Oil and Gas Technologies for the Arctic and Deepwater · 2018-04-29 · Recommended Citation: Oil and Gas Technologies for the Arctic and Deepwater (Washington, DC: U.S. Congress,

Oil and Gas Technologies for the Arctic andDeepwater

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 DocumentsU.S. Government Printing Office, Washington, DC 20402

Foreword

centNearly 2 billion acres of offshore public domain is owned by the United States adja-to 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 occurin deeper water and in the Arctic where operating conditions are severe, development costshigh, and financial risks immense. As the pace of exploration increases in these ‘ ‘fron-tier’ regions, questions arise about the technologies needed to safely and efficiently ex-plore and develop oil and gas in harsh environments.

The Office of Technology Assessment undertook this assessment at the joint requestof the House Committees on Interior and Insular Affairs and on Merchant Marine andFisheries. The study explores the range of technologies required for exploration and develop-ment of offshore energy resources and assesses associated economic factors and financialrisks. It also evaluates the environmental factors related to energy activities in frontierregions and considers important government regulatory and service programs.

In March 1985, the Secretary of the Interior announced the Administration’s pro-posed new 5-year offshore leasing program that will determine the pace of oil and gas ex-ploration in Federal offshore waters through 1991. The proposed leasing schedule will beunder 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 anduseful reference for the Congress as it reflects on the Department of the Interior’s pro-posed program.

OTA is grateful to the Offshore Technologies Advisory Panel and participants in OTA’sworkshops for their help in the assessment. Splendid cooperation was received from a numberof executive agencies during the course of the study, including the Minerals ManagementService, National Oceanic and Atmospheric Administration, and the U.S. Coast Guard.Special thanks go to the Arctic Environmental Information and Data Center of the Univer-sity of Alaska and its Director, David Hickok, for field assistance to OTA in Alaska.

JOHN H. GIBBONSDirector

Oil and Gas Technologies for the Arcticand Deepwater Advisory Panel

Jacob AdamsPresidentArctic Slope Regional Corp.

Larry N. BellVice PresidentArco Oil & Gas Co.

Dr. John H. Steele, ChairmanDirector, Woods Hole Oceanographic Institute

Charles L. BlackburnExecutive Vice PresidentExploration and DevelopmentShell Oil Co.

Sarah ChasisSenior Staff AttorneyNatural Resources Defense Council

Clifton E. CurtisExecutive Vice PresidentThe Oceanic Society

Gordon DuffySecretary, Environmental AffairsState of California

Walter R. EckelmannSenior Vice PresidentSohio Petroleum Corp.

William FisherState GeologistState of Texas

Robert GroganAssociate Director for Governmental

CoordinationOffice of the Governor of Alaska

Frank J. IarossiPresidentExxon Shipping

Don E. KashDirector

c o .

Science and Public Policy ProgramUniversity of Oklahoma

Paul Kelly*Vice President, Government RelationsRowan Companies, Inc.

Dan R. MotykaVice President-FrontierGulf Canada Resources, Inc.

C. Robert PalmerBoard Chairman and PresidentRowan Companies, Inc.

Sandford Sagalkin* *Counsel for North Slope Burrough

Stanley StiansenVice PresidentAmerican Bureau

Wallace TynerProfessorPurdue University

Michael T. WelchVice PresidentCitibank, N.A.

of Shipping

● Represented C. Robert Palmer at panel meetings● “Represented Clifton E Curtis at panel meetings.

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OTA Project Staff—Oil and Gas Technologies for theArctic and Deepwater

John Andelin, Assistant Director, OTAScience, 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 TechnologyVirgil Keith, ECOFrancois Lampietti

Leslie MarcusPeter Noble, Marine Technology Corp.

Denzil PauliRobert Schulze

Dr. James Smith, University of HoustonRobert Visser, Belmar Engineering

Other Contributors

Thomas AlbertNorth Slope Borough

Vera AlexanderProfessorUniversity of Alaska

Alan A. AllenSpiltec

Jean AudibertEarth Technology Corp.

Robert G. BeaSenior International ConsultantPMB Systems Engineering, Inc.

David BentonBenton & Associates

Ken BlenkhernAmoco Production Co.

Ted BourgoyneProfessorLouisiana State University

Katherine R. BoydAmerican Petroleum Institute

Robert E. BunneyNational Oceanic and Atmospheric

Administration

Gus CassityPlacid Oil Co.

Bruce ClardySohio Petroleum Corp.

Gordon CoxU.S. Army Cold Regions Research

and Engineering Lab

Charles EhlerNational Oceanic and Atmospheric

Administration

Mark FrakerSohio Alaska Petroleum Co.

John Norton GarrettInternational Petroleum Consultant

Ronald L. GeerSenior Mechanical Engineering

ConsultantShell Oil Co.

John GregoryMinerals Management Service

Richard GriffithsU.S. Environmental Protection Agency

John HaeberVetco Offshore, Inc.

Dillard HammettSedco, Inc.

Jim HeckerTerris and Sunderland

R. P. HermannSonat Offshore Drilling, Inc.

David HickokProfessorUniversity of Alaska

Sharon HillmanSohio Alaska Petroleum Co.

W. E. HollandExxon, U.S.A.

Baxter D. HoneycuttArco Oil and Gas Co.

Jerry ImmMinerals Management Service

James K. JacksonAmerican Petroleum Institute

Leland A. JohnsonPresidentArctic Slope Consulting Engineers

Graham KingArco Oil and Gas Co.

Joseph H. KravitzNational Oceanic and Atmospheric

Administration

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Jack LewisMinerals Management Service

Gary LoreMinerals Management Service

Bonnie A. McGregorU.S. Geological Survey

D. B. McLeanGulf Canada Resources, Inc.

Jim MielkeCongressional Research Service

David NortonProfessorUniversity of Alaska

Paul O’BrienAlaska Department of Environmental

Conservation

John OktollikAlaska Eskimo Whaling Commission

Raj PhansalkarConoco, Inc.

Richard PomfretExxon International Co.

Jim RayShell Oil Co.

Joe RivaCongressional Research

William M. SackingerProfessorUniversity of Alaska

Service

John ShanzCongressional Research Service

William H. SilcoxStandard Oil of California

Walt SpringMobil Research and Development Corp.

Tim SullivanMinerals Management Service

Rod SwopeAlaskan Governor’s Office

Pete TebeauLieutenant CommanderU.S. Coast Guard

Ed TennysonMinerals Management Service

J. Kim VandiverProfessorMassachusetts Institute of Technology

R. H. WeaverExxon Corp.

Robert WilsonU.S. General Accounting Office

Doug WolfeNational Oceanic and Atmospheric

Administration

John Wolfe, Jr.Conoco Oil Co.

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

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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, theeconomics, and the operational and environmentalfactors affecting the exploration and developmentof energy resources in the deepwater and Arctic re-gions of the U.S. Outer Continental Shelf (OCS)and the 200-mile Exclusive Economic Zone (EEZ)established in March 1983. For the purposes of thisstudy, OTA defined ‘‘deepwater’ as those offshoreareas where water depths exceed 400 meters or1,320 feet. The ‘ ‘Arctic’ is defined as the Beaufort,Chukchi, and Bering Seas north of the AleutianIslands.

Leasing submerged coastal lands for oil and gasdevelopment began with State programs in Cali-fornia, Louisiana, and Texas years before there wasa Federal offshore leasing program. Leasing in Fed-eral offshore lands began in 1954 after the OuterContinental Shelf Lands Act of 1953 provided theSecretary of the Interior guidance and authority forsuch activity. The industry leased, explored, anddeveloped OCS oil and gas under the provisionsof the 1953 Act for 25 years. Most of the offshoreactivity during that period was in the Gulf of Mex-ico and the Pacific Ocean off southern California.Then, in 1978, an emerging national awareness ofthe environment coupled with the Arab oil embargoand increased concern about energy supplies ledto enactment of the OCS Lands Act Amendments.

Congress included in the 1978 amendments a di-rective that the Secretary of the Interior seek a bal-ance in the OCS leasing program that would ac-commodate ‘‘expeditious’ development whileprotecting the environment and the interests of thecoastal States. The amendments established pro-cedures for considering environmental and Stateconcerns in leasing decisions, required the orderlyformulation of future leasing schedules, and orderedexperimentation with a variety of alternative bid-ding systems. In seeking to balance energy devel-opment and other values, the offshore leasing pro-gram has been the target of criticism from coastal

States, environmentalists, and the industry. Thesecriticisms have sharpened in the 1980s as offshoreactivities have expanded into the deepwater andArctic frontier areas.

The revised leasing system mandated by the 1978amendments has been in place slightly more than6 years. During this period, two Presidents and fourSecretaries at the Department of the Interior lefttheir mark on the implementation of the offshoreleasing program, In addition, Secretary James Wattinitiated a major departmental reorganizationwhich brought together components of the Bureauof Land Management, the U.S. Geological Sur-vey, and the OCS policy office in the Office of theAssistant Secretary for Policy, Budget, and Admin-istration. These were placed in a newly formedMinerals Management Service (MMS). Responsi-bility for Secretarial oversight of MMS was shiftedfrom what was once the Assistant Secretary forEnergy and Minerals to a new secretarial direc-torate in the Office of the Assistant Secretary forLand and Minerals Management.

The changes in leadership and the reorganiza-tions, the shift in leasing from nearshore areas tooffshore frontier regions, and the short period oftime since the passage of the 1978 amendmentshave all affected the offshore oil and gas leasing pro-gram. In spite of the fact that it has proven to beone of the government’s most controversial natu-ral resource programs, the offshore leasing programhas generally performed well in achieving the ob-jectives set by Congress. It is unlikely that any stat-utory framework devised to expand and expediteexploration for oil and gas on Federal lands, whilegiving equal weight to protecting the environmentand honoring the sovereign goals of the States, canbe anything but adversarial and contentious. De-spite the conflicts which have arisen, leasing of off-shore oil and gas has worked more smoothly andefficiently than other Federal energy leasingprograms.

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4 ● Oil and Gas Technologies for the Arctic and Deepwater

The existing OCS Lands Act appears to provide OCS Lands Act allows the administrative flexi-Congress and the executive branch sufficient lat- bility needed to adjust leasing terms and condi-itude 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 FUTUREENERGY NEEDS

Energy supply and demand projections to the endof the century indicate that demand for oil and gasin the United States will increase and domestic sup-plies will not. Falling oil and gas prices have re-duced incentives to conserve energy and to substi-tute alternative fuels for petroleum products. At thesame time, domestic oil production is likely to de-cline and the country is unable to maintain its re-serves. Oil imports, which have declined in recentyears, are expected to gradually increase and mayagain reach the high levels of the 1970s.

Forecasts by the Department of Energy and theGas Research Institute indicate domestic energyshortfalls may necessitate oil imports over 7 mil-lion barrels per day and natural gas imports ofabout 3 trillion cubic feet per day by the end of thecentury. Projections by OTA and the Congres-sional Research Service anticipate higher oil im-port rates in the 1990s, perhaps again reaching thehistoric 1977 high of 9.3 million barrels per day.Predictions of declining real oil prices in the shortterm, which would reduce incentives for explora-tion and production of domestic resources, makeeven these forecasts optimistic. Oil imports of themagnitude expected in the 1990s would make thecountry more vulnerable to supply interruptionsand would increase the trade deficit.

Where might new domestic oil and gas resourcesbe found to assist in meeting future U.S. energyneeds? The onshore areas of the lower 48 Statesare the most densely explored and developed oilprovinces in the world. But—with the exception ofPrudhoe Bay, the largest field in North America—few sizable onshore discoveries have come on lineduring the past decade. Domestic reserves continueto dwindle. It is unlikely—but not impossible—that a giant field similar to Prudhoe Bay will befound onshore in the lower 48 States.

Most of the undiscovered oil and gas in theUnited States is expected to be in offshore areasor onshore Alaska. But resource estimates of un-discovered oil and gas, while useful as indicatorsof relative potential, are little more than educatedguesses. Experts agree that prospects for oil andgas offshore are good, but they also admit there isa chance that only an insignificant amount of eco-nomically recoverable oil and gas may be found.In fact, only one major offshore field of a sizeneeded to significantly increase reserves-the PointArguello Field off southern California—has beendiscovered since offshore exploration was accel-erated in the 1970s.

Exploration in the offshore frontier regions dur-ing the last 5 years has yielded some information—most of it negative—about potential oil and gas re-sources. The U.S. Geological Survey estimated thatbetween 26 and 41 percent of the future oil and be-tween 25 and 30 percent of the future natural gasis offshore. The most promising prospects are be-lieved to be in the deepwater and Arctic frontiers.However, MMS recently lowered the estimates ofundiscovered recoverable offshore oil by half andof natural gas by 44 percent as a result of un-successful exploration efforts in Alaska and theAtlantic.

Much of the 1.9 billion acres within the offshorejurisdiction of the United States is still unexplored.Only actual exploratory drilling can determine thepresence of hydrocarbons. The offshore oil and gasindustry will drill the most promising geologicalstructures as exploration expands in the Arctic anddeepwater frontiers. If significant reserves are notdiscovered in the first round of drilling, the gov-ernment may need to consider a ‘‘second-round’leasing strategy to induce the industry to drillsecond-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” leasingthe OCS Lands Act, it is important that the oil and strategy may also be needed to assess the extentgas industry have access to Federal offshore lands of smaller offshore reservoirs that could cumula-to more accurately determine the resource poten- tively contribute to the Nation’s energy security.

TECHNOLOGIES FOR ARCTIC ANDDEEPWATER AREAS

Developing oil and gas in the deepwater and Arc-tic frontiers will be a major technological challenge.The severe environments and remote locations willrequire the design and construction of innovativeand costly exploration and production systems. Thekey to safe, efficient, and economical developmentof offshore resources in these frontiers will be thetechnology used for exploring, producing, andtransporting oil and gas under some extreme envi-ronmental conditions.

Offshore technology has generally developed—and will probably continue to develop—in an evolu-tionary fashion. Once wholly landbased, the oil andgas industry has moved its onshore technology off-shore, first onto piers, then onto seabed-bound plat-forms, and finally onto floating vessels as it ven-tured into deeper water.

Exploration systems have been operating inmany deepwater and Arctic areas for several years.But production systems have not yet been installedin frontier areas. Several production systems havebeen designed, however, and some have been testedin prototype. In addition, many of the individualcomponents that make up total production systemsare in service elsewhere in the world. The systemsfinally adapted for use in the deepwater and Arc-tic frontiers probably will be a combination of pre-viously tested subsystems and new componentsdesigned to withstand specific and often severe con-ditions.

The industry may be characterized as cautiouslyconservative in its approach to designing and de-ploying new technology. Yet, in general, it appearsthat development of offshore technology is pro-gressing at a pace compatible with governmentleasing schedules and projected exploration anddevelopment timeframes.

Arctic Technologies

The severity of the Arctic environment general-ly dictates a rigorous approach to design and con-struction of all primary and support systems. Thecold temperatures, ice, harsh weather, and remote-ness of many Arctic regions will force the use ofcostly equipment to achieve required reliability.

Technology for meeting the challenges of theArctic will have to develop concurrently with ex-ploration for oil and gas. Because of the immensecosts of development in this hostile environment,there is a tremendous incentive for industry to de-sign and build using advanced technologies andmaterials that will ensure reliability and cost effec-tiveness. This is particularly true for production sys-tems which, unlike exploration equipment, mustwithstand the severe, exposed, and corrosive con-ditions for the life of the field-usually 20 years ormore.

In order to assess the technology needed to ex-plore, develop, and produce oil and gas in the Arc-tic, OTA studied hypothetical sites at Harrison Bayin the Beaufort Sea, the Norton Basin in the Ber-ing Sea, and the Navarin Basin in the Bering Sea.Each of the three Arctic scenarios was based on dif-ferent 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 avail-able industry and government Arctic research anddevelopment programs indicate that priority shouldbe given to additional research related to ice prop-erties, ice movements and forces, oceanographicand meteorological processes, and seismicity.

Sea ice is considered to be the most importantdesign factor for engineering in the Beaufort, Chuk-


chi, and northern reaches of the Bering Seas. Ad-ditional research is needed to obtain basic data onice strength, ice forces due to movements, and iceproperties under the range of conditions likely tobe encountered. Better surveillance of ice move-ments from satellites and aircraft could providemore accurate and up-to-date information. Addi-tional research and development may be warrantedon more rapid and effective trenching techniquesto bury subsea pipelines below ice-gouge depths.The construction of ice-breaking tankers that arecapable of working year round in the Beaufort andChukchi Seas will require better design data. Forthe St. George and North Aleutian Basins, moreinformation is needed on seismic activities associ-ated with the subduction of the Pacific plate beneaththe North American plate.

Deepwater Technologies

Deepwater technologies must be developed towithstand such environmental factors as water cur-rents, seafloor instability, mud slides, and hur-ricane-force winds and waves. In the United StatesOCS, there has been a natural progression of off-shore technology from shallow water into ever-increasing depths. As the severity of the operatingenvironment has increased, incremental modifica-tions have been made to basic designs to deal withthese changing factors. In general, as depths haveincreased, structures have become larger, more sub-stantial, and consequently, more expensive. Toassist in understanding the technology needed toexplore, develop, and produce oil in the deepwaterfrontiers, OTA studied a hypothetical site off thecentral California coast in water depths of up to4,100 feet.

Exploratory drilling in very deep water is limitedby extreme ocean waves and currents and subseaformation conditions which make drilling slow anddifficult. To date, the deepest offshore explorationwell was drilled in 6,952 feet of water in the Atlan-tic offshore region in 1984. The Department of theInterior is now offering leases in 7,500 feet in theAtlantic and up to 10,000 feet in the Pacific.

The deepest water from which oil is currently be-ing produced is 1,025 feet in the Gulf of Mexico.Discoveries have been made in 1,640 feet of waterin the Gulf of Mexico, but production systems are

only now being developed. In the MediterraneanSea, development wells have been drilled in 2,500feet of water, but production has not yet begun.

Nearly all offshore fields discovered thus far havebeen developed using fixed-leg production plat-forms. This trend has been an extension of scaled-up shallow-water technology. Technically, fixed-leg platforms can probably be designed for waterdepths of 1,575 feet or more. However, the im-mense amounts of steel required, coupled with thecost of fabrication and installation, may limit theeconomic application of fixed-leg platforms to waterdepths of about 1,480 feet

It is reasonable to expect that in a few years, sev-eral types of production systems will be designedand built for water depths of 1,640 to 2,500 feet.Advanced conceptual design and some componenttesting are underway for compliant and floatingplatforms, subsea wellheads, and submerged pro-duction systems for these water depths. However,there has been limited effort to develop site-specificengineered solutions for use in deeper waters be-cause of the lack of commercial discoveries.

Industry experts generally agree that currenttechnology may be extended to about 8,000 feetwithout the need for major breakthroughs. Existingtechnologies which are particularly promising fordeepwater include buoyant towers, tension leg plat-forms, and subsea production units. All but thesubsea production units are generically referred toas ‘‘compliant structures, which flex and give wayunder wind, wave, and current forces.

A number of technologies related to the produc-tion system are critical to deepwater development.These include unique structures design, materialsdevelopment, and ocean floor foundation engineer-ing. Innovative installation, maintenance, and re-pair techniques are important for structures, risers,and deepwater pipelines. Drilling, well control, andwell completion are also important to deepwaterdevelopment. Human diving capability is currentlylimited to about 1,640 feet, although there havebeen experimental dives to 2,300 feet. Both one-atmosphere manned vehicles and remote-controlledunmanned vehicles will be increasingly used forconstruction, maintenance, monitoring, and repairof equipment. Deepwater pipeline systems will in-volve adaptation of conventional pipelaying tech-niques and new approaches to overcome problems


of buckling caused by long unsupported spanlengths, higher strain levels, and severe sea states.

Offshore Safety

Special safety risks are present in oil and gas de-velopment in offshore frontier regions because ofthe harsh environments and remote locations. Ingeneral, the safety record of offshore operations ap-pears equal to or better than the record of compara-ble onshore industries. Still, there may be a needfor new approaches to preventing work-related in-juries and fatalities in coping with new hazardsin the hostile Arctic and deepwater frontiers. Theoil and gas industry has the primary responsibilityfor ensuring the safety of offshore operations andis governed by a complex system of regulations.Both the Coast Guard and MMS enforce regula-tions controlling aspects of workplace safety.

The possibility of catastrophic rig accidents is thegreatest concern in offshore frontier areas. Such in-cidents have occurred in the past because of storms,structural failures, and capsizings. Other fatalitieshave been caused by well blowouts, explosions, andfires. Currently, there is no regulatory requirementfor the submission of integrated safety plans whichaddress technical, managerial, and other aspectsof the safety of offshore operations. In addition, in-sufficient funding by the Federal Government mayresult in inadequate rig safety inspections and mon-itoring efforts. Comprehensive safety plans, in-creased regularity of government monitoring ef-forts, and improved inspection techniques to matchthe increasing complexity and sophistication of off-shore facilities may be needed.

Environmental conditions in frontier regions alsopresent unique problems in evacuating personnelfrom rigs and platforms. Conventional lifeboats andrafts cannot be used on ice or in remote locations.Free-falling boats, air-cushioned vehicles, specialaircraft or helicopters, and icebreaking ships maybe needed to evacuate personnel from rigs. It hasbeen proposed that appropriate standby vessels berequired by law to be stationed near offshore facil-ities. The adequacy of evacuation measures couldbe assured by evacuation performance require-ments, regular inspections, and evaluation of evac-uation drills.

Since offshore accidents are most frequentlycaused by human errors rather than by equipmentfailures, there are limits to safety improvementspossible through purely technical means. Toachieve some improvement in human performance,responsibility for safety could be delineated moreclearly and better defined chains of command couldbe established. More extensive and improved workforce training also may be necessary for operationsin hostile frontier regions.

There is currently no single comprehensivesource of statistics on offshore injury and fatalityrates. The lack of integrated data makes it diffi-cult to evaluate the level of safety achieved by theoffshore oil and gas industry or to assess the effectsof safety regulations and equipment on the indus-try’s safety performance. Improved population andinjury data collection systems, greater consistencyamong data sources, and centralization of data col-lection and analysis in a single government agencycould aid in evaluating the effectiveness of safetymeasures. Offshore safety data systems could beimproved to include comprehensive event and ex-posure data; to relate events to specific employers,locations, operations, and equipment; to calculatefrequency and severity rates and analyze trends;and to permit monitoring of the relative safety per-formance of owners and employers, locations, andactivities.

Federal Offshore Services

The Federal Government provides a variety ofservices and information that bear on the develop-ment and protection of offshore resources. Govern-ment services most useful to the offshore oil andgas industry are those that support maritime oper-ations, including research and development, weath-er information, navigation services, and icebreak-ing. The adequacy of these services for large-scaleoil and gas development in offshore frontier areas,particularly the Arctic, is in question. There is alsodebate regarding the appropriate division of costsand responsibilities between the government andthe private sector in the provision of offshoreservices.

The most significant government research anddevelopment program is the MMS Technology As-


sessment and Research Program, which focuses onthe evaluation of offshore technologies with regardto safe operation and pollution avoidance. This pro-gram, which has almost been eliminated in pastbudget cuts, is the primary research activity sup-porting Federal regulatory efforts and deservescontinued support. In 1984, Congress enacted theArctic Research and Policy Act to facilitate the co-ordination of Arctic research. However, this Actdoes not contain authority for the appropriation ofadditional funds, and budget support for Arctic re-search must come from existing programs.

Federal programs providing weather and ice in-formation and navigational services are generallyconsidered marginal for increased industry activi-ties in offshore frontier regions, but at the same timeare targeted for budget cuts. The Administrationhas proposed shifting the responsibility for weathersatellite services and coastal and bathymetric chart-ing to the private sector. In addition, there are plansto phase out existing radionavigation systems and

replace them with a single satellite system—theGlobal Positioning System (GPS). Despite the de-pendence of the oil and gas industry on accurateice information, there are limitations on sensingequipment and significant voids in satellite cover-age for a major part of the Arctic.

The proper role of the government in the provi-sion of icebreaking services is also in question. Ice-breaking will be essential to maintaining shippinglanes and drillship sites, protecting drilling opera-tions from drifting ice, and aiding supply and lo-gistics operations, oil spill response, and search andrescue. However, the U.S. Coast Guard, whichwould normally provide these services, has no plansfor an Arctic facility. The closest Coast Guard fa-cility to Point Barrow, Alaska, is now 400 milesto the south. While the Coast Guard will continueto meet its overall icebreaking obligations to the ex-tent allowed by the budget, additional capacity maynot be available to serve the expanding needs ofthe offshore petroleum industry.

ECONOMIC FACTORS

Exploration and development of oil and gas re-sources in Arctic and deepwater frontiers will re-sult only if the promise of economic returns out-weighs the associated high risks and costs. Ingeneral, higher costs and longer lead-times to pro-duction lower the profit margins of resource devel-opment in offshore frontier areas. As a result, thesensitivity of project economics to changes in vari-ous economic factors—e.g., costs, prices, and gov-ernment payments—is higher in frontier areas thanin mature producing regions such as the shallowareas of the Gulf of Mexico. The leasing and pay-ment provisions of the OCS Lands Act Amend-ments of 1978 were based largely on experiencegained from oil and gas leasing in State submergedlands and the Federal areas of the Gulf of Mexicoand California.

OTA used a computer simulation model to ana-lyze the economic attractiveness of oil and gas de-velopment under deepwater and Arctic conditionsand to assess the implications of government pol-icies. Cash flow profiles were developed for the four

technology scenarios in the Navarin Basin, Harri-son Bay, Norton Basin, and California deepwater,as well as for a more conventional project in theGulf of Mexico.

Extremely large oil and gas discoveries areneeded to offset the high costs and long timeframesof development in offshore frontier areas. Whilea 40- to 50-million barrel field may be highly pro-fitable in the shallow-water areas of the Gulf ofMexico, some economic projects in the Alaskan off-shore may depend on finding 1 to 2 billion barrelsor more of recoverable reserves. Fields of this mag-nitude are called ‘ ‘elephants’ by the industry andare extremely limited.

The OTA computer simulation indicated thatgovernment lease and tax payments affect the prof-itability of offshore fields differently in frontier areasthan in other leasing areas. Fixed royalties tend toovertax small fields and remove the economic in-centive for the development of resources. Biddingsystems 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 eco-tier-area fields and provide greater incentive to the nomic market outlets for oil and gas—from the ex-development of marginal resources. port of Alaskan oil and the development of proc-

In 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 gasof offshore fields.

FEDERAL LEASING POLICIES

In the 1980s, the Department of the Interior ac-celerated the rate and extent of offshore leasing asa means of hastening exploration and developmentof energy resources. Secretary Watt initiated a sys-tem of ‘ ‘area-wide leasing, which expanded theoffshore acreage considered for each lease sale. Thenumber of lease sales to be held each year was in-creased, and the focus was on leasing in deepwaterand Arctic frontier areas. However, the actual paceof offshore leasing in this period was constrainedby opposition and conflicts. Resolution of the issuessurrounding area-wide leasing could allow the new5-year leasing program (1986-91) to proceed moresmoothly.

Challenges to the area-wide leasing approachhave been based on the adequacy of environmentalinformation to support lease sale decisions. Otherlitigation stemmed from disagreements betweenCoastal States and the Federal Government overrequirements that Federal offshore actions be con-sistent with State coastal zone management pro-grams. Congress imposed moratoria on leasing insome areas, largely as a result of Federal-Statedisputes on the division of escrow money from joint-ly owned tracts, the failure to devise a mutually ac-ceptable revenue-sharing formula, and coastal zonemanagement issues. Because of these delays, only7 of the 21 lease sales scheduled through the endof 1984 were held on the originally scheduled date.

The extent of offshore acreage offered for leasehas also been constrained by military deferrals ofareas for fleet operations, submarine transit lanes,missile flights, aircraft testing, underwater listen-ing posts, and other uses. As offshore oil and gasactivities have expanded into frontier regions, thepossible incompatibility between military and energy

development uses in some areas of the ocean hasbecome more obvious. Continuing deferrals mayresult in permanent withdrawals of OCS lands formilitary reservations. Such reservations couldremove a significant amount of potentially produc-tive acreage from oil and gas development. Cur-rently, there is some confusion as to who has finalauthority for withdrawing acreage from oil and gasdevelopment— the Department of the Interior, De-partment of Defense, or Congress. If uncertaintyin the frontier-area leasing process is to be reduced,this issue as well as questions regarding U.S. in-ternational boundaries in several frontier regionsand the exact delimitation of the U.S. Outer Con-tinental Shelf eventually should be resolved.

In order to provide the necessary incentives forexploration and development in offshore frontierareas, it may be desirable to implement new leas-ing approaches or modify lease terms and condi-tions. There is general agreement on the need forlonger lease terms for offshore deepwater and Arcticareas in view of the much longer period of timeneeded to explore and develop resources under hos-tile operating conditions. As leasing in offshorefrontier areas has increased, more tracts have beenoffered and leased with 10-year rather than 5-yearlease terms. However, specific criteria may beneeded for extending lease terms. In addition, thereshould probably be a requirement for submissionof exploration plans within a specified timeframe.

There is less agreement on the type of biddingsystems appropriate to offshore frontier areas. TheDepartment of the Interior prefers the traditionalcash bonus bid with a fixed royalty system that hasgained general acceptance from industry and is easyto 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 mayfixed 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 costsing in frontier areas generally have used a more and risks of development. More analysis and testingflexible work commitment system in conjunction are needed before any attempts at implementationwith larger lease areas and longer lease terms. After of these systems on a broad basis.

ENVIRONMENTAL CONSIDERATIONS

The development of offshore oil and gas resourcesand protection of the environment are potentiallyconflicting objectives and the subject of continu-ing debate. Nevertheless, the OCS Lands ActAmendments of 1978 require that energy and envi-ronmental policy goals be balanced in offshore de-velopment. Other Federal laws provide additionalenvironmental safeguards. Major environmentalconsiderations related to the development of Arc-tic and deepwater areas include trends in the De-partment of the Interior’s Environmental StudiesProgram, the status of the endangered bowheadwhale and other marine mammals, and the ade-quacy of oil spill containment and cleanup tech-niques.

The OCS Lands Act directs the Department ofthe Interior to systematically study the environ-mental components that may be affected by offshoredevelopment. The MMS Environmental StudiesProgram includes research on the distribution andpopulation dynamics of marine species, the fate andeffect of oil spills, and general ecosystem processes.Overall funding for the Environmental Studies Pro-gram has been decreasing at a nearly constant ratesince 1978. The MMS maintains that a great dealhas been learned about the offshore environmentin the past 10 years of the program, and that sub-stantial additional research may not now be war-ranted. However, OTA believes that the projectedpace of leasing in the relatively unknown deepwaterand Arctic regions and the need to monitor and reg-ulate post-lease exploration and development activ-ities may require more rather than less study ofenvironmental effects.

Although many species of fish, marine mammals,and birds may be affected by oil and gas develop-ment, bowhead whales have received the most at-

tention in recent years. Controversies surroundingthe bowhead whale demonstrate the complexity ofmanaging and protecting marine animals. Bowheadwhales, which are classified as an endangered spe-cies, could be adversely affected by offshore oil andgas operations in the Arctic. Bowhead whales holdspecial meaning for the native Alaskan Inuit andYupik people, and they serve as a supplementaryfood source for native people throughout much ofthe Arctic region. In addition, whales are involvedin the politics of the international conservationmovement and come under the scrutiny of the In-ternational Whaling Commission.

