin (1991); and

Kodiak (1991).

ENVIRONMENTAL ASSESSMENT

The National Environmental Policy Act (NEPA) of

1969 requires the analysis, assessment, and disclosure

of environmental impacts that may result from Federal

offshore leasing. The environmental assessment process for offshore lease sales involves the preparation of

preliminary and final environmental impact statements,

public hearings, and consultation with affected States

and all interested parties.

The first step is the preparation of a Draft Environmental Impact Statement (DEIS) by the Department

of the Interior. For the first sale in a planning area, the

DEIS is prepared for the entire area; abbreviated

statements are prepared for subsequent sales. The DEIS

includes a description of the lease proposal, a description of the marine and nearby onshore environment,

a detailed analysis of possible adverse impacts on the

environment, the technology to be used, the socioeconomic impacts, mitigating measures proposed, alternatives to the proposal, and the records of consultation and

coordination with others in preparation of the statement.

The DEIS is published in the Federal Register with a

60-day comment period, and public hearings on the

DEIS are held within the vicinity of the proposed lease

sale.

A Final Environmental Impact Statement (FEIS) is

then prepared taking into account the comments received during the review period and at the public hearings. The FEIS is filed with the Environmental Protection Agency and made available to the public.

NOTICE OF LEASE SALE

At least 30 days after the submission of the FEIS to

the Environmental Protection Agency, a final decision

is made by the Secretary of the Interior as to whether

or not the proposed sale will be held. A Secretarial Issue

Document (SID) is first prepared which analyzes the

issues and options pertaining to the sale area, and includes information on alternative terms and procedures

to be used in the lease sale. If the decision is to hold a

sale, the SID and the final EIS are submitted to the affected States for comment within 60 days. A Proposed

Notice of Lease Sale is published in the Federal Register identifying the blocks to be leased and the leasing

stipulations, terms, and procedures.

After the 60-day comment period, the Final Notice

of Lease Sale is published in the Federal Register. Taking into consideration public comments and State concerns, the final notice lists the tracts to be included in

the sale, the terms under which the sale will be held,

and any special stipulations that may be imposed on particular tracts. It also gives at least a 30-day notice of

the date, place, and time that bids are to be opened.

LEASE SALE

All leases are sold through a competitive bidding process with firms submitting separate sealed cash bids for

each individual tract. All bids are opened and read at

a public sale, after which the bids are checked for technical and legal adequacy. In addition, a determination

of the adequacy of the high bids is conducted. The

acceptance or rejection of each bid occurs within 90 days

after the lease sale is held.

LEASE CONTRACT

The oil and gas lease contract grants the right to the

lessee to conduct necessary operations to explore, drill

and produce oil and gas from a specific tract. The primary term of the lease contract is usually 5 years, although 10-year terms are granted for special conditions,

such as ice-prone areas or deepwater sites. During this

time, oil and gas in commercial quantities must be found

or approved drilling or well reworking operations must

be conducted, or the lease is forfeited. Leases may be

extended beyond the initial lease terms as long as production is occuring, drilling or well reworking is undertaken, or a special suspension order is obtained.

EXPLORATION

The lessee is obligated to proceed diligently to explore

and develop the tract and must submit an exploration

plan to the Department of the Interior for approval by

the fourth year of a 5-year lease. Details of drilling technology, geophysical equipment, location of exploratory

wells, oil spill contingency plans, an air quality analysis, and other relevant geological and geophysical information must be included in the plan. The exploration plan must be accompanied by an environmental

report, and certifications of consistency must be obtained from coastal States under the Coastal Zone Management Act. After an environmental assessment, an

environmental impact statement if necessary, and a

technical review, the Department of the Interior approves, rejects, or modifies the exploration plan.

Before exploratory drilling can be initiated, an Application for Permit to Drill (APD) must be submitted.

This includes detailed information on equipment design,

well location and depth, and potential geophysical

hazards. Additional approvals are required each time

a well is deepened, reworked, redrilled, or plugged back.

In addition to the Department of the Interior permit to

drill, appropriate permits must be received from the
210 ● Oil and Gas Technologies for the Arctic and Deepwater

U.S. Coast Guard, U.S. Army Corps of Engineers,

Environmental Protection Agency, and other federal

agencies to satisfy environmental or safety requirements.

DEVELOPMENT AND PRODUCTION

The planning, environmental assessment, and approval process starts anew when oil and gas is discovered on a tract. A detailed Development and Production Plan and accompanying environmental report must

be submitted by the lessee to the Department of the Interior for approval. Certifications of consistency also

must be obtained from the coastal zone management

programs of the affected States. The plan and environmental report are reviewed by a number of Federal

agencies and affected States, and the Department of the

Interior prepares its own environmental evaluation and

technical review. In addition, a separate platform verification and certification process, involving third-party

verification agents, is initiated for the evaluation and

monitoring of platform design, fabrication, and installation.

An APD must be received prior to drilling any development well, and any reworking of development wells

also must be approved. All other necessary Federal permits, such as for offshore structures, navigation aids,

and pollution discharge, must be obtained prior to approval of the APD by the Department of the Interior.

Permits and approvals also must be received for the construction and operation of offshore pipelines and for any

significant modification of production equipment and

procedures. As production proceeds, the Department

of the Interior is responsible for on-site inspection and

monitoring of offshore operations. The lessee must submit monthly reports of operations and royalty payments

to the government.

RELINQUISHMENT

Leases expire at the end of their initial term unless

actual production is occurring or a suspension of production or operation (SOP) is received for development

activities or approved drilling or well reworking operations. Leases may also be relinquished by a lessee or

cancelled by the Department of the Interior for noncompliance with OCS regulations. At the time of abandonment, the operator must plug the wells in accordance with Interior requirements. All oil and gas zones

must be isolated by the installation of cement plugs to

ensure a permanent seal. All pipe casings must be cut

off below the ocean floor and the well location must be

cleared.

Offshore Leasing Revenues

LEASE PAYMENTS

Revenues from offshore leasing consist of bonuses,

rents, and royalties in addition to taxes. Bonuses are

advance cash payments made by companies for the right

to explore and develop particular tracts. Rents are annual fees, now set at $3 per acre, paid on leased acreage. Royalties are pre-set percentages of the value of

oil and gas production paid after production begins. The

standard royalty rate on offshore production has been

162/3 percent, although some tracts have been leased

with 121⁄2 percent and 331/3 percent royalties. A few

tracts also have been leased with profit share payments

and sliding scale royalties rather than fixed royalties.

From the start of the OCS leasing program in 1954

to the end of 1983, bonuses, rents, and royalties from

offshore leases have totaled approximately $68 billion

(see table A-2). OCS receipts increased from an average of $280 million per year in the 1950s and 1960s to

an average of $3 billion per year in the decade of the

1970s. In the early 1980s, OCS receipts averaged more

than $8 billion per year. In general, the level of receipts

has increased with the quantity of acreage leased, the

amount of oil and gas produced, and increases in energy

prices.

Bonuses have comprised the largest share of government lease payments (69 percent) other than taxes and

account for most of the variation in annual OCS

receipts. Bonus receipts increased substantially in 1973-

74, as a result of the Nixon administration initiatives

to increase offshore leasing, and in 1979-83 as leasing

was again accelerated. In 1981, bonus receipts reached

a high of $6.6 billion for over 2 million leased acres.

Bonus revenues declined from the 1981 level in 1982

and 1983, due to depressed oil prices, the more costly

and risky nature of the deepwater and Alaskan tracts

being leased, and other factors.

From 1953 to 1983, a total of 6 billion barrels of oil

and 62 trillion cubic feet of gas were produced in Federal offshore areas. Although offshore oil production declined every year between 1971 and 1980, it again

turned upward in 1981 when 286 million barrels of oil

were produced. In 1983, Federal offshore hydrocarbon

production represented approximately 11 percent of the

oil and 24 percent of the natural gas produced in the

United States, The cumulative value of the oil and gas

produced offshore between 1953 and 1983 is estimated

at $128 billion, of which $20 billion or 16 percent was

paid to the Federal Government in royalties. Lease payments by companies (not counting taxes) accounted for
App. A—Offshore Leasing Systems • 211

Table A-2.—OCS Acreage, Production, and Revenues (1953-1983)

Acreage Production Revenues ($ billion)

Year Sales Offered Leased Oil (mbbl) Gas (tcf) Bonuses Royalties Rents* Total

1953 . . . . . . . . . . . . .