In comparison to funds spent on studying otherendangered species, a large proportion of availablefunds has been spent on bowhead whale research.Despite this, most scientists are reluctant to makeunqualified statements concerning population, re-production, or the effects of oil and noise on theanimals. Four major areas are targeted for moreresearch: 1 ) bowhead whale population estimates;2) the effects of noise on whales; 3) the long-termcumulative effects of industrial activities on whales;and 4) identification of critical habitats for bow-heads.

Although the risk of catastrophic oil spills fromoffshore operations is believed to be low, effectivecontainment and cleanup measures are essential inlight of the potential harmful effects of any suchspill. The offshore oil and gas industry is genuinelyconcerned and has diligently prepared for dealingwith the eventuality of oil spills. Industry has in-vested large amounts of funds and effort in engi-neering technology to prevent blowouts and othercatastrophic rig accidents. Considerable costs forcleanup and damage claims could be associated witha large spill. Some claim, however, that there is

Ch. 1—Summary, Issues, and Options • 11

little market incentive for developing oil spillcountermeasures compared to spill avoidance.

For the most part, oil spill containment andcleanup technology has been developed for spillsin nearshore and temperate regions. It may not besuitable for use under the extreme conditions ofdeepwater and the Arctic. Arctic oil spill coun-termeasures may be complicated by extremely coldtemperatures, the presence of ice, long periods of

darkness, intense storms, and lack of transporta-tion and storage facilities in most areas. In deep-water areas, high sea-states may be encountered,and greater distances from shore may create logis-tical problems for oil spill cleanup. To date, it hasnot been demonstrated in a real situation that in-dustry will be able to use effectively the existing oilspill equipment and countermeasure strategies inhostile environments.

ISSUES AND OPTIONS

Little is known about the actual resource poten-tial of the offshore lands of the United States. Ex-perts believe that major new oil and gas suppliesmay be located in the Arctic and deepwater fron-tiers. The country will need this oil and gas to fillenergy requirements at the end of the century—amere 15 years away. The history of petroleum ex-ploration suggests that large fields are generally dis-covered early in the exploration cycle. Even if ma-jor resource discoveries are made by the end of thenext 5-year leasing program in 1991, the Nationwill still have serious decisions to make about itsenergy future. The offshore oil and gas industrymay need incentives to reenter the frontier areasfor a ‘ ‘second-round’ of exploration of the prom-ising but smaller oil and gas prospects.

OTA has identified policy options for expeditingexploration and development of oil and gas in deep-water and Arctic offshore regions and for provid-ing additional incentives to the industry. OTA hasalso outlined options for protecting environmentalvalues and increasing offshore safety in conjunc-tion with exploration and development activities.These issues and options should be considered byCongress in the review of the next 5-year leasingprogram ( 1986-91), which will place emphasis onleasing in offshore frontier areas.

Energy Planning andOffshore Resources

The goal of the offshore leasing program is toincrease the Nations energy supply, thereby re-ducing dependence on oil imports. The offshore

frontier areas are believed to have the greatest po-tential for major new domestic oil and gas discov-eries, In the next few years, most of the remainingprospective areas of the offshore frontier regionswill be considered for leasing. Substantial explora-tion has already occurred in some offshore fron-tier areas, such as the Gulf of Alaska and Atlanticregions, However, except in the Gulf of Mexicoand California nearshore areas, exploration thusfar has added very little to proven reserves. Ac-curate knowledge of the resource potential of theNation’s offshore areas is critical to overall energyplanning and to making decisions about the offshoreleasing program and alternative energy programs.In order to effectively plan for future energy needs,the Nation may need to reevaluate the role and re-source potential of offshore areas when the find-ings of additional exploratory drilling in offshorefrontiers are available.

Congressional Options

Option 1: Reassess available information aboutthe resources of the OCS with regard to the po-tential of offshore oil and gas in supplementing theNation’s future energy supplies in the context ofNational Energy Planning.

Action: Establish a Congressional Commissionor request an existing body (e. g., National Re-search Council, National Petroleum Council) toreassess the role of offshore oil and gas in the Na-tion energy future at some point in the next 5-year leasing schedule.


Area- Wide Leasing

Exploration and development of oil and gas re-sources in offshore frontier areas can be encouragedby more rapid and efficient leasing of offshore acre-age. The system of area-wide leasing initiated bythe Department of the Interior in 1983 has in-creased the pace of leasing with the hope of earlyidentification of resources. Area-wide leasing per-mits the industry to select from among the full rangeof available tracts in deepwater and Arctic regionsand to explore those of greatest resource potential.However, the greater size and faster pace of leaseofferings under the area-wide system may reducethe detailed consideration of environmental con-cerns, competing land uses, and State and localviews in the leasing process. A return to the previ-ous tract nomination system could allow for greateroutside input into the leasing process, but may slowdetermination of the resource potential of offshorefrontier areas.


Option 1: Allow the Secretary of the Interior todetermine the size of lease offerings in offshorefrontier areas.

Action: No action required by Congress.

Option 2: Direct the Secretary of the Interiorto use a “tract nomination system” for lease of-ferings in offshore frontier areas.

Action: Amendment to OCS Lands Act or con-gressional directive through the appropriationsprocess.

Military Use Conflicts

As exploration and development have expandedto offshore frontier regions, there has been increas-ing conflict between oil and gas activities and mil-itary uses of offshore areas. An estimated 40 to 55million acres of offshore land are restricted fromoil and gas development for military and nationalsecurity purposes, and as much as 75 million ad-ditional acres are affected by restrictions on the den-sity of oil and gas operations. Deferrals and exclu-sions of lease tracts for military reasons are nownegotiated by the Department of the Interior andthe Department of Defense. Past disagreements on

offshore land uses have prompted a review of thisprocedure and have led to a new memorandum ofunderstanding between the agencies. While theOCS Lands Act gives authority for withdrawal ofoffshore acreage for national defense purposes tothe Secretary of Defense, the Withdrawal of Landsfor Defense Purposes Act reserves this authority forCongress. Continuing confusion over who has fi-nal authority to withdraw offshore acreage adds un-certainty to the leasing process and may delay ex-ploration in offshore frontier areas. A procedureis needed which resolves the conflicting authoritiesand adequately balances energy and military usesof offshore lands.


Option 1: Allow Secretary of the Interior andSecretary of Defense to continue negotiating mil-itary withdrawals of OCS acreage.


Option 2: Delegate authority for military with-drawal of OCS acreage to one department.

Action: Amendment to OCS Lands Act and/oramendment to Withdrawal of Lands for DefensePurposes Act.

Option 3: Reserve authority for military with-drawal of OCS acreage to Congress.

Action: Amendment to OCS Lands Act.

Disputed International Boundaries

Contested international boundaries eventuallymay contribute to delays in oil and gas exploration.There are unresolved disputes between the UnitedStates and other countries in several offshore fron-tier regions, including those with the Soviet Unionin the Bering Sea and with Canada in the BeaufortSea. A dispute between the United States and Can-ada over Georges Bank was recently arbitrated bythe International Court of Justice, but importantbilateral management issues are yet to be workedout. In addition, the outer boundary of the exten-sive U.S. continental shelf has not been delimited,and uncertain jurisdiction in the central Gulf ofMexico may eventually cause tension between theUnited States, Mexico, and possibly Cuba. Al-though there is no immediate need to resolve con-


tested boundaries, such disputes could be settledthrough bilateral negotiation, arbitration, or media-tion. Arrangements could be made for joint explor-ation and/or development of contested areas by theparties to the dispute. Contested offshore areascould also be withdrawn from oil and gas develop-ment pending settlement of disputes. Resolutionof offshore boundary questions would help reduceinternational tensions and allow exploration and de-velopment of frontier areas to proceed in an orderlymanner.


Option 1: Allow arbitration by the InternationalCourt of Justice to resolve boundary disputes.

Action: Congressional directive to Departmentof State to negotiate arbitration agreements withother countries.

Option 2: Establish an interim arrangement forexploration and/or development of disputed off-shore areas.

Action: Congressional directive to Departmentof State to negotiate appropriate agreements.

Option 3: Create buffer zones in disputed areaswhere no oil or gas development would take place.

Action: Congressional directive to Departmentof State to negotiate appropriate agreements.

Lease Terms1

Longer lease terms may be needed in offshorefrontier areas to allow sufficient time for explora-tion and identification of resources. The standard5-year lease term for offshore tracts has been in-creased to 10 years for many tracts in deepwaterand Arctic areas under the authority provided tothe Secretary of the Interior in the OCS Lands Act.However, the lack of specific criteria for 10-yearlease terms adds uncertainty to the offshore leas-ing process in Arctic and deepwater frontier areas.In addition, 10-year lease terms in deepwater noware provided only for tracts in water deeper than

1MMS has extended lease terms for deepwater tracts (Federal Reg-

ister, Apr. 3, 1985). Tracts in water depths between 400 and 900 meterswill have 8-year terms, and tracts in waters deeper than 900 meterswill have 10-year terms. To ensure exploration diligence, explorationdrilling is required during the first 5 years.

900 meters or 2,950 feet. An established policy on10-year lease terms and a more realistic deepwaterthreshold may be needed. The Department of theInterior has proposed automatic 10-year lease termsfor all tracts in water deeper than 400 meters or1,320 feet. Currently, companies with 10-yearleases have no set deadline for the submission ofexploration plans and may hold a lease for 8 or 9years before filing a statement of intention to ex-plore. In conjunction with a longer lease term pol-icy, the Department of the Interior may need toensure diligent exploration in frontier areas by re-quiring submission of exploration plans at a spe-cific time in the lease term (e. g., fifth or sixth year).


Option 1: Establish automatic 10-year leaseterms for tracts in water depths greater than 400meters or 1,320 feet and for selected Arctic regions.

Action: Congressional directive to Departmentof the Interior through the appropriations process.

Option 2: Establish automatic 10-year leaseterms for selected offshore frontier areas and in-clude provisions for submission of explorationplans within a specific time period.


Alternative Bidding Systems

The United States has traditionally allocated off-shore tracts on the basis of the highest cash bonusbid with a fixed royalty payment, The OCS LandsAct Amendments of 1978 mandated testing of sev-eral alternative bidding systems. However, aftertesting, the Department of the Interior prefers thetraditional system. This bidding system is easy toadminister, has promoted efficient exploration anddevelopment of offshore tracts in conventional leas-ing areas, and has been accepted by both govern-ment and industry. However, there may be disad-vantages in using this system to allocate offshorefrontier tracts. The requirement for upfront cashbonus payments may be a deterrent to continuedexploration of frontier areas, because these areasinvolve greater uncertainty and far higher costs.Alternative arrangements such as ‘‘work commit-


ment leases’ may be needed to sustain activitiesin high-risk deepwater and Arctic regions. In ad-dition, because of low profit margins in frontierareas, fixed royalties may overtax small fields andlead to nondevelopment of resources. Bidding sys-tems with other types of lease payments, such assliding scale royalties, net profit shares, or even zeroroyalties, may provide more incentives to marginalresource development. Effective implementation ofalternative bidding systems, however, will requireadditional experimentation, analysis of costs andbenefits, and adjustments in other lease conditionssuch as the size of the lease tracts.


Option 1: Allow the Secretary of the Interior toselect the bidding system to be used in offshorefrontier areas.


Option 2: Direct the Secretary of the Interiorto continue testing alternative bidding systems inoffshore frontier areas.

Action: Amendment to OCS Lands Act.

Alaskan Oil Export Ban2

Removing the ban on exporting oil produced inoffshore Alaskan areas could provide an added eco-nomic incentive to developing offshore resourcesin the Arctic. In the 1970s, concern about the Na-tion’s increasing oil import dependence promptedCongress to place restrictions on the export of oilproduced on Alaska’s North Slope and in offshoreareas. About half of the oil produced on the NorthSlope is now shipped to Gulf of Mexico and AtlanticCoast refining centers. Exporting oil to closer mar-kets in Japan and other Asian countries could re-duce transportation costs and increase the profitsof producing Alaskan oil. The increased profit mar-gins on offshore fields could improve the incentivesfor developing marginal resources in Alaskan off-shore areas. However, removing the export bancould have economic and national security costs asa result of increased dependence on imported oil

‘The House of Representatives passed a 4-year extension of the Ex-port Administration Act, which contains restrictions on the export ofAlaskan oil, on Apr. 16, 1985.

and adverse effects on domestic shipping whichheavily depends on the Alaskan tanker trade. Inaddition, it is not certain that export markets inJapan could be established.


Option 1: Remove restrictions on exporting oilproduced in Arctic offshore regions.

Action: Amendment to Export AdministrationAct.

Option 2: Evaluate advantages and disadvan-tages of exporting Alaskan oil, with reference toeconomics of Alaskan offshore oil production andmarket development.

Action: Establish an Alaskan Oil Export Com-mission to make recommendations on exportingAlaskan oil.

Environmental Information

The Environmental Studies Program adminis-tered by the Minerals Management Service is themajor research program on the effects of oil andgas development on offshore environments. Thisinformation is used in preparing EnvironmentalImpact Statements and as an aid to the Secretaryof the Interior in weighing the costs and benefitsof offshore development. The Environmental Stud-ies Program is changing its emphasis in the Alaskanregion from acquiring pre-lease information to ac-quiring post-lease data needed for management ofoil and gas activities. Funding for the program,however, has been decreased and led to a reduc-tion in both pre-lease and post-lease studies. Pro-portionally, the decrease in funds for the Alaskanregions has been greater than that for temperatecoastal areas. In general, decreases in the Environ-mental Studies Program budget are not justifiedin view of the relative lack of understanding of Arc-tic and deepwater marine environments, the pro-jected pace of leasing in frontier areas, and the con-tinuing need to monitor offshore oil and gasactivities.


Option 1: Allow Secretary of the Interior to de-termine the allocation of research funds for envi-ronmental studies of different offshore regions.

Ch. 1—Summary, Issues, and Options ● 1 5


Option 2: Review funding levels for environ-mental studies in offshore frontier regions in lightof new 5-year leasing schedule.

Action: Conduct congressional hearings on En-vironmental Studies Program and oversight review.Appropriate additional funds if found necessary.

Oil Spills

The offshore oil and gas industry has a good rec-ord of preventing oil spills. However, it has littleexperience in containing and cleaning up oil spillsin offshore frontier environments, where there isnow little oil production. Most current technologywas developed for nearshore and inshore areas andmay not be suited to frontier areas characterizedby severe wind and waves, ice, extended periodsof darkness, and/or low temperatures. Industry hasdirected its investments primarily to oil spill pre-vention rather than containment and cleanup, andgovernment funding for oil spill technology researchhas been low. The OHMSETT (Oil and Hazard-ous Material Simulated Environmental Test Tank)Interagency Technical Committee has conductedlimited testing of Arctic oil spill countermeasurestechnology, but budget constraints may reducefuture testing. Government evaluation and publica-tion of oil spill equipment test results could pro-vide incentives to industry to improve coun-termeasures technology. Certain performancerequirements might also encourage the industry todevelop new technology and engineering approachesfor dealing with oil spills.


Option 1: Increase funding for research on oilspill countermeasures technology in offshore fron-tier areas.

Action: Increased appropriations to OHMSETT,MMS, Environmental Protection Agency, NationalOceanic and Atmospheric Administration, and/orU.S. Coast Guard oil spill research programs.

Option 2: Develop a program for oil spill equip-ment testing and publication of results.


Option 3: Establish performance standards forindustry oil spill response capability.

Action: Amendment to OCS Lands Act and/orcongressional directive to Department of the In-terior through the appropriations process.

Offshore Safety

The hostile operating conditions in deepwaterand Arctic areas may require greater attention topersonnel safety concerns during oil and gas activ-ities. New technological approaches, managementpractices, and monitoring efforts may be neededto ensure high safety standards in offshore frontierregions. Improved Minerals Management Serviceand Coast Guard monitoring and inspection of off-shore facilities could assure minimum safety stand-ards and uniformity of safety conditions. Concernabout possible catastrophic rig accidents has promptedproposals for better evacuation procedures and tech-niques, regular evacuation drills, and requirementsfor standby vessels. Regulations concerning workforce training and management safety practicesmay need to be reviewed and revised for frontierareas. In addition, it is difficult to evaluate the seri-ousness of offshore safety hazards because of in-complete and inconsistent safety data. Implemen-tation of Federal safety responsibilities in offshorefrontier areas will require adequate and accuratedata in order to monitor safety performance andthe effectiveness of safety initiatives.


Option 1: Increase funding for MMS and/orU.S. Coast Guard safety inspection programs inoffshore frontier areas.

Action: Congressional directive through the ap-propriations process.

Option 2: Establish standards for evacuationprocedures from fixed platforms and mobile drill-ing vessels in offshore frontier areas and periodi-cally monitor emergency evacuation drills.

Action: Congressional directive through the ap-propriations process or Amendment to OCS LandsAct.

Option 3: Consolidate responsibility for collect-ing, analyzing, and reporting safety-related datain a single agency (MMS or U.S. Coast Guard).


Action: Congressional directive through theappropriations process or Amendment to OCSLands Act.

U.S. Coast Guard Programs

The capacity of the U.S. Coast Guard to effec-tively conduct its missions in Arctic regions islimited and will be increasingly inadequate as off-shore oil and gas development proceeds. Due to thecurrent lack of activities in northern Alaskan off-shore areas, U.S Coast Guard operations in Alaskaare concentrated in the Gulf of Alaska, far to thesouth of the prospective Arctic oil areas in the Ber-ing, Chukchi, and Beaufort Seas. The lack of anoperational Coast Guard facility in the Arcticgreatly impedes the agency’s capabilities for searchand rescue, vessel and platform safety inspection,law enforcement, maintenance of navigation, oilspill cleanup response, and icebreaking. Despite thepotential for greater human safety and environ-mental risks in the region as a result of the increasein oil and gas activities, the Coast Guard currently

has no plans for basing equipment and personnelin Arctic areas. However, studies of a potential Arc-tic facility are underway.


Option 1: Establish a U.S. Coast Guard base inthe Arctic region.

Action: Congressional directive through the au-thorization/appropriations process.

Ice Information

Arctic oil and gas operations depend on timelyinformation about the location and movement ofsea ice. Weather conditions and remoteness of fa-cilities potentially make satellite imagery a veryuseful source of information on ice conditions.However, U.S. Arctic satellite-sensing capabilityis limited by the number of satellites and the capa-bilities of existing sensors. In addition, the useful-ness of ice information obtained from satellites isreduced by the length of time needed for process-ing and delivery to users. Planned improvementsin U.S. satellite systems will increase ice-relatedcoverage of Arctic areas and contribute to the safety

and efficiency of Arctic oil and gas development.Use of data from European and Canadian satel-lites could also assist offshore activities. However,there are uncertainties as to the timing and extentof improvements in U.S. satellites, the availabil-ity of information from foreign satellites, and themeans for making satellite information available tothe private sector. The Navy/NOAA Joint Ice Cen-ter, which has primary responsibility for process-ing and disseminating satellite ice data, could beupgraded to provide more timely operational data.In the absence of improved government ice datacollection and distribution, the industry will haveto place greater reliance on private sector ice in-formation services.


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


Option 2: Increase government acquisition ofice information from foreign polar satellite sys-tems.


Option 3: Expand ice information processingand dissemination by the Joint Ice Center.

Action: Increased appropriations for the Navy/NOAA Joint Ice Center. Establish the Center per-manently through authorizing legislation.

Government Information Services

Improved coordination and delivery of govern-ment information could facilitate operations in off-shore frontier areas. Information and data relat-ing to offshore oil and gas activities are now dividedamong several government agencies, including theMinerals Management Service, the National Ocean-ic and Atmospheric Administration, the U. S, CoastGuard, the U.S. Navy, and the EnvironmentalProtection Agency, Users of offshore technical,environmental, and leasing information often findit difficult to identify agency contacts and sourcesof information within the government. The centrali-

Ch. 1—Summary, Issues, and Options ● 1 7

zation of information services within a single agencyhas been proposed, but this would be difficult toimplement in view of the contrasting responsibilitiesof the various agencies. NOAA has established asystem of national ocean service centers, includingan Anchorage, Alaska, center for the Arctic offshorearea, which may provide a prototype for other agen-cies. These service centers act as regional clearing-houses for environmental and meteorological in-formation gathered by NOAA. Other agencies,separately or in coordination with NOAA, could

establish similar regional clearinghouses for infor-mation distribution to the offshore oil and gas in-dustry.


Option 1: Establish regional clearinghouses tocollect and distribute government information re-lating to offshore oil and gas operations.


Chapter 2

The Role of Offshore Resources

Contents

Page

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

U.S. Energy Outlook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Energy Demand Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21Energy Supply Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Resource Projection Problems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Comparability Among Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Reliability of Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Interpretation of Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26Other Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

U.S. Exclusive Economic Zone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27Oil Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28Natural Gas Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32Resources by Lease Sale Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

TABLESTable No. Page

2-1. Energy Demand and Domestic Supply: 1978-83. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 222-2. U.S. Energy Demand and Supply Forecasts to 2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232-3. Definitions of Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262-4. Offshore Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292-5. Comparison of Estimates of Alaskan Offshore Oil Resources . . . . . . . . . . . . . . . . . . . . . . . . . . 312-6. Comparison of Estimates of Alaskan Offshore Gas Resources . . . . . . . . . . . . . . . . . . . . . . . . . 332-7. Estimates of Offshore Acreage With Hydrocarbon Potential . . . . . . . . . . . . . . . . . . . . . . . . . . 34

FIGURESFigure No. Page

2-1. Profile of Physiographic Features of the Geological Continental Margin of the U.S.. . . . . . 282-2. Oil Resources by Planning Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 292-3. Oil Resources in Alaska Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 322-4. Natural Gas Resources by Planning Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 332-5. Natural Gas Resources in Alaska Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342-6. Minerals Management Service Lease Sale Planning Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . 352-7. Distribution of Gulf of Mexico Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . 372-8. Trends in Gulf of Mexico Oil and Gas Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 382-9. Distribution of Atlantic Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 392-10. Distribution of Pacific Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 412-11. Trends in Pacific Region Oil and Gas Production.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 412-12. Distribution of Alaskan Planning Areas by Water Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Chapter 2

The Role of Offshore Resources

OVERVIEW

The petroleum and natural gas resources of off-shore areas of the United States could be a key ad-ditional energy source to help meet U.S energyneeds and limit oil import growth in future years.Although plentiful energy supplies and decliningworld prices have dampened concern about theenergy situation, supply and demand trends in-dicate potential domestic shortfalls and rising oilimports by the end of the century. At present, off-shore oil accounts for about 11 percent of total do-mestic petroleum production and offshore naturalgas accounts for about 24 percent of total domes-tic gas production. The potential for increasing thecontribution of offshore areas to U.S. energy supplymay be large. Most U.S. offshore acreage remainsto be explored, and the search is just beginning inthe deepwater and Arctic frontier areas.

Resource recoverability is determined by a com-bination of geologic, technologic, and economic fac-tors which can change over time. In addition, pe-troleum resource statistics are confusing becauseeach estimate seems to be the result of differentdefinitions and statistical methods. Given the in-accuracy and uncertainty associated with publishedresource estimates, they probably should be con-

sidered only as indicators of relative ranking amongprospective oil and gas producing areas.

Offshore areas are expected to contain 21 to 41percent of the oil and 25 to 30 percent of the natu-ral gas that is undiscovered and recoverable in theUnited States. As much as one-third to one-half ofthe offshore oil may lie under waters 660 to 12,000feet deep, If onshore and offshore Alaska are con-sidered together, Alaska may contain as much asone-half of the total amount of recoverable oil ex-pected to be found in the United States. About 31percent of the natural gas expected to occur offshoreprobably lies in water depths between 660 and 8,200feet. Gas occurring in the Arctic offshore regionsis now considered to be uneconomical to recover.

California, while having a long history of offshorepetroleum production, still remains largely unex-plored in many areas. Similarly, the Atlantic andAlaskan regions have had only limited exploration,and as yet their Federal offshore areas have no oilor gas production. The Gulf of Mexico region con-tinues to produce about 90 percent of the oil andvirtually all of the natural gas produced fromsubmerged lands.

U.S. ENERGY OUTLOOK

Although the United States is now in a periodof relative stability as far as energy prices and sup-plies are concerned, energy trends include slowlyincreasing demand, declining domestic production,and rising imports to the end of the century. Al-though oil imports have decreased in the last 5years, domestic demand is outpacing supply andleading to higher import levels. Low oil and gasprices have reduced incentives to conserve onenergy uses and to substitute alternative fuels, Fore-casts indicate that imports could reach record highsin the 1990s, increasing U.S. vulnerability to supply

disruptions. Against this background, the oil andgas resources of the offshore areas of the UnitedStates take on new significance in their potentialcontribution to future U.S. energy needs.

Energy Demand Trends

U.S. energy demand decreased over the past dec-ade largely because of the increase in the price ofoil and natural gas that began in the early 1970sand the resulting energy conservation efforts (seetable 2-l). The real increase in the price of both

21


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

Energy demand

Oil Natural gas Coal Nuclear Hydro TotalYear (MMBD) (TCF) (MMT) (BkWh) (BkWh) (QUADS)

1968 . . . . . . . . . . . . . . . . . 13.4 18.6 509.8 12.5 225.2 60.91971 . . . . . . . . . . . . . . . . . 15.2 21.8 501.6 38.1 273.1 67.81974 . . . . . . . . . . . . . . . . . 16.7 21.2 558.4 114.0 316.9 72.51977 . . . . . . . . . . . . . . . . . 18.4 21.7 625.3 250.9 241.0 76.21980 . . . . . . . . . . . . . . . . . 17.0 19.9 702.7 251.1 300.1 75.91983 . . . . . . . . . . . . . . . . . 15.2 17.0 736.7 293.7 373.2 70.7

Domestic energy production

oil Natural gas Coal Nuclear Hydro TotalYear (MMBD) (TCF) (MMT) (BkWh) (BkWh) (QUADS)

1968 . . . . . . . . . . . . . . . . . 10.6 18.5 556.7 12.5 225.9 56.71971 . . . . . . . . . . . . . . . . . 11.2 20.2 560.9 38.1 269.5 61.21974 . . . . . . . . . . . . . . . . . 10.5 20.7 610.0 114.0 304.2 60.81977 . . . . . . . . . . . . . . . . . 9.9 19.2 697.2 250.9 223.6 60.11980 . . . . . . . . . . . . . . . . . 10.2 19.4 829.7 251.1 279.2 64.71983 . . . . . . . . . . . . . . . . . 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 and1983. In the same period, energy use per unit ofgross national product dropped more than 22 per-cent. In the industrial sector, energy demand de-clined by 15.5 percent as a result of increasedenergy efficiency in various industrial processes anda shift to less energy-intensive products. In the resi-dential and commercial sectors, energy demand re-mained nearly constant due to building insulationefforts and reduced heating and cooling levels. Inthe transportation sector, driving mileage has beenreduced, and fuel consumption has become moreefficient since the Corporate Average Fuel Econ-omy (CAFE) standards were put in place.

Today, a combination of stable energy prices andrecovery from the 1982-83 economic recession hascaused demand to grow once again. Total energydemand in 1984 increased about 7 percent over1983. Most of the increase is probably to restoredemand capacity lost during the recession. Thereare indications, however, that fuel-use efficiencymay be dropping. Driving mileage is up andautomobile manufacturers are producing and sell-ing more cars with lower fuel economy. Just ashigher prices prompted fuel conservation, it appearsthat lower petroleum prices may now be encourag-ing greater energy use.

There is also less incentive to switch from oil andgas to alternative fuel sources. After the oil and gasprice increases of the 1970s, demand for alterna-tive fuels grew. Electric utilities, in particular, madegreater use of coal and nuclear power in place ofoil and natural gas. However, low oil and gas priceshave now reduced the economic advantage of usingcoal, and the future of nuclear power is limitedunless changes are made in the technology, man-agement, and regulation of the industry. Low oilprices have halted the development of synthetic fuelsmade from more abundant resources (e. g., coal,oil shale, heavy oils, tar sands). Similarly, the highcapital costs of converting direct renewable energysources (e. g., solar, wind, wood) has severelylimited their potential for replacing oil and gas.

Energy forecasts indicate that overall U.S. energydemand will grow modestly to the end of the cen-tury and that oil will remain the largest singleenergy source. Projections by the Department ofEnergy (DOE) and the Gas Research Institute(GRI) show energy consumption in the UnitedStates growing by about 1 percent per year—lessthan half the expected growth rate of the gross na-tional product (see table 2-2). The percentage ofoil used in relation to total energy use is forecastto 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 ImportsEnergy source GRI DOE GRI DOE GRI DOE

Oil and NGL (MMBD) . . . . . . . . . 16.7 15.2 9.2 8.1 7.5 7.1Natural gas (TCF). . . . . . . . . . . . 19.0 18.7 15.9 15.9 3.8 2.8Coal (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 anysignificant replacement of oil, but rather indicatesthat growth in the electric utility sector will con-tinue to be accommodated partly by coal and nu-clear power.

Energy Supply Trends

Despite the large oil and gas price increases ofthe 1970s, domestic energy production remainedvirtually level over the past decade (see table 2-1 ).Growth in the production of coal and nuclear poweroffset declines in domestic oil and natural gas pro-duction, If the contribution of Alaskan crude oilproduction is removed, domestic oil production de-clined more than 18 percent between 1974 and1983. The slight increase in domestic oil produc-tion since 1980 is due entirely to production fromthe Prudhoe Bay Field on Alaska’s North Slope.Domestic oil and gas reserves have declined evenmore rapidly than production, despite enormousincreases in resource exploration and developmentsince 1973, and particularly since 1980. Accord-ing to DOE, proven reserves of economically re-coverable oil dropped from 47 billion barrels in1970 to 35 billion barrels in 1984,

As a result of the recent increase in energy de-mand, however, domestic energy production in-creased in 1984 as compared to 1983. Crude oil pro-duction grew slightly with increases in Alaskanproduction, and natural gas output was about 11percent ahead of 1983. Coal production, which de-clined between 1981 and 1983, was up sharply as

electricity demand rebounded from the recession.Similarly, the production of nuclear-generated elec-

tricity was expanded in 1984, as new power plantscame on line.

Oil import levels have increased as growth in do-mestic demand has outpaced domestic oil produc-tion. Oil imports decreased after the oil embargoand price increase of 1973, but shortly thereaftergrew to an all time high of 9.3 million barrels perday in 1977. Over the next 2 years, Alaskan oilbegan to flow in significant quantities and U.S. im-ports of petroleum declined slightly. A second oilprice rise in 1979 and cumulative conservation ef-forts led to declining imports and a record oil im-port low of 4.9 million barrels per day in 1983.However, in 1984, oil imports once again startedto climb and increased about 7 percent over 1983,accounting for about one-third of U.S. petroleumrequirements.

The DOE and GRI energy forecasts indicate acontinuing decline in the production of domesticoil and natural gas to the year 2000 (see table 2-2). In both forecasts, oil and gas imports are ex-pected to increase substantially, to between 7.1 and7.5 million barrels of oil per day and 2.8 and 3.8trillion cubic feet (Tcf) of natural gas per day. Thereare indications, however, that even the DOE andGRI projections maybe optimistic and that importsmay reach higher levels. Continued low energyprices may lead to greater fuel usage, reduced con-servation efforts, and limited replacement of oil byalternative fuels. There are also uncertainties aboutnatural gas supplies and the possibility that pricecontrols and a failure to develop unconventionalsources may promote substitution of oil for natu-ral gas.

38-749 0 - 85 - 2


In comparison with the DOE projection of 8.1million barrels per day and the GRI projection of9.2 million barrels per day, studies by the Officeof Technology Assessment (OTA)1 and the Con-gressional Research Service (CRS)2 forecast evengreater declines in domestic production of crudeoil. OTA projected that domestic oil and naturalgas liquids production would decline to 4 to 7 mil-lion barrels per day by 2000. CRS was less pessi-mistic, but still estimated a decline in productionto 7.3 to 8.5 million barrels per day. These pro-duction levels indicate that oil imports may rangefrom 7 to as high as 10 million barrels per day in2000, contributing to high trade deficits and de-creases in energy and economic security.

‘U. S. Congress, OffIce of Technology Assessment, World Petro-leum Avaifabifity: 1980-2000 (Washington, DC: U.S. GovernmentPrinting Office, October 1980).

‘Congressional Research Service, ‘‘Domestic Crude Oil Produc-tion Projected to the Year 2000 on the Basis of Resource Capability’Uuly 1984).

Current energy forecasts underline the impor-tance of the oil and gas resources of the U.S. OuterContinental Shelf (OCS) and the Exclusive Eco-nomic Zone (EEZ). Since domestic reserves havebeen dropping over the last several years, an in-creasing percentage of our domestic oil productionmust come from oil reserves as yet undiscovered.Widespread exploration and development of thelower 48 States make large field discoveries in on-shore areas of the United States, outside Alaska,somewhat doubtful. In contrast to the overallenergy reserve status in the United States, estimatedrecoverable oil and gas reserves in Federal offshoreareas have increased steadily in recent years. How-ever, only a small percentage of total U.S. offshorearea has been explored. Offshore resources, par-ticularly those of the unexplored deepwater andArctic frontier regions, offer the best hope forlimiting future U.S. energy import dependence.

RESOURCE PROJECTION PROBLEMS

The U.S. Geological Survey (USGS) estimatedin 1981 that 26 to 41 percent of the oil and 25 to30 percent of the natural gas that is undiscoveredand recoverable in the United States would befound offshore within the EEZ. However, that esti-mate is by no means certain. Published projectionsof oil and gas reserves and resources are generallyincomplete and lack accuracy. There are severalreasons for this.

●

●

●

Projections of oil and gas resources are gen-erally based on averages or aggregated valuesfrom independent analyses and expert opin-ions, which results in widely ranging estimatesthat are subject to large errors.Until an area is sufficiently explored, resourceprojections are largely inferred from indirectgeological information, e.g., seismic records,gravity and magnetic data, and geomorphol-ogy, and Continental Offshore StratigraphicTest (COST) wells.Information on oil and gas reserves in existingfields and assessments of resource potential forfrontier regions are considered by the petro-leum industry to be proprietary and highly

sensitive, therefore it is unlikely that precise,detailed information on recoverable reservesand resources from individual firms will beavailable to Congress, the Department of theInterior, or the public.

The amount of recoverable oil and gas that re-mains to be discovered beyond the currently esti-mated reserves will be produced from two sources:1) extension of known fields through new develop-ments in drilling technology and new techniquesfor increasing (enhancing) oil and gas recovery fromold fields; and 2) new discoveries in unexploredfrontier regions and undeveloped areas of provenregions.

Over three-fourths of the oil discovered thus farin the United States is located in ‘ ‘giant’ fields of100 million barrels or more—e.g., the Gulf of Mex-ico and Prudhoe Bay, Alaska. About 8 percent ofthe discovered oil is found in fields smaller than 10million barrels. Therefore, the reliability of dis-coverable resource projections for the EEZ will de-pend on how well geologists and petroleum engi-neers can predict the existence of giant fields

Ch. 2—The Role of Offshore Resources ● 2 5

offshore, and how accurately they can evaluate theextent of the recoverable resources that lie therein. 3

When estimates go beyond proved reserves, ac-curacy rapidly deteriorates with errors of perhaps50 percent or more.

Comparability Among Estimates

Although resource estimates may be useful toCongress in considering national policies, theirvalue lies primarily in indicating the relative reservepotential from the likely petroleum-bearing basinsrather than as estimates of absolute quantities ofoil and gas available offshore. The primary use ofpublished resource assessments is for general in-formation.

Published sources have little technical use in ei-ther the administration of the offshore leasing pro-gram by the Department of the Interior or the for-mulation of industry leasing strategies. Firms makelarge investments to develop detailed informationon resource prospects in the individual basins ofthe OCS for the purpose of corporate planning.Good resource information is a major competitivefactor among oil and gas firms bidding on offshoretracts, and therefore is considered proprietary.However, it is unlikely that even the industry hasaccurate estimates.

Four independent assessments of the oil and gasresources of the OCS are currently available to thepublic:

1.

2.

3.

4.

It

USGS Circular 860 (1981): Estimates of Un-discovered Recoverable Conventional Re-sources of Oil and Gas in the United States.National Petroleum Council (1981): U.S.Arctic Oil and Gas.Rand Corporation (1981): The Discovery ofSignificant Oil and Gas Fields in the UnitedStates.Potential Gas Committee (1983): PotentialSupply of Natural Gas in the United States.

is difficult to make area-by-area comparisonsof the estimates of undiscovered oil and gas pub-lished in the four resource assessments. The diffi-

3M. King Hubbert, ‘ ‘Techniques of Prediction as Applied to theProduction of Oil and Gas, ’ Oil and Gas Supply AZodeIing, S. I.Grass (cd, ) (Washington, DC: National Bureau of Standards SpecialPublication 631, May 1982).

culty in comparing these estimates arises from: 1 )differences in methodologies used in deriving theresource estimates; 2) differences in reporting sta-tistical data, e.g., errors, ranges, and probabilities;3) inconsistencies in definitions of resources and re-serves; 4) differences in technical and economicassumptions in deriving recoverable resourcevalues; 5) the inclusion or exclusion of unconven-tional resources, e.g., low permeability formations;6) lack of agreement on boundaries (water depth,international boundaries, etc. ) of the resource areabeing estimated; and the fact that 7) the professionalperspectives of the estimators may influence theprobabilities assigned to the estimates; and 8) theconditions and assumptions on which the estimatesare based are seldom specified in sufficient detail.

Furthermore, several government agencies withvarying missions often report resource statistics indifferent ways to suit their particular purpose. Thismay result in inconsistencies among governmentreports and add to the confusion.

Reliability of Estimates

It is difficult to determine the reliability andcredibility of the various resource assessments formany of the same reasons. In addition: 1 ) detailsof the methods used for estimating resources arenot published; 2) data bases and geological infor-mation used for the assessments are often consid-ered to be proprietary and confidential; and 3) theprocess used for deriving resource estimates relieslargely on the ‘ ‘expert opinion’ of geologists andpetroleum engineers.

While it is not entirely accurate to characterizethe collective (averaged) judgment of resource ex-perts as ‘‘subjective, the use of ‘opinions’ in lieuof science-based hypotheses and experimental dataprevent these expert-derived estimates from beingconsidered wholly ‘ ‘objective.

There can probably, therefore, be no determina-tion as to which resource assessment is the ‘ ‘best’or ‘ ‘most accurate. In any oil and gas resourceassessment, the quantitative volumes should be con-sidered speculative and may or may not accuratelyreflect the volumes of oil and gas that will or couldbe ultimately discovered in any single basin or re-gion. Many of the basins with large estimated po-

26 • Oil and Gas Technologies for the Arctic and Deepwater

tential may prove unproductive; some may yieldpetroleum recoveries exceeding even the most op-timistic estimates. Estimates are made recognizingthe uncertainties involved, but are based on the cur-rent level of knowledge.

Interpretation of Estimates

Aside from problems of comparability and reli-ability, there are problems associated with inter-preting various estimates. Statistics for potential oiland gas resources are reported using a lexicon thatmay confuse and befuddle those unfamiliar withpetroleum resources. Petroleum reserves and re-sources are frequently explained, as shown in table2-3.

In addition, crude oil and natural gas resourcesare often reported in combined units of ‘‘barrelsof oil equivalent (BOE). This measure is calcu-lated by converting estimated natural gas and nat-ural gas liquids to oil (product) equivalents basedon comparable energy (Btu) units. While BOE re-source statistics provide a common unit of meas-ure which is easily communicated and compara-ble, it can be misleading where natural gasproduction is not immediately planned.

For example, the National Petroleum Council(NPC) study reports a risked mean of 31 billionBOE in Arctic offshore basins. However, only 57percent (18 billion barrels) is oil, and the balanceis gas and natural gas liquids, In remote regionsof the Arctic and in many deepwater areas, natu-

Table 2-3.—Definitions of Reserves and Resources

Pastproduction

Wellcapacity

Delivery system

Present price andtechnology l imit

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 quantityof 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 drillingand development.

Subeconomic Resources: Oil and gas that has been discovered, but in the judgment of the operators cannot be produced under current priceswith existing technology. Subeconomic resources are sometimes divided into two portions: First, the unrecoverable, high-cost portion of oil andgas currently left behind in producing reservoirs. Second, oil and gas in other reservoirs that have been found but are not now producing or havebeen 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 notproceeded to a point where there is physical evidence of the actual presence of oil and gas. Only expectation exists, and estimates of un-discovered 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, aswell 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., oilshale, 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).


ral gas production is not now economically feasi-ble. Therefore, to combine oil and natural gas intoa single measure can be misleading to those not fa-miliar with the distinction between oil equivalentresource statistics (which may include unmarketablenatural gas) and crude oil resource statistics.

Other Factors

Estimates of potentially recoverable resources willchange in response to: 1) oil prices, productioncosts, and economic conditions; 2) new technologi-cal developments that enable more efficient recov-ery of oil and gas; and 3) new knowledge about re-

sources gained from exploration. For example, theUSGS revised its 1975 resource estimates in 1981to reflect changes in technology (resource estimateswere included down to water depths of 7,870 feetin Alaska and 8,200 feet elsewhere); changing eco-nomic conditions; and more geological informationgained from exploration. As a result, estimates ofoffshore oil potential decreased slightly even withthe additions from the Continental Slope. Offshoreoil resources were estimated at 17 to 49 billion bar-rels in 1975 and decreased to 17 to 44 billion bar-rels in 1981. Estimates of natural gas increased sig-nificantly from 42 to 81 Tcf in 1975 to 72 to 167Tcf in 1981.

U.S. EXCLUSIVE ECONOMIC ZONE

The 200-nautical mile U.S. Exclusive EconomicZone encompasses 1.9 billion acres adjacent to thecoasts of the continental United States. * Approx-imately 1.3 billion acres of the EEZ is underlainby the Continental Shelf, the extension of the con-tinental land mass that was flooded when the oceansrose. Almost half of the U.S. Continental Shelf (815million acres) lies adjacent to Alaska.

Along most of the U.S. coastline, the ContinentalShelf gradually slopes downward (see figure 2-1)until it breaks abruptly at the edge of the Continen-tal Slope where it plunges steeply toward the deepocean floor. At the transition zone between the deepocean and the base of the Continental Slope is theContinental Rise, which rises gradually from theAbyssal Plain.5

Water depths over the Continental Shelf rangeto more than 600 feet at the edge of the Continen-tal Slope. Undersea canyons have been cut deeplyinto the Continental Shelf at the mouths of majorrivers, such as the Hudson, the Mississippi, andoff the mouth of the Chesapeake Bay, The Con-

4Robert W’. Smith, “The Maritime Boundaries of the UnitedStates, Geographical Review (October 1981), p. 395.

50nc should distinguish between the ‘‘geologic Cent inental Shelfand the ‘ ‘legal (;ontinenta] Shell. The former is defined by scientificprim iplc of landfhrm, pos]tion and Seologica] orig~n The latter is aconstruct of law imposed by the need for regulating international af-fairs among coastal nations under the I.aw of the Sea and interna-tional agreements.

tinental Slope plunges to depths over 8,250 feetbefore merging with the Continental Rise. Depthsover the Continental Rise range between 11,500and 20,000 feet.

Much of the Continental Shelf was formed underprehistoric conditions that favored the evolution ofpetroleum —accumulated organic-rich sediments,extremely high pressures from overlying materials,and high subsurface temperatures. Thirty-foursedimentary basins with oil and gas potential havebeen identified in the U.S. Continental Shelf. TheDepartment of the Interior recognizes 26 offshoreareas with commercial oil and gas potential for pur-poses of leasing in the OCS. Sediments in someof these basins reach thicknesses of more than43,000 feet. In addition, portions of the ContinentalSlope and the Continental Rise are underlain bya great wedge of sediments and ancient buried reefsthat may contain petroleum deposits. Deep oceanicbasins, particularly the Gulf of Mexico, may alsocontain petroleum, but because of the water depthsmuch less is known about these prospects. G

The breadth of the U.S. Continental Margin(Shelf, Slope, and Rise) varies considerably, rang-ing from a few miles along steep segments of thePacific Coast to perhaps 500 miles adjacent to partsof Alaska. The establishment of the U.S. EEZ in

6H, D. Hedberg, U. D. Moody, and R. M. Hedberg, ‘‘PetroleumProspects of the Deep Offshore, AAPG Bulletin 63(3):286-300.


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

Margin of the U.S.

Exclusive economic zoneTerritorial Contiguous

Sea zone3 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 GeographicalPerspective, ” Ocean Development and International Law Journal 3:3 -

1983 added about 46 percent more ocean area tothat already under the jurisdiction of the UnitedStates for the purpose of exploring and developingthe living and nonliving resources of the sea. Thenet effect was to add approximately 600 millionacres of seabed to that already claimed for exclusiveresource development by the United States offshorethe 50 States.

Oil Resources

The two most widely quoted assessments of off-shore oil resources are USGS Circular 860 and theNPC study. The NPC study dealt only with Arc-tic resources and, in general, there is some agree-ment between the two assessments on Arctic oilpotential. Both assessments used an averaging tech-nique (modified Delphi) to aggregate expert opin-ion of estimates based on ‘‘geological analogies,i.e. , the prediction of the occurrence of oil in anunexplored area based on similarities between thatarea and one in which oil is known to exist. 7 How-ever, because the statistical treatment of the data

7JOSePh p Riva, Jr., ‘ ‘The Occurrence of Petroleum, World Pe-troleum Resources and Reserves (Boulder, CO: Westview Press,1983)

is different in the two assessments, the estimatescan not be directly compared.

Resource estimates from USGS Circular 860 arethe most widely cited and have been used in thepast by the Minerals Management Service (MMS)in general lease sale planning and for public infor-mation (see table 2-4). Total offshore oil resourcesaccording to the USGS study are about 30 billionbarrels, one-third of which is in water depths greaterthan 660 feet (see figure 2-2). However, as a re-sult of an institutional reorganization, the MMSno longer uses USGS estimates in lease sale plan-ning. Henceforth, MMS will be responsible for de-veloping all offshore resource estimates and hasrecently revised the estimates of offshore oil andgas (see box). a

Deepwater Oil Resources

According to the 1981 USGS estimates, about40 percent of the recoverable oil expected to befound in the Continental Slope beneath waterdepths greater than 660 feet is in the Atlantic

‘Minerals Management Service, Estimatc=s of ~Tndiscot’ered Oil andGas Resources for the Outer Continental Shelf (personal corre-spondence, Feb. 4, 1985),

Ch. 2—The Role of Offshore Resources . 29

Table 2-4.—Offshore Resource Estimates Ocean. Nearly 25 percent of the projected deep-water oil resource is in the Pacific Ocean off Cali-fornia, Oregon, and Washington, and a likeamount is expected to be found in deepwater re-gions of the Gulf of Mexico. Deepwater resourcesin Alaska are estimated to be about 1.1 billionbarrels.

The USGS did not include recoverable oil andgas that may occur in deep ocean regions, e.g., theGulf of Mexico Oceanic Basin or in extremely deepwater in the Pacific Ocean, in its 1981 assessment.It is possible, therefore, that one-third to one-halfof U.S. offshore oil resources lie under waters rang-ing in depth from 660 feet to more than 12,000 feetwhen the potential of the oceanic basins within theOCS is included.

OilWater depth (billion Gas

(meters) barrels) (TCF)

AlaskaNorton Basin . . . . . . . . . . . . . . . . . . . .St. George Basin ., . . . . . . . . . . . . . . .Navarin Basin . . . . . . . . . . . . . . .

(0-200)(0-200)(0-200)

(200-2500)(0-200)(0-200)

(200-2500)(0-200)

(200-2500)

0.20.40.90.10.27.80.83.60.2

2.82.41.20.2

1.01.40.91.00.10.2

0,41.00.82.30

0.9

1.22.55.601.0

39.34.3

13.81.1

42.926.1

2.40.4

1.32.61.01.30.60.8

2.43.25.68.60.23.6

North Aleutian Basin . . . . . . . . . . . . .Beaufort Sea . . . . . . . . . . . . . . . . . . . .

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

Gulf of MexicoCentral and Western Gulf of Mexico (0-200)

(200-2500)(0-200)

(200-2500)Eastern Gulf of Mexico. . . . . . . . . .

PacificSouthern 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 con-tain about one-half of the recoverable oil (offshoreand onshore) remaining in the United States. TheNPC assessment estimates the mean undiscoveredrecoverable resource in the Arctic to be 18 billion

AtlanticNorth 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, (basedon 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.

[Page Omitted]

This page was originally printed on a gray background.The scanned version of the page is almost entirely black and is unusable.

It has been intentionally omitted.If a replacement page image of higher quality

becomes available, it will be posted within the copy of this report

found on one of the OTA websites.

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 % changeAlaska:

Beaufort Sea . . . . . . . . . . . . . . . . . . . . . . . . . .7.8Navarin Basin . . . . . . . . . . . . . . . . . . . . . . . . . 1.0Chukchi Sea . . . . . . . . . . . . . . . . . . . . . . . . . .1.6St. George Basin . . . . . . . . . . . . . . . . . . . . . . 0.4Norton Basin . . . . . . . . . . . . . . . . . . . . . . . . . 0.2Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Total Alaska 12.2

Atlantic:North Atlantic. . . . . . . . . . . . . . . . . . . . . . . . . 1.4Mid-Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . .South Atlantic . . . . . . . . . . . . . . . . . . . . . . . . 0.9Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -Total Atlantic 5.4

Gulf of Mexico:Western Gulf . . . . . . . . . . . . . . . . . . . . . . . . . 5.2Central Gulf . . . . . . . . . . . . . . . . . . . . . . . . . . —Eastern Gulf . . . . . . . . . . . . . . . . . . . . . . . . . .Total Gulf of Mexico

Pacific:Northern California . . . . . . . . . . . . . . . . . . . . 0.5Southern CaIifornia . . . . . . . . . . . . . . . . . . . . 2.4Central California . . . . . . . . . . . . . . . . . . . . . . -Washington and Oregon . . . . . . . . . . . . . . . . 0.3Total Pacific

Total Offshore 27.0

0.89

0.540.370,000.113.30

0.110.350.22

0.68

3.720.416.03

0.25

0.360.042.19

12.2

39.35.6

13.82.5

2.2-73 84.6

5.614.23.60.3

-87 23.7

85.4

2.8- 3 88.2

3.9

1.4-31-55 162.7

3.83

3.023.470.431.42

13.85 –78

2.146.024.040.11

12.31 -48

28.7630.69

2.1959.84 - 1 3

1.122.420.510.854.70 -24

90.5 - 4 4SOURCE: U.S. ~sdodd Suwey, Olmdm=, Sefln?atee of UndieoovefsdRtoow3mbte Cwwntfond Resoumee of Of/ end C3ee /rr the United States (lWI).

Minera!8 Menaownent Servt~ Eethnetee of LJndkoverud 0// and G- Resources & the Outer Cent/nentu/ Shelf (personal correspondence,Feb. 4, 1S86).

barrels while USGS estimates a resource base of11 billion barrels of crude oil (see table 2-5).

In terms of undiscovered potentially recoverableoil (based on 1981 technology), according to theNPC, the Beaufort Sea has the greatest resourcepotential in Alaska with 9.5 billion barrels (USGSestimated 7.8 billion barrels) including both theContinental Shelf and the Slope (see figure 2-3).

The Navarin Basin ranks second in resource po-tential with 2.4 billion barrels (USGS estimated 0.9billion barrels); third is the Central Chukchi Shelf(NPC estimated 1.7 billion barrels, USGS esti-mated 0.6 billion barrels); followed by the NorthChukchi Shelf and Slope (NPC estimated 1.5 bil-lion 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 0.8Navarin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 0.1 0.8 0.1Central Chukchi . . . . . . . . . . . . . . . . . . . . 1.7 — 0.6St. George . . . . . . . . . . . . . . . . . . . . . . . . . 1.2

—0.4

N. Chukchi . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 0.3 0.8 0.2Bristol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.6 — 0.2Norton . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.3

——

Hope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .—

0.2 0.0Zhemchug . . . . . . . . . . . . . . . . . . . . . . . . . 0.1 0.0 0.0 0.0Aleutian . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.0 0.0 0.0 0.0Umnak 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


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 containsabout 172 Tcf of natural gas. The Potential GasCommittee (PGC), an industry-staffed group oper-ating through the Colorado School of Mines,evaluated the natural gas resources that are ex-pected to occur up to a maximum depth of 3,280feet. It estimated that the OCS to that depth “prob-ably’ contains 35 Tcf of natural gas. (The PGC“probable” estimate is a modal estimate and maybe comparable to the statistical mean.) Because thePGC assumed the economic limits of gas produc-tion to be about 3,000 feet on the ContinentalSlope, the USGS and PGC resource estimates fornatural gas cannot be compared directly. It appears,however, that the PGC estimates are considerably

more conservative than those of the USGS. Al-though the PGC has historically been optimisticabout U.S. onshore natural gas resources, it esti-mates a probable potential offshore supply of 35Tcf, a possible supply of 76 Tcf, and a speculativesupply of 122 Tcf. Even its most optimistic esti-mate falls short of the USGS mean estimate of 172Tcf. In waters 660 feet or less, the PGC estimatesthe probable occurrence of 32 Tcf of natural gas,while the USGS estimate is about 120 Tcf.

As more geological information is gained fromexploratory drilling in frontier regions, natural gasestimates are revised upwards. In 1975, the USGSestimated that the Continental Shelf contained be-tween 42 and 81 Tcf (at the 95 and 5 percent prob-ability levels respectively) of natural gas. Whenrevised in 1981, these estimates were increased tobetween 72 and 167 Tcf respectively. The upwardadjustment resulted from indications of the pres-ence of more gas and less crude oil in exploratorywells in the Atlantic, Gulf of Mexico, and Pacificoffshore regions.

The Gulf of Mexico and the Alaskan Arctic areexpected to contain nearly 82 percent of the natu-ral gas in the OCS (72 and 70 Tcf respectively),while the Atlantic is estimated to contain 24 Tcfand the Pacific only 8 Tcf (see figure 2-4).

Deepwater Natural Gas Resources

Approximately 31 percent of the natural gas inthe OCS is expected to occur in water depths be-tween 660 and 8,200 feet. About half of this (27Tcf) is in the Gulf of Mexico, while 16 Tcf is inthe Atlantic, 6 Tcf in the Arctic, and 5 Tcf in thePacific.

Arctic Natural Gas Resources

The USGS estimates that 58 Tcf of natural gasmay occur in the Arctic. The NPC estimates that69 Tcf of natural gas may be expected to occur inthat region (see table 2-6). The NPC estimate in-cludes natural gas liquids while the USGS estimatedoes not. If natural gas liquids (2.5 billion barrels)are removed from the NPC estimate, the two assess-ments of Arctic natural gas potential agree within20 percent.

Over 90 percent of Alaskan offshore gas lies indepths 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 areexpected to contain about 78 percent (39 Tcf and14 Tcf respectively) of the natural gas in the Arc-tic while the Navarin Basin contains 6 Tcf, St.George Basin 3 Tcf, and the Norton and NorthAleutian Basins about 1 Tcf each (see figure 2-5).

Area

Legend:

0-660 feet

660-8,200 feet

Resources by Lease SalePlanning Areas

The EEZ is subdivided into 26 planning areasby the Department of the Interior for leasing pur-poses (see figure 2-6). Each planning area encom-passes one or more sedimentary basins that havepotential for petroleum resources. Nearly 1.1 bil-lion acres of the total 1.9 billion acres within theOCS are included in the planning areas. However,only about 17 percent of the acreage (179 millionacres) in the planning areas is considered to beunderlain by ‘‘promising geological structures’with significant potential for accumulated oil andnatural gas (see table 2-7).

Over half of the acreage(110 million acres) con-sidered to have promising geological structures foroil and gas is adjacent to Alaska. About 15 percent(27 million acres) of the area over promising struc-tures is in planning areas located in the AtlanticOcean, where exploration activities have failed toconfirm the presence of commercial quantities ofoil or gas. A similar proportion of the promisinggeology (25 million acres) lies in the Gulf of Mex-ico planning areas which historically have producedlarge 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . 26.3Navarin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.5Central Chukchi . . . . . . . . . . . . . . . . . . . . 9.0St. George . . . . . . . . . . . . . . . . . . . . . . . . . 5.6N. Chukchi . . . . . . . . . . . . . . . . . . . . . . . . . 5.0Norton . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4Hope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1Bristol. ., . . . . . . . . . . . . . . . . . . . . . . . . . . 0.3St. Matthew - Hall . . . . . . . . . . . . . . . . . . . <1.0Zhemchug . . . . . . . . . . . . . . . . . . . . . . . . . <1.0Umnak ., . . . . . . . . . . . . . . . . . . . . . . . . . . <1.0Aleutian . . . . . . . . . . . . . . . . . . . . . . . . . . . <1.0

6.7<1.0

35.05.23.02.33.41.2

4.30.4——1.1—

1.7—— —

1.00.00.10.00.0

—— —

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


Figure 2-5.—Natural Gas Resources in AlaskaPlanning 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 extensivelydeveloped offshore region of the United States. Itcurrently produces over 90 percent of total U.S.offshore oil production and virtually all of the off-shore natural gas. The region consists of three leaseplanning areas: Western Gulf, Central Gulf, andEastern Gulf. Projections indicate that the Gulf ofMexico will continue to dominate offshore oil andgas production as the industry expands its explora-tion into the deepwater frontier areas of the GulfOceanic Basin.

Exploration and development is most advancedin the Central Gulf of Mexico planning area, whichlies south of the States of Louisiana and Mississippi.

Table 2.7.—Estimates of Offshore Acreage WithHydrocarbon Potential (millions of acres)

Geological HydrocarbonPlanning 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 . . . . . . . . . . . . . . . . . . . . . . . .

17.39.46.09.49.39.97.5

2.03.2

29.216.07.58.0

14.030.6

179.3

26.063.258.046.035.012.0N/A

148.412.435.028.9

8.9N/A29.719.1

522.6

‘Estimates of the acreage covered by promising geological structures.Department of the Interior, Final Supplement to the Final EnvironmentalStatement, 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 placein the Eastern Gulf of Mexico planning area adja-cent to Alabama and Florida.

Resource estimates. The Central Gulf of Mex-ico planning area is estimated to contain 3.2 bil-lion barrels of oil and 34 Tcf of natural gas, whichis more than half of the total undiscovered economi-cally recoverable oil resources in the Gulf of Mex-ico region. The Western Gulf of Mexico planningarea is expected to be rich in natural gas (26 Tcf),but contains only 2 billion barrels of oil. The East-ern Gulf of Mexico planning area is estimated tocontain 1.2 billion barrels of oil and only 1.6 Tcfof natural gas. Remaining oil reserves in the Gulfof Mexico region are estimated to be 3 billion bar-rels of oil and 40 Tcf of natural gas. g

Physical and geological characteristics. The Continental Shelf in the Gulf of Mexico region slope:gently seaward at an angle of less than one degreeIt forms a broad plain of relatively shallow waterranging in breadth from 12 miles off the alluviafan of the Mississippi River to as much as 140 mileoff 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 1983p. 8.


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

WashingtonOregon

NorthernCalifornia

CentralCalifornia Mid-Atlantic

SouthernCalifornia 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 I100° 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.


Continental Slope is relatively steep, ranging be-tween 2 and 45 degrees. Beyond the base of theContinental Slope, the Abyssal Plain of the Gulfof Mexico Oceanic Basin reach depths of up to12,000 feet at the outer edge of the EEZ. Althoughthe Continental Shelf in the Gulf of Mexico regionis extensive, 42 to 68 percent of the acreage withinthe Gulf of Mexico lease planning areas is in watersdeeper than 660 feet (see figure 2-7).

Geological conditions that may occur in the Gulfof Mexico lease planning areas include unstablesediments on the sea floor, active faults, shallowgas accumulations, and underlying karst topogra-phy consisting of limestone caverns and voids inthe seafloor. The area off the Mississippi Delta andalong steeply sloping areas of the Continental Slopemay be subject to mass sediment movements.

Leasing and exploration. The Gulf of Mexico isthe most heavily explored and extensively devel-oped offshore petroleum region in the world. Theregion has been explored for more than 50 yearsand has been producing oil and natural gas for morethan 35 years. Nearly 21,000 wells have been drilledoffshore in the Gulf of Mexico, most of them in theCentral Gulf of Mexico planning area.

While exploration in the historically productiveareas of the Central and Western Gulf of Mexicoplanning areas continues at a high level, the off-shore industry’s interest in deepwater tracts has alsoincreased. The deepest exploratory well in the Gulfof Mexico was drilled in 1980 in the MississippiCanyon in 2,210 feet of water, and several otherwells have been drilled in waters ranging from 1,500to 1,835 feet.

Several tracts leased in the Atwater Valley sec-tor of the Central Gulf of Mexico planning areaare in waters of 3,500 feet and deeper, and oneblock in the Port Isabel area of the Western Gulfof Mexico is in 3,500 feet of water.10 Industry in-terest in deepwater tracts is centered on the areareferred to as the ‘‘flexure play, a sloping deep-water site that rapidly descends at the edge of theContinental Shelf.

Development, production, and reserves. Crudeoil production from the Gulf of Mexico region was

IOData Offshore Services, Supplement to the Ocean COnsfrUCfJOnReport (Houston, TX: Offshore Data Services, July 23, 1984).

about 310 million barrels in 1983, and natural gasproduction was approximately 3.9 billion cubic feet.Between 1972 and 1980, oil production in the Gulfof Mexico declined each year (see figure 2-8). Thistrend was reversed in 1981 and oil and condensateproduction is now at pre-1977 levels. The reboundin Gulf of Mexico oil production is considered tobean anomaly, however, and oil production is ex-pected to soon resume its previous decline. Gas pro-duction may have reached its peak in 1981 and isalso expected to begin a noticeable decline. At thebeginning of 1984, Gulf of Mexico oil reserves wereestimated at 3.4 billion barrels and natural gas at43.7 Tcf.11

Atlantic

The Atlantic region, while one of the mostgeologically studied oceanic regions in the world,is considered to be a frontier region for oil and nat-ural gas exploration. The region consists of fourlease planning areas: North Atlantic, Mid-Atlantic,South Atlantic, and Florida Straits. There is nocommercial crude oil or natural gas productionfrom the Atlantic region, and no reserve estimatesare available.

Resource estimates. Over three-quarters of theAtlantic region’s undiscovered economically recov-erable crude oil resources (4. 2 billion barrels) andabout two-thirds of its natural gas (15.4 Tcf) lie inwater depths of 660 to 8,200 feet. Total undis-covered recoverable resources in the three leaseplanning areas of the Atlantic region are estimatedto be 5.4 billion barrels of oil and 23.6 Tcf of nat-ural gas.

Nearly 60 percent of the oil (3.1 billion barrels)and natural gas (14.6 Tcf) within the entire Atlan-tic region is expected to occur in the Mid-Atlanticplanning area, between two-thirds and three-quarters of it in water depths between 660 and8,200 feet. The North Atlantic planning area is esti-mated to contain 1.4 billion barrels of crude oil and5.6 Tcf of natural gas, while the South Atlantic areais estimated to contain only 900 million barrels ofcrude oil—all in waters ranging in depth from 660to 8,250 feet—and 3.8 Tcf of natural gas.

1 IMiner~S Mma~ement service, Federaf OffShort statistics (Wash-

ington, DC: U.S. Department of the Interior, 1984).