1954 . . . . . . . . . . . . .

1955 . . . . . . . . . . . . .

1956 . . . . . . . . . . . . .

1957 . . . . . . . . . . . . .

1958 . . . . . . . . . . . . .

1959 . . . . . . . . . . . . .

1960 . . . . . . . . . . . . .

1961 . . . . . . . . . . . . .

1962 . . . . . . . . . . . . .

1963 . . . . . . . . . . . . .

1964 . . . . . . . . . . . . .

1965 . . . . . . . . . . . . .

1966 . . . . . . . . . . . . .

1967 . . . . . . . . . . . . .

1968 . . . . . . . . . . . . .

1969 . . . . . . . . . . . . .

1970 . . . . . . . . . . . . .

1971 . . . . . . . . . . . . .

1972 . . . . . . . . . . . . .

1973 . . . . . . . . . . . . .

1974 . . . . . . . . . . . . .

1975 . . . . . . . . . . . . .

1976 . . . . . . . . . . . . .

1977 . . . . . . . . . . . . .

1978 . . . . . . . . . . . . .

1979 . . . . . . . . . . . . .

1980 . . . . . . . . . . . . .

1981 . . . . . . . . . . . . .

1982 . . . . . . . . . . . . .

1983 . . . . . . . . . . . . .

Totals . . . . . . . . . .

3

1

0

0

0

2

2

0

3

1

2

1

3

2

3

3

2

1

2

2

4

4

4

2

4

6

3

7

5

8

77

1384238

674095

0

0

0

539813

1632339

0

3718115

669777

1124102

947520

265886

988484

1315984

355758

666845

55872

970711

1514940

5006881

7247327

2827342

1843116

3140696

3413352

2563452

7679740

5815872

120094037

176456294

486870

402567

0

0

0

171300

707026

0

1929177

312945

613524

72000

141768

746951

934164

114282

598540

37222

826195

1032570

1762158

1679877

1277937

1100734

1297274

1767443

1134238

2237005

1886360

6593517

29863644

1

3

7

11

16

25

36

50

64

90

105

123

145

189

222

269

313

361

419

412

395

361

330

317

304

292

286

277

286

321

341

6371

0.020

0.056

0.081

0.083

0.083

0.127

0.207

0.273

0.318

0.452

0.564

0.622

0.646

1.007

1.187

1.524

1.954

2.419

2.777

3.039

3.212

3.515

3.459

3.596

3.738

4.385

4.673

4.641

4.880

4.679

3.940

62.157

0.000

0.141

0.108

0.000

0.000

0.000

0.090

0.283

0.000

0.489

0.013

0.096

0.034

0.209

0.510

1.346

0.112

0.945

0.096

2.251

3.082

5.023

1.088

2.243

1.568

1.767

5.079

4.205

6.602

3.987

5.749

47.116

0.001

0.003

0.005

0.008

0.011

0.018

0.027

0.037

0.048

0.067

0.078

0.089

0.104

0.144

0.160

0.203

0.242

0.285

0.352

0.366

0.404

0.562

0.618

0.702

0.921

1.152

1.517

2.139

3.274

3.815

3.376

20.728

0.001

0.004

0.003

0.004

0.003

0.002

0.002

0.004

0.003

0.008

0.008

0.010

0.009

0.007

0.006

0.008

0.009

0.009

0.008

0.008

0.009

0.014

0.018

0.023

0.020

0.022

0.020

0.019

0.021

0.020

0.037

0.339

0.002

0.148

0.116

0.012

0.014

0.020

0.119

0.324

0.051

0.564

0.099

0.195

0.147

0.360

0.676

1.557

0.363

1.239

0.456

2.625

3.495

5.599

1.724

2.968

2.509

2.941

6.616

6.363

9.897

7.822

9.161

68.182

‘Includes minimum royalties, shut-in gas, etc.

SOURCE: Minerals Management Service.

about 53 percent of the total value of oil and gas pro- production and 96 percent of all oil production in Fedduction in that period. eral offshore areas. The balance of offshore oil and gas

The greatest share of OCS receipts (83 percent) has production in Federal waters is from offshore Califorbeen from the Gulf of Mexico (see table A-3 and figure nia. As a result, the Gulf of Mexico has accounted for

A-2). The Gulf of Mexico, predominantly offshore Loui- 77 percent of bonus revenues, 97 percent of oil and gas

siana, accounts for over 99 percent of all natural gas royalties, and 79 percent of all rents received. Leasing

Table A-3.—OCS Regions: Production and Revenues (1953-1983)

Production Revenues ($million)

oil Gas

Regions (mbbl) (bcf) Bonuses Royalties Rents Total

Gulf. . . . . . . . . . . . . . . . . . 6,096 62,037 36,076 20,196 269 56,541

Pacific . . . . . . . . . . . . . . . 275 120 3,840 532 31 4,403

Alaska . . . . . . . . . . . . . . . 0 0 4,360 0 22 4,382

Atlantic . . . . . . . . . . . . . . 0 0 2,840 0 17 2,857

Total . . . . . . . . . . . . . . . 6,371 62,157 47,116 20,728 339 68,183

mbbl - million barrels

bcf-billion cubic feet

SOURCE: Minerals Management Service,
212 • Oil and Gas Technologies for the Arctic and Deepwater

Figure A-2.—Federal Revenues From OCS Regions

1953-1983

 A

Pacific (6

Atlantic (4.2°/0)

Alaska (6.4°/0)

.5%)

SOURCE: Office of Technology Assessment

in the Alaskan and Atlantic offshore regions began in

1976, and while they have contributed some bonus

revenues and rents, there is as yet no oil and gas production or royalty revenues from these regions.

FEDERAL TAXES

In addition to lease payments, companies also pay

Federal taxes on offshore oil and gas production. In general, the oil and gas producing industry in the United

States benefits from special tax provisions designed to

encourage domestic energy exploration and production.

In recent years, this tax advantage has been reduced

by the Crude Oil Windfall Profits Tax. Offshore oil and

gas producers may currently expense and deduct certain costs, including intangible drilling costs (up to 80

percent) and dry hole costs, which would normally be

recovered through depreciation. Oil and gas producers

also benefit from two general provisons of the Federal

tax code available to all business: the depreciation

deductions under the Accelerated Cost Recovery System and the regular 10 percent investment tax credit.

In 1980, Congress enacted the Crude Oil Windfall

Profits Tax, an excise tax per barrel on the difference

between the crude oil market price and an established

base oil price. The rate varies between 15 and 70 percent depending on the oil tier (e. g., old oil, stripper oil),

type of producer, and year of production. The tax on

newly discovered oil is to be phased down from the current 22.5 percent to 20 percent in 1988 and to 15 percent in 1989 and thereafter. The Windfall Profits Tax

does not apply to oil production from Arctic areas. The

Windfall Profits Tax should not apply to oil producers

in other offshore frontier areas, as the base price should

exceed the market price before fields come on stream

in these regions.

REVENUE TRENDS

Owing to the substantial funds received by the Federal Government from offshore leasing, there has been

controversy regarding the relationship between offshore

leasing and revenue policy. It is widely believed that

the pace of leasing has been partly dictated by budget

concerns. In the early years of leasing, the Department

of the Interior was accused of maintaining a deliberately

slow rate of leasing in order to keep the demand for

leases and bonus revenues high. In the 1970s, the General Accounting Office (GAO) charged that the government accelerated leasing in order to increase revenues

for the general Treasury. Similarly, the accelerated leasing schedule which began in 1982 is believed by some

to stem partly from the need to generate revenues and

reduce the large Federal budget deficit.

Budget concerns may have also influenced government forecasts of future revenues from OCS leasing. It

is difficult to project OCS receipts because of the subjective nature of resource estimates, unpredictability of

future prices and development costs, and unforseen

changes to lease schedules. The Office of Management

and Budget (OMB) has overestimated—by a factor of

2 or more—projected receipts from offshore leasing in

the 1980s. The original OMB budget estimates for fiscal

year 1984 were for $18 billion in receipts from OCS leasing; this was later revised downward to $12 billion; however, actual fiscal year 1984 OCS leasing revenues were

in the area of $8-9 billion. For fiscal year 1985, OMB

has again projected $12 billion in OCS revenues, as

compared to a Department of the Interior estimate of

$6 billion.