Ch. 2—The Role of Offshore Resources • 37

0

* l - ”

0&


2

1

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

1955 1960 1965 1970 1975 1980

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

1983.

Physical and geological characteristics. The Con-tinental Shelf in the Atlantic region varies in widthfrom 14 miles off Cape Hatteras to 200 miles offthe coast of New England. From the break at theedge of the Continental Shelf to the base of the Con-tinental Slope, water depths plunge to between6,560 and 9,840 feet. From the base of the Con-tinental Slope, the Continental Rise extends grad-ually seaward to depths of 16,405 feet in the AbyssalPlain of the oceanic basin at the outer edge of theEEZ.

The major geological feature of the North Atlan-tic lease planning area is the Georges Bank plateauon the eastern edge of the Continental Shelf offCape Cod. About 58 percent of the waters withinthe North Atlantic planning area are 660 feet orless, and 35 percent are 6,560 feet or deeper (seefigure 2-9).

Deep canyons intersect the Continental Slope inthe Atlantic region. The Baltimore Canyon Troughis a major physiographic feature of the Mid-Atlanticplanning area, extending 300 miles from northeastto southwest. It appears likely that the area of great-est hydrocarbon potential in the Atlantic region islocated in the deeper waters of the ContinentalSlope of the Mid-Atlantic planning area, where apossible extension of Mexico’s Reforma-Chiapasoil-bearing reef complex may be buried under mile-deep ocean sediment. Seventy-eight percent of thearea within the Mid-Atlantic lease planning areais overlain by waters deeper than 6,560 feet.

The South Atlantic area is dominated by theBlake Plateau, a broad gently sloping segment ofthe Continental Shelf off Florida and Georgia, andthe Carolina Trough, a steep sloping segment ofthe Continental Slope trending from northeast tosouthwest off North and South Carolina. Over two-thirds of the South Atlantic lease planning area isin water depths of 6,560 feet or deeper.

Geological conditions that may affect oil and nat-ural gas development in the Atlantic region include:shallow recent faults, shallow gas deposits, massmovement of sediments, filled channels, erosionand scour, sand waves, faults present below the un-consolidated sedimentary section, and gas-chargedsediments. 12 The northerly flowing Gulf Streamalso may affect exploration and development of oiland gas in areas influenced by its currents.

Leasing and exploration. The first Atlantic re-gion sale was held in the Mid-Atlantic lease plan-ning area in 1976, Exploration in the Atlanticregion peaked in 1979. Since that time, the disap-pointing results of earlier tests coupled with gen-eral economic conditions and worldwide petroleummarkets has slowed the pace of the offshore indus-try’s exploration efforts.

Pacific

The Pacific region is considered the cradle of theoffshore oil and gas industry in the United States.In the 1890s, numerous shallow wells were drilledfrom wooden piers along southern Californiabeaches. From these piers, the offshore petroleumindustry ventured onto offshore platforms and ex-panded its operations to the Gulf of Mexico. It wasnot until 1950, however, that oil and gas produc-tion from offshore platforms in State waters beganin the Pacific region. It was also off southern Cali-fornia in the Santa Barbara area where the mostserious offshore well blowout occurred in 1969. Theimpression that the Santa Barbara blowout madeon the public continues to influence the Federal off-shore leasing program, although a similar incidenthas not occurred again in the United States.

Four lease sale planning areas are located in thePacific region: Southern California, Central Cali-fornia, Northern California, and Washington and

lZMiner~5 Managment Service, Mid Atlantic Summary Repoti(Washington, DC: U.S. Department of the Interior, 1983), p. 6,


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 AreaWater depth (meters) 0/0 of area

0-200 36%— — — - — -

— — — — — -

30 ”/0

>2000

SOURCE: Office of Technology Assessment


Oregon. A large proportion (over 90 percent) ofthe area within the lease sale planning areas in thePacific region is in water depths of more than 660feet. Eleven sedimentary basins with potential forcontaining hydrocarbons are located in the Pacificregion. The Santa Maria, Santa Barbara Channel,and Borderland basins in southern California arenearly geographically contiguous and offer the high-est potential for petroleum development.

Oil and gas development in the Pacific regionis concentrated in the Southern California area.Production from this area makes California the sec-ond ranking oil producing State and third rankingin natural gas production from the Federal OuterContinental Shelf. The most frequent oil and gasdiscoveries in the Pacific region have been mostlysmall fields of 100 million barrels or less. However,80 percent of the combined reserves of oil and nat-ural gas occur in larger fields ranging up to 400million barrels.

Resource estimates. Total undiscovered eco-nomically recoverable crude oil resources are esti-mated to be about 4.6 billion barrels for all Pacificplanning regions. Over half (2.4 billion barrels) isexpected to occur in the Southern CaliforniaBorderlands and Santa Barbara Channel lease plan-ning areas. The largest proportion of crude oil isestimated to be located in the Central and North-ern California lease planning area (1.9 billion bar-rels). Only 300 million barrels are estimated to existin the Washington and Oregon area.

Total undiscovered economically recoverablenatural gas resources (7.6 Tcf) are expected to besimilarly distributed among the lease planningareas, with the most (2. 5 Tcf) located in the SantaBarbara Channel, and a nearly like amount (2.3Tcf) in the Central and Northern California leaseplanning areas. Approximately 60 percent of crudeoil and natural gas within the Pacific region leaseplanning areas is expected to occur in water depthsof 660 to 8,200 feet.

Physical and geological characteristics. Thebreadth of the Continental Shelf in the Pacific re-gion ranges from about 25 to 30 miles off PointConception in California to over 100 miles off SanDiego. The Continental Slope plunges to depthsbetween 1,300 and 9,750 feet at the base of theSlope. Depths in the Abyssal Plain beyond the Con-

tinental Rise within the EEZ may reach depths ofabout 14,675 feet off Washington and Oregon. Sev-enty six percent of the area in the Central andNorthern lease planning areas and 48 percent ofthe area in the Southern California Borderland leaseplanning area are in water depths of 6,560 feet ormore (see figure 2-10). Depths in the Santa Bar-bara Channel may reach 2,050 feet.13

Of the offshore areas in the Pacific region thathave been explored for oil and gas, the Santa Bar-bara Channel and the Santa Maria basin have beenmost productive. In both instances, onshore oil andgas development adjacent to Point Conception andPoint Arguello preceded petroleum discoveries off-shore. The Point Arguello field within the SantaMaria basin is considered the largest field yet dis-covered in the U.S. Outer Continental Shelf. Itspotential is rated at 300 to 500 million barrels.

The Pacific region lies along an axis of knownseismic activity, and the potential for earthquakesis the major engineering factor affecting design ofoffshore platforms and underwater pipelines. Otherhazards may exist in the form of subsidence,seafloor erosion, shallow gas deposits, and masssediment movements.

Leasing and exploration. Oil and natural gasleasing in the Pacific region began in 1963 in theCentral California lease planning area. A total of14 oil and gas fields have been identified in the Pa-cific region. Two of these are natural gas fields; sixare oil fields; and six are a combination of oil andgas. Oil has been discovered at wells in waters rang-ing from 1,097 to 1,544 feet deep off Point Arguelloin southern California, but most of the oil discov-ered is heavy crude which may require developmentof special lift technologies to produce from thosedepths economically .14 Exxon is planning to installa production platform (Hondo ‘‘B”) in 1,200 feetof water in the Santa Ynez unit in 1987.

Development, production, and reserves. Crudeoil production from the Pacific region peaked at 31million barrels in 1971 and decreased to 10.2 mil-lion barrels in 1980. Pacific crude oil production

1qMiner~s Management Service, Pacific Summary Report (Wash-ington, 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 byCentral 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 figure2-1 1). Natural gas production followed a similartrend, peaking in 1971 at 15.7 billion cubic feetwhile decreasing to 2.9 billion cubic feet in 1979,and rebounding to nearly 18 billion cubic feet by1983. Due to new discoveries, original reserve esti-mates for crude oil increased to 1.2 billion barrelsin 1983 and natural gas to 2 Tcf.

Alaska

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

35

0 5

n

35

o1972 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,


are high, and its potential for oil and gas resourcesenormous. There is currently no oil or gas producedfrom Federal offshore lands in the Alaska region.

About 4 billion barrels of crude oil have been pro-duced thus far from State offshore leases in theCook Inlet since before 1954. In addition, onshorediscoveries at the North Slope (Prudhoe Bay andKuparuk fields) indicate that there may be 10 bil-lion barrels of recoverable crude oil and 35 Tcf ofnatural gas directly adjacent to offshore areas inthe Beaufort Sea. The occurrence of these petro-leum resources on State lands which are adjacentto the Federal Outer Continental Shelf is consid-ered to be an encouraging indication that vast pe-troleum resources may occur offshore.

The Alaska region consists of 15 lease sale plan-ning areas: 1) Gulf of Alaska; 2) Kodiak; 3) LowerCook Inlet-Shelikof Strait; 4) Shumagin; 5) NorthAleutian Basin; 6) St. George Basin; 7) NavarinBasin; 8) St. Matthew Hall; 9) Norton Basin; 10)Bowers Basin; 11) Aleutian Basin; 12) AleutianArc; 13) Hope Basin; 14) Chukchi Sea; and 15)Beaufort Sea. Planning areas 1 through 4 are inthe Gulf of Alaska subregion; 5 through 12 are inthe Bering Sea subregion; and 13 through 15 arein the Arctic subregion. This assessment consid-ers the Bering Sea subregion and the Arctic sub-region—the offshore subregions north of the Aleu-tian Islands—as the ‘ ‘Arctic’ for the purpose ofassessing Arctic technology.

Resource estimates. The Beaufort Sea lease saleplanning area is estimated to contain about 70 per-cent of the undiscovered economically recoverablecrude oil and natural gas (8 billion barrels and 39Tcf expected to be found in the subregions northof the Aleutian Islands. The Chukchi Sea planningarea, which lies to the west of the Beaufort Sea,is expected to contain about 4 billion barrels ofcrude oil and about 14 Tcf of natural gas. In total,over 80 percent of the crude oil and 76 perecentof the natural gas which may occur north of theAleutian Islands in the Arctic and sub-Arctic leaseplanning areas of Alaska are expected to be in theBeaufort and Chukchi Seas.

Physical and geological characteristics. The Con-tinental Shelf adjacent to Alaska represents aboutone-half the total U.S. Continental Shelf. Breadthof the Alaskan Continental Shelf varies signifi-

cantly, from as narrow as 8 miles at the eastern endof the Gulf of Alaska to perhaps as wide as 500 milesor more in the northwest Chukchi Sea.

The Continental Slope adjacent to Alaska dropssteeply to the abyssal depths. South of the Aleu-tian Islands, the Slope plunges between 16,400 and19,680 feet in the Aleutian Trench. Depths in theAbyssal Plain of the Gulf of Alaska range to about13,120 feet. Maximum depths in the Navarin Basinlie between 11,480 and 12,790 feet, while the max-imum depths in the Arctic Ocean within the U.S.EEZ are about 7,870 feet.

Over 80 percent of the area within the NavarinBasin lease sale planning area is in water depthsof about 660 feet or less while about 83 percent ofthe area in the Beaufort Sea planning area is inwaters 66 feet or less (see figure 2-12).

The southern Alaskan lease sale planning areasalong the Alaskan peninsula and the AleutianIslands are in seismically active areas where earth-quakes and possible tsunamis must be consideredin designing oil and gas exploration and produc-tion systems. Sediment instability, which may re-sult in sediment slides and slumping in areasseaward of about 160 to 213 feet, may occur in theAlaska region. In the Bering Sea, faulting, shallowgas-charged sediments, and sediment erosion andtransport are geological factors that must be con-sidered in offshore engineering design.15

Leasing and exploration. The first oil and gaslease sale in Federal waters off Alaska was in theGulf of Alaska in 1976. Since that time, about 3.8million acres have been leased in Alaskan waters,This represents more leased acreage than any otheroffshore region, with the exception of the Gulf ofMexico.

Exploration efforts in the Yakataga area of theGulf of Alaska, which began in 1976, resulted in11 dry holes. Since that time, the industry hasshown less interest in exploration in that area. Eightexploratory wells drilled in the Lower Cook Inletplanning area between 1978 and 1980 also yieldeddry holes, and no further exploration has takenplace.

lsMiner~s Management Service, Bering Sea Summary Re~ti(Washington, DC: U.S. Department of the Interior, 1983), p. 33.


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 areaSea” level

o-1o n 1 00/0

30-40

40-50—

SOURCE: Office of Technology Assessment.


In the Bering Sea subregion, six deep strati-graphic test wells have been drilled. Explorationhas recently commenced in the St. George Basinand Norton Sound planning areas. Planning forexploration in the Navarin Basin lease planningarea is currently underway.

Exploration in the Arctic subregion has shownmixed results. The disappointment of the failure

of Sohio Alaska Petroleum Company’s Mukluk ex-ploration well, which reportedly cost $140 million,is offset by the Shell commercial discovery at SealIsland in the Beaufort Sea planning area (jointFederal-State lease) near the Prudhoe Bay onshorefield. The next exploration well in the Beaufort Seawill be at Exxon’s Antares site about 45 miles north-west of the Mukluk site.

Chapter 3

Technologies for Arctic andDeepwater Areas

Contents

Page

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

The Arctic Frontier . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ... .... .. .+.Field Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Environmental Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Technology Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Deepwater Frontiers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Overview . . . . . . . . . . . . . . . . . . . . . .....+.. . . . . . . . . . . . . . . .........Field Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Environmental Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Technology Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLESTable 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

5050525563

7373757678

Page

495657737476


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

484950525356586162717475798485

Chapter 3

Technologies for Arctic andDeepwater Areas

OVERVIEW

Technology employed by the offshore petroleumindustry has changed dramatically over the past 20years, allowing the international petroleum industryto explore and produce in environments that wereconsidered almost prohibitive two decades ago. Thistechnology development which has revolutionizedthe offshore petroleum business is a result of adap-tion, innovation, and integration.

Industry began its move to deep and hostile envi-ronments by first applying land-based techniquesto the marine environment in discrete incrementalsteps. Progressively, industry resolved the problemsencountered offshore by adapting existing systemsor techniques or by designing new ones as needed.Experience in the Gulf of Mexico, where explora-tion and production have moved from land toshallow water to deep water, demonstrates this pro-gression of technology adaptation.

New technologies also have resulted when a ma-jor challenge or opportunity called for innovativeapproaches. For example, dynamic positioning wasa major innovation during the government’s 1960Mohole Project; acoustic-guided hole reentry wasa major innovation of the government’s DeepseaDrilling Project of the 1970s; and innovations indiving and underwater vehicles grew out of Navyprograms in the 1960s and 1970s. In private in-dustry, Deep Oil Technology’s tension leg plat-form, IMODCO’s single point mooring system,Shell’s first semi-submersible rig in the 1960s, Ex-xon’s deepwater guyed tower, and Conoco’s ten-sion leg platform in the 1980s are also examplesof major innovations.1

Finally, the integration of marine and ocean engi-neering with petroleum engineering and the busi-ness of oil drilling and production has brought var-

‘ U. S. Congress, Office of Technology Assessment, Ocean N4argin

Drilling—A Technicaj Memorandum (May 1980); and Proceedingsof the Offshore Technolo~r Conference (May 1984).

ied experience to bear on design, construction,safety and reliability. The basic principles of eachfield have been used effectively to design new sys-tems to develop and produce petroleum resourcesin the hostile marine environment (see figure 3-1).

Today more than one-quarter of world oil pro-duction is from offshore regions (see table 3-l). Thatportion has been growing at a rate of nearly 10 per-cent per year for the past decade, and major ex-ploration activities continue off the East, West, andGulf Coasts of the United States; in offshore Alaska;in the Asia-Pacific, especially the China Sea; offLatin America, especially Brazil; in the northernNorth Sea; and off Canada. Several of these regionscould be categorized as hostile environments be-cause of storms, severe waves and currents, deepwater, or Arctic or sub-arctic conditions.

For example, exploration has been underway forseveral years under the severe ice conditions of theBeaufort Sea off the United States and Canada; iniceberg conditions along Greenland and easternCanada; and under severe wind, wave, current,and deepwater conditions along the eastern Cana-dian and U.S. coasts, in the North Sea, and offsouthern 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 hos-tile waters (without production to date) has beenoff the coast of Canada.

The Canadian Beaufort Sea exploration activi-ties have been in the forefront of operations insevere ice and cold conditions. Eastern Canada andU.S. Atlantic Coast offshore exploratory drillinghave set rough water records. Exploratory activi-ties in the Mediterranean and off the U.S. Atlan-tic coast have set water depth records (see figure3-2).

4 7


Figure 3-1 .—Progression of Production Platforms for the North Sea

1968 1975 1976 1978Leman AUK A Brent A Cormorant A

SOURCE Shell 011 Co

In each of these situations, new technologies werenecessary for effective operations in very harsh envi-ronments. These technologies ranged from deep-water risers to concrete gravity structures to deep-water pipelines. Some examples of productionplatform technologies for hostile environments areshown in figure 3--3.

Offshore petroleum activities are commonlydivided into three phases: 1) exploration; 2) devel-opment; and 3) production. Exploration includes

1500ft

1350ft

1200ft

1050ft

&ft .

750

ft

450ft

ft

150ft

1990rr World Trade

Troll Field Center Tower

some pre-lease activities such as geological and geo-physical surveys as well as the exploratory drillingthat occurs (in the United States) after a lease sale.Development begins after an oil or gas discoveryis determined economic and includes the delinea-tion of the reservoir as well as the drilling of pro-duction wells and the design and construction ofall facilities for producing a field. Production beginswith the flow of oil or gas to a market and concludeswhen 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 product ion(million bbl/day)

1983 1984Region or area (ac tua l ) ( p ro jec ted )

Middle East . . . . . . . . . . . . . . . . . . . . 3.74 3.88Latin America/Caribbeana . . . . . . . . . 3.24 3.36North Sea . . . . . . . . . . . . . . . . . . . . . . 2.88 3.05United States (GOM + Calif.) . . . . . . 1.68 1.78Southeast Asia and Oceania. . . . . . . 1.53 1.56West Africa . . . . . . . . . . . . . . . . . . . . 0.80 0.80U.S.S.R. . . . . . . . . . . . . . . . . . . . . . . . . 0.18 0.17Mediterranean . . . . . . . . . . . . . . . . . . 0.14 0.15

Total . . . . . . . . . . . . . . . . . . . . . . . . . 14.19 14.75Percent of onshore + offshore. . . . . 26.6°/0 27.70/o

aLatln Amerlcalcarlbbean Includes Mexico, Venezuela, Trlnldad, Brazil. andArgentina as key producers

SOURCE Offshore Magazine, May 1984

tinue for 10 years or more, development work tocontinue for 10 years, and production to continue20 or more years. One would expect, therefore, thatif discoveries are made in U.S. deepwater or Arc-

tic regions, the major activities would continue wellinto the next century.

The three phases described above do not startand end abruptly; they usually overlap to a con-siderable extent. Exploration for smaller fields maycontinue long after major fields in a region are infull production. The development of a field mayproceed in stages with the addition of gas injection,water injection, or other systems to enhance recov-ery as the field is being produced. And productionusually starts before a field is completely developed,especially if it is very large and complex.

Since the focus of this assessment is the deepwaterand Arctic frontiers where no production hasbegun, the technologies discussed fall into two cat-egories: 1) exploration systems which have beenused for several years; and 2) production systemswhich 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

Exxon4500 Surinam 4348’

—

Seagap

3862 r

PhillipsAust.

4505’

5000 Africa 4876 BNOC

Texaco U.K.

5500 Canada

5624’6000 C.P. F.

France

6500

t

L6448’Shell

70001- New Jersey 69Shell

7500 New Jersey

SOURCE Proceedings, DOI EEZ Symposium, Nov 1983, updated 1984


Figure 3-3.—Production Platform Technologies for Frontier Areas

Statfjord 8 MagnusConcrete 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 proximityhave not been used in the regions under consider- to other developments. For example, a discoveryation, many individual components are similar to in the Alaskan Beaufort Sea near Prudhoe Baythose already in service in other regions. A total probably would be developed using much of thetechnical system will, therefore, be built from a same technology as that used on the nearby landcombination of tried and tested subsystems and sites. Because of the site-specific nature of most off-components newly designed to meet added demands. shore oil and gas technology and also because of

The types of drilling, production, and transpor-tation systems for each frontier area must beselected to fit the prevailing conditions of the work-ing environment (e. g., ice, deepwater, or storms),

the great variety of technology possibilities avail-able, discussions in this chapter are based on spe-cific systems which may be used in the Arctic anddeepwater scenarios developed by OTA.

THE ARCTIC FRONTIERS

Overview Offshore exploration in the Arctic region beganin 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 into a State lease sale in December 1964 onshore in the Alaskan offshore was outside the Arctic in Cookthe Prudhoe Bay area. Production from the onshore Inlet and the Gulf of Alaska. Oil production fromNorth Slope fields began in 1977 and in 1984 was offshore platforms in Cook Inlet began in 1964. Ex-1.6 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 sig-nificance.

The first exploratory wells in the waters northof Alaska were drilled from natural islands in Stef-fenson Sound (e. g., Gull Island in 1974 and NiakukIsland) followed in 1977 by drilling from a built-up sea ice platform in Harrison Bay. Since then,many exploratory holes have been drilled frommanmade gravel islands or off the barrier islandsalong the Beaufort Sea coast. Exploratory drillingin the Bering Sea region began in 1982. Drillingin the Bering Sea has been conducted in the sum-mer ice-free season with technologies that have beenused in temperate offshore regions. A concreteisland drilling structure is now being used for ex-ploratory drilling north of Cape Halkett in Har-rison Bay.

The first FederalAlaska was the joint

offshore activity in ArcticFederal/State Beaufort Sea

lease sale in December 1979. Since then, the paceof offshore activity and the rate of technological ad-vancement have increased significantly. The firstwholly Federal offshore lease sale took place in Oc-tober 1982 in the Beaufort Sea. To date, the Fed-eral Government has conducted four more sales inArctic Alaska, three in the Bering Sea—NortonSound, the St. George Basin, and the NavarinBasin—and a second in the Beaufort Sea (DiapirField).

In May 1982, Sohio and Exxon jointly an-nounced tentative plans to develop the 350-million-barrel Endicott field (also known as the Sag River/Duck Island field) portion of the joint Federal/Statelease sale area. By February 1985, Sohio had re-ceived all necessary permits and launched workleading to the first commercial oil production inU.S. Arctic waters. In November 1983, Sohiobegan 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


Mukluk area of Diapir Field. However, Muklukwas determined nonproductive. In May 1984, Shellannounced a large oil discovery from Seal Islandin a joint Federal/State sale area. In both cases,drilling was from manmade gravel islands. Exxondrilled the first exploratory well from an Arcticmobile offshore drilling unit (MODU) in late 1984northwest of Mukluk. This used a concrete islanddrilling system known as “Super CIDS, ” whichcan be moved to another location if desired afterdrilling is completed at the site2 (see figure 3-4).

Offshore petroleum development in the Arcticwill be a major technological challenge. The envi-

2 ’ ‘Drillers Seek Alaska Supergiant, OfIshore (January 1984),

Figure 3-4.—Mobile

ronment is severe and will dictate a rigorous ap-proach to design and construction of all primaryand support systems. While considerable data havebeen collected, additional engineering data willneed to be compiled and verified. The cold tem-peratures, ice, harsh weather, and remoteness ofmany Arctic regions will force the use of costlyequipment to achieve the required reliability. Someof the exploration and development milestones inoffshore Arctic technology are shown in figure 3-5.

Field Characteristics

The field characteristics of the six key Arctic plan-ning areas are given below.

Offshore Drilling Unit

Ch.

3—T

echnologies for

Arctic

and D

eepwater

Areas

● 5

3

Figure 3·S.-Arc· ic Exploration and Development Milestones

Production pia forms

Steel Tower Cook Inlet

1964

Artificial Island Beaufort Sea

1973 (Canada)

Exploratory systems

....... -.L. . Ice Platform I- If~::'Plellon Arctic Islands Arctic Islands

1974 1978 (Canada) (canada)

Proceedings of 001 EEl Symposium, November 1983.

caisson-Retained Island Beaufort Sea

1981 (Canada)


Beaufort Sea

There are four main types of geologic settingsin the Beaufort Sea which potentially contain oil.They are listed below in the order of probability.Only the first two are candidates for exploratorydrilling at this time.

Ellesmerian Sequence. —This prospective se-quence extends from Smith Bay on the west to Mik-kelsen Bay on the east, becomes thinner as it ex-tends north from land, and ends at approximately71 013‘ N latitude. It includes the Lease Sale 71 areawhich incorporates Harrison Bay. Since the Elles-merian Sequence includes the Prudhoe Bay fields,oil similar to the Prudhoe type may be found inthe Lease Sale 71 area. This means an oil with anaverage gravity of about 280 and with a low sulphurcontent; therefore, a good quality oil. The area ofEllesmerian potential has gentle structural foldswhich means that it could contain several very largeaccumulations of oil instead of numerous smallones.

Tertiary Structures. —These structures are eastof the Ellesmerian Sequence and extend fromCamden Bay to the Canadian border. This meansthat they are east of the Lease Sale 71 area butwithin Lease Sale 87 which occurred in August1984. The seaward extent of these structures is ap-proximately to 70035 N latitude. These structurescontain more convolutions and peaks than theEllesmerian Sequence which means that the area,if productive, may contain more smaller oil fields.These structures also are located in regions of moresevere ice conditions.

Growth Fault Structures. —These structuresrelate to the growth faults and roll-over anticlines.They overlap the Ellesmerian Sequence in thenortheasterly portion of Lease Sale 71 and then ex-tend seaward. Little is known about possible oilfields in these structures.

Cretaceus Tertiary Clays. —These formationsare expected to contain scattered smaller fields andare less promising than the Growth Fault Struc-tures for finding oil. They are located in the cen-tral and western Beaufort shelf regions.

Chukchi Sea

The Chukchi Sea appears to contain three areaswith favorable hydrocarbon potential. Most fa-vorable is the Central Chukchi Shelf, which isnorthwest of Alaska—particularly the area alongthe northern coast. It contains a very thick sedimen-tary section and many anticlines. It is the offshoreextension of the Colville Trough—the province ofNorth Slope oil and gas. Reservoir rocks are po-tentially the same as those in the Sadlerochit Groupand the Kuparuk River sandstones.

The southern part of the Central Chukchi Shelfand the Northern Chukchi Shelf are the other twopotential areas. The southern part is an overthrustzone similar to the foothills province of the BrooksRange. The North Chukchi Shelf contains greatthicknesses of (inferred) Cretaceus and Tertiaryrocks containing shale diapirs.3

Reservoirs in this area could be located from5,000 to 25,000 feet below the seafloor with an aver-age well depth of 10,000 feet. It is geologically pos-sible that a giant oil field in excess of 1 billion bar-rels in size could exist in this area.

Norton Basin

Due to the limited geologic information avail-able on Norton Basin, reservoir and productionassumptions have been made based on similargeologic basins for which more data were available;specifically, these are the Anadyr Basin of north-east Siberia and Cook Inlet in Alaska. The assump-tions are that the average reservoir depths rangefrom 2,500 to 7,500 feet, that the recoverable re-serves per acre could range from 20,000 to 60,000barrels, and that the initial well productivity couldrange from 1,000 to 5,000 barrels per day. Fieldsizes could be in the range of 100 million barrelsor more.4

3Dames & Moore, “Chukchi Sea Petroleum Technology Assess-m e n t , report prepared for the Minerats Management Service (De-cember 1982).

4Dames & Moore, ‘ ‘Norton Basin OCS Lease Sale No. 47 Petro-leum Development Scenarios, report prepared for Bureau of LandManagement (August 1980).

Ch. 3—Technologies for Arctic and Deepwater Areas ● 5 5

St. George Basin

The St. George Basin is floored and flanked byfolded Mesozoic rocks that extend from southernAlaska to eastern Siberia. Geophysical data and theextrapolation of onshore information to offshoreareas suggest that suitable source beds, reservoirrocks and traps all exist within the St, George Basin.Very little data are available with which to speculateon field characteristics.5

North Aleutian Basin

The North Aleutian Basin is a large sediment-filled structural depression that underlies portionsof the Alaska Peninsula and the Bering Sea. Withinthe basin, Mesozoic basement rocks are overlainprimarily by Cenozoic sedimentary rocks. The in-formation garnered from nine wells drilled on theAlaska Peninsula adjacent to the axis of the basinis encouraging for the prospect of discoveringhydrocarbons. The majority of potential oil and gastraps within the basin are believed to be associatedwith anticlinal structures.

Navarin Basin

Navarin Basin includes three thick sedimentarysub-basins. There are also several large anticlinalstructures, smaller folds, diapirs, and stratigraphictraps. There is potential for giant oil fields in ex-cess of 100 million barrels. Due to the great thick-nesses of the sedimentary deposit, reservoirs couldoccur at depths below the seafloor, ranging fromshallow to very deep. Reservoir depths are esti-mated between 6,500 and 11,500 feet in the north-ern portion of the Basin and between 3,300 and13,000 feet in the southern portion. G

Environmental Conditions

Petroleum resource development in the offshoreArctic is conducted under unique cold-region, high-latitude environmental conditions. Among the con-ditions are: ice and its many impacts; ocean floorgeotechnical properties; seasonal fog; and periods

‘Dames & Moor-e, ‘ ‘St. George lh+in Petroleum Technology Assess-m e n t , repot-t prepared for Bureau of Land hlanagcment (August1980)

bDames & Nloore, “ Na\’arin Basin Petroleum Technology Assess-m e n t , reported pmparcd for Bureau of Land NI anagemcnt (June1982)

of up to 24 hours of light or darkness. Offshore con-ditions are severe and the locations are remote anddifficult to support. In order to operate successfullyand to minimize the risk to personnel, facilities, andthe environment, these environmental conditions,and their impact on materials, logistics, operations,and human factors, must be taken into considera-tion. Because of these conditions, time relationshipsbecome critical—not only for exploration but alsofor data gathering, logistics, production, and vir-tually every other operational consideration. Fig-ure 3-6 illustrates environmental load comparisonsfor different structures and regions to show the sig-nificance of wave and ice loads.

The northern Alaska environment can bethought of as a frigid desert with some precipita-tion, low temperature, high wind, and periods ofextended fog. The climate in the areas north of theBering Strait is very harsh. Based on data from theClimatic Atlas, early air temperatures vary froma low of approximately – 470 F to a high of ap-proximately 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 theNorton 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 windnorth of the Bering Strait is 97 knots. This increasessouth of the Bering Strait to a maximum of 108knots in the Navarin Basin.7

7B’. A. 13rower and H. W. Set-by, Climatic A das of the Outer Con-tinentai Shelf Waters and Coastal Regions of Alaska (1977).

Offshore platforms in frontier areastremendous environmental

Photo credit: Shell Oil

must withstandforces

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 stableseismically. A review of observations made over thepast 20 years in the Beaufort Sea region from thecoast out to about 100 miles offshore shows fourseismic events, each equal or less than 4.5 on theRichter Scale. Significant seismic activity, however,is located along the Mid-Arctic Ridge in the Eura-sian Basin of the Arctic Ocean and along the Aleu-tian Chain off southwest Alaska. Oil explorationand development operations in the southern Ber-ing Sea must take into account seismic activityalong the Aleutian Chain.