The Department of the Interior projects that royalty

revenues will surpass bonus revenues for the first time

in 1985-86 (see figure A-3). Interior forecasts show that

annual bonus revenues will decline to an average $2 to

$3 billion per year while royalties level off at $3 to $4

billion per year during 1985-89. At the same time, the

costs of post-lease management activities will rise as a

result of the increases in leased acreage and the difficulty of operating conditions in frontier areas. The balance between income from offshore leasing and the costs

of management programs may change as leasing proceeds in offshore frontier areas.

State Offshore Leasing Policies

The offshore leasing systems used by the coastal States

are similar to that used by the Federal Government.

Certain aspects of the Federal leasing process were
App. A—Offshore Leasing Systems ● 213

Figure A-3.—OCS Revenues Forecast

Bonuses and Royalties

c

9

n Bonuses

O Royalties

8

7

I

5

3

2

1

0

1953 1960 1965 1970

SOURCE Off Ice of Technology Assessment,

adapted from the State experience, such as the one-sixth

royalty rate which was that traditionally used for offshore tracts by the State of Louisiana. Louisiana, California, and Texas leased offshore lands under their jurisdiction prior to the enactment of the Submerged Lands

Act of 1953, which established offshore State/Federal

boundaries, and the 1953 OCS Lands Act, which provided guidelines for the Federal system. Through 1983,

the States accounted for 39 percent of the oil and 19 percent of the natural gas produced in the offshore areas

of the United States. Currently, State offshore oil and

gas production is decreasing. Production in Federal

waters now accounts for about 80 percent of total offshore oil production and 88 percent of total offshore gas

production.

Although Florida, Alabama, Mississippi, and Washington State have leased offshore tracts, the States of

Louisiana, California, Texas, and Alaska have accounted for most of the State offshore activity and are

the only States to have offshore hydrocarbon production (see table A-4). Since the start of State leasing in

the 1920s, Louisiana has accounted for most of the wells

drilled and hydrocarbons produced in State waters. California, which has not issued any leases since 1969, ac1975 1980 1985 1990

Year

Table A-4.—State Offshore Leasing Statistics

(cumulative through 1983)

Production

Wells Oil* Gas

State drilled (mbbl) (bcf)

Louisiana . . . . . . . . . . . . . . . . 4,688 1,338 9,654

California . . . . . . . . . . . . . . . . 3,598 1,884 716

Texas . . . . . . . . . . . . . . . . . . . 1,451 26 2,877

Alaska . . . . . . . . . . . . . . . . . . 379 816 1,126

Other . . . . . . . . . . . . . . . . . . . 29 0 0

Total State , . . . . . . . . . . . . 10,145 4,064 14,373

Total Federal . ..........22,095 6,371 62.157

“Includes condensate.

mbbl - million barrels.

bcf - billion cubic feet,

SOURCE: Minerals Management Service.

counts for the highest percentage of oil and condensate

produced in State offshore areas. Currently, most State

drilling activity is centered off Louisiana and Texas.

The leasing process used by the States is generally

similar to the Federal system in its administrative

framework, competitive bidding system, and lease terms

(see table A-5). AS does the Federal Government, the
214 . Oil and Gas Technologies for the Arctic and Deepwater

Lead Leasing Agency

Permitting Agencies

Frequency of Sales

EIS Requred

Lease Term

Primary Bidding

System

Royalty Rate

Rental

Taxes

Table A-5.—Comparison of Federal and State Leasing Policies

Federal Louisiana California Texas Alaska

Minerals Management State Mineraal State Lands School Land Board Department of Natural

Service

EPA, Coast Guard,

Army Corps of

Engineers

5-8 year

Yes

5/10 years

Cash bonus bid/

fixed royalty

121⁄2% or

162/3 0/0

$3 per acre annually

Corporate Income Tax

Windfall Profits Tax

(except in Arctic)

Board

Office of Conservation, Depts.

of Natural Res.,

Env. Quality, and

Wildlife & Fish

Monthly

No

5 years

Cash bonus and

royalty bid

Estimated 21 -26°/0

1/2 cash bonus

Severance Tax

(12.50/,)

SOURCE: Office of Technology Assessment.

States receive revenues from offshore leasing in the form

of cash bonuses, royalties, and other types of lease payments, and from various tax levies. The States have

typically set higher royalty rates on production than the

Federal Government, largely because State offshore

areas are nearer to shore and less costly and risky to

explore and develop than Federal waters.

Louisiana

Most oil and gas activity in State offshore areas has

been off the coast of Louisiana, which has developed

a sizeable onshore support, service, and refining base.

The first offshore tract was leased in the 1920s, and

through 1983, almost 4,700 wells had been drilled in

Louisiana waters. Oil and gas production from offshore

Louisiana has been declining since the early 1970s. In

1983, Louisiana produced 24 million barrels of oil and

316 million cubic feet of natural gas. In contrast, production in Federal waters offshore Louisiana in 1983

was about 290 million barrels of oil and almost 3 billion cubic feet of gas. Approximately 40 percent of Louisiana’s 1 million acres of State offshore lands was under

lease as of 1983.

Louisiana conducts monthly lease sales, and State

revenues have depended heavily on offshore leasing. The

bidding system used in Louisiana is a hybrid with both

the cash bonus amount and the royalty rate open to bid.

In addition, companies may submit several bids on the

same tract. Each bid is considered if it meets the minimum royalty rate of 121⁄2 percent and any specified minCommission

Coastal Commission State Railroad

(in dispute)

Not since 1969

Yes

20 years

Cash bonus bid/

sliding royalty

Estimated 25%

$1 per acre

annually

Corporate Income

Tax (9%)

Commission

Twice a year

No

5 years

Cash bonus bid/

fixed royalty

250/o

$1 per acre

annually

Severance Tax

(4.6°/0 oil/

7.50/0 gas)

Resources

Oil and Gas Cons. Comm.

Dept. of Env. Cons.

Dept. of Fish and Game

Office of the Governor

At least 3 per year

Yes (for major sales)

10 years

Cash bonus bid/

fixed royalty

200/0

$1 per acre annually

Corporate Income Tax

(9.4%)

Severance Tax

(12.5-15°/0)

Property Tax

imum bonus amount. In the 1980s, it is estimated that

the average royalty rate has been 21 to 26 percent. The

rental fee is set at one-half of the cash bonus amount

for each tract. Louisiana has no corporate income tax,

but has a severance tax of 12.5 percent on oil and 7 cents

per cubic foot of gas.

California

From the start of leasing in 1929 through 1969,

the State of California issued 62 offshore leases. A

moratorium was placed on offshore leasing in 1969

as a result of the Santa Barbara Channel blowout.

However, drilling on previously leased lands was

allowed to continue and some leases were extended.

The State is currently planning to resume leasing

in the Point Conception/Point Arguello offshore

areas, pending the settlement of jurisdictional questions with the California Coastal Commission.

From the start of leasing through 1983, approximately 1.9 billion barrels of oil and 700 billion

cubic feet of gas have been produced in the California offshore. This is far more than has been produced in Federal waters offshore the State, representing almost 90 percent of the total oil and gas

produced off the coast of California to date.

California traditionally has awarded leases on the

basis of a cash bonus bid with a sliding scale royalty

rate, set at a minimum of 162/3 percent. It is esti-
App. A—Offshore Leasing Systems ● 215

mated that the sliding scale royalty system has resulted in an overall effective royalty rate of 25 percent. Several other types of bidding systems are

authorized by California regulations, and the State

plans to experiment with net profit share payments

in future lease sales. The other lease payment is

an annual rental fee of not less than one dollar per

acre, Taxes on offshore operators include a 9 percent corporate income tax, which is applicable to

the worldwide income of the company. Although

the State does not have a

it does levy a small fee on

in order to finance offshore

ulatory activities.

severance tax as such,

oil and gas production

administrative and regTexas

Texas issued its first offshore lease in 1922, drilled

the first well in State waters in 1938, and recorded the

first production in 1940. Until the 1980s, oil and gas

production from State waters remained about equal with

that from Federal waters offshore the State. However,

oil production in Federal waters has now increased to

about 90 percent of total oil produced offshore Texas,

while Federal offshore natural gas production increased

to 78 percent of the total in 1983. It is estimated that

more than two-third’s of the State’s offshore area has

been leased, and that State offshore oil and gas production will continue to decline. In 1983, approximately

2 million barrels of oil and 148 million cubic feet of gas

were produced in State waters.

Texas holds lease sales twice a year and leases most

offshore tracts by a cash bonus bid/fixed royalty bidding system. However, Texas also has used royalty bidding for 10 to 15 percent of its offshore tracts, primarily those where hydrocarbon prospects were high. In

both types of bidding systems, the minimum royalty rate

is now 25 percent, Texas also has a graduated rental

fee system which increases with the number of years

acreage is held, amounting to $1 per acre after the fourth

year. The Texas severance tax consists of 4.6 percent

on oil production and 7.5 percent on natural gas production, and there is also a small regulatory tax.

Alaska

Alaska issued its first State offshore leases in 1959.

Unlike other States with offshore oil and gas production, Alaska has as yet no oil or gas production in Federal waters off the State. However, a probable commercial discovery was announced at Seal Island in the

Beaufort Sea in 1984. In 1983, Alaska produced 22 million barrels of oil and 90 million cubic feet of gas from

offshore State leases. Offshore gas production has continued to increase, while offshore oil production has declined since the 1970s. There is still substantial activity

in State waters where 14 drilling platforms were stationed and 18 wells drilled in 1983, as compared to 3

structures in Federal waters in that year.

Prior to 1978, Alaska used the Federal bidding system of cash bonus bid and 162/3 or 121⁄2 percent royalty

in leasing State offshore tracts. Amendments to Alaska’s

oil and gas leasing laws in 1978 broadened the State’s

bidding methods. Since 1978, Alaska has leased a

greater number of tracts with sliding scale royalties as

well as with profit share and royalty rate bidding. In

addition, the minimum royalty rate was increased to 20

percent. This was due to concern about declining oil

production and the desire to increase revenues from potentially large oil and gas discoveries, particularly

downstream revenues. Alaska is one of the few States

which collects more revenues from oil and gas production in the form of taxes than in the form of lease payments. These taxes include a corporate income tax, a

property tax, and a severance tax, which increases from

12.5 percent to 15 percent of the value of oil and gas

production after 5 years.

Foreign Offshore Leasing Policies

Comparison of U.S. and Foreign Systems

The offshore leasing systems used in other countries

differ from that used in the United States. Canada, the

United Kingdom, and Norway, as well as the United

States, are currently leasing offshore tracts in high-risk,

high-cost regions of the Arctic and the North Sea. These

areas are characterized by harsh operating environments

that require complex planning, long lead-times to first

production, high capital outlays, and the use of innovative technologies. In the design of its leasing system

for offshore frontier areas, the United States differs from

these countries in several aspects (see table A-6).

ALLOCATION OF LEASE RIGHTS

The United States is one of the few countries to grant

leases solely on the basis of financial competition. Most

other countries rely on governmental discretion and

industry-government negotiation to award lease rights.

Foreign lease allocation is by subjective comparison of

the qualifications and terms being offered by applicants.

After negotiation with the firm, foreign governments

may include stipulations in the leases to ensure rapid

exploration and development of specified areas, provide

for government participation in oil and gas production,

protect the environment, provide for local employment,

or further other national goals. While discretionary allocation provides greater scope for government influ-
216 ● Oil and Gas Technologies for the Arctic and Deepwater

Table A-6.—Comparison of United States and Foreign Offshore Leasing Policies

Leasing Provisions

Allocation

Lease terms

Work program

Relinquishment

Average tract size

Financial Provisions

Government

participation

Lease payments

Incentive

payments

Taxes

United States Canada United Kingdom Norway

Competitive

5/10 years or as

as producing

None

None

25 sq. km

None

long

Cash bonus, 121⁄2%

or 162

/s O/0 royalty

None

Corporate Tax: 46°/0

Windfall Profits Tax

(except in Arctic)

Discretionary

Exploration: 5 years

Production: 10 years,

renewable for 10

years

Yes

50 percent of acreage

2000 sq. km

25 percent (optional)

100/0 royalty, plus

incremental royalty

Up to 80% for

Canadian firms,

25°/0 for foreign

firms (exploration

only)

Corporate Tax: 46°/0

Petroleum Revenue

Tax: 12°/0

Discretionary

Exploration: 3 years

Production: 6 years,

renewable for 40

years

Yes

Up to 2/3 of acreage

250 sq. km

None

121⁄2% royalty

(none for frontier

areas)

None

Corporate Tax: 52°/0

Petroleum Revenue

Tax: 75°/0

Discretionary

Exploration: 3 years

Production: 6 years,

renewable for 30

years

Yes

50 percent of acreage

550 sq. km

>50 percent (optional)

Sliding scale

royalties

None

Corporate Tax: 50.8°/0

Special Petroleum

Tax: 35°/0

SOURCE: Office of Technology Assessment.

ence than competitive bidding, it is also more expensive to administer.

LEASE STAGES

The United States is unique in jointly granting leases

for offshore exploration and development. Other countries make a greater distinction between exploration and

development lease rights. In these countries, exploration leases are granted for large areas for terms of 3 to

5 years, specify the work to be completed, and require

that all data be shared with the government. If a discovery is made, the terms of a production lease are then

negotiated. The advantage of the two-stage system is

that it provides for rapid exploration of large offshore

areas and gives the government greater flexibility in

establishing production lease terms.

WORK PROGRAMS

In the United States, lease rights are obtained through

the payment of upfront bonuses, which provide an incentive for firms to engage in efficient exploration and

development so as to recover the initial investment. The

U.S. government only requires the submission of exploration and development plans and diligent exploration. The discretionary allocation method used by other

countries usually entails a mandatory work program negotiated in conjunction with the lease rights. This may

consist of detailed exploration and development plans,

drilling of a certain number of wells, and/or a minimum

expenditure. Firms which fail to carry out the terms of

the work program can lose lease rights or any collateral

paid to the government. Work commitments ensure

rapid exploration and development, but also can be expensive to administer.

RELINQUISHMENT

Other countries usually have relinquishment requirements for nonproductive acreage in conjunction with

much larger tract sizes. Canada, the United Kingdom,

and Norway have stipulations in their exploration

and/or production leases that firms relinquish, at specified times, a certain percentage of their tracts. This

requirement forces companies to explore rapidly to determine the most premising acreage for further exploration and development. In addition, the initial tracts

leased for exploration are 10 to 80 times larger than

tracts in the United States, which are limited to 25

square kilometers. The United States has an indirect

incentive for relinquishment of nonproductive acreage

in its tax system, which allows companies to write off

expenses related to dry holes or nonproductive tracts.
App. A—Offshore Leasing Systems ● 217

FINANCIAL PROVISIONS

The United States relies primarily on lease payments

for government income from offshore oil and gas development. In Canada, the United Kingdom, and Norway, the primary revenue source is government participation and/or taxation. The United States is also one

of the few countries to require an upfront cash bonus

payment for lease rights, rather than stretching out all

lease payments over the life of the field. The United

States uses a fixed royalty on production, rather than

a sliding scale or incremental royalty linked to field productivity. The United States, like other countries, gives

some incentive to exploration through its tax system,

but does not offer direct exploration subsidies as does

Canada.

Foreign Leasing Systems

CANADA

Canada began offshore leasing in the late 1950s and

initiated leasing in the frontier Arctic areas (with as yet

no production) in the 1960s. After the introduction of

the National Energy Program in 1980, these leases were

renegotiatied into exploration agreements and over a

hundred new agreements were entered into for exploration in frontier areas. In recent years, Canada’s offshore

leasing program has been focused on rapid exploration

and development of resources, achievement of national

energy self-sufficiency, and increased government participation in the oil and gas industry. Since the 1984

national elections, the offshore leasing and financial

terms have been under government review.