There is some controversy about the complete-ness and accuracy of existing data on environmentalconditions in the offshore regions. Some believe theClimatic Atlas data may overestimate oceano-graphic conditions, while others believe that givenextremes may be even greater than existing data.The American Petroleum Institute is sponsoringwork to produce a recommended-practice docu-ment that will include ranges of wind, wave, andcurrent values based on more accurate and recentmeasurements. The revised values being consid-ered are shown in table 3-2. Based on these esti-mates, maximum wave heights could vary fromabout 40 feet in the Beaufort Sea up to 90 feet in

Table 3-2.—Proposed Arctic Environmental DesignConditions

Significant SurfaceMaximum 100-year wave currents

100-year winda height velocityArea (knots) (feet) (knots)

Beaufort Sea. . . . . . . . . 60 to 80 20 to 30 1 to 6Chukchi Sea ., . . . . . . . 60 to 80 20 to 30 1 to 5Norton Basin . . . . . . . . . 55 to 85 (90)b 30 to 40C 1 to 4St. George Basin . . . . . . 55 to 85 (88)b 40 to 50 2 to 4Navarin Basin . . . . . . . . 50 to 80 (90)b 40 to 50 1 to 3aTheSe are I hour averages to combine with extreme waves. Totally wave in-

dependent values would be somewhat higher, but structural loading calcula-tions 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 (correspondingto the 100-year storm).

Most experts agree that for design purposes seaice is the most significant environmental parame-ter in the Arctic offshore. The duration of ice covercan vary from 10 months or more duration for theBeaufort Sea and Chukchi Sea to 1 month or lessin the southwest Alaska St. George Basin. In someyears there is no ice in the St. George Basin. Sincethe Navarin Basin is quite large, ice conditions varyconsiderably from north to south. Ice thicknesses

Ch. 3—Technologies for Arctic and Deepwater Areas • 57

vary correspondingly. The Climatic Atlas datashow single-year, plane ice thicknesses of up to 7feet in Diapir and 2.5 feet in St. George.

Additional offshore Arctic environmental designconditions for five of the lease sale planning areasare shown in table 3-3. These data are derived fromthe Climatic Atlas and are considered representa-tive although site-to-site variations may be sub-stantial.

Ice

Ice problems largely dictate criteria for Arctic de-sign and operations. Sea ice creates the major dif-ficulties. However, other ice, such as ice islands,floebergs, and structural icing on platforms, ships,and helicopters also present problems. The char-acteristics of sea ice, pressure ridges, and ice move-ment are the main concern in the design of Arcticstructures. Some ice islands are so large that ma-jor damage could result from a collision betweenthem and an offshore structure. Fortunately, be-cause of the scarcity of ice islands, the probabilityof such an occurrence is relatively low. More likelyevents are the collision of pressure ridges with cer-tain types of platforms and the ride-up of sea iceonto gravel islands. Ice ride-up can occur when thewind or current forces acting on ice cover force theice against the land or an offshore structure. If theforces are large enough the ice can be driven uponto the structure or inland for distances of 300 feetor more. Pressure ridge keel seabottom gouging

depths are a design concern which influences thedepth of burial of offshore pipelines and seafloorwell heads.

Sea ice is the single most important environ-mental factor affecting operations in the Arctic. Iceaffects all aspects of oil and gas activities—from thedesign and construction of facilities which canwithstand ice conditions to planning for transpor-tation or possible rescues.

There is no simple description for Arctic sea ice.Even the initial formation of crystals varies widelydepending on the roughness of the sea. With calmerseas, the crystals are larger and more platelike. Inrougher waters the crystals are smaller and moregranular. Once crystals have formed and have de-veloped a thin skin on the surface of the water, thegrowth of the ice takes place on the underside. Saltbrine pockets develop between the lattice networksof relatively pure water crystals. Over a period oftime these pockets drain. The process of drainageis complicated by the percolation of summer meltthrough the ice. Multi-year ice becomes nearlydrained of the salt and takes on a bluish hue.

The strength of ice is dependent on many fac-tors including brine content, crystal orientation,temperature, age, and ice type. Recent data showthat multi-year ice strengths may fall within the up-per range of first-year ice strengths and in somecases (granular ice) may not be as strong. How-ever, statistically and probabilistically, multi-year

Table 3-3.—Arctic Environmental Design Conditions

Temperature Minimum

Wind Ice Ice daylight Water Distancechill 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 3-40Dec.

Chukchi Sea -85 -44 8-10 5-7 0 Jan. 30-150 3-45Dec.

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 wereexcluded

2 Distance from shore for Navarin Basin IS from Dutch Harbor in the Aleutians, all others are from the mainland3 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


ice is stronger than first-year ice. While first yearice may grow to 6 to 7 feet thick, multi-year icemay grow to about 12 to 16 feet thick. In shallowwater, shore-fast ice areas, first-year ice as thickas seven feet has been observed. The ultimatethickness depends on many factors including theradiant solar energy absorbed, long wave periodenergy radiated from ice into space, temperatureof the air above the ice, and the thermal insula-tion, or inversely, the heat conductivity of the layerof ice and any snow cover. An equilibrium occurs,and the ice thickness is stable when the amount ofheat absorbed by the ice from the water is in bal-ance with the heat absorbed from the ice by the air.However, a large amount of thickness ‘ ‘growth’can be attributed to pressure ridge building andrafting. 8

Sea ice modification results from interactionswith the wind and ocean currents, The build-upof forces within the ice floes can cause the fractur-ing of the plates and a restructuring of the ice. Theice may be split apart resulting in long openings,perhaps tens or hundreds of kilometers long. Shouldthese be sufficiently wide for the passage of a shipor whales they become ‘‘leads. Many are verynarrow, however, and immediately refreeze or closeagain as the ice continues to move.

8W, F. Weeks and G. Cox, “The Mechanical Properties of SeaIce, A Status Report, in Ocean Science and Engineering (9:2).

Having once parted, the two walls may be driventogether causing upheavals and downward thrustsof the sheets and the formation of pressure ridges.Pressure buildup within ice floes may also causedeformation resulting in pressure ridges and raft-ing. The surface height of the ridge sails formedmay be as much as 25 feet, while the depth of theridge keels thus formed may be as great as 100 feet.

The restructuring of the broken ice results in va-rious orientations of blocks. Any preferred orien-tation of ice crystals within the ice structure priorto ridging becomes randomized as broken blocksare tilted and tumbled. Interstices between thesubmerged blocks fill with sea water. The heat-sinkcapacity of the ice blocks can cause this water tofreeze in the smaller voids and at block-to-blockcontact points. This often will occur in the first 6to 8 feet. Also, a strong ice structure can developin this depth zone due to heat flow to the surfacewhich allows for further solidification of the rub-ble. Below this depth the blocks will generally forma weaker conglomerate. Rafting of ice of similarthickness will double the local ice thickness.

The location of the ice determines to a great ex-tent how it responds to external forces. The sea icenorth of Alaska can be considered as being madeup in three zones (see figure 3-7):

1. the fast ice zone, which includes the groundedridges, when they exist and any extension of

Figure 3-7.—Arctic Ice Zones

SOURCE U.S. Army Cold Regions Research and Engineering Lab, 1984.


2.

3.

the fast ice resulting from the ice cover beinganchored to the grounded ice;transition ice zone: a transitional zone be-tween the rotating ice pack and relatively mo-tionless fast zones; andpolar pack ice: mostly multi-year ice that cov-ers 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 200to 225 feet. Shallow waters extend over a large por-tion of the shelf near Harrison Bay with the 60-footisobath being about 45 miles offshore. Off CamdenBay in the eastern Beaufort, however, the 60-footisobath is only about 11 miles offshore.

In the Beaufort Sea, the fast ice generally beginsto melt in late May-early June. Near the coast thisprocess is accelerated by rivers flooding over theice surface. Once the fast ice melts away from theshore, its anchorage is lost and it can be moved bywind and currents. Such movement can cause theice to break into smaller and smaller floes, furtheraccelerating the dissipation process through melt-ing and by being driven away from the area, Openwater frequently exists along portions of the Beau-fort Sea coast during the months of July, August,and September. The length of the open waterseason, however, is variable and is frequently con-trolled by the prevailing winds. Some seasons thewinds drive the pack ice offshore far beyond thecontinental shelf. In other years, onshore windskeep the pack close to shore. During these sum-mers, coastal shipping can be greatly restricted,even prevented. In 1975, some barges supplyingthe North Slopes were caught and had to winterover in the ice at Prudhoe Bay.

The grounded ridge zone is an area of consider-able pressure ridge formation activity. The shallowdepth, however, limits keel depths of the ridges.The grounded ridge zone is not continuous, doesnot necessarily occur at the same locations eachyear, and, where such ridges form, the resultingice rubble may be quite extensive and massive orof minor consequence.

The transitional ice zone is one of great energy,The cracks and leads open and close in this zoneas the pack deforms under wind and current dragforces. Pressure ridges are formed from floes drivenagainst one another and from the sliding, shear-

ing action between the various ice masses. Keelsformed in these may be driven by a combinationof wind, current, and ice interactions into waterdepths shallower than their keel depths. Here theice keel can be pushed into the seabed, and like acutting tool, gouge depressions and furrows in thesediments (see figure 3-8). As this happens re-peatedly, the seafloor is completely scarred by icegouges. In water depths of less than 45 feet, icegouging occurs very frequently, but in these watersshore currents and storms can cause filling by sedi-ment. Beyond the 45-foot depth, ice gouges are notfilled and will remain until altered by later ice goug-ing. Ice gouge orientation tends to follow depthcontours.

The polar pack region is composed primarily ofmulti-year ice. However, it too is subject to the in-teractions of winds, causing leads to open and close.Pressure ridges are continually formed. The icepack north of Prudhoe Bay drifts clockwise with themovement of the Beaufort Sea Gyre. Ice islands,large icebergs which originate from the northerncoast of Ellesmere Island, can also be found drift-ing within the gyre. These ice islands may be 150feet thick. Ice islands in this gyre may remain therefor decades before leaving the Arctic Ocean. Fromtime to time ice islands are grounded in the coastalwaters of the Beaufort Sea.

There are significant differences in the ice in theBering Sea as compared to the Arctic Basin. TheAlaskan shelf south of the Bering Strait is quitewide. The majority of the Navarin Basin lease salearea is in water depths ranging from 300 to 600feet. Multi-year ice can drift into the northern partof the Bering Sea but even that portion of the seabecomes ice-free during the summer. Ice is formedeach year in the northern part of the Bering Seato thicknesses of about 1 to 2 feet. Fast ice in thevery northern Bering Sea may grow to a thicknessof more than 4 feet but multiple rafted ice can beover 15 feet thick. Ice starts forming at the shoreand extends outward and southward. The edge ofthe ice may be driven southward by wind forces.Pressure ridging occurs but, like the average icethickness, is much less than in the Arctic Basinwaters. Ridges may have sails of 15 feet above thesurface and keels four to six times as deep. Cur-rents through the Bering Strait generally run north-ward. There is an occasional reversal which can


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 depthw - gouge width

- gouge orientationh - lateral embankment heightz - water depth

sf - sea floorN - true north

--’ S f

(Recent tests indicate gouge depths can vary from 3 feet in shallow lagoons to15 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 featuressouthward. The maximum and minimum extentsof the sea ice cover in the seas off the Alaska coastare shown in figure 3-9.

Other ice conditions may be hazardous. Whencombined with freezing conditions, the winds andwaves produce an icing spray which can causedangerous ice build-up on ships and structures. Theinteractions of blocks of floating sea ice with wavescan propel the ice into the sides of ships and struc-tures resulting in large localized forces. Duringsome atmospheric conditions, fixed wing aircraftand helicopters traveling at critical altitudes can besubjected to icing, creating dangerous situations.

Other Factors

Fine, silty sediments and sub-bottom permafrostare the two geotechnical factors of concern in Arc-

tic waters. Permafrost exists only in the ArcticOcean. In the southern part of the Bering Sea nearthe Aleutian Chain, seismicity is also of concern.

The engineering properties of the upper sedi-ments of the ocean floor must be considered in thedesign of foundations for bottom-founded struc-tures. The possibility of mud slides must be con-sidered in the foundations of structures placed onthe steeper slopes of the Navarin Basin. Industryis conducting investigations of the instability ofsediments and the design of foundations for theseconditions.

Permafrost could affect the design and routingof pipelines in the Beaufort Sea. Some related de-sign problems include the differential thaw sub-sidence of permafrost and adjacent foundations,thaw subsidence around wells, and frost heaving.


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.


In general, the Arctic environmental factorsaffecting the design, installation, and operation ofoffshore systems vary depending on the season ofoperation and upon the ice conditions. But data onice condition, oceanographic, meteorological, andgeotechnical factors are relatively sparse for manyareas. And, like all Arctic operations, collection ofadditional data is costly.

Meteorological data are particularly sparse forthe areas north of Alaska and in the Bering Sea.Satellites and ice buoys are used to obtain ice move-ment and weather data for the regions north ofPoint Barrow. However, much of the sensory datado not have the resolution necessary for many ap-plications. Unfortunately, most of the visual sen-sors are usable only during the daylight summermonths, and even then their effectiveness is lowereddue to clouds and fogs that develop above meltingice and evaporating ice melts. The lack of sufficientice and meteorological data has severely limited theability to detect and forecast ice movement andweather conditions for the Arctic region.

Technology Development

OTA has developed three Arctic scenarios to il-lustrate the approaches that may be used to developand produce Alaskan oil discoveries, based ontoday’s knowledge of the environment and suitabletechnology (see box). A complete production sys-tem for these conditions does not currently exist.Because of the very high costs involved, there isa significant incentive to improve system reliabilityand cost effectiveness by using advanced technol-ogies. A range of engineering development, tests,and evaluation may be required before industry cansafely and economically produce possible petroleumdiscoveries in hostile offshore Arctic environments.

Figure 3-10 illustrates some of the productionplatform systems and structures that currently ap-pear to be the most favored alternatives for eachof the Alaskan offshore planning areas. In eachcase, the system is based on operating experiencein a related situation or a similar environment.

Technology for exploring, developing, and pro-ducing oil and gas in offshore Arctic environmentsappears to be progressing at a pace compatible withgovernment leasing schedules and industry’s con-

templated development schedules. Prior to a salein a planning area, industry usually proceeds withresearch and engineering programs to developbaseline data, design criteria, and engineering de-signs for exploration and production systems whichmatch the expected conditions. This research andengineering effort is intended to: 1) establish thefeasibility of systems and the confidence that thesesystems can be constructed and operated safely; 2)estimate system costs to guide in economic evalua-tions of the resource prospects, and thus help estab-lish the lease bid level; 3) identify key site-specificinformation needed for system selection and designif oil and gas discoveries are made; 4) ensure thatpost-lease sale exploration, development, and pro-duction could be brought onstream on approx-imately the time table assumed in pre-lease sale eco-nomic analyses; and 5) enable industry to movequickly to drill exploration wells.

After the discovery of economic reserves result-ing from exploratory drilling, considerably moreresearch and development, data collection, andtesting is necessary for industry to move into thedevelopment and production phases in the Arctic.Some research and development areas are morecritical than others, especially when economics areconsidered. The following areas are judged to beimportant to future Arctic development.

Ice

Additional research is needed to obtain basic dataon ice properties and ice strengths under differentconditions as actually encountered in the field, onthe strength characteristics of pressure ridges andof the ice within such ridges, and on variations ofice properties.

Although data on ice and its properties are highon the list of needed research, there is a significantdata base on ice strengths and properties. Indus-try is developing more data on ice feature size andgeometries and conducting model tests to investi-gate ice/structure interactions. Ridges are beingsampled, their ice strengths determined for theappropriate ridge thermal profile, and ridge tem-peratures are being monitored throughout the year.In almost all cases, exploratory drilling structuresare instrumented to measure the loads exerted by



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 arenot 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 rfiedice can be avoided or their effects rnitigat~ by icebr%ak@%. In Harrison Bay and Norton Basin, keels frompress@’e ridges could penetrate the seabud, rcquiringpipt~~e~ to~ burkd beneath gouge depth. Althoughno major -e piPIiUe SYSWIKM exist k &ctic waters, ikenthk~ by sub= P1OWS =~ pipelfne fnst~a-tkm by the bottom tow method am considered ikadbk. k HarriMn Bay, however, permafiwst precautionswould 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 intosubsea 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 tosupport a pipeline to shore.

S& soils-+ potential problem in some -of H an Bay and the Navarin Basin-could requireeither soil strengthening or more elaborate fwdation diisigns. P@*ti approaches used elsewhere to over-come soft soils include piles, wicks or drains, replacing the soil with gravel, cement infection to strengthensoils, kwgerbear%g tmrfiwe areas for gravity structure, and dredging out the soft-bottom to reach freersoil underneath. Structures for soft sea bottoms ham been ddgned for pre-lease sale technoioW verifka-tion and structure costing in l?kvarin Bay, but extensive site-$pecifk soil surveys would be requir@ forfinal 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- ‘ayescan 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~dmaintain its position with anclmrs where bottom conditi.a~ are suitable, or with dynamic ~sitioning equip-ment including cornputcr-contro~~ main propulsion and thruster units and acoustic signals emitted bybeacons on the seafloor. Similar wmi-submm=sib~es have been used successfdy in the North Sea and east-ern Canada under severe weather conditions. ,

Exp&3ratkm

the size of the field~’However, desi~ requirements for production structurti are more stringent than thosefor 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).


The scenarios assume that gravel islands (possibly with cassion-retained protection) would be usedfor field development in Harrison Bay and Norton Basin, and gravity platforms in Navarin Basin. Theoil would be treated on the gravel islands or gravity platforms, and stored in either onshore or offshorestorage tanks (Harrison Bay and Norton Basin) or in gravity structures (Navarin Basin). Alternatives togravity storage now under consideration by industry include moored tankers tied to an icebreaking, singleanchor 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 60feet. An alternative preferred by some is the bottom-founded gravity structure similar to those used in theCanadian and U.S. Beaufort Sea for exploratory platforms. Designs are proposed for many types of thesestructures including conical shapes to reduce ice forces. Another advantage of such a structure is the abilityto construct it in one piece at a shipyard and then tow it to the site for installation, thus lowering onsiteconstruction costs substantially.

Infrastructure and Support Services

In addition to the severe environment, the primary consideration in designating infrastructure andsupport services is the distance of the field from established bases onshore. For example, the establishedfacilities at Prudhoe Bay provide the basic infrastructure for operating in Harrison Bay. Work camps, main-tenance shops, living accommodations, and catering operations already exist, and procedures for workingand coping with the environment have been established. However, reliance on the Prudhoe Bay infrastruc-ture as the sole support base could have prohibitively high transportation costs, and a satellite base closerto Harrison Bay would be needed.

Some support for Norton Basin exists at Nome, but it is not nearly as extensive as at Prudhoe. Inanticipation of increased oil activity, Nome plans to build a deepwater harbor—a causeway with dockingfacilities. 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. DutchHarbor on Unalaska Island in the Aleutians-a World War 11 Navy base and already a base for oil com-pany exploration operations and a center for fishing activity—could be a support base for Navarin. DutchHarbor is ice-free so all necessary supplies and equipment could be transported thereby conventional cargovessels year-round. It also is a potential location for a storage and transshipment terminal. Other devel-oped Aleutian harbors such as Cold Bay have been considered but at present lack sufficient harbor facilitiesor water depth. Even Dutch Harbor, however, is too far from the Navarin Basin to be the sole supportbase, 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 NorthSlope onshore production begins to decline in a few years. The most likely transportation scenarios forthe three production areas were chosen. Critical considerations include offshore pipeline depth sufficientto 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 andNavarin Basin. Some recent industry studies have shown that use of ice-reinforced tankers with icebreakersuport is the most cost effective system for Navarin and Norton. Also, the use of a transshipment terminaldoes 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 BasinEnvironmental conditions:Temperature and wind chill . . . . . . . .Extremely low: –47°F, 15 knot

winds; –90°F wind chill temp.

Ice conditions ... . . . . . . . . . . . . . .Severe: 10-month coverage; withinshore fast ice zone; plane fast ice7 ft, rafted ice 22 ft, ridges 75 ft

Winter daylight . . . . . . . . . . . . . . . . . . None in Dec. -Jan., 2.5 hr/day inNov., 6.5 hr/day in Feb.

Approximate distance from shore .. ..20 miWater depth . . . . . . . . . . . . . . .......50 ftOther . . . . . . . . . . . . . . . . . . . . . . . . . Permafrost precautions to prevent

melting and subsidence

Exploration:Number of wells . . . . . . . . . ........6Type of rig. . . . . . . . . . . . . . . . . . . . . .Arctic land rig on gravel islanda

Development:Peak production rate (B/D) . .......500,000Type of platform . . . . . . . . . . . . . . . . .Gravel island a

No. of platforms/islandsc . . ........7Number of rigs . . . . .. . . . . ........2 per islandTotal number of wellsc . ...........271Field size (billion barrels) . . . . . . . . . . 2.0d

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 fromFairbanks; winter ice roads on landfast ice

Sea access . . . . . . . . . . . . . . . . . . . . .Annual sealift for barges in openwater season (Aug. -Sept.)

Transportation:To shore . . . . . . . . . . . . . . . . . . . . . . . Pipelines-buried beneath gouge

depth with permafrost protection

Moderately low: –36°F, 11 knotwinds; –72°F wind chill temp.

Moderate: 8-month coverage; smoothice 3.5-4 ft, rafted ice 15 ft,ridges 75 ft; dynamic icemovement

Some

40 mi50 ftStrong bottom currents, storm waves

and surges; potential for gas-charged sediments

6Jackup

125,000Gravel isianda

42 per island1360.52,000

Dutch Harbor; some facilities in Nome

Commercial airport in Nome

None

Deepwater harbor planned in Nome;Dutch Harbor ice-free year-roundfor conventional cargo vessels

Onshore or offshore storage tanks tooffshore deep draft mooring andtransfer terminal for onloading to250,000 DWT ice-reinforcedtankers 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 12-18ft; ridge frequency more criticalthan thickness

Some

400-700 mi450 ftSevere storms, wind-driven waves,

spray icing; remoteness posesextreme logistics problems; softsoils potential

6Semisubmersible

500,000Gravity platformb

7, plus 2 service2 per platform2712.0d

4,000

Dutch Harbor or Cold Bay; forwardbase on St. Matthew Island or St.Paul Island; 2 advanced servicebases

Commercial airport in Nome;helicopter from forward base

None

Deepwater harbor planned in Nome;Dutch Harbor ice-free year-roundfor conventional cargo vessels

Storage in gravity structures;e

offshore deep draft mooring andtransfer terminal for onloading to150,000 DWT ice-reinforcedtankers with icebreaker escorts’

Onshore . . . . . . . . . . . . . . . . . . . . . . . .Along-the-shore pipeline connectswith TAPS offshore; or pipeline towest coast of Alaska with ice-reinforced offshore tanker terminal

aFo r ~ 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 icebraak-

ing tankers.

SOURCE: office of Technology Assessment.


Harrison Bay Scenario(Beaufort Sea)

Planning and permitting I l lConstruct exploration Island

Explora tion and d g

Prepare and submit plans

I

1 2 3 4 5

rton Basin Scenarioorthern Bering Sea)

\

Ch. 3-Technologies for Arctic and Deepwater Areas • 69 ------------------------------------~---------------------------------------------

No (N

L-________________________________ _______

Location of discovery

Jack-up exploratIon rig

, 19 : 20


Navarin Basin Scenario(Central Bering Sea)

Location of discovery

I I I I 1Planning and permitting (

I I I IExplo rat ion and d elineation drilling

Discovery

IConstruct 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


Figure 3-10.— Alternative Arctic Production Structures

Gravel islands a

— 1

Concrete or Jacket structuredsteel 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)cThese types of structures would be extension of technology developed for North SeadThese 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 naturalislands to make load measurements. 9

Ice Reconnaissance

Increased surveillance from satellites and by air-craft is needed to provide real time data. Icesurveillance is important for structural design pur-poses, logistics, and tanker transportation designand planning. Many companies have utilized allrelevant satellite data to describe ice conditions. Icemovements have been measured for several yearsby 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 Nlc-c 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 Proceedingsc)f the Offshore “1’cchnolo,q (;onfi’rcncc (Ma> 1984).

Helicopters and fixed wing aircraft are used to assistin making ice forecasts for operations that couldbe hampered by ice invasions.

Marine Pipelines

More rapid and effective trenching techniquesbelow ice-gouge depths, and rapid and effectivetechniques for alignment, connection, and repairof pipelines are essential. Recognizing that Arcticpipelines are a critical future design problem, morecost-effective installation techniques and designs forareas with warm subsea permafrost are being in-vestigated. Repetitive surveys are being conductedin the Beaufort Sea to assess gouge depths and therate at which gouges are being filled by wave andice actions on the seafloor.

7 2 ● O i l a n d G a s T e c h n o l o g i e s f o f t h e A r c t i c a n d D e e p w a t e 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 character-istics.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 re-will be important. search and engineering programs underway by the

oil industry. In addition to programs that are pro-

Seismicityprietary to individual companies, over 275 joint in-dustry programs that deal with wide-ranging

For two of the planning areas, St. George and aspects of Arctic technology have been undertakenNorth Aleutian Basins, a unique problem exists by member companies of the Alaska Oil and Gasconcerning strong motion seismic (earthquake) Association (AOGA) (see table 3-4). Many Cana-activity associated with the subduction of the Pa- dian design projects, strength tests, and model testscific plate beneath the North American plate. Re- are also applicable to the U.S. offshore,


Table 3-4.—Summary of Cooperative Arctic Research Projects

AreaSubject 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—3262———1—

5—4344——12—

15—2327——21

—

14—2444——221

14—1124——1

——

62—97

1117

316—3

—15

1—2

199

142—

1alce 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 technol-ogies incrementally as exploration and productionhave moved from shallow to deepwaters. In thisprogression, as the severity of the environment hasincreased, additional design requirements havebeen recognized. To meet these requirements, off-shore structures have become larger and morecostly. The logistic support for construction andoperation has likewise increased. Governmentagencies have also had to increase their capabilitiesto monitor industry’s activities to assure safety andenvironmental protection.

This section discusses technologies for oil and gasdevelopment in water depths greater than 1,320feet. There has been extensive exploration at suchdepths but no production to date. Many of the tech-nologies required for deepwater production areavailable although not applied commercially at thistime, As new technologies are applied to deepwaterfrontier areas, testing and verification will beneeded. Some new concepts may be abandoned andothers developed further. Safety is a major concernin offshore engineering and construction. Technol-ogies used must provide reliability, not only toassure human safety but also to minimize the riskof losing a platform or other structure and to min-imize operational costs.

A number of technological areas are critical indeepwater petroleum development. These include:1) structural design, which ranges from the metal-lurgy of the steels or composition of materials used,through welding techniques and ocean floor plat-form foundation engineering; 2) techniques for in-stallation, maintenance and repair of structures,risers, and pipelines; 3) drilling, well control, andcompletion; and 4) technologies for support oper-ations, such as diving and navigation. Human div-ing capability is limited to approximately 1,640 feet,with only experimental dives to 2,300 feet. Thus,one-atmosphere manned vehicles and remotely con-trolled unmanned vehicles may become increasinglyimportant for support services. Navigation technol-ogies are important during seismic surveys, ex-ploration drilling, and platform and pipeline in-stallations. This includes acoustic, radio, andsatellite technologies for seismic survey navigation;directional drilling; and ship, submersible, andremote vehicle operations.

Historically, the offshore petroleum industry hasa good record of developing adequate technologyto meet ever more challenging conditions as devel-opment has moved to more hostile environmentsfarther offshore. Some existing systems—especially

compliant platforms and subsea wells—have the ca-pability of fairly direct extension to deeper water.Others—e.g., deepwater risers, control and well


maintenance technologies—may need further de-velopment for use in deep water.

New technological achievements are being madecontinually as new resource discoveries are madein deeper waters. For example, in Norske Shell’sTroll Field in 1,148 feet of water in the North Sea,a large concrete gravity structure is under detaileddesign and testing. Exxon has initiated productionfrom its Lena guyed tower in approximately 1,000feet of water in the Gulf of Mexico (see figure 3-11). Other structures are planned for Gulf of Mex-ico discoveries in up to 1,500 feet of water.

In addition, advanced conceptual designs existand some component testing has been accomplishedfor systems to be used in water depths up to 2,000to 2,500 feet. Among these systems are Exxon’ssubmerged production system, Chevron’s subseawellhead system, and Conoco’s tension leg plat-form. It is reasonable to expect that in a few yearsseveral types of structures and production systemswill be built for use in these water depths.

Figure 3-11 .—Guyed Tower

Beyond about the 2,500-foot depth, there has notyet been as much activity aimed at developing spe-cific production systems because opportunities forsignificant petroleum discoveries at that depth arestill more speculative. However, oil exploration indeepwaters of the U.S. Exclusive Economic Zone(EEZ) is underway. Sonat’s drillship DiscoverSeven Seas drilled for Shell Offshore, Inc., in waterdepths of more than 6,000 feet in the WilmingtonCanyon area of the Atlantic coast during 1983-84.Other leases have been sold in the Atlantic withwater depths of about 7,500 feet. Blocks were leasedin water depths of approximately 5,800 feet in theApril 1984 Gulf of Mexico sale. And blocks in ap-proximately 10,000 feet of water are now being of-fered offshore California.

Deepwater achievements of various system com-ponents are shown in table 3-5. The history andstatus of subsea well and facility water depth recordsare shown in figure 3-12.

Based on its deepwater drilling and productionachievements, the petroleum industry believes thatthere are no significant technological limits to oper-ations in up to 8,000 feet of water. Petroleum basinswhich are developed in the deepwater frontiers willrequire new technologies which will be deployedfor the first time. Because these new systems arebeing developed continually, it may not be reason-able to establish water depth or other regulatorylimits based on present technologies. But sufficientprecautions must be taken to assure that the gov-

Table 3-5.—Deepwater Drilling and ProductionAchievements (through March 1985)

Recordwater depthexperience

Component or to dateactivity (feet) Place, date

Exploratory drilling ., . . . . . . . . 6,952 U.S. Atlantic, 1984Development drilling . . . . . . . . . 2,500 Mediterranean, 1983Fixed steel/production

platform . . . . . . . . . . . . . . 1,025 Gulf of Mexico, 1978Guyed tower production

platform . . . . . . . . . . . . . . . 1,000 Gulf of Mexico, 1983Floating production platform . . 460 Tunisia, 1982Tension leg platform . . . . . . . . 485 North Sea, 1984Subsea wellheads . . . . . . . . . . 1,007 Brazil, 1984Subsea production system . . . . 500 North Sea, 1982Deepwater pipeline . . . . . . . . . . 2,060 Sicily, 1979Tanker loading systems . . . . . . 530 North Sea, 1980

SOURCES: Proceedings of the Offshore Technology Conference (1984); USGSCircular 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 FacilitiesHistory and Current Status

1950 1960 1970 1980 1990

Year

SOURCE DOI EEZ Symposium, November 1983, update 1984

ernment regulations imposed on offshore operationsare appropriate and the responsible governmentagencies monitoring offshore operations have theskills and technology necessary for judging the ade-quacy of industry’s engineering designs, equip-ment, and procedures.

Field Characteristics

The three key offshore planning regions includ-ing deepwater frontier areas are the Atlantic, Gulfof Mexico, and the Pacific. This section describesthe field characteristics for these three regions.


Atlantic

Since there have been no commercial oil discov-eries in the Atlantic region, it is not possible to pre-dict the field characteristics. There is reason tobelieve, however, that some of the reef formationspresent in the Bay of Campeche, Mexico, may ex-tend northward to the deepwater basins in theAtlantic. If this is the case, oil fields could be simi-lar to the prolific offshore fields with high well flowrates now producing in Mexico, If such fields werefound in the Atlantic, it would be a significant com-mercial discovery.

Gulf of Mexico

The Gulf Coast reservoirs range in size from verysmall (less than 5 million barrels of recoverable oil)to major oil fields of over 100 million barrels. Themedian oil field size is 29 million barrels and themean size is 66 million barrels. Of the 105 analyzedoil fields, 21 are over 100 million barrels. Thesereservoirs also vary widely in other characteristics.Formations often consist of unconsolidated sandswhich require gravel packing and hole condition-ing. Generally, production rates are modest. A1,500-barrel-per-day well in the Gulf of Mexico isconsidered very good. Drilling rates (feet per day)are high. This high drilling rate may not be sus-tainable in deepwater if the upper formations re-quire several casing strings to be set near the sur-face. More often 4 weeks is required to drill adeepwater well. As experience is gained, these deep-water operations may speed up.

Pacific

All the known West Coast oil fields lie off cen-tral and southern California. Many of these fieldsproduce relatively heavy oil. In addition, the oiloften contains sulfur. The West Coast oil is shippedto the Gulf Coast for refining.

Drilling is slower and more difficult in this re-gion. Structures are often faulted and are hard todelineate. However, there are some very large andproductive fields in California. The Point Arguellofield is one of the largest discoveries in U.S. (OuterContinental Shelf (OCS) history. Recoverable re-serve estimates range from 400 to 500 million bar-rels, and combined field flow rates are projectedto reach 160,000 barrels per day by the end of the

century. In addition, total flow rates from the fieldsoff Santa Barbara County are expected to reach450,000 barrels per day by the early 1990s. Theeast Wilmington field further south in Long Beachproduces 120,000 barrels per day. These three fieldshave the highest production rates in the lower 48States.

West Coast drilling rates offshore are slow bycomparison with the Gulf Coast. A typical offshorewell requires 6 to 8 weeks to complete. Gravel pack-ing is often necessary. If more than one reservoiris present at a drill site, the casing may be per-forated to enable the wells to produce from multi-ple zones.

The low gravity, asphalt-base oil means thatprocessing facilities are complex. This, coupled withthe thick formations, makes the typical West Coastplatforms larger than Gulf Coast platforms. Sixty-well platforms are common, and large expensiveproduction facilities are the norm. It can be ex-pected that this trend will continue in deep water.

Environmental Conditions

Important environmental parameters that affectthe design of production platforms and systems aresummarized in table 3-6 for the Atlantic, Gulf, andPacific regions. These values are based on generalindustry practice. Conditions that are peculiar toa specific region are discussed below.

Table 3-6.—Deepwater Environmental DesignConditions

TypicalMaximum wind current

velocity* ● Maximum velocity*(knots) 100 year (surface to(1 hour wave height 200 ft.)

Region duration) (feet) (knots)

Atlantic . . . . 90 85 3.0Gulf . . . . . . . 90 70 3.0Pacific . . . . . 60 60 2.0

“Exact value of current velocity varies and is highly dependent on preciselocation, particularly in the Atlantic and Gulf,

“ “For 10 meter elevation; higher elevations may be subject to higher velocitiesand gusts.



Atlantic

Hurricanes, other severe storms, and the GulfStream are major environmental factors in theAtlantic region. The Gulf Stream presents prob-lems in both exploratory drilling and for produc-tion systems if commercial discoveries are in areasaffected by its currents. The current velocity is upto 5 knots near the surface and in the range of 3knots to a depth of more than 1,000 feet. This highcurrent velocity may require streamlined risers forexploratory drilling and must be considered in thedesign of compliant structures if they are used. Themajor impact of the Gulf Stream is confined to thesouthern portion of the Atlantic region. The Mid-Atlantic a-rid North Atlantic areasaffected since they are not in thethe current. However, warm core

are only slightlymain stream ofeddies may spin

off the Gulf Stream and affect systems in theseareas.

Seafloor instability, especially on the Continen-tal Slope, may require that specific sites be avoidedor that special foundation stabilization techniquesbe used and/or developed. Other environmentalconditions in the Atlantic region generally are lesssevere than in the North Sea and more severe thanin the Gulf of Mexico. The design methods, as wellas the operational experience gained from the Gulf,probably can be upgraded to meet Atlantic devel-opment requirements.

Gulf of Mexico

Hurricanes are also a major environmental fac-tor 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


of experience in designing fixed offshore structuresto withstand the high winds and waves generatedby these intense storms, and this experience recentlyhas been applied to Exxon’s Platform Lena whichis a compliant structure. Mud slides are anotherunusual environmental factor in the Gulf. Theseslides may cause foundation instability in someareas. Another factor is the Gulf of Mexico loopcurrent and the eddies which are produced by thatcurrent. These eddies affect operational practicesand the design of structures since they may causevibrations which could lead to metal fatigue or otherfailures. Generally, in the Gulf, there is a wealthof experience to draw upon as development movesinto deep water.

Pacific

The wind and wave conditions in the Pacific re-gion are less severe than either the Atlantic or theGulf of Mexico, but earthquakes area factor whichmust be considered in system designs. Design cri-teria and analytical methods have been developedfor the entire West Coast, and these have been ap-plied successfully to numerous offshore structures.Earthquakes should not pose serious problems forproperly designed compliant structures since thenatural vibration response periods of these struc-tures are well outside the high energy portion ofthe earthquake spectrum. Soil characteristics mustalso be considered in system designs for the Pacificregion because of the steep slopes present in someareas.


Exploratory Drilling

The offshore drilling industry currently has a fleetof 13 drillships and semi-submersibles capable ofdrilling in waters deeper than 3,000 feet. Of these,four drilling units are capable of drilling in 6,000feet of water and one in 7,500 feet of water.

Several technical advances have made this deep-water capability possible. These include: 1) dy-namic positioning utilizing controllable pitchthruster propulsion units and computerized auto-matic station-keeping systems (see figure 3-13); 2)reentry systems utilizing television and sonar in-stead of guidelines; 3) electrohydraulic blow out

preventer control to reduce signal transit time; and4) marine risers equipped with syntactic foambuoyancy material and improved riser couplings.l0

Limitations to exploratory drilling in very deepwater come primarily from environmental condi-tions and a low formation fracture gradient. Ex-cessive current velocities (approximately 5 knots orgreater) could prevent some dynamically positioneddrilling units from maintaining their position be-cause of the large amount of power required tocounteract such forces. Also, wave heights ex-ceeding 20 feet can interrupt drilling operationsfrom a dynamically positioned drill ship. Some ofthese limitations may be overcome through the useof a dynamically positioned semi-submersible withsubstantially greater station-keeping capability thanexisting vessels. Abnormally high formation pres-sures, particularly at shallow formation depths, canalso cause difficulty in deepwater drilling and couldlimit or prevent development of some deepwaterreserves.

Field Development

Nearly all offshore fields to date have been de-veloped using fixed-leg platforms. During the1970s, industry progressed from the capability to

design and install fixed-leg platforms in about 400feet of water to design and installation for the cur-rent record depth of 1,025 feet for Shell’s Cognacplatform in the Gulf of Mexico. Designs also havebeen completed by Exxon for a fixed-leg platformfor installation in 1,200 feet of water in the SantaBarbara Channel. Technically, fixed-leg platformscan be built for a water depth of 1,575 feet or more.However, due to the large amount of steel requiredand limitations of fabrication and installation meth-ods, there is probably an economic limit for thesestructures at a water depth of about 1,480 feet.11

There are several concepts for extending waterdepth 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 Drillingin 7,500 Feet of Water’ (Society of Petroleum Engineers, Paper 12793,1984); and J. C. Albers, “Exploratory Drilling Systems” (Outer Con-tinental Shelf Frontier Technology Symposium, 1979).

] IF. P. Dunn, ‘ ‘Deep Water Drilling and Production Platforms inNon-Arctic Areas” (National Academy of Sciences, 1980); and R.L. Geer, ‘‘ Engineering Challenges for Offshore Exploration and Pro-duction in the 1980s’ (BOSS Conference, 1982).


Figure 3-13.—Dynamic Positioning for Deepwater Drilling

LBS hydrophore

SOURCE: Proceedings of the Offshore Technology Conference, 1984


the tension leg platform, and the subsea produc-tion system. All but the subsea production systemsare ‘‘compliant structures, which are designed tomove slightly with environmental forces of wind,waves, and current as opposed to conventionalstructures which rigidly resist such loads.

The guyed tower is a tall, slender structure thatrequires less steel than a fixed-leg platform. Guylines or anchor lines are used to resist lateral forcesand to hold the structure in a nearly vertical posi-tion. Exxon has recently installed the first guyedtower, Lena, in 1,000 feet of water in the Gulf ofMexico. The platform, with space for 58 wells, issecured with 20 guy lines, eight main piles, andsix perimeter torsion piles.12 Current technical opin-ion is that guyed towers are structurally and eco-nomically feasible in water depths to about 2,500feet. Beyond these water depths, the guyed towerswill require much greater amounts of steel to main-tain an acceptable stiffness.

The buoyant tower is a tall, slender structure likethe guyed tower but is maintained in a vertical posi-tion by large buoyancy tanks rather than by guylines. Rotation at the base is accounted for eitherby an articulated joint or by a flexible foundation.

The tension leg platform is a floating platformfixed by vertical tension legs to foundation tem-plates on the ocean bottom. OTA has selected atension leg platform for its hypothetical deepwaterscenario (see box). Buoyancy is provided by thepontoons and columns of the hull. The buoyancythat is in excess of the platform weight maintainsthe legs in tension in all loading and environmentalconditions. The floating hull of the tension leg plat-form, similar to that of a semi-submersible, issecured at each corner by a number of so-called ten-dons. The hull pulls upon the tendons so that theynever go slack, even in the trough of the maximumdesign wave and when carrying maximum oper-ating loads.

The substantial advantage of the tension leg plat-form is its relative low cost sensitivity to increasesin water depth. The principal design influence ofincreasing water depth is in the tendon and riserlengths, with the hull size and weight increasing

relatively slowly with water depth. The main dis-advantages of a tension leg platform are the oper-ational complexity of its well and tendon systemsrelative to fixed platforms and its limited deck loadcapacity.

The first tension leg platform was installed in1984 by Conoco in 485 feet of water in the NorthSea. This probably is not an economical waterdepth for a tension leg platform, but its installa-tion in the North Sea will provide the experienceand information needed to successfully install theseunits in deeper waters.

Practical application of tension leg platforms willstart where it is no longer economically attractiveto construct a fixed-leg platform. This water depthis estimated to be around 1,500 feet, depending onlocation. For intermediate depths of 1,000 to 2,500feet, the guyed tower is thought to be the attrac-tive alternative. Theoretical maximum water depthsfor tension leg platforms are estimated by Conocoto be 6,000 feet by the year 1990 and 10,000 feetby the year 2,000.

Subsea production systems are also a major alter-native for deepwater field development. With thesesystems, wells are drilled from a floating rig andcompleted on the seafloor. Several such systemshave been extensively tested in operations in shallowwater. These include Exxon’s system in the Gulfof Mexico (see figure 3-14), Hamilton’s Argyll Fieldin the North Sea, and Shell/Esso’s system in theCormorant Field in the North Sea.

Currently, there are more than 100 offshoresubsea well installations in operation in waterdepths of up to 960 feet. An additional 36 subseawell completions currently are scheduled for in-stallation. *3 One of these is a subsea well comple-tion by Chevron offshore Spain in a water depthof 2,500 feet.

Subsea well completions can be either “wet’ or“dry” systems. The wet system is relatively insen-sitive to water depth and can be installed in deep-water in the same manner as shallow water. Its ap-plication is limited only to the water depth capabilityof the floating drilling unit and the flowline installa-tion technique, In the dry system, the well head

12P. H. Kelly, F. B. Plummer, and P. J. Pike, ‘‘The Lena GuyerTower: A Pioneering Structure” (Proceedings of the DOT Confer-ence, 1983).

13M. Tubb, “ 1983 Subsea Completion Survey, ” Ocean Industry(October 1983).


Deepwater Technology Scenario

To assess deepwater technology, OTA selected one hypothetical prospect located offshore the centralCalifornia coast approximately 3$ miles west of Point Conception in water 3,000 to 4,100 feet deep. Assump-tions about field conditions, exploration and development, infrastructure and support services, and trans-portation for this deepwater scenario are shown in the accompanying table. It should be noted that theassumptions made for this area are illustrative, and actual conditions may vary substantially. The oil ac-cumulation could be deeper, the gravity of the crude could be sour, and well spacing might need to becloser. All of these factors would increase the cost of development and change the technical approacheschosen for this scenario.

Schedule

The schedule begins with the lease sale and ends with the completion of development drilling-a totalof 13 to 14 years. First production is assumed to occur 10 years from the lease sale date. This scheduleis 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 concur-rently with permitting and approval. Timeframes would also increase if the area is more difficult to developthan postulated (e.g., heavier crude, sour crude, nonsircular field), or if two platforms are required insteadof one.

Exploration and Development

Water depth in the scenario area is within present industry capabilities for exploration. Severaldynamically positioned drilling units, ship-shape and semi-submersible, currently are able to drill exploratorywells in water depths of 6,000 to 7,500 feet. Drilling units of this type are equipped with computer con-trolled main propulsion and thruster units. The unit is kept on location by these thrusters with positioningdata from a continuous acoustic signal emitted by one or more beacons located on the seafloor. The useof this dynamic positioning equiment has made these drilling units independent of the constraints imposedby a mooring system.

Development of a discovery in a water depth of 3,000 to 6,000 feet appears to be technically feasiblebut 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 thetension leg platform with surface completed wells. These have been designed for water depths up to 3,000feet, but there has not yet been a commercial discovery in such depths. A subsea production system isan alternative for this scenario but most designs to date are not self-contained units; storage and processingfacilities would be required on a separate platform. Satellite subsea wells oculd be used in conjunction witha 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 con-ductors from the ocean bottom to the lower deck for completion and hook-up in a manner similar to (al-though operationally more complex than) methods used for fixed, bottom-founded platforms. Alternativedesigns provide for incorporation of the conductors inside the mooring legs or for completing the wells onthe seafloor. With the latter method, an ocean floor manifold would be required and one or two risers wouldbring oil to the surface.

Transportation and Infrastructure

For environmental reasons, California State prefers a subsea pipeline rather than shuttle tankers totransport crude oil to shore. Deepwater pipelaying capability has advanced to where the technology (butnot the actual equipment) exists to install a 20-inch pipeline in water depths of 7,500 to 10,000 feet. How-ever, actual experience has been limited to water depths of about 2,000 feet. A tensioned 20-inch pipelineriser would be installed between the ocean floor template and the deck of the tension leg platform. Thepipeline would be connected to the riser through a pull-in assembly.


This aoenario "'IUD'" would mvolri" the iJl81_aqQn'olrOjJ nate.ppa~~\ .'.~~kilt i_~lStqt1 ,.. nOt ·.,a.tor .t~ .act CUlCIlWIed ~tI>()l ... ,

. SUe

· ·rIeUt •. oae "PlY'·'''~,;.c~ •. ~ ~·:'·~.···'f.!·'" aa a;~Y~i _ •.. T",.,-.- tr-P" tranlpOi'tat~ ~ W'lilUlll


Deepwater Scenario(Offshore California)

Location Of discovery

Riser and cont ro l sys tem

I

Approval of plans by governmental agencies

I I IDesign and contruct offshore facility

IL I Development drilling

I

IDesign and construct pipeline

II

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


Figure 3-14.—Subsea Production System

SOURCE: Exxon.

is housed in a dry, atmospheric chamber on theseafloor. Flowline connection and maintenancework can be performed by workmen inside thechamber in a normal atmospheric, shirt-sleeve envi-ronment. The workmen are transported to andfrom the chamber in a tethered, atmospheric div-ing bell which mates to the chamber allowing com-pletely dry access for nondivers. Current develop-ment of subsea systems seems to favor the wetinstead of the dry system.14

Most of the subsea installations are single wellcompletions with the well producing through aflowline 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 Capa-bilities, Department of Interior Hearing (May 1977).

an underwater manifold with a common produc-tion riser to a floating production unit. One suchsystem is represented by Shell/Esso’s UnderwaterManifold Center recently installed in 500 feet ofwater in the North Sea (see figure 3-15). This sys-tem provides for a number of subsea wells clusteredon an underwater template with associated mani-folding and control equipment. Maintenance oper-ations are performed with a remote vehicle con-nected to a production platform located severalmiles away. 15

An inherent limitation of the subsea productionsystem is the need to have surface facilities to proc-

15T, BaStiaanSe and J. R. Liles, ‘ ‘Overview of the Central Cor-morant Mannifold Centre Project ( 1974- 1983), Proceedings of theOffshore Technology Conference (1983).

ess the oil and gas for transport to market. Addi-tionally, all well work that cannot be handled bythru flow-line techniques requires an expensive,floating platform. Artificial lift to bring the prod-uct to the sea surface is complex and difficult tomaintain with hydraulic or electric pumps. How-ever, gas lifting is suitable for these subsea wells.The application of subsea production systems is ex-pected to be more suited to the development of sat-ellite reservoirs where oil can be routed to a pre-existing platform.

One of the assumptions that was made for OTA’sdeepwater scenario was an essentially circular field.This enables the use of a single tension leg plat-form from which directional development wells canbe drilled to fully develop the discovered reserves.

In reality this is rarely the case and, particularlywith a long and narrow field, it may be desirableto use subsea completed wells in conjunction witha tension leg platform. This approach may makeit possible to more completely drain the reservoirand to develop a deepwater field more econom-ically.

Transportation

Conventional pipelaying techniques such as thelay barge, reelship, surface tow, and bottom towwill require adaptation before they can be appliedto deepwater situations such as those involved inoffshore California. While deepwater pipelaying ca-pabilities have improved considerably, driven par-ticularly by the need to lay pipelines in deepwater


areas of the Mediterranean, such techniques andrequired equipment are not fully developed, widelyavailable, or in commercial demand. Semi-sub-mersible, ship-shape, and more conventional barge-shape hulls have been used in the current genera-tion of deepwater pipelay vessels. Other more ad-vanced vessel designs are based on inclined rampor J-curve methods as opposed to using the con-ventional ‘‘stinger. Bottom-tow or flotation tech-niques are also considered viable deepwater tech-niques. 16

Pipelay capabilities have advanced considerablyin order to deal with the specific problems attachedto deepwater pipeline installations. These problemareas include: pipe failure due to propagatingbuckle phenomenon, longer unsupported spanlengths, higher strain levels, more severe sea states,longer pipe exposure time during pipelays, and theneed for greater accuracy in the control of vesselmotions, new mooring techniques, and new classesof thicker diameter pipe.

In general, most of these problems have been suc-cessfully solved or are being solved through im-proved techniques, equipment modifications, orchanges in basic technological applications. Vesselscapable of laying pipe in deep water may now in-corporate the following features: automatic posi-tion control systems; high tension capacity; ad-vanced mooring systems; automatic welding,including single-station pipe joining or double join-ing capability; large pipe storage capacity; and useof computer simulations to optimize a pipelayingspread.

At the present time, it appears feasible that pipe-lines up to 20-inch (51 centimeters) diameter canbe laid in water depths of 4,000 feet using existing

or slightly modified equipment, although proveninstallation has taken place in only 2,000 feet.Saipem’s dynamically positioned semi-submersiblepipelayer Castoro SEI laid 3 20-inch lines acrossthe Strait of Sicily in the Mediterranean in 1979in waters to 2,000 feet.

An alternative to pipeline transportation of thecrude oil to shore is the use of a floating storageand loading system from which shuttle tankerswould move the crude to market. A variety of sys-tems have been developed to provide floating off-shore storage and/or treatment and loading systemsfor transferring oil to shuttle tankers. Offshore stor-age and loading systems were initially designed toallow continuous production in areas with severeweather conditions or with deep trenches inhibitingpipelines such as in the North Sea. These systemsnow have been greatly expanded or modified to aidin the use of subsea production systems, to allowmarginal field development, and to initiate produc-tion from a field as early as possible.17

Floating ship-shape or semi-submersible produc-tion facilities and combined production/storage/loading facilities recently have become attractiveto offshore operators. Floating production units aregaining acceptance by the oil industry as alterna-tives to fixed platforms for deepwater applications.Many floating systems are already in operation,mostly converted semi-submersible drilling rigs andtankers. State-of-the-art installations include Shell’smultiwell floating production, storage, and offload-ing system for Tunisia’s Tazerka field in 460 feetwhich is tied-in to subsea wells. No systems of thistype are currently available for use in water depthsin excess of about 3,000 feet.

l~Dames & Moore, GMDI, and Belmar Engineering, ‘‘Deep waterPetroleum Exploration and Development in the California OCS,report prcparcci lor the Minerals Management Service (January 1984).

17D. M. Coleman, “Offshore Storage, Tanker Loading, andFloating Facilities, Outer Continental Shelf Frontier TechnologySymposium (1979); and ‘‘A Complete Producing System for DeepWater , 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLESTable No.

4-1. Representative MMS-Sponsored Arctic and Deepwater Research Pr4-2. Coast Guard Polar Icebreakers , . . . . . . . . . .

4-3. Comparative Government Polar Icebreaker Figures4-4. Condition of Coast Guard Icebreaking Fleet4-5. Comparable Industry

Figure No.

Rates (

jects

. . . . . . .

. . . .

. . . . . . . . . .

983) . . . . . .

4-1. Loran-C Coverage of Alaska . . . . . . . . .4-2. Offshore Drilling Injury Rate . . .

. . ..

. . .

. .

Page89

898991

9292

9698

103104106109111

Page

9 0.

9 9. . . .

9 9. . .

. 100 106

Page9 6

105

Chapter 4

Federal Services and Regulation

OVERVIEW

The oil and gas development process largely iscontrolled by private industry after leasing landsfrom the Federal Government. However, indus-try must adhere to the terms of the leases whichinclude safety and environmental regulations andstipulations. There is, therefore, a significant Fed-eral responsibility to develop effective environ-mental standards, establish safe practices, moni-tor development activities, inspect operations,enforce regulations, and provide backup for emer-gency situations. These are broadly defined as reg-ulatory responsibilities.

In addition, the Federal Government performsa number of public services which can affect thepace, the cost, and the reliability of future offshoredevelopment. Some of these services are providedfor multiple public uses and offshore developmentis just one of these. Satellite data collection and pro-vision of navigation systems are examples. Otherservices may be provided to fulfill broad nationalneeds. Basic and applied research that will add to

general knowledge of ice mechanics, oceanography,and materials applications in the Arctic are ex-amples.

The Federal Government is both a regulator(e.g., of personnel safety) and a facilitator (e.g.,in providing environmental information) of offshoredevelopment. Key questions about these two Fed-eral

●

●

●

●

responsibilities are:

Are present technology and institutional ar-rangements adequate for meeting Federalresponsibilities?Is the level of Federal involvement in the de-velopment of Arctic and deepwater frontiersadequate?Does the present level of Federal activity inthese areas adequately safeguard the public in-terest?Is the division between Federal and private ef-forts appropriate?

RESEARCH AND DEVELOPMENT

The level of difficulty and the technical complex-ity of offshore petroleum systems in Arctic or deep-water regions dictates the need for substantial re-search and development efforts by industry andgovernment. Industry sponsors research directedat developing or improving cost-effective and envi-ronmentally safe oil production systems. The Fed-eral Government sponsors research which mayenable it to perform its regulatory or service func-tions and research which advances the state of theart and knowledge in materials, environmental con-ditions, and technology.

Federal Research Programs

Although no major Federal program is focusedon long-range development of Outer ContinentalShelf (OCS) deepwater or Arctic frontier technol-ogies, some work of this type is sponsored by theSea Grant Program. The lack of this type of re-search may be partly a result of the executivebranch and petroleum industry views that such ef-forts are properly left to private companies ratherthan the government. However, several Federalagencies have direct or indirect missions which re-

89


quire research activities related to the developmentof offshore petroleum resources. These are the De-partment of the Interior (DOI), the NationalOceanic and Atmospheric Administration (NOAA),the U.S. Coast Guard and the Maritime Admin-istration (MarAd) of the Department of Transpor-tation, and the Department of Energy (DOE). Inaddition, the Office of Naval Research (ONR), theNational Science Foundation (NSF), and the U.S.Army support Arctic research efforts which havespin-offs or goals which are related to offshore pe-troleum work.

As the regulating agency for the development ofoffshore oil and gas, the Minerals ManagementService (MMS) in DOI supports several technol-ogy research and environmental assessment pro-grams. The most important offshore technology re-search effort is the the Technology Assessment andResearch Program (TA&R). The TA&R Programis designed to meet the need for an independentFederal assessment of the status of offshore tech-nology so that MMS operations personnel can carryout their ‘ ‘regulatory’ or ‘‘inspection’ activities.The program focuses on technologies pertaining toblowout prevention, verification of the integrity ofstructures and pipelines, and oil spill containmentand cleanup.

The TA&R program supports the followingMMS functions: safety and pollution inspection,enforcement actions, accident investigations, per-mit and plan approvals, and well control trainingrequirements. Where technology gaps are iden-tified, original research is performed. Studies areconducted by universities, private companies, andgovernment laboratories. Each work task providesfor technical dialog between investigators, the in-dustry, and MMS operations personnel. These in-vestigators are used as staff adjuncts who presenttheir work to MMS operations personnel througha technology transfer network of working groupsknown as Operations Technology AssessmentCommittees located in regional OCS offices andin headquarters.

Projects are conducted wherever possible in ad-vance of OCS leasing. The TA&R Program, to-gether with the technology transfer network, alsois used by MMS as the primary method for iden-tifying the “best available and safest technologies, ”

which industry is required by law to use. Aboutone-third of the projects are assessments and two-thirds examine technology gaps. Although the pro-gram covers all Federal leasing areas, a major em-phasis is on the Arctic and deepwater. About one-third of TA&R projects are participatory with theindustry (see table 4-l).

The Outer Continental Shelf EnvironmentalAssessment Program office of NOAA undertakesor manages much of the environmental data col-lection program under the MMS EnvironmentalStudies Program. Additionally, the NationalWeather Service, a part of NOAA, collects and dis-seminates weather data, and NOAA participateswith the U.S. Navy in the operation of the JointIce Center. NOAA also has recently announced aresearch project to study Arctic storms.

The DOE Arctic program has acted as a clear-inghouse for government and industry technologyresearch. In addition, technology programs haveincluded sea ice engineering properties; geotech-nology related to sediments and their interactionswith ice and seismicity; and concept studies of thedevelopment of petroleum resources found below

Table 4-1 .—Representative MMS-SponsoredArctic and Deepwater Research Projects

Engineering properties of multiyear sea icea

Ice forces against Arctic offshore platformsReliability of concrete structures in the Arctica

Assessment of ice accretion on offshore structuresFracture toughness of steel weldments for Arctic

structuresDynamic response of offshore structures due to waves

and vortex sheddingUnmanned free-swimming undersea inspection

technologyFluidic mud pulser for measurements while drilling

systemsAcoustic transmission of digital data from underwater

sensorsControl of blowout fires with water spraysSubsea collection of oil from a blowing wellDemonstration of the capability of a robot inspection

vehicle for the performance of useful workApplications of risk analysis in offshore safetyEarly detection of damage in offshore structures by a

global ultrasonic inspection techniqueDevelopment of improved blowout prevention procedures

for deepwater drilling operationsEnvironmental cracking of high strength tension

members in seawatera

aJoint project with industw.bJoint project with another a9encY.


Ch. 4—Federal Services and Regulation ● 9 1

the ice canopy in deep Arctic waters. In the past,DOE sponsored a research program directed atlong-range technology development, including asizable drilling technology program. Some DOEdrilling research is now carried out under the DOEgeothermal program, and there may be spin-offsto petroleum drilling.

MarAd sponsors research related to the futureof the U.S. shipping industry. In order to under-stand the problems of commercial ships in navigat-ing the Arctic Ocean, MarAd has supported studiesin ice navigation. Using Coast Guard icebreakers,trafficability studies have measured power require-ments, the time required to navigate through ice-infested waters, and the forces imposed on shipsby the ice. Funding for this work has been signifi-cantly reduced in recent years.

ONR traditionally has supported research inthose disciplines which would provide the basis forthe understanding of natural phenomena and whichmight be used in the development of new equip-ment or at-sea naval operations. Research infor-mation developed by ONR academic investigatorsis generally published in the scientific literature andthus available to the agencies and industries in-volved in Arctic energy resource development.

NSF supports a broad range of basic researchaddressing Arctic scientific problems. The NSF re-search grants that pertain to offshore areas includebiological, oceanographic, geological/geophysical,glaciology, meteorology and atmospheric sciences,and engineering.

The U.S. Army Cold Regions Research andEngineering Laboratory is a specialty laboratoryoperated by the U.S. Army Corps of Engineers.The laboratory focuses on geophysics and engineer-ing in the world cold regions as these subjectsrelate to military operations and construction. Thelaboratory also possesses a large library that worksin conjunction with the Library of Congress to ac-cess the world literature on the geophysics and engi-neering of the cold regions. The Army laboratoryhas a long and distinguished record of work onproblems related to the science and engineering ofthe polar oceans. This has focused on problemscaused by the presence of ice, ice islands andicebergs, snow cover, and subsea permafrost. Mostresearch on polar ocean problems has been fundedby other government agencies and private industry.

Photo credit: ARCTEC, Inc.

Model ice-breaking tanker (a scale replica of the SSManhatten) being tested to measure force required

for passage through first-year ice

Future Research and Development

It appears that industry’s research and develop-ment needs will continue to be met in a timely man-ner without any significant changes in Federal pol-icy or incentives. However, there are concernsrelated to the government role in supporting andmonitoring future research, maintaining nationalfacilities, and supporting excellence in universitiesand other research institutions. Some have beenconcerned about the uncoordinated and fragmentednature of Federal programs, and suggestions havebeen made to consolidate or coordinate researchthrough a joint industry/government/academiccouncil.

Most industry spokesmen support the existingMMS research program which concentrates onmatters directly related to that agency’s regulatoryrole. However, they believe any expansion of thisprogram may overlap with industry activities. Aca-demic researchers generally maintain that the pres-ent government effort is not sufficient to assure ade-quate support for basic and advanced engineeringresearch and to provide continuing support for edu-cation. Larger and longer term commitments maybe needed to accomplish relevant basic research,to prepare academic institutions to better accom-modate and address specific industry needs, andto ensure a steady supply of well-trained andtalented scientists and engineers.


While cooperative industry research has pro-duced hundreds of reports on critical subjects, veryfew of these have been made available to the pub-lic. Most research and data are kept confidentialby the participants, but it could possibly be madepublic after a certain time period. There is gener-ally a need to promote more cooperation betweenthe Federal Government, industry, other publicgroups, and other governments in Arctic programs.Efficient data collection often requires coverage overterritories of several nations (e.g., Canadian andAlaskan Beaufort Sea regions). Cooperative re-search with public groups could assist communi-cation of the results and the implications of devel-opment options.

One of the greatest values of federally sponsoredresearch is the ability of some agencies to designprograms with multi-year continuity so that basicproblems can be consistently studied and long-termdata can be collected and applied. This is essentialto an undemanding of some basic phenomena suchas ice movement and forces, meteorological, andoceanographic processes. It is, therefore, importantto maintain continuity in many of the government-supported research efforts.

One approach to enhancing Federal researchefforts is contained in the Arctic Research and Pol-icy Act (ARPA) of 1984. The Act finds that Fed-eral Arctic research is fragmented and uncoordi-nated and that a comprehensive policy and programto organize and fund Arctic scientific research isnecessary to fulfill national objectives. National Arc-tic objectives specifically cited in the bill, which re-quire or would benefit from a more comprehen-sive scientific research effort, include developmentof the living and nonliving resources of the Arctic,environmental protection, national security, miti-

gation of the adverse consequences of developmentto Arctic residents, and better understanding ofglobal weather patterns.