Canada has a two-stage leasing system, where exploration and production licenses are granted separately

and different procedures govern each. Exploration

agreements are made on a discretionary basis, usually

with provisions for work commitments. They are

granted for large areas, averaging 2000 square kilometers, and include measures for relinquishment of 50

percent of the acreage at the end of the initial 5-year

term. The remaining lease area may be retained by renegotiating the exploration agreement. Production

licenses may be obtained by lessees at any time and are

renewable in 10-year increments.

Since 1980, Canada has increased government participation in oil and gas development and enacted an

exploration subsidy program which favors Canadianowned firms. The Canadian national oil company,

Petro-Canada, has the right to a 25 percent working interest in any commercial discovery on offshore tracts.

The Petroleum Incentives Program initiated in 1982 reimburses Canadian-owned companies for up to 80

percent and foreign companies for up to 25 percent of

eligible exploration costs. This program replaced the

favorable “superdepletion” provisions allowed against

the Corporate Income Tax, which still allows the immediate deduction of both tangible and intangible

drilling costs. In addition, Canada has a Petroleum and

Gas Revenue Tax levied since 1981 at an effective rate

of 12 percent on gross income. Together with a fixed

10 percent royalty, this tax makes the Canadian revenue system on offshore fields somewhat regressive. Canada also has a progressive incremental royalty on net

income from offshore production.

UNITED KINGDOM

The United Kingdom has leased offshore tracts since

the mid-1960s, but leasing in the northern North Sea

tracts did not begin until the early 1970s. The United

Kingdom has relied on frequent adjustments to a complicated tax system to influence the level of offshore

activity and the flow of government revenues. In 1983,

the financial terms for offshore leasing were liberalized

to encourage exploration in frontier areas and the development of marginal fields.

The United Kingdom has held eight oil and gas ‘‘leasing rounds, each characterized by different leasing and

financial provisions. The government has generally used

a discretionary system for offshore leasing, but has experimented with competitive bidding and offered 15

North Sea blocks for cash bonus bids in the eighth leasing round in 1982-83. Exploration licenses are granted

for periods of 3 years and specify a schedule of geological and geophysical surveys and well drilling. All data

are to be relinquished to the government. Production

licenses also involve negotiated work programs and are

granted for initial terms of 6 years. Tracts are ten times

larger than those in the United States, averaging 250

square kilometers in size, but up to two-thirds of the

tract must be relinquished at the end of the initial term.

The United Kingdom traditionally has relied on government participation and taxation for the major share

of revenues from offshore leasing. However, companies

no longer have to take the British National Oil Corporation as a partner in offshore development, although

some licensing preference is still given to groups which

include government participation. In 1983, the government changed the lease terms and tax provisions to spur

offshore exploration and development. Royalties were

eliminated for northern North Sea fields, although a

121⁄2 percent production royalty is still charged for other

areas. Firms now may recover all exploration and development costs prior to paying the Petroleum Revenue Tax, which is field specific. They also receive special

allowances for small fields. In addition, the Corporation Tax, which is ‘‘ringfenced” to offshore fields, is

being decreased gradually from a rate of 52 percent to

35 percent in 1986-87.
218 • Oil and Gas Technologies for the Arctic and Deepwater

NORWAY

Norway began offshore leasing after the passage of

the Continental Shelf Act of 1963, and oil from North

Sea areas is now being produced under some of the most

difficult operating conditions in the world. Leasing policy has changed emphasis from encouraging rapid exploration and development to increasing government

returns from oil and gas development. Norway gains

substantial income from offshore hydrocarbon production from an excess profits tax and a requirement that

at least a 50 percent equity interest in every tract be

given to the Norwegian State Oil Company, Statoil.

Norway uses a discretionary, two-stage system for

allocating lease rights, with initial exploration licenses

granted for large offshore areas. The licenses are for

periods up to 3 years and contain provisions for datasharing with the government. Production licenses with

mandatory work programs are valid for initial terms of

6 years for initial tracts averaging 550 square kilometers.

Production licenses can be renewed for an additional

30 years for 50 percent of the original area.

The Norwegian government obtains oil and gas

revenues from state participation, taxation, and moderate royalties on production. Since 1972, Statoil has

had at least 50 percent equity in all production licenses

and has been appointed operator for more than onethird of these licenses. Norway has a Corporate Tax and

also a Special Petroleum Tax on net income. The

Special Petroleum Tax is calculated on the basis of total

offshore operations, and unlike the British Petroleum

Revenue Tax, does not contain any exemptions for

small fields. As a result, the Norwegian marginal tax

rate is extremely high for all fields and has caused

Norwegian authorities to undertake a review of the current tax system. In addition, Norway has a system of

sliding scale royalties on petroleum production and a

flat 121⁄2 percent royalty on natural gas.
Appendix B

Glossary

Bidding System: Combination of bid variable and other

lease payment(s) used for allocation of lease rights,

e.g., cash bonus bid and fried royalty.

Blowout Preventer: The equipment installed at the

wellhead to prevent the escape of pressure.

Break-up: The period in the Arctic during which ice

in water bodies thaws and breaks up (late May to

mid-June for river ice, early July to mid-August for

ocean ice. )

Cash Bonus: Money paid by a lessee for the execution

of an oil and gas lease.

Casing: Steel pipe placed in an oil or gas well as drilling

progresses to prevent the wall of the hole from caving in during drilling and to provide a means of extracting petroleum if the well is productive.

Commercial Accumulation: An occurrence of oil and

gas that meets the minimum requirements for size

and accessibility to be of commercial interest to a

company. The term commercial is frequently synonymous with economic.

Deferral: Temporary exclusion of specific offshore areas

from leasing.

Development Well: A well drilled in proven territory

in a field to complete a production pattern.

Directional Drilling: Drilling at an angle from the vertical. Directional drilling makes it possible to reach

subsurface areas laterally remote, from the point

where the bit enters the earth.

Discovered Resources: That portion of the oil and gas

in the earth whose presence has been physically confirmed through actual exploration drilling.

Discovery Well: The first oil or gas well drilled in a

new field; the well that reveals the presence of a petroleum-bearing reservoir. Subsequent wells are development wells.

Drill Ship: A ship constructed to permit a well to be

drilled from it at an offshore location. While not as

stable as other floating structures, drill ships are capable of drilling exploratory wells in relatively deep

waters.

Dynamic Positioning: A method by which a floating

offshore drilling rig is maintained in position over an

offshore well location. Several motors called thrusters

are located on the hulls and are activated by a sensing system, which maintains the rig on location.

Economic Rent: Profits from oil and gas development

in excess of a firm’s normal return to capital.

Economies of Scale: Reduction in costs stemming from

a larger scale of operations or higher units of production.

Environmental Impact Statement (EIS): A document

required by the National Environmental Policy Act

(NEPA) of 1969 or similar State law in relation to

any action significantly affecting the environment.

Fair Market Value: Price a property brings in a competitive market where either party to the transaction

has the freedom to reject the offer.

Freeze-up: The period in the Arctic during which lakes,

rivers, and other water bodies freeze.

Indicated Reserves: Known oil and gas that is currently

producible but cannnot be estimated accurately

enough to qualify as proved.

Inferred Reserves: Reserves that are producible but the

assumption of their presence is based on limited physical evidence and considerable geologic extrapolation.

This places them on the borderline of being undiscovered. The accuracy of the estimate is very poor.

In Place: All of the oil and gas in the reservoir, combining both the recoverable and nonrecoverable

portions.

Ice Leads: Large openings in sea ice.

Jack-up Drilling Rig: An offshore drilling structure

with tubular or derrick legs that support the deck and

hull. When positioned over the drilling site, the bottoms of the legs rest on the surface. A jack-up rig

is towed or propelled to a location with its legs up.

Once the legs are firmly positioned on the bottom,

the deck and hull height are adjusted and levelled.

Landfast Ice Zone: The area extending from the shore

and consisting of two sub-zones: bottomfast ice,

where sea ice is frozen to the bottom, and floating

fast ice, seaward of the bottomfast ice and extending

outward from shore.

Lease: A contract authorizing exploration for and development and production of oil and gas in a specific offshore tract.

Lease Sale: Competitive auction for offshore leases by

sealed bid.

Leasing System: Combination of bidding systems and

other leasing conditions (terms, tract size, etc. ) used

in offshore leasing.

Lease Term: Period of time granted for offshore lease

rights.

Lease Tract: Geographical and legal extent of a single

offshore lease area.

Lessee: Firm or group of firms holding lease rights.

219
220 . Oil and Gas Technologies for the Arctic and Deepwater

Marginal Field: Recoverable reserves of oil and gas

which are barely profitable to produce.

Minimum Economic Field Size: Recoverable reserves

of oil and gas which are needed to assure profitable

production.

Moratoria: Temporary exclusion of specific offshore

areas from leasing.

Net Present Value: Total combined value in current

dollars of future costs and revenues associated with

a project.

Oil Basin: A large basin-like geologic structure in which

oil and gas fields will be found.

Oil Field: A geologic unit in which one or more individual, structurally and geologically related reservoirs

are found.

Oil Region: A large oil-bearing area in which oil basins

and fields are found in close proximity.

Pack Ice Zone: The area in which sea ice consists predominantly of multi-year floes; the area in which ice

does not melt annually.

Permafrost: Permanently frozen ground.

Profit Share: Lease payment based on percentage of

net income or profits from oil and gas production.

Proved Reserves: An estimate of oil and gas reserves

contained primarily in the drilled portion of fields.

The data to be employed and the method of estimation are specified so that the average error will normally be less than 20 percent, May also be called

measured reserves.

Rent: Money paid by a lessee for the right to occupy

an offshore tract.

Reservation: Offshore area permanently withdrawn

from leasing.

Reservoir: A natural underground container of hydrocarbons.

Reserves: Oil and gas that has been discovered and is

producible at the prices and technology that existed

when the estimate was made.

Resource Base: The total amount of oil and gas that

physically exists in a specified volume of the earth’s

crust.

Resources: The total amount of oil and gas including

reserves that is expected to be produced in the future.

Royalty: Lease payment based on percentage of gross

income or total value of oil and gas produced.

Semi-submersible Drilling Rig: A floating offshore

drilling structure that has hulls submerged in the

water but not resting on the seafloor, Semi-submersible rigs are either self-propelled or towed to a drilling

site and either anchored or dynamically positioned

over the site or both. Semi-submersibles are more

stable than drill ships and are used extensively to drill

wildcat wells in rough waters such as the North Sea.

Shorefast Ice Zone: Two subzones of ice; bottomfast

ice, where sea ice is frozen to the bottom, and floating

fast ice, seaward of bottomfast ice.

Sliding Scale Royalty: Lease payment based on a

royalty rate which increases with the amount of oil

and gas production.

Subeconomic Resources: Oil and gas in the ground that

are not producible under present prices and technology but may become producible at some future date

under higher prices or improved technology.

Submersible Drilling Rig: An offshore drilling structure with several compartments that are flooded to

cause the structure to submerge and rest on the

seafloor. Most submersible rigs are used only in

shallow waters.

Tundra: A rolling, treeless, often marshy plain.

Undiscovered Resources: Resources which are estimated totally by geologic speculation with no physical evidence through drilling available.

Windfall Profits Tax: Tax on profits from oil and gas

development brought about by increased prices

which are not accompanied by increased costs.

Withdrawal: Permanent exclusion of specific offshore

areas from leasing.

Work Commitment: Extent of exploration on an offshore lease to be carried out by the lessee.
Index
Index