ARPA creates two new institutions—the ArcticResearch Commission and the Interagency ArcticResearch Policy Committee—to carry out the pur-poses of the Act. The Interagency Arctic ResearchPolicy Committee is composed of representativesof all Federal agencies with responsibilities in theArctic. The National Science Foundation chairs theCommittee and is responsible for ensuring the im-plementation of national Arctic research policy.ARPA calls for a 5-year implementation plan,which, at a minimum, must assess national needsand problems regarding the Arctic and the researchnecessary to address those needs and problems. TheArctic Research Commission is, in essence, an in-dependent advisory board. The Commission is re-sponsible for: developing and recommending an in-tegrated national research policy; facilitatingcooperation among Federal, State, and local gov-ernments; and assisting in developing the 5-yearplan.

However, ARPA provides no additional fund-ing for Arctic research. Moreover, although the lawurges agency coordination and integration of re-search programs, there is no authority in the billto direct departmental budgeting. Therefore, de-partments will continue to set their own researchpriorities based on agency-specific missions. With-out research funds and with authority limited togiving advice and making recommendations, theCommission’s present duties are limited. However,both the 5-year implementation plan and the sur-vey of Arctic research that the Interagency Com-mittee will conduct will be useful if they help co-ordinate the overall Federal Arctic research effort.

FEDERAL SERVICES

Environmental Information seismicity—for the design and operation of offshorestructures and supporting systems.

Firms engaged in offshore oil and gas develop- The offshore industry receives information onment require a great deal of technical environ- these conditions from both Federal and privatemental information—information about weather, sources, and many firms collect their own data asice, oceanographic conditions, soil mechanics, and well. Federal environmental data services are de-


signed to serve the public at large, broad sectorsof the economy, and the needs of other Federalagencies. Such information is used by the offshorepetroleum industry to gain information on global,regional, and local conditions over both short andlong timeframes. There is no charge for most Fed-eral forecast or operational data products. How-ever, charges are assessed for some products thathave more identifiable users (e. g., for provision ofLANDSAT images), and often users must pay forthe communications devices (e. g., dedicated phonelines) used to access information.

The main Federal agencies involved in collect-ing, processing, and disseminating offshore envi-ronmental information are NOAA, Navy, the Na-tional Aeronautics and Space Administration(NASA), and the Air Force. NOAA is the primarypoint of contact between civilian users and Federalagencies. Principal NOAA units are the NationalWeather Service; National Environmental Satel-lite, Data, and Information Service; and the Na-tional Ocean Service. The Navy/NOAA Joint IceCenter plays a key role in disseminating ice chartsand other ice-related information. NOAA has sev-eral units involved in maintaining and improvinguser services, notably two Ocean Service Centersin Anchorage, Alaska and Seattle, Washington.

Most data used by Federal agencies come fromfederally operated satellites, ships, and other sys-tems. However, agencies also incorporate data fromprivate sources. Site-specific information used byfirms developing oil and gas resources is usuallyobtained from private firms, including the firmscontracted to conduct actual operations. For exam-ple, operators in an area affected by ice movementsmay supplement information received from Fed-eral agencies with direct observations from com-pany supply vessels or helicopters.

‘ ‘Value-added private firms take> historicaland/or forecast data from Federal sources, refineit by additional processing and interpretation, andoften supplement it byadditional observations.Such firms tailor products to specific user needs,giving forecasts with greater frequwncy and moregeographic specificity than usually can be obtainedfrom Federal agencies.

Information Needs

There are some problems with the current pro-vision of offshore environmental information. Voidsexist in historical and near real-time data. Thereis less information available about some types ofenvironmental conditions and some offshore re-gions. Greater precision and accuracy are neededin describing and forecasting conditions. For someactivities, the environmental information availablemay be insufficiently precise. Many users desiregreater accuracy and better spatial resolution in theobservations and forecasts. In addition, productsmay be too infrequent. Some users suggest that thetime intervals between measurements of conditions,and between measurements and delivery of infor-mation to users, should be shortened. The need formore accurate, longer range forecasts has also beenstressed. 1

Data are lacking for a variety of reasons. For ex-ample, the sensors mounted on current NOAA sat-ellites are impeded by clouds, fogs, blowing snow,and in the case of sensors restricted to the visiblespectrum, darkness. Outside of well- traveled oceanroutes and populated coastal areas, data to supple-ment satellite observations are limited. Minimal ar-chived data are available for use in ‘‘ hindcasting"conditions. Much of the satellite data which couldbe available are not collected and that collected areusually not archived because of either a lack of fundsor the absence of a specific program to do so.

Nontechnical problems also affect the perform-ance of Federal agencies. Many NOAA programshave been targeted for reduction and may find itdifficult to cope with the increases in user demandslikely to occur with the expansion of Arctic devel-opment. Suggestions have also been made that theFederal Government establish a single focal pointfor collecting, evaluating, and disseminating envi-ronmental data.

An OTA survey showed that improvements maybe needed in many information areas for pre-leasesale planning and, to an even greater extent, forsite 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


quently mentioned as needing improvements are:ice-related information in the Chukchi and BeaufortSeas, and to a lesser extent, the northern Beringand Norton Sound; soil geotechnical properties inevery offshore area; permafrost in the Chukchi andBeaufort; storm surges in the Chukchi and north-ern Bering; wave climatology in the Chukchi and,to a lesser extent, the Bering; currents in theChukchi; and wind velocity and visibility in thenorthern Bering, and bathymetry, to a lesser ex-tent, in all areas. Information about air tempera-ture, precipitation, and tides was generally seen asbeing satisfactory or not requiring major im-provement.

Better data about environmental conditions couldresult in financial savings and improve the safetyof offshore operations. Lack of information aboutenvironmental conditions may cause overdesign ofdrilling platforms and ships. Better informationcould reduce a portion of the costs associated withoverly conservative design.

Several rigs have been lost to severe storms innon-Arctic areas, at a cost of scores of lives and tensof millions of dollars, and oil spills have resultedfrom ship accidents. While human error has oftenbeen a contributing factor, better information aboutstorms could help prevent recurrences of theseevents.

Operations are planned and carried out on theexpectation of suitable weather, ice, and ocean con-ditions. Adverse environmental conditions oftencause offshore operations to be suspended. Whenexpensive pieces of equipment and their support-ing systems are laid up due to unforeseen changesin environmental conditions, additional expensesquickly accumulate. For example, lease costs forsemi-submersibles can exceed $50,000 per day, withweather-related losses of over $1 million per rig peryear not uncommon. Similarly, many days are lostfor resupply operations due to weather conditions.It is possible that better information could reducesuch losses.2

More efficient ship routing, based on better in-formation, could also result in large savings in timeat sea, and associated costs in fuel, damage to cargo,and other items.

‘Jet Propulsion Laboratory, ‘ ‘Ocean Services User Needs Assess-ment” (Apr. 5, 1984), pp. 4-29.

Photo credit: Gulf 0il Corp.

A great deal must be known about ice forces to allowsafe Arctic operations

Future Information Services

Federal agencies are undertaking several initia-tives that may improve environmental informationservices. For example, the NOAA Ocean ServiceCenter concept appears particularly promising asa way to improve contacts with users of NOAAservices. Several technological improvements alsoare important, including new sensors scheduled tobe placed on future satellites. These advances, espe-cially new satellite systems, could substantially re-duce data gaps. New Navy oceanographic and AirForce meteorologic satellites will penetrate cloud


cover and other low visibility conditions withmicrowave sensors.

For extremely high resolution, synthetic apera-ture radar (SAR) imagery is needed. No U.S. sat-ellite is scheduled to carry a SAR during this dec-ade. However, planned European Space Agency(ESA), Canadian, and Japanese satellites arescheduled to have SARs. NASA has proposed toestablish a SAR receiving station in Alaska to col-lect data on offshore Alaskan areas from the ESAsatellite ERS-1, and NOAA has expressed inter-est in disseminating and perhaps processing suchdata. Acquisition of SAR data would greatly im-prove existing information on sea ice, and the off-shore industry has gone on record in support of theproposed NASA receiving station and associateddata processing capability. However, some uncer-tainties remain about acquiring the ERS-1 SARdata. Funding for the NASA and NOAA initiativesto handle such data have not yet been approved.It is also uncertain whether ERS-1 will be launchedon time, and whether its sensors will be switchedon while it is flying over Alaska.

It is equally uncertain whether operational prod-ucts and real-time data would be provided as a re-sult of accessing the ERS-1 SAR data. The offshoreindustry wants processed images made available toforecasters or industrial users within hours of dataacquisition. Current NASA plans are to processdata several days after acquisition. Near real-timedissemination of data would require additionalprocessing capacity, and NASA does not see itsfunction as including provision of operationalproducts or real-time data. However, companiessurveyed by the Jet Propulsion Laboratory at theCalifornia Institute of Technology expressed awillingness to contribute to a NOAA-sponsoredpilot program to develop real-time SAR data dis-semination, depending on the results of furtherstudy.

Another uncertainty lies in Administration plansfor funding reductions for meteorological satellitesfrom two polar orbiters to one. According toNOAA, a one-polar-satellite system would meet thecore of U.S. weather forecasting requirements.However, the frequency with which any one areawould be covered would be reduced from onceevery 6 hours to once every 12 hours. Reduction

of frequency would have significant effects onprediction of weather affecting Alaska, Hawaii, andother Pacific territories, and on activities using sat-ellite data services, This would be especially truein areas poorly covered by nonsatellite informationgathering systems, including most of the offshorefrontier areas. In addition, the amount of informa-tion shared with other countries would be reduced,potentially affecting reciprocal information ex-changes.

In addition, the Administration is seeking to in-crease the role of the private sector in supplyingenvironmental information services. In March1983, the Administration endorsed the transfer ofnondefense remote sensing satellite systems—LANDSAT, civilian weather satellites, and anyfuture ocean sensing satellites—to the private sec-tor. Weather services and, to a lesser extent, futureocean sensing services are considered by many peo-ple to be public goods, appropriate for the FederalGovernment to provide, even if at a loss. Congres-sional concern culminated in an authorization billsigned into law prohibiting the sale of the weathersatellite system to the private sector. Plans for thesale of LANDSAT have continued, however, andlegislation to transfer LANDSAT to the private sec-tor was enacted in July 1984 (Public Law 98-365).Industries involved in offshore oil and gas devel-opment fear that nongovernmental managers ofLANDSAT may not devote adequate resources tofurther develop remote sensing technology and thatcosts may greatly increase. 3

Current NOAA plans are to transfer a portionof its nautical chart-making to the private sector.As with satellite commercialization, the Adminis-tration sees advantages in reducing the Federal rolein an area where the private sector could take overoperations. Critics have argued that safety couldbe reduced if fewer charts were made or if peoplewere reluctant to purchase updated charts becauseof increased charges. There is also concern aboutFederal liability in marine casualty cases.

3U. S, Congress, OffIcc of Technology .Assessmcnt ‘‘ Remote Sens-ing and the Prit’atc Sector: Issues for Discussion-A ~’cchn ical hlcnlo-randum ” (Washington, DC: U S. Gof’crnmcnt Printing Office,March 1984).


Navigation Services

Federal agencies operate ground stations and sat-ellite platforms that beam radio transmissions usedto navigate and to position vessels and structures.Such transmissions are vital to many offshore oper-ations, such as vessel positioning for seismic sur-veys, positioning of platforms, pipeline laying, andtanker transport. Radio aids provide a high levelof accuracy, combined with broad coverage. Theyare especially important in situations where visi-bility is reduced. Arctic operations in particular are,or will be, dependent on radio aids. This is becauseArctic waters are relatively poorly charted and con-tain many hazards, short-range aids such as buoysare often difficult to maintain in Arctic waters, andvisibility is reduced in many areas by extendeddarkness and frequent storms or fog.4

This section covers only those navigation serv-ices which are known as ‘‘radiodetermination.”This encompasses both radionavigation and radio-location, or positioning for purposes other thannavigation. Federal agencies usually use the term‘‘radionavigation when describing Federal serv-ices in this area. While Federal radio systems areused by the civil sector for uses going beyondnavigation, the statutory responsibility of Federalagencies only extends to providing a level of serv-ice that is sufficient for safe and efficient naviga-tion. Radiolocation or positioning generally re-quires more precise data.

Federal Radionavigation Systems

Offshore operators commonly use their ownshore-based portable positioning systems or con-tract with private companies for such systems dur-ing seismic exploration and for rig positioning,where high accuracy is needed. For many purposes,however, systems operated by the U.S. CoastGuard, Navy, and Air Force are vital to offshoreexploration, production, and transportation of oiland gas.

The Coast Guard operates two types of long-range radio aids, LORAN-C and OMEGA.LORAN-C operates by measuring differences in

4Maritime Transportation Research Board, ‘‘Maritime Services toSupport Polar Resource Development” (Washington, DC: NationalAcademy Press, 1981).

the time of receipt between radio pulses fromtransmitters several hundred miles from each other.The usable range of LORAN-C is up to 1,500miles, depending on system configuration. World-wide, there are 43 U.S.-operated LORAN-C sta-tions. While Alaskan waters up into the Bering Seaare covered by LORAN-C, waters north of PointClarence either are not covered or coverage is sub-ject to interference (see figure 4-l). At the presenttime, there are no plans to extend LORAN-C cov-erage to Arctic regions not currently served.

OMEGA is a radionavigation system similar toLORAN-C, operating at lower frequencies. It hasgreater range, covering the entire world, but its ac-curacy is less: 2 to 4 nautical miles for predictableand repeatable accuracy. Eight stations, two ofwhich are in the United States, comprise theOMEGA system.5

The Navy operates a satellite system calledTRANSIT, with the Coast Guard as the point ofcontact for civilian users. More than 90 percent ofusers of TRANSIT are civilians. The TRANSIT

5Nevin A. Pealer, ‘ ‘Federal Radionavigation Planning, ” Pro-ceedings of the National Technical Meeting of the Institute of Naviga-tion (January 1984).

Figure 4.1.— Loran-C Coverage of Alaska

45“N1

40“N170 “w 160°W 140 “w150 “w

SOURCE: Transportation Systems Center, “Benefits and Costs of Loran-C Ex-pansion Alternatives in Alaska,” April 1983.


system has five satellites in polar orbit, withworldwide coverage. The limited number of satel-lites in the TRANSIT system means that, depend-ing on their location, users experience gaps lastingfrom 30 minutes to several hours in the receptionof transmissions. Transmission gaps are greatestat the equator, less at northern latitudes.

Present Federal plans are for LORAN-C,OMEGA, and TRANSIT to be phased out andeventually replaced by the Global Positioning Sys-tem (GPS), which is to be operated by the AirForce. As with TRANSIT, the Coast Guard is tobe the contact agency for civilian uses of GPS.When fully developed, the GPS will use 18 satel-lites, with three operating spares also in orbit. GPSis intended to provide highly accurate, continuous,worldwide positioning information for weapons de-

Photo credit: Rockwell International

The Global Positioning System (GPS) will provideradionavigation services for Arctic operators

livery systems; however, it also will be used bycivilians for nonmilitary purposes.

GPS is currently in a research/demonstrationphase. Some test satellites have been launched andused to verify the GPS concept. Launches of thesatellites that will establish the operational systemare scheduled to begin in late 1986, By 1987 or1988, two-dimensional coverage suitable for marineoperations should be achieved, with full three-dimensional coverage suitable for aircraft availableby late 1988 or early 1989. TRANSIT is to be ter-minated in 1994, or as soon as the military canchange over to GPS, which is expected to be com-plete by the early 1990s. Although terminationdates for LORAN-C and OMEGA have not beenfixed, suggested dates range from soon after 1994to beyond 2000. The Coast Guard favors continua-tion of LORAN-C at least until 2000. ForeignLORAN-C stations could continue to operate forsome time after domestic U.S. stations are termi-nated, depending on foreign governmental support.

The European Space Agency (ESA) is conduct-ing studies on the feasibility of a 24-satellite civil-ian navigation system called NAVSAT. Fundingmay come from indirect charges, rather thanthrough direct user charges. NAVSAT may haveadvantages over GPS in that it would be a civilian-oriented system, whereas GPS is primarily a mili-tary system. The timeframe for development ofNAVSAT is not clear. In addition, the SovietUnion is developing a satellite navigation systemcalled GLONASS that will be similar to GPS. Itis not clear when GLONASS will become fullyoperational. Although initially intended for use bySoviet civil aviation and special-purpose oceanvessels, GLONASS may eventually be offered forworldwide use free of charge.

Radionavigation Needs

Different radiodetermination tasks require dif-ferent levels of accuracy. For example, seismic sur-veys require extremely high repeatable accuracylevels. Vessel navigation generally requires less ac-curate satellite data. OMEGA is adequate for oceannavigation, especially away from the coastal zone,but for other purposes does not provide sufficientaccuracy. LORAN-C gives greater accuracy, andthe continuous broadcasts of LORAN-C are an im-


portant asset. LORAN-C capabilities are sufficientfor most coastal navigation. A major drawback ofLORAN-C is its lack of coverage of northernAlaskan waters. LORAN-C and other nonsatellitesystems are also more susceptible to atmosphericinterference. TRANSIT provides greater accuracythan LORAN-C, but its usefulness is lowered bygaps in transmissions.

Whether or not current radiodetermination sys-tems should be upgraded depends largely on evalua-tion of the prospects for GPS. Concerns haveemerged regarding GPS agency/user relations, theaccuracy of GPS information provided to civilianusers, the timing of the phase-in of the system, andcosts and charges to users.

If TRANSIT were phased out before GPS weremade available, the overall level of Federal servicewould be lowered. Many users seek assurances thatGPS will provide services comparable to existingsystems, and that other systems will continue tooperate until GPS provides such levels of service.The offshore industry believes that GPS usercharges are acceptable in principle, but that suchcharges should be ‘ ‘equitably’ assessed. Industrygroups have opposed plans that would favor recrea-tional boaters or fishermen.

Icebreaking

Alaskan Arctic waters are ice-covered or experi-ence significant ice concentrations for all or partof the year. Specialized vessels that can operate inice-infested waters will be needed if developmentis to proceed. Possible missions performed byicebreaking or ice-capable vessels related to oil andgas operations include opening of shipping lanesand drilling vessel sites, protection of drilling oper-ations against drifting ice, supply of operations, pol-lution response, search and rescue, and transportof petroleum products. In U.S. waters, missionssuch as supply operations and transport of prod-ucts are private sector responsibilities. Missionssuch as pollution response and search and rescueare undertaken by both private and Federal units.The Coast Guard also carries out vessel-towing andother rescue and safety-related missions.

The need for icebreakers will vary with the loca-tion of oil and gas fields, their size, and their dis-tribution. Because it is difficult to project what the

conditions of oil and gas development will be, pro-jections of future icebreaker needs are uncertain.If fields are close to shore, use of pipelines, aircraft,hovercraft, and land transport over ice would min-imize the need for icebreakers. However, in manysituations, especially for remote fields, it may beadvantageous to use icebreakers. For example, airoperations tend to be far more expensive than shipoperations, especially for supply tasks involvinglarge volumes. In addition, helicopter range islimited, and aircraft are more limited than shipsby weather conditions.

Federal Icebreaking Services

With the transfer of Navy icebreaking functionsto the Coast Guard in 1965, the Coast Guard be-came the sole Federal agency to operate icebreakers.Apart from its own missions, such as enforcementof laws and treaties, the Coast Guard also providesicebreaking support to other Federal agencies forsuch purposes as scientific observation and supplyof installations. In the early 1980s, Coast Guardpolar icebreakers spent an average of 127 days peryear in the United States and western CanadianArctic. G

The Coast Guard currently maintains five polaricebreakers (see table 4-2). In terms of numbers,the Coast Guard icebreaking fleet ranks third inthe world, behind the Soviet and Canadian fleets(see table 4-3). Private icebreaking services areavailable in some U.S. Arctic areas. For example,tugboat-pushed barges supply North Slope oil oper-ations, breaking ice each year from August untilOctober.

However, some believe that the Coast Guard hasbarely adequate resources to undertake currentoperations and would have inadequate resourcesto carry out the expanded duties brought about byincreased oil and gas development in the Arctic.Apart from the two Polar class ships, the Federalicebreaking fleet is in fair to poor condition (seetable 4-4). The U.S. polar icebreaking fleet is oneof the the world’s oldest, with a median age of about30 years. Two of the four original Wind class vesselswere ret i red several years ago, and the other twostill in service have poor crew facilities and defi-

6U. S. Coast Guard, “United States Polar Icebreaker RequirementsStudy” 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, ALNorthwind . . . . 1945 269 6,260 10,000 3 11 181 Wilmington, NCGlacier. . . . . . . 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, WAPolar 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.

JapanCanadaCanada

(private)U.S.S.R.

U.S.S.R.

U.S.S.R.

Canada(private)

USACanadaCanada

ArgentinaCanada

(private)W. GermanyJapanCanada

(private)CanadaUSA

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

197519771985195919761978

1974-76

198219691983

1959-69

1980-81

1977-78

1979

19551960

1978-82

19781983

198219651982

19531944-45

446

439399

442

440366289

400

433

433

299

310315316

391258

387328272

290269

36

3431

36

303126

31

28

28

28

282824

3125

352918

3028

25,000

19,24013,000

20,241

17,60014,0007,000

15,360

14,900

14,900

6,500

8,0009,1608,055

14,5006,000

14,8008,5666,512

7,0007,000

75,000

44,00060,000 or18,00036,000

30,00024,00023,200

22,000

22,000

22,000

16,360

21,00015,00013,600

16,20014,900

20,00012,0009,000

10,00010,000

N

NGT orDEDE

DETEGD

DE

DE

DE

GD

DEDEDE

DEGD

GDDEGD

DEDE

8

76 +

6

54-55

4.5

4.5

4.5

4-5

3.53.53.5

3.53-4

333-4

33

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.


Table 4-4.—Condition of Coast Guard IcebreakingFleet

Icebreaker typeWind Polar

Category class Glacier class

Prime mission equipment/science facilities . . . . . . . . . . 2 3 3

Habitability . . . . . . . . . . . . . . . . 1 2 5Hull and ship structure. . . . . . . 1 3 5Main propulsion . . . . . . . . . . . . 4 3 4Auxiliary . . . . . . . . . . . . . . . . . . . 1 3 4Command 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. Theseolder icebreakers are considered by the CoastGuard to be nearing the end of their ability to pro-vide reliable service. Their active service is pro-jected to end in the late 1980s.

The Coast Guard currently assumes that it willcontinue 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 involvedin the design, construction, and testing of ice-breakers— about 5 to 8 years—decisions must bemade soon concerning the number of icebreakersdesired and their characteristics (size, draft, pro-pulsion systems, equipment, etc.). Congress has au-thorized the construction of at least two new Polarclass icebreakers by the end of fiscal year 1990.

Future Icebreaking Needs

Offshore developments in Arctic regions may re-quire icebreaker support for much of the year. Dif-ferent levels of service could be provided by theCoast Guard. The Coast Guard believes that thecontinuous presence of Coast Guard icebreakers isnot required in the Arctic at this time; rather, itseeks to maintain the ability to enter Arctic watersand perform required missions. If a continuouspresence were needed, different icebreaker designand/or more northern icebreaker basing would berequired.


The most capable icebreakers in the Coast Guardfleet, the Polar Star and the Polar Sea, are capa-ble of transiting continuously through over 6 feetof first-year ice at 3 knots, without backing andramming. They can break through ice thicknessesof 21 feet by backing and ramming. There is somedisagreement regarding the adequacy of these shipsfor operations in all Arctic winter conditions. TheCoast Guard believes that the Polar class vesselshave sufficient characteristics, while some othersources believe that far more powerful icebreakersare needed. If many operations take place in theBeaufort and Chukchi Seas, as opposed to the Ber-ing, icebreakers will have to meet more rigorousrequirements. The Coast Guard is currently de-ciding the class of future polar icebreakers.

A problem for year-round service is the endur-ance of icebreakers. The gas turbine engines on thePolar class vessels, used for heavy icebreaking, con-sume large amounts of fuel and require relativelyfrequent refueling. Even in conditions where dieselelectric engines are used, icebreakers that have longtraveling times to reach Arctic duty experience en-durance problems. The home bases of the polar fleetare Seattle, Long Beach, Mobile, and Wilmington,with two (soon to be three) of the five polaricebreakers based in Seattle. From Seattle to theNorth Slope is at least a 2-week voyage. Currently,there are no refueling stations north of the Aleu-tians. If a more substantial Coast Guard icebreak-ing presence were to be established, vessels withgreater endurance would be needed or refueling andother support facilities would have to be constructedcloser to offshore operations. One problem withnorthern basing is that the closer the operations baseis to the Arctic, the farther away it would be fromAntarctica, where many missions are carried out.It is also thought that ship maintenance would bemore difficult if northern bases were used. TheCoast Guard has no present plans to establishnorthern basing for icebreakers.

Some Arctic areas such as the eastern Beaufortare relatively shallow for long distances offshore andshallow draft icebreaking capability may be needed.Such icebreakers must be able to operate in less than20-foot water depths and to break ice continuously2 to 3 feet thick.7 The Coast Guard currently lacks

‘Lawson W. Brigham, ‘ ‘Future U.S. Coast Guard Shallow-DraftIcebreaker Requirements in Alaska, Proceedings of the Symposiumon Science and Arctic Hydrocarbon Exploration: The Beau/brt Ex-perience (September 1983).

vessels that combine sufficient strength to transitthrough Arctic ice with shallow enough drafts tocome close to shore. The new generation of Polaricebreakers planned for purchase by the CoastGuard will also be deep-draft. The Coast Guardis waiting to see what level of commitment indus-try will be making to offshore exploration beforedeciding what type of shallow-draft icebreakingservice may be needed.

Icebreakers are expensive to build and operate.Total annual costs of operating four to five ice-breakers under various alternatives range from $35to $50 million. Icebreakers support the missions ofa number of agencies besides the Coast Guard,especially the Department of Defense and the Na-tional Science Foundation. Participating agenciesand groups pay a proportionate share of CoastGuard expenses incurred on icebreaking missions,including pay, maintenance, and fuel costs. BecauseCoast Guard icebreaking is dependent on the year-to-year operational plans of several agencies, CoastGuard planners face considerable uncertainty. Ifa single agency decides not to utilize icebreakingservices, the Coast Guard may have to withdrawa ship from service. The Coast Guard is currentlyseeking a revision of the cost-sharing system.

There are also questions about the extent towhich icebreaking services should be provided toprivate firms developing offshore oil and gas.Icebreaking could be a private sector activity, withicebreakers owned and operated by private firms.Or the government could be reimbursed by the off-shore oil and gas industry for all or part of itsservices.

No Federal icebreaking assistance is providedroutinely to North Slope commercial operations.The position of the Coast Guard is that respon-sibility for routine icebreaking for marine commercerests primarily with the marine industry and notwith the Federal Government. However, if avail-able commercial icebreaking services are inade-quate, the Coast Guard will provide icebreakingassistance. Decisions on the availability and ade-quacy of commercial services are made by CoastGuard District Commanders.

There is a need for the Coast Guard to continueicebreaking services in support of such statutorymandated missions as search and rescue, emer-gency response, enforcement of laws and treaties,


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 opera-tors feel that they can provide the offshore oil andgas industry icebreaking services such as supply andchannel breaking. At the present time, there arefew U.S. private sector icebreakers, and currentcapabilities are limited to the summer months. Asoil and gas development proceeds, these capabil-ities may expand. The Coast Guard would prob-ably still be called upon for icebreaking support inemergency ice conditions.

There are incentives for industry to provide itsown icebreaking or contract with private firms foricebreaking services to support oil and gas devel-opment. Special Coast Guard requirements for

larger ships increase the cost of Federal icebreakersand icebreaking services in comparison with pri-vate services and would add to any Federal userfees. Also, without the need to design and operatevessels for the multi-mission roles that Coast Guardvessels must fulfill, private sector icebreaking vesselscould be tailored to meet industry missions. 8

In general, private icebreaking firms have beenstrong supporters of user fees, believing that theycould not compete against taxpayer-subsidizedCoast Guard services. The Coast Guard advocates

8National Petroleum Council, U, S. Arctic Oil and Gas, WorkingPaper-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 indus-the statutory responsibilities of the Coast Guard. try. Presently there are no plans for Coast GuardCoast Guard policy for the Arctic is not clearly icebreakers to be used to directly support petroleumestablished and may not be until there is increased exploitation and commerce. If such support wereoil and gas development. A 1982 interagency study provided, it would be appropriate for user fees.declared that ‘ ‘although Arctic petroleum develop-ment could be argued to be in the national inter-est, 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 anddangerous work. Special risks are presented in fron-tier regions because of harsh environments andremote locations. Offshore operators have madesubstantial efforts to safeguard health and safety,and the safety record of offshore operations appearsequal to or better than the record of comparableonshore industries. Still, there is a need for con-tinuing attention to ways in which the Federal Gov-ernment can assist in preventing work-related in-juries and fatalities.

As in other industrial sectors, offshore employersvary greatly in their safety records. Industry asso-ciations and many employers have strongly pro-moted safety, e.g., through sponsoring training ofpersonnel, while other employers have been morelax. Public concerns about offshore operations havebeen stimulated by incidents that resulted in thedeath of a large number of workers. The bestknown of these incidents are the sinkings of the con-verted floating hotel Alexander Kielland (North Sea1980, 123 fatalities), the Ocean Ranger (EasternCanada 1982, 84 fatalities), and the drill shipGlomar Java Sea (South China Sea 1983, 81 fa-talities). The last two were U.S. flag casualties. Off-shore incidents in 1984 included a fire on the En-chova Central Platform off Brazil with 41 fatalities,and a natural gas explosion that killed 4 on theZapata Lexington Number 26 semi-submersible rigin the Gulf of Mexico.

Offshore hazards can be categorized in differentways. A Marine Board report separates hazardsaccording to the type of offshore activity: construc-tion, drilling and well maintenance, production,

and transportation.10 Exploratory drilling is often

considered to be the most hazardous phase of off-shore operations, perhaps because less is known atthat stage about formation characteristics. Onlyabout one-fifth of all offshore employees are en-gaged in drilling; however, they experience adisproportionately larger number of accidents.

Accidents can also be categorized according tothe facility where they occur: tankers, fixed plat-forms, mobile rigs, and support vessels and struc-tures.11

Another division emphasizes the scale of ac-cidents. There are individual accidents, such asfalls, being struck by objects, and being pinned be-tween objects. There are also occupational healthproblems separate from accidents, such as hearingloss due to machinery noise. Then, there are largerscale, catastrophic incidents, such as rig sinkings.Catastrophic incidents have occurred because ofstorms, structural failures, and capsizings. Otherfatalities have resulted from well blowouts, explo-sions, and fires. Unlike most onshore occupations,offshore jobs pose hazards to off-duty workers, whooften remain in close proximity to the work-site.Multiple fatalities and injuries also have resultedfrom transportation accidents involving helicoptersand supply vessels.

This section focuses on several potential safetyproblems present in frontier regions. In general,

1 ~M arlne ~omd, Sa fc(}, and Offshore Oil ( \\’ash ington, I~C” N~l-tional 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.


Photo credit: Peter Johnson, OTA

Roughnecks on the drilling rig floor at Shell’s SealIsland discovery in the Beaufort Sea

the same types of offshore operational hazards arepresent no matter where operations take place, fromthe day-to-day dangers of working with machin-ery in confined spaces to unusual events such asevacuation under storm conditions. The high levelsof investment required in frontier areas and the in-volvement of larger companies with relatively well-organized health and safety programs may makethe future safety record of operations in such areascomparable to operations in more benign regions.Still, other things being equal, frontier conditionscompound operational risks.