Abyssal Plain, 27, 36, 38

Agriculture, U.S. Department of, 198

Air Force, 93, 94, 109, 145, 147

Alabama, 34, 144

Mobile, 101

Alaska, 4, 8, 9, 11, 14, 16, 21, 23, 24, 27, 29, 30,

31, 32, 33, 41, 42, 47, 50, 51, 54, 55, 56, 63,

92, 93, 95, 98, 109, 111, 117, 128, 132, 133,

134, 143, 145, 146, 149, 150, 156, 158, 165,

166, 167, 168, 170, 177, 178, 179, 185, 187,

193, 194, 196, 200

Aleutian Islands and Basins, 6, 33, 42, 55, 56,

59, 61, 66, 72, 135

Anchorage, 93, 197

Beaufort Sea, 3, 5, 6, 30, 31, 33, 42, 44, 50, 51,

54, 56, 59, 61, 64, 65, 66, 71, 72, 92, 94,

101, 135, 149, 150, 154, 158, 170, 174, 176,

179, 181, 187, 188, 190, 199

Bowers Basin, 42

Brooks Range, 54

Camden Bay, 54

Cape Halkett,

Chukchi Sea, 3, 5, 6, 16, 31, 54, 56, 72, 94,

101, 151, 171, 174, 179, 181, 187, 188

Cold Bay, 66

Colville Trough, 54

Cook Inlet, 42, 50, 54, 185, 200

Diapir Field, 52, 57, 132, 158

Duck Island, 51

Dutch Harbor, 66, 188

Ellesmere Island, 59

Fairbanks, 197

Gulf of Alaska, 6, 11, 15, 30, 42, 50, 199

Gull Island, 51

Harrison Bay, 5, 8, 51, 54, 59, 64, 65, 66, 119,

120

Hope Basin, 42

Inuit, 177

Kenai, 191

Kodiak, 42, 111, 188

Kuparuk Field, 42

Mikelsen Bay, 54

Muklak, 52

Navaron Basin, 5, 8, 30, 31, 32, 33, 42, 44, 51,

55, 56, 59, 61, 64, 65, 66, 118, 119, 120, 121,

122, 124, 132, 135, 151, 158, 174, 175, 196,

199

Niakuk Island, 51

North Slope, 41, 23, 42, 50, 54, 59, 65, 119,

124, 125, 126, 127, 128, 180, 182, 183, 184,

187, 191, 194, 195

Norton Basin, 5, 8, 30, 42, 54, 64, 65, 66, 132,

151

Norton Sound, 51, 199

Point Barrow, 8, 63, 111, 176

Prudhoe Bay, 4, 24, 42, 44, 50, 54, 66, 124, 126,

187, 188, 191, 196

St. George, 6, 12, 30, 31, 32, 42, 44, 55, 56, 57,

72, 132, 135, 176, 199

St. Lawrence Island, 174, 176

St. Matthew Island, 66, 174, 175

St. Paul Island, 66

Seal Island, 30, 44

Smith Bay, 54

Steffenson Sound, 51

Yakataga, 42

Yukon, 65

Alaskan Beaufort Sea Oilspill Response Body, 195,

199

Alaskan Clean Seas, 190, 199

Alaska Oil and Gas Association, 72

Alaska Eskimo Whaling Commission, 164, 180,

181, 183

Alaskan Natural Gas Transportation System, 126,

127, 128

Aleutian Basin, 6, 33, 42, 55, 56, 59, 61, 66, 72,

135

Unimak Pass

Alexander Kielland, 103, 111, 112

American Bureau of Shipping, 107, 114

American Petroleum Institute, 56, 107

American Society of Mechanical Engineers, 107

Anadyr Basin, 54

Anchorage, 93, 197

Arab, 3, 132

Arctic, 3, 4, 5, 7, 8, 9, 10, 11, 12, 13, 14, 15, 21,

24, 29, 32, 42, 44, 47, 49, 50, 51, 56, 57, 59,

61, 63, 65, 72, 89, 90, 91, 92, 96, 98, 101,

103, 104, 111, 114, 120, 158, 160, 164, 172,

176, 177, 178, 181, 185, 187, 188, 189, 191,

194, 195, 196, 197, 199, 200, 201

Arctic Research Commission, 92

Army, U. S., 90, 91

Atlantic Coast, 14, 47, 125, 132, 145, 148

Atlantic Ocean, 6, 11, 28, 30, 32, 33, 36, 38, 75,

76, 77, 132, 133, 137, 144, 145, 158, 166, 167

Australia, 47

Barter Island, 182

Bay of Campeche, 76

Beaufort Sea, 3, 5, 16, 31, 32, 33, 47, 51, 54, 56,

59, 61, 65, 66, 71, 72, 94, 101, 135, 149, 150,

154, 158, 170, 174, 176, 179, 181, 187, 188,

190, 199

Bering Sea, 3, 5, 12, 16, 42, 44, 51, 55, 56, 59, 61,

63, 94, 150, 153, 171, 174, 175, 176, 177,

179, 181, 183, 187, 188, 191

Bering Strait, 55, 59

223
224 ● Oil and Gas Technologies for the Arctic and Deepwater

Blake Plateau, 38

Borderland Basin, 40

Bowers Basin, 42

Brazil, 47, 103

Bristol Bay, 174

British Petroleum, 196

Brooks Range, 54

Bureau of Labor Statistics, 105, 109

Bureau of Land Management, 3, 164

California, 3, 4, 5, 6, 8, 11, 21, 29, 30, 38, 40, 74,

76, 81, 85, 109, 117, 118, 119, 120, 121, 125,

131, 132, 133, 135, 139, 144, 145, 148, 158,

181, 185

Borderland Basin, 40

Long Beach, 76, 101

Point Arguello Field, 4, 40, 76

Santa Barbara, 38, 40, 76, 78, 132, 173, 185,

197

Santa Maria, 40

Santa Ynez, California, 40

Summerland, 131

California Institute of Technology, 95

Camden Bay, 54, 59

Canada, 12, 30, 47, 54, 65, 92, 95, 98, 103, 111,

135, 148, 149, 150, 154, 156, 159, 176, 194

Cape Canaveral, 1 45

Cape Cod, 38, 148

Cape Halkett, 51

Cape Hatteras, 38

Cape Lisburne, 176

Caribbean Islands, 143

Carolina Trough, 38

Challenge Island, 188

Chesapeake Bay, 27

Chevron, 74, 80, 159

Chukchi Sea, 3, 6, 31, 32, 33, 42, 54, 56, 72, 94,

101, 151, 171, 174, 179, 181, 187, 188

Civil Air Patrol, 109

Clark, William, 133, 135, 144

Climatic Atlas, 56, 57

Coast Guard, U. S., 7, 8, 15, 16, 90, 96, 97, 98,

101, 102, 103, 104, 105, 106, 107, 108, 109,

110, 111, 112, 113, 11 4, 165, 188, 193, 198,

199, 200, 201

Marine Board of Investigation, 112

National Strike Force, 198

Coastal Energy Impact Program, 140

Code for the Construction and Equipment of

Mobile Drilling Units, 107

Cold Bay, 66

Colorado School of Mines, 32

Colville Trough, 54

Commerce, U.S. Department of, 140, 198

Congress, 3, 5, 8, 9, 11, 12, 14, 15, 24, 25, 132,

139, 140, 142, 143, 144, 145, 147, 148, 151,

154, 157

House Committee on Appropriations, Subcommittee of the Department of Interior and

Related Agencies, 144

House of Representatives, U. S., 143

Senate, U. S., 143, 153

Congressional Research Service, 4, 24

Conoco, 47, 74, 80

Continental Offshore Stratigraphic Test Wells, 24,

30

Continental Shelf, 27, 31, 32, 34, 36, 38, 42, 139,

148, 151, 153, 154

Continental Shelf Convention, 150

Continental Slope, 27, 32, 36, 38, 40, 77

Continental Rise, 27, 38, 40

Cook Inlet, Alaska, 42, 50, 54, 185, 200

Corporate Average Fuel Economy, 22

Crystal River, Florida, 34

Cuba, 12, 148, 153, 154

Deep Oil Technology, 47

Deepsea Drilling Project, 47

Defense, U.S. Department of, 9, 12, 101, 109, 125,

144, 145, 146, 198

Air Force, 93, 94, 109, 145, 147

Army, 90, 91

Corps. of Engineers, 91

Coast Guard, 7, 8, 15, 16, 90, 96, 97, 98, 101,

102, 103, 104, 105, 106, 107, 108, 109, 110,

111, 112, 114, 114

Eglin Air Force Base, 147

Navy, 90, 93, 94, 96, 98, 145, 147, 200

Office of Naval Research, 90, 91

Weinberger, Casper, 146

DeSota Canyon, 147

Diapir Field, Alaska, 52, 57, 132, 158

Duck Island, 51

Dutch Harbor, 66, 188

economic factors, 117

cost of offshore exploration and development, 117

government lease and tax payments, 123

prices and markets, 124

profitability of offshore development, 120

Eglin Air Force Base, 147

Ellesmere Island, 59

Energy, U.S. Department of, 4, 22, 23, 24, 90, 91,

198

environmental considerations

biological resources, 173
Index ● 2 2 5

environmental information, 164

oil spills, 185

Environmental Protection Agency, 15, 16, 165, 172,

195, 198, 200

Eurasina Basin, 56

European Space Agency, 95, 97

exclusive economic zone, 3, 24, 27, 33, 36, 38, 42,

74, 131, 148, 151, 153

Exxon, 40, 44, 51, 74, 78, 80, 159, 196

Fairbanks, 197

Federal Emergency Management Agency, 198

Federal services and regulations

Federal services, 92

research and development, 89

safety, 103

Federal leasing policies, 131

disputed international boundaries, 148

Fish and Wildlife Service, 178

leasing policies for offshore frontier areas, 154

military operations, 145

rate and extent of offshore leasing, 131

Florida, 34, 36, 38, 109, 139, 144

Cape Canaveral, 145

Crystal River, 34

Straits, 36

Gas Research Institute, 4, 22, 23, 24

General Accounting Office, 157

Geneva, 139

Geneva Convention, the Continental Shelf, 151, 153

Geological Survey, U. S., 3, 4, 24, 27, 28, 29, 30,

31, 32

Georges Bank, 38, 132, 144, 148, 149, 150, 153,

154, 174

Georgia, 38

global positioning system, 8

Glomar Jova Sea, 103

Great Britain, United Kingdom, 112, 135, 150,

151, 156, 158, 159, 175

Great Lakes, 143

Gulf of Alaska, 6, 11, 15, 30, 42, 50, 174, 199

Gulf Coast, 76, 125

Gulf of Maine, 148

Gulf of Mexico, 3, 6, 8, 11, 12, 14, 21, 24, 27, 30,

32, 33, 34, 36, 47, 74, 75, 76, 77, 78, 80,

103, 114, 117, 118, 119, 120, 121, 122, 131,

132, 133, 135, 136, 137, 139, 144, 145, 147,

148, 151, 153, 154, 156, 158, 165, 167, 185

Atwater Valley, 36

Port Isabel, 36

Gulf stream, 38, 77

Gull Island, 51

Harrison Bay, 5, 8, 51, 54, 59, 64, 65, 66, 119,

120

Hawaii, 95

Health and Human Services, U.S. Department of,

109, 198

Hodel, Don, 135

Hope Basin, Alaska, 42

Hudson River, 27

Illinois, 109

Scott Air Force Base, 109

IMODCO, 47

Interagency Arctic Research Policy Committee, 92

Interagency Committee on Ocean Pollution

Reserch, Development and Monitoring, 170,

171

Interagency Technical Committee, 15

Interior, U.S. Department of the, 3, 6, 9, 10, 12,

13, 14, 15, 24, 25, 27, 90, 132, 133, 134, 135,

137, 138, 140, 141, 142, 143, 144, 145, 146,

147, 148, 154, 155, 156, 158, 159, 164, 165,

170, 171, 173, 197, 198

Bureau of Land Management,

Clark, William, 133, 135, 144

Geological Survey, U. S., 3, 4,

31, 32

Hodel, Don, 135

Mineral Management Service,

3

24, 27, 28, 29, 30,

3, 4, 7, 10, 15,

16, 28, 30, 90, 91, 106, 107, 108, 109, 113,

114, 136, 144, 145, 147, 164, 165, 167, 169,

170, 171, 172, 173, 175, 179, 180, 181, 182,

183, 184, 185, 188, 191, 198, 199, 200, 201

Environmental Studies Program, 10, 15, 164,

167, 168, 170, 173

Technology Assessment and Research Program,

8

Watt, James, 3, 9, 132, 144, 146

International Association of Drilling Contractors,

104, 105

International Court of Justice, 12, 13, 148

International Labor Organization, 107

International Maritime Organization, 107

International Tribunal for the Law of the Sea, 154

International Whaling Commission, 176, 178, 179

Interorganization Bowhead Whale Research Planning and Technical Coordination Group, 182

Inuit, 177, 184

Japan, 14, 95, 125, 126, 127, 174

Justice, U.S. Department of, 198

Kenai, 191

Kodiak, Alaska, 42, 111, 188

Kuparuk Field, 42, 54
226 ● Oil and Gas Technologies for the Arctic and Deepwater

Landsat, 93, 95, 110, 197

Labor, U.S. Department of, 109, 198

Law of the Sea Conference (Convention), 139, 150

Law of the Sea Treaty, 151, 153, 154

legislation

Arctic Research and Policy Act, 8, 92

Clean Air Act, 141

Coastal Zone Management Act, 132, 140, 141,

142, 163

Department of Defense Authorizations Act of

1984, 145

Endangered Species Act, 163, 170, 176, 178

Export Administration Act, 125

Federal Water Pollution Control Act, 140-141,

163, 197, 198

Marine Mammal Protection Act, 163, 178, 183

Marine Protection, Research and Sanctuaries Act,

163

Merchant Marine Act (the Jones Act), 125

National Environmental Policy Act, 140, 142,

163, 165, 171

Occupational Safety and Health Act, 109

Outer Continental Shelf Lands Act, 3, 4, 5, 8,

10, 12, 13, 15, 16, 106, 107, 131, 132, 139,

140, 141, 143, 147, 150, 154, 158, 159, 163,

165, 171, 172, 200

amendments, 132, 135, 136, 144, 157, 159

Submerged Lands Act, 139

Withdrawal of Lands for Defense Purposes Act,

12, 147

Library of Congress, 91

Long Beach, California, 76, 101

Louisiana, 3, 34, 131, 139, 144

Maritime Administration, U. S., 90, 91, 125

Marine Board, 103, 106, 111

Marine Board of Investigation (Coast Guard), 112

Mediterranean Sea, 6, 47, 86

Mexico, 76, 126, 148, 153, 154, 185

Bay of Compeche, 76

Mikelsen Bay, Alaska, 54

Minerals Management Service, 3, 4, 7, 10, 15, 16,

28, 30, 90, 91, 106, 107, 108, 109, 113, 114,

136, 144, 145, 147, 164, 165, 167, 169, 170,

171, 172, 173, 175, 179, 180, 181, 182, 183,

184, 185, 188, 191, 198, 199, 200, 201

Mississippi River, 27, 34

Mississippi, State of, 34, 144

canyon, 36

delta, 36

Mohole Project, 47

Mobil, 159

Mobile, 101

Muklak, Alaska, 52

National Aeronautics and Space Administration, 93,

95, 145

National Economic Research Associates, 136, 137

National Environmental Satellite, Data and Information Service, 93

National Institute of Occupational Safety and

Health, 107, 109

National Marine Fisheries Service, 164, 178, 179

National Marine Mammal Laboratory, 183

National Ocean Service, 93

National Oceanic and Atmospheric Adminstration,

15, 16, 17, 90, 94, 95, 109, 165, 167, 172,

179, 198

Outer Continental Shelf Environmental Assessment Program, 165

National Oil and Hazardous Substances Pollution

Contingency Plan, 198

National Petroleum Council, 11, 25, 26, 28, 29, 30,

31, 32, 64, 118

National Research Council, 11, 30, 106, 111, 170,

171

Marine Board, 103, 106, 111

National Response Team, 198

National Science Foundation, 90, 91, 92, 101

National Sea Grant College Program, 143

National Strike Force, 198

National Transportation Safety Board, 112

National Weather Service, 93

Navarin Basin, Alaska, 5, 8, 30, 31, 32, 33, 42, 51,

55, 57, 59, 61, 64, 66, 118, 119, 120, 121,

122, 124, 132, 135, 151, 158, 174, 175, 196,

199

Navy, U. S., 16, 90, 93, 94, 96, 98, 145, 147, 200

Navy/NOAA Joint Ice Center, 16, 93

New England, 38, 144

New Jersey, 144, 200

Niakuk Island, Alaska, 51

North Sea, 47, 65, 74, 77, 80, 86, 103, 151, 185

North Slope, Alaska, 14, 23, 42, 50, 54, 59, 65, 98,

101, 124, 125, 126, 127, 128, 180, 182, 183,

184, 187, 191, 194, 195

Norton Basin, Alaska, 5, 8, 30, 42, 54, 64, 65, 66,

119, 132, 151

Norton Sound, Alaska, 51, 199

Norway, 112, 151, 156, 159

Occupational Safety and Health Administration,

107, 108, 109, 114

Ocean Ranger, 103, 104, 111, 112,

Office of Naval Research, 90, 91

Office of Technology Assessment, 3,

11, 24, 30, 50, 63, 64, 80, 81,

121, 123, 124, 137, 157

offshore resources and future energy

113, 114

4, 5, 6, 8, 10,

85, 93, 117,

needs, 4
Index ● 227

technologies for Arctic and deepwater areas, 5

economic factors, 8

Federal leasing policies, 9

environmental considerations, 10

issues and options, 11

oil and hazardous material simulated environmental

test tank, 15

Oregon, 29, 30, 40

Outer Continental Shelf, 3, 9, 11, 12, 24, 25, 27,

29, 30, 32, 33, 38, 40, 56, 64, 76, 89, 90,

105, 106, 107, 108, 113, 132, 134, 138, 140,

142, 143, 144, 145, 146, 147, 149, 154, 156,

158, 159, 160, 163, 164, 168, 169, 170, 171,

172, 173, 175, 178, 179, 184, 185, 196, 197,

200, 201

Pacific Coast, U. S., 27, 30, 76, 145

Pacific Ocean, 3, 6, 29, 32, 38, 40, 75, 95, 132,

133, 137, 143, 158, 166, 167

Pacific Trust Territories, 143

Panama Canal, 125, 126

Point Arguello Field, California, 4, 40, 76

Point Conception, California, 40

Point Barrow, Alaska, 8, 63, 111, 176

Port Clarence, 111

Potential Gas Committee, 25, 32

Pribilof Islands, 174, 176

Prudhoe Bay, Alaska, 4, 24, 42, 44, 50, 59, 66,

124, 126, 187, 188, 191, 196

Rand Corp., 25

Reagan, (Ronald) (President) Administration of,

143, 148

role of offshore resources

energy outlook, 21

exclusive economic zone, 27

resource project problems, 24

Safety of Life at Sea convention, 107

St. George Basin, Alaska, 6, 12, 30, 31, 32, 42, 44,

51, 55, 56, 57, 72, 132, 135, 176, 199

St. Lawrence Island, 174, 176

St. Matthew Island, 66, 174, 175

St. Paul Island, 66

Saipem, 86

Santa Barbara, California, 38, 40, 76, 78, 132, 173,

185, 197

Santa Maria, California, 40

Santa Ynez, California, 40

Scott Air Force Base, 109

Sea Grant College Program, 144

Seal Island, Alaska, 30, 44

Seattle, Washington, 93, 101, 111, 183, 191

Shell, 30, 44, 78, 86, 147, 159

Seal Island Field, 30

Shell/Esso, 84

Siberia, 54, 55

Anadyr Basin, 54

Smith Bay, 54

Sohio Alaska Petroleum Co., 44, 51

Mukluk, 44

Sonat, 74, 98

South Carolina, 38

South China Sea, 103

South Korea, 174

Soviet Union, Russia, 12, 110, 148, 150, 151, 154,

174

Spain, 80

Standard Oil of California, 159

State, U.S. Department of, 13, 148, 153, 198

Steffenson Sound, Alaska, 51

Summerland, California, 131

Supreme Court, U. S., 139, 140, 142

Technology Assessment and Research Program, 90

Texaco, 159

Texas, 3, 109, 131, 136, 139, 143

Torrey Canyon, 173, 195

Transportation, U.S. Department of, 90, 198

Tunisia, 85

Underwriters Laboratories, 107

Unimak Pass, 176

United Nations Law of the Sea Convention, 150

Venezuela, 126

Washington, State of, 29, 30, 38, 40, 93, 111, 166,

183

Long Beach, 76, 101

Seattle, 93, 101, 111, 183, 191

Washington, DC, 167

Watt, James, 3, 9, 132, 144, 146

Wilmington, 101

Wilmington Canyon, 74

Yakataga, Alaska, 42

Yukatan Peninsula, 153

Yukon, 65, 149