The environmental conditions in offshore fron-tier areas—extreme cold, ice, extended periods ofdarkness, blizzards and fog in the Arctic and severestorm conditions in the sub-Arctic and many deep-water areas—increase the dangers of operations.The remote location of many rigs in frontier areasmakes evacuation of personnel more time-consum-ing and difficult, and delays medical treatment. Thecold temperatures found in the Arctic and othernorthern regions are hazardous both in their directeffects on human health and in their reduction ofworker efficiency. Although employees usually workin heated areas, at times they are exposed to cold.Human ability to perform tasks (e. g., in terms ofreaction time) declines with decreasing tempera-ture. 12 Bulky protective clothing worn for warmth

12R. Goldsmith, ‘ ‘Cold and Work in the Cold, ” Encyclopedia ofOccupational Safety and Health (Geneva: International Labor Orga-nization, 1983).

may interfere with tasks in ways that cause injuryrisks 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 subse-quent death to occur varies with such factors aswater temperature, the weight and physical con-dition of the person in the water (thinner peoplesuffer quicker heat loss), the type of clothing theyare wearing (heavier clothing provides greater in-sulation), and the person’s behavior (e. g., curlingup in a fetal position decreases the rate of heat loss).Without an immersion suit, even a heavily clothedperson in good physical condition can survive foronly a few hours in winter seas. More lightly clothedpeople die from hypothermia in much less time.With a suit, survival time is increased many-fold.A major factor contributing to the deaths result-ing from the Ocean Ranger disaster was the lackof exposure suits on board. Within a few minutesof entering the water, personnel were too numb tograsp life ropes and rings thrown to them from therescue vessel. A Coast Guard rule went into effectin August 1984 requiring exposure suits for per-sonnel on mobile offshore drilling units, amongother types of vessels, that are located in specificoffshore areas.

Injury and Fatality Statistics

There is currently no single comprehensivesource of statistics on U.S. offshore accidents, andthere are no reliable injury and fatality rate statis-tics for offshore operations beyond those compiledby the International Association of Drilling Con-tractors (IADC) for individual workplace accidentsin offshore drilling. The lack of data makes it dif-ficult to evaluate the level of safety achieved by oiland gas operators, safety-related equipment, andFederal regulation. It also makes it difficult to assessthe effects on safety when changes are introduced.The data bases that do exist do not separate in-cidents that occur in frontier regions. To date, therehave been no major (catastrophic) accidents in U.S.frontier areas. However, such accidents haveoccurred to U.S. facilities in other areas.

Several different agencies and organizations keepoffshore accident records, using a variety of report-ing systems. The Coast Guard requires accidents

Ch. 4—Federal Services and Regulation • 105

to be reported if they result in an injury causingabsence from work for more than 72 hours. TheBureau of Labor Statistics (BLS) collects data onthose accidents which cause the employee to be un-available for work at the beginning of his next work-day. The IADC collects data on accidents whichcause 12 hours of work to be lost.

The BLS and IADC standards are roughly com-parable, but their statistics often differ due to dif-ferent data bases. For example, IADC usuallyreports drilling-related injuries, while BLS coversall aspects. IADC statistics are derived from com-panies employing about 90 percent of the offshoredrilling workers, while BLS relies on statisticalsampling. In addition, the IADC does not includeaccident statistics from catastrophic incidents oraccidents involving personnel not employed bydrilling contractors, such as oil company represent-atives and employees of firms providing drillingmuds, well cement, or specialty tools. Neither theIADC nor the Coast Guard ordinarily include sta-tistics on accidents and fatalities for helicopter per-sonnel 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 offshorefacilities.

Injury Rates

Available data indicate that offshore injury rateshave declined in recent years (see figure 4-2). IADCfigures show the accident rate for offshore drillinghas been declining since 1976 equaling a reductionof over 60 percent. However, the IADC reportedan increase in the incidence of injuries for the first9 months of 1984 as compared with 1983. Over-all, offshore drilling injury rates are comparable tothose in the mining sector and are less than onshoredrilling injury rates (see table 4-5).

Using a 72-hour reporting standard and endingwith 1981, Coast Guard data show a similar trendfor the offshore industry since 1978. According tothe Coast Guard, over 80 percent of OCS injuriesare caused by human factors, rather than equip-ment failure. A major cause of accidents is inex-perience: about 75 percent of the injuries occur toworkers 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


Table 4.5.–Comparable Industry Injury Rates (1983)

Injury rate perIndustry 200,000 manhours

Total private sector . . . . . . . . . . . . . . . . . 3.4Construction . . . . . . . . . . . . . . . . . . . . . . . 6.2Mining (other than oil and

gas extraction). . . . . . . . . . . . . . . . . . . . 4.4Anthracite mining . . . . . . . . . . . . . . . . . . . 6.1Total 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 ex-perience. However, some workers contend thatsome accidents listed as being caused by human er-ror are the result of unsafe management practicerather than worker carelessness. In boom periods,when operations expand, there is an influx of newworkers, and accident rates increase. In slack peri-ods, only more experienced workers are retained.

Fatality Rates

There are fewer reliable statistics on offshorefatality rates. Unlike offshore injuries, the dataavailable show no clear pattern of decline in fa-talities. Coast Guard data show the fatality rate(deaths per 210 million man-hours) for offshoredrilling fluctuating between 1976 and 1981, witha high of 226 and a low of 80. Fatality rates for theoffshore oil and gas industry as a whole fluctuatedbetween a high of 118 and a low of 54 in this timeperiod. The reliability of these statistics is unclear,as the Coast Guard lacks data on man-hoursworked. 13

The Coast Guard is seeking to establish an im-proved injury and population data collection sys-tem. One change will be the collection of data incomputer form. Perhaps the most important im-provement sought is better information on the num-ber of workers and the hours worked offshore. Thisis necessary to monitor progress towards the CoastGuard and Federal goal of decreasing injuries andfatalities. If a new permanent data collection sys-tem cannot be implemented, the Coast Guardhopes to make a comprehensive assessment of in-

jury and population data in 1988. The last statisti-cal assessment of offshore injury and fatality ratesmade by the Coast Guard was in 1982.

Consistency among data systems would aid inevaluating the effectiveness of safety measures. Areport by the Marine Board of the National Re-search Council recommended several improve-ments in the present inspection and data system,including the formation of a system that acquirescomprehensive event and exposure data; relatesevents to specific employers, locations, operations,and equipment; calculates frequency and severityrates, and analyzes trends; and permits monitor-ing of the relative safety performance of owners andemployers, locations, and activities.14

The Marine Board also concluded that a singlelead agency should be established to handle safetydata and recommended MMS in this role. MMSwas seen by the Marine Board as having a strongerpresence offshore than other agencies, and itbelieved that MMS would better integrate safetydata into day-to-day regulation. On the other hand,the Coast Guard is also a strong candidate sinceit has the bulk of the offshore personnel safety-related responsibilities.

Safety Regulation

Offshore Regulatory Structure

Under the OCS Lands Act and its regulations,private industry is responsible for ensuring thesafety of offshore operations:

Each holder of a lease or permit under the Actshall ensure that all places of employment withinthe lease area or within the area covered by thepermit on the OCS are maintained in compliancewith workplace safety and health regulations ofthis part, and, in addition, free from recognizedhazards . . . . Persons responsible for actual oper-ations, including owners, operators, contractors,and subcontractors, shall ensure that those oper-ations subject to their control are conducted incompliance with workplace safety and health reg-ulations of this part and, in addition, free fromrecognized hazards. 15

IJTestimony of Thomm Tutwiler, Hearing before the Subcommitteeon Panama Canal/Outer Continental Shelf of the Committee on theMerchant Marine and Fisheries, House of Representatives (June 16,1983)

14Marine Bored, Safety In fomnation and Management on the OuterContinental Shc4f (Washington, DC: National Academy Press, 1984).

1533 CFR Sections 142. l(a) (b).


Private industry responsibility for safety is gov-erned by a complex regulatory structure. Depend-ing on where they are located, offshore facilities areaffected by several sets of mandatory and volun-tary authorities and standards. These includeinternational agreements and conventions, flag na-tion standards, coastal nation standards, and non-governmental organizations.

The International Maritime Organization(IMO), whose membership includes most of theworld’s maritime nations, sets standards on marinesafety, pollution, and navigation. IMO memberstates have adopted many of these standards as min-imum requirements, supplementing IMO stand-ards as deemed necessary with their own regula-tions. The International Labor Organization alsohas recommended safety standards in consultationwith IMO. Among other related actions, IMO haspublished a Code for the Construction and Equip-ment of mobile drilling units (1979) and a conven-tion on Safety of Life at Sea (SOLAS) (1974), whichcontain man y safety recommendations. RecentSOLAS lifesaving requirements include provisionof above-water means of escape from enclosedlifeboats in case of flooded capsizings, lifeboat re-lease mechanisms that permit both on-load and off-load releases, and requirements for training on useof all survival equipment, including life rafts.16

The nation under whose flag a given mobiledrilling unit is registered has its own set of regula-tory authorities governing design, construction, andoperation of rigs and their equipment. The nationoff whose coasts a rig is operating may have juris-diction over aspects of operation. In addition, stateor provincial governments may have additionalstandards.

Nongovernmental organizations such as theAmerican Bureau of Shipping (ABS) conduct de-sign and construction review and surveys for ships,rigs, and other marine equipment. Most insuranceunderwriters require classification by societies suchas ABS before they will insure a ship or rig. TheCoast Guard accepts certain ABS inspections in lieuof direct Coast Guard inspection. Other U.S. pri-vate organizations with notable roles include theIADC, 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 Petro-leum Institute, which publishes standards and rec-ommended practices for facility and componentdesign, construction, and operation, as well as per-sonnel training; the Underwriters’ Laboratories,which performs classification and testing for suchthings as fire protection systems; and the Ameri-can Society of Mechanical Engineers, which pub-lishes industry codes for piping and pressure vessels.

Federal Safety Responsibilities

The OCS Lands Act gives primary offshoresafety responsibilities to the Coast Guard andMMS. The Coast Guard is the lead agency for per-sonnel protection, and enforces most regulationscontrolling workplace safety. MMS enforces reg-ulations bearing on safety as part of its responsibilityfor the regulation of drilling and production. Boththe Coast Guard and MMS have responsibilitiesfor reviewing the design and construction of facil-ities. MMS also evaluates installation of fixed fa-cilities to ensure that they are in compliance withplans and that no significant damage has occurredduring installation.

Both agencies have regulations covering train-ing, drills, and emergency procedures on offshorefacilities. Each agency has provisions for conduct-ing scheduled and unannounced inspections to en-sure compliance. The Coast Guard is normally thelead 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. MMSis the lead agency for cases of fires and explosions,pollution, and failure of or damage to fixed facil-ities. For incidents where they do not have leadagency responsibility, each agency participates inany investigation that bears on its jurisdiction.

Other agencies with offshore safety roles includethe Occupational Safety and Health Administra-tion (OSHA) and National Institute of Occupa-tional Safety and Health (NIOSH). Memorandaof Agreement have been signed between agenciesdelineating jurisdictions. The Memorandum of Un-derstanding between the Minerals ManagementService and the Coast Guard gives authority forregulating specific operations dealing with drillingto MMS, and other aspects of OCS operations tothe Coast Guard.


COAST GUARD

Coast Guard regulations deal with hazardousworking conditions offshore and apply to the per-formance of safety-related equipment and drills forpersonnel for the evacuation of facilities. The CoastGuard reviews and approves design, construction,alteration and repair for vessels, rigs, and floatingfacilities. The Coast Guard also regulates the safetyof commercial diving operations.

The Coast Guard is in the process of modifyingsafety standards for mobile offshore drilling units,fixed structures, and mobile well servicing units.For mobile offshore drilling units, revisions are be-ing considered regarding ballast control, fire pro-tection, and lifeboat and life raft launching underadverse conditions. One proposal would requirethat a mandatory safety briefing be given to eacharrival on board. Other regulatory changes underconsideration would apply to fixed as well as mobilefacilities.

Other possible changes include: 1) expandingregulations to more specifically cover support units,such as specialized vessels used for standby, supply,and well servicing; 2) expanding workplace safetyrules, including personal protective equipment, andguarding of openings; 3) clarifying division ofresponsibility with OSHA; 4) updating evacuationand firefighting standards; 5) clarifying best andsafest technologies (BAST) regulations; and 6) clari-fying training requirements.

The Coast Guard also conducts research to im-prove prevention of offshore work-related injuryand illness. Investigations are being conducted onsuch things as improving the seakeeping charac-teristics of mobile offshore drilling units. Currentresearch contracts include investigation of ballastsystems, tension leg platform design and service-ability, and methods for evacuation of Arctic drill-ing units.

MINERALS MANAGEMENT SERVICE

MMS, the lead offshore Federal agency, has thepower to halt operations or even cancel a lease ifit determines that such operations constitute a suf-ficient hazard. MMS issues OCS Orders for eachregion that cover such things as well control, pro-duction safety systems, pollution prevention andcontrol, and structural safety. Lessees have to show

compliance with the orders to obtain permits to drilland produce.

MMS conducts technical reviews and approvesdesign, fabrication, and installation of all fixed OCSfacilities. For floating facilities, MMS has approvalof the design and fabrication by the Coast Guard.MMS also conducts inspections of facilities to checkfor compliance with regulations and is the leadagency for the investigation of accidents involvingfires, blowouts, and explosions. MMS regulationis done primarily through working with the oper-ator/lessee rather than with contractors or sub-contractors.

During inspections, MMS technicians monitortesting of drilling safety equipment, check to seethat required equipment is in place, and reviewrecords to verify that periodic tests have been per-formed. Violations can be punished with a warn-ing 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 facil-ity depends whether it is fixed on the seafloor orfloating. Some facilities may require both CoastGuard and MMS approval, due to their change incharacter from being a floating facility while in tran-sit to the site to being fixed when on site. The ten-sion leg platform is even more complex. The sur-face portion and the legs are approved by the CoastGuard while the ocean floor foundation is theresponsibility of MMS.

MMS design verification and fabrication inspec-tion are largely conducted by approved third-partyverifiers who, while paid for by the constructionor operating company, verify to the responsibleagency that the facility meets regulatory require-ments, An inspection of fixed structures during orimmediately after construction or installation is apart of the third-party verification system. Post-installation underwater inspections are not requiredin subsequent years, but may be needed, particu-larly in frontier areas.

Post-installation inspection requirements of thelegs or the underwater portion of the floating struc-ture of the tension leg platform have not been deter-


mined. However, other floating structures certifiedby the Coast Guard such as mobile drilling unitsand ships generally undergo a regular docking forinspection. MMS announced its intention in 1980to develop requirements for periodic structural in-spection of fixed offshore facilities.

As new concepts evolve, certification respon-sibilities may change and certification proceduresmay be blurred. For example, ocean sub-sea com-pletion systems and future ocean floor productionfacilities may require different arrangements. Thegovernment’s regulatory role in the inspection ofunderwater portions of the structure during the lifeof the structure is now limited,. The governmentdoes require structural integrity data from indus-try after a platform has been installed and is sub-jected to a major event, such as a storm or colli-sion. As structures become more complex and arelocated in deepwater or Arctic areas, inspectiontechniques must also become more sophisticated.Government-sponsored research may be necessaryto enhance Federal inspection capabilities for thefuture.

OTHER FEDERAL AGENCIES

The Memorandum of Understanding betweenOSHA and the Coast Guard states that the Occupa-tional Safety and Health Act (which is enforced byOSHA) applies to offshore working conditions, but‘ ‘does not apply to working conditions with respectto which the Coast Guard or other Federal agen-cies exercise statutory authority to prescribe or en-force standards affecting occupational safety andhealth.” OSHA enforces standards in State watersout to the 3-mile limit (out to 9 miles for Texas andFlorida), except in California and Alaska, whichadminister federally approved safety and health pro-grams. OSHA does not conduct separate offshoreinspections. If Coast Guard inspectors detect viola-tions of OSHA standards in the course of inspec-tions, they notify OSHA. The two agencies haveagreed to coordinate activities and exchange datain areas where they may overlap. OSHA turns overto the Coast Guard all worker safety and healthcomplaints, while Coast Guard makes available toOSHA the results of Coast Guard accident inves-tigations. OSHA is proceeding with rulemaking toimprove workplace standards for onshore oil drillingand servicing, which could be useful to offshoreoperations.

Other Federal agencies with lesser roles includeNIOSH, U.S. Department of Health and HumanServices; and BLS of the U.S. Department of La-bor. NIOSH does research related to preventingwork-related injury and illness. They have spon-sored research on diving hazards and on identify-ing injury causal factors on drill rigs. They haverecently released recommendations for protectingworkers on land-based drill rigs which may partlyapply to offshore drilling operations. The BLS isresponsible for collecting and reporting statistics forwork-related injury and illness.

Arctic Search and Rescue

Offshore development in the Arctic presentsspecial safety problems. Ice, extreme cold, occa-sional white-outs and fog, and possibly, long dis-tances from human settlements, make evacuationdifficult. It is uncertain how evacuation will be con-ducted from rigs surrounded by ice. Conventionallifeboats and land capsules cannot be used. For thenear future at least, helicopters, suitable fixed-wingaircraft, and/or icebreaking ships will have to bemaintained by private or Federal sources. Becauseof lack of Federal resources, it is likely that offshoredevelopers will have primary responsibility for theirown rescue efforts.

The Coast Guard is the lead Federal search andrescue agency in maritime regions. It coordinatesits efforts with those of other Federal agencies, espe-cially the Department of Defense, and with Stateand local governments and the private sector.17 Inaddition, the Coast Guard reimburses fuel expensesfor the Coast Guard Auxiliary, a volunteer orga-nization that performs about one-fifth of CoastGuard search and rescue missions. The Air Forceis lead agency for search and rescue in land areasand is frequently called on for maritime search andrescue. The Air Force also operates the MissionControl Center at Scott Air Force Base, Illinois,through which Search and Rescue Satellite AidedTracking (SARSAT) rescues are coordinated.Many rescues have been made through the CivilAir Patrol and Coast Guard responding to SAR-SAT information,

SARSAT is a search and rescue packagemounted on one NOAA polar orbiting meteorolog-

17u, S, coast Guard, “National Search and Rescue Plan” ( 1981).


ical satellite. Three Soviet cosmos satellites in theCOSPAS system also have search and rescue sen-sors. Eventually, the system will probably consistof two U.S. and two Soviet satellites. As of Decem-ber 1984, over 300 people have been rescued as aresult of COSPAS-SARSAT in the brief period oftime in which these satellites have been in opera-tion. About half of these people were U.S. citizens.

SARSAT detects emergency signals from smallinexpensive transmitters activated on ships, aircraft,and other vessels in distress. SARSAT offers manyadvantages, especially in remote areas such as theArctic, where ship and aircraft passages are infre-quent and they may not be found when in distress.Locating vessels is much faster if they are equippedwith SARSAT transmitters. However, the Admin-

istration has proposed placing SARSAT aboardLANDSAT or another satellite and its future is un-certain.

Some deficiencies have been identified in CoastGuard capabilities to carry out search and rescuemissions. Problems include age of vessels, lack ofadequate maintenance, lack of training of person-nel, excessive overtime required of personnel, andproblems in retaining experienced personnel. Per-sonnel policies that have increased the concentra-tion of Coast Guard officers in desk jobs and de-creased rotation have been criticized as lesseningthe amount of experience officers would otherwisegain in search and rescue.18

1 eCO~greSS]on~ Rewarch sen,i~e, ‘‘The U.S. Coast Guard (Mar.1, 1982).


There has been little demand for Arctic searchand rescue, due to the lack of commercial andrecreational activities in the region. It is reason-able to assume that given expansion of Arctic off-shore activities, incidents requiring some search andrescue operations will increase.

However, Coast Guard search and rescue capa-bilities are constrained in the Arctic. All CoastGuard units in the 17th District are located far fromArctic offshore areas—the closest unit is a smallLORAN station at Port Clarence, about 400 milesfrom Barrow-and all of the major units are on theother side of the State. The ice-strengthened vesselsstationed in Alaska are designed for light ice con-ditions. No unit has icebreakers capable of tran-siting ice 3 feet and greater in depth, as would beessential for search and rescue during most of theyear in northern Alaskan waters. The nearest suchvessel, the Polar Sea, is in the Arctic approximately5 months out of the year (February through Apriland September through November). At othertimes, it is based in Seattle, Washington, severaldays voyage from offshore Arctic sites.19

Due to the distance of Coast Guard stations fromArctic operations, lack of permanently stationedicebreakers, and lack of icebreakers capable ofwinter-round operations, current Coast Guard Arc-tic search and rescue efforts depend largely on airoperations out of Kodiak, Alaska. Air operationsare limited by darkness and weather conditions.

The Coast Guard currently has no plans to estab-lish a more permanent Arctic presence, and manysearch and rescue tasks in the Arctic will be per-formed by industry itself rather than by the CoastGuard. Industry vessels and helicopters positionedin northern Alaska will have swifter response timesthan Coast Guard units. Several industry heli-copters are already available at Prudhoe Bay. TheCoast Guard will coordinate search and rescue ef-forts of various entities when appropriate.

Improving Offshore Safety

There are economic incentives for the industryto prevent accidents, which can mean time lost fromoperations and money spent defending against

‘qMarine Board, ‘ ‘U.S. Capability to Support Ocean Engineeringin the Arctic” (Januar) 1984)

lawsuits. Insurance rates reflect safety records andinsurance costs can become exorbitant as a resultof bad safety records. Industry believes that moregovernment regulations are not needed to improvesafety and that the industry is already overregu -lated. The Marine Board of the National ResearchCouncil concluded that:

. . . current technology and engineering systemsnow in use on the OCS appear to provide ade-quate workplace safety . . . there is no evidencethat additional regulations regarding workplacesafety are needed for frontier areas nor that ma-jor developments in workplace safety technology

are indicated. 20

However, the Marine Board and others havepointed out possible improvements that could bemade in technologies, training, management tech-niques, and regulation to improve offshore safety.What constitutes a reasonable level of safety, andwhat costs are reasonable to reach that level, is asubjective decision. Improvements to workplacesafety are possible in at least three areas: 1 ) evacua-tion, 2) management, and 3) regulation.

Evacuation

Offshore rigs may carry several types of craft forevacuation of personnel in emergency situations.These include life boats, survival capsules (a typeof covered lifeboat designed for heavy seas), andinflatable life rafts. With the exception of life rafts,these craft are generally boarded on the rig and thenlowered into the water. While there have beenmany safe evacuations, it is often difficult to launchthese craft from offshore rigs. Factors such as highwinds, heavy seas, height above water (craft mayhave to be lowered 50 or more feet) and awkwardpositioning (rigs may be listing 10 or more degreesat the time of evacuation) make the 1aunch hazard-ous. In some cases, such as the Alexander L.Kielland and Ocean Ranger, evacuation craft havebeen battered against structures, killing and injur-ing personnel. Though all launching systems arevulnerable to weather conditions, new systems uti-lizing free-falling boats reduce launching dangersby removing personnel more swiftly and placingthem further away from rigs.21

zo~~arlne ~Oard, &fi~\, and ~f]shorr ~i], P. 1.52 I De{ Norskc \’critas, “ E~acuation of Personnel by Sea’ (.AuSust

1983), pp. 11 -]~,


Facilities surrounded by ice have special evacua-

tion problems. Different methods of evacuation

from those used on water are being investigated,including air-cushioned vehicles and vehicles usingArchimedean screw propulsion. While these sys-tems are suitable for some ice conditions, they haveproblems, including difficulty in negotiating steeppressure ridges. The Coast Guard is now testinga Norwegian free fall system, and should soon issuean approval which would allow rig owners to in-stall the system. Another system utilizing ramps todirect survival craft away from rigs is still in theconceptual stage.

Personnel can also be evacuated from offshorestructures, lifeboats and other craft, and from thewater itself by helicopter, standby vessel, or a shipdispatched from shore. Legislation has been intro-duced to require that standby vessels be stationednearby offshore facilities. Vessels not stationed inthe immediate vicinity could not arrive quickly toassist at isolated facilities, and even helicopter rescuemay take a long time, depending on the locationof facilities in distress and of the helicopters them-selves. (If standby ships are not stationed close by,they suffer the same disadvantage. The standbyship for the Ocean Ranger was 8 miles away at thetime it was radioed for assistance. ) Helicopters maynot be able to operate in severe weather conditionsand are less suitable for evacuating divers suffer-ing decompression injuries. The psychologicalreassurance brought to personnel by knowledge thata boat is nearby also may be considered.

Standby vessels are required in Norway, GreatBritain, and Canada. In the United States, standbyboats are not required by regulation but are sta-tioned voluntarily by some employers. Standbyvessels may not always be the most appropriatemeans of evacuation. For example, helicopters cantake injured people to shore more quickly than cana ship and are not impeded by sea states. In someice conditions, aircraft, icebreakers, or ice-strength-ened rescue ships would be necessary. A Norwegiangovernmental commission investigating the Alex-ander L. Kielland incident concluded that theNorweigan requirement that standby vessels be sta-tioned be abolished in favor of regulatory flex-ibility. 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 Rangersinking by the National Transportation SafetyBoard and the U.S. Coast Guard Marine Boardof Investigation recommended that the CoastGuard require owners or operators to providestandby vessels. The Coast Guard Commandant,however, did not concur. Coast Guard regulatoryrevisions will rule on standby vessels. 23

The safety of evacuation methods might be bestadvanced through performance requirements.Without specifying a system, employers could berequired to provide adequate means to evacuatepersonnel within a certain time. Performance stand-ards have the advantage of increasing the flexibilityof employers in meeting requirements. The CoastGuard plans to increase use of performance stand-ards in several areas, using industry standards asa guideline.

Even if rescue ships or helicopters arrive swiftly,they may not be able to recover personnel withoutspecialized equipment. In the case of the OceanRanger, standby ships were unable to rescueanyone despite courageous attempts, mostly dueto the lack of nets, baskets, cranes, or other sys-tems which could be used to recover persons tooweak to assist themselves. Other problems discov-ered in the course of investigations of the OceanRanger incident included design limitations of thestandby ships (e. g., high freeboard), lack of train-ing and protective clothing for their personnel, andlack of facilities for treating hypothermia.

Injuries also occur in the course of transferringpeople between offshore structures and standbyboats. Usually, personnel are transferred usingbaskets or nets suspended from cranes. Extendable,flexible bridge concepts are being explored by somesources.

Management

Responsibility for safety is not always clearlydelineated on offshore rigs. A common practice hasbeen for Toolpushers (drilling supervisors) to beformally in command while rigs are anchored, whileMasters (maritime captains) are in command whilethe rig is being moved. In addition, a representa-

Ch. 4—Federal Services and Regulation Ž 113

tive of the company contracting out the unit mayhave considerable informal authority. This arrange-ment has at times resulted in confused lines ofresponsibility, especially during emergencies. Poorcoordination between the drilling unit and shore-based personnel and lack of a well-defined chainof command can slow response time, as was dem-onstrated in the Ocean Ranger incident. The CoastGuard has undertaken a review of licensing regu-lations in order to clarify rules for assignment ofresponsibility y.

In addition, safety problems and solutions oftenlie in the attitudes and actions of personnel, ratherthan equipment. Some offshore companies anddrilling contractors give safety a high priority usingthe safety records of prospective contractors as anelement in the bid selection process. Many com-panies hold safety meetings where workers can voicesafety concerns.

Training is the foundation for safety. MMS re-quires that training be given to specialized person-nel. Many offshore companies operate trainingschools or pay for employees to attend such schools.However, investigations of catastrophic offshore in-cidents have found that training of personnel, in-cluding those responsible for operating systemscrucial to the safety of others, has been inadequateon some rigs. For example, no one on board theOcean Ranger had more than a rudimentary un-derstanding of the ballast control system, and therewere no trained lifeboat crews.

Among other applicable regulations, the CoastGuard requires that emergency drills be held at leastonce each month on manned offshore facilities. Formobile drilling units, a boat drill is required at leastonce each week in which all personnel report to theirstations and demonstrate their ability to performtheir assigned duties, and weather permitting, atleast one lifeboat is partially lowered and its enginestarted and operated. Each lifeboat is to be loweredto water, launched, and operated at least once every3 months. There are, however, no requirementsthat Federal inspectors witness and evaluate theadequacy of evacuation drills on OCS facilities.

According to some observers, drills are not heldaccording to this schedule or are pro forma exer-cises on some rigs, held only to meet minimum reg-ulatory requirements. Similarly, personnel have re-

ported that they have not been informed of theiremergency assignments even though posting of suchinformation is required. Periods of large turnoverof personnel on rigs increase the difficulty of estab-lishing a high degree of proficiency (e. g., throughteamwork) in safety-related tasks. The MarineBoard has recommended that Federal regulationsinclude mechanisms that promote more active com-pany attention to safety, such as pubic visibility andaccountability, safety performance standards, andpersonnel standards.

Regulation

Despite the great number and variety of regula-tory requirements bearing on offshore safety, thereare no specific requirements that employers sub-mit safety plans that aim at an integrated assess-ment of the adequacy of safety measures, such asdrills, evacuation plans, and lines of responsibility.There are existing requirements that bear on plan-ning, but there is no separate rig-by-rig review thatlooks at all of the components of technology andmanagement practices that are involved in offshoresafety.

Regulations mandate scheduled inspections of allfacilities at least once a year, supplemented by anunspecified number of periodic, unannounced in-spections. These are performed by the Coast Guardand MMS. A drilling technician inspects rigs onan average of once a month after drilling begins.If a violation is found, sanctions range from a warn-ing, with 1 week given to correct the deficiency,to shutdown of the piece of equipment, the well,or the entire operation. Also, an investigation isconducted following any accident, and notices aresent to all lessees and operators describing incidents,apparent causes, and actions taken by operators toprevent a recurrence. Civil and criminal penaltiesare provided for infractions of requirements.

However, the Ocean Ranger disaster pointed outimportant deficiencies in Coast Guard inspectionprocedures. After the initial inspection in Decem-ber 1979, no subsequent formal inspections of theOcean Ranger were carried out, aside from onebrief visit from an official. Although its certifica-tion had expired in December 1981, no reinspec-tion was made up to the time of the February 1982sinking. Although the Coast Guard directed that


the lifeboats and life rafts on the Ocean Ranger bereplaced within 2 years, no replacements were madeand no effort was made by the Coast Guard toascertain whether its directive had been carried out.In addition, the rig was not manned according torequirements of its inspection and cargo ship safetyequipment certificates.

In general, the Coast Guard relied on the clas-sification given to the Ocean Ranger by the Amer-ican Bureau of Shipping (ABS) as proof of designadequacy, and the Coast Guard did not independ-ently assess such things as the capability of theballast pumping system. ABS ratings focus on cer-tification of structure, machinery, and equipment,and do not cover personnel competence, training,or safety management practices.24

The Coast Guard has had difficulty in carryingout the required number of inspections on fixedplatforms due to funding limitations.25 It is unclearhow the Coast Guard will handle inspections shouldactivities be significantly expanded in Arctic re-gions. Currently, Coast Guard inspection resourcesare concentrated in the Gulf of Mexico, and asidefrom several small LORAN stations, all CoastGuard installations in Alaska are located in south-ern portions of the State, many hundreds of milesaway from frontier areas.

Z4Roy~ Comission on the ocean Ranger Marine Disaster, Re-port One: The Loss of the Semisubmersible Drill Rig Ocean Rangerand 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 ScrippsInstitute of Oceanogmphy, June 1983), p. 54,

Inspection alternatives considered by the CoastGuard include relinquishing some scheduled inspec-tions to MMS, the lessee, or to a third-party.However, the Coast Guard would continue unan-nounced inspections on a small percentage of fa-cilities, and worker complaints could trigger otherinspections. The main disadvantage of self-certi-fication is the possibility that inspections would beless strict, thereby lowering safety. Third-party in-spection analogous to current third-party verifica-tion of design and construction would be preferablein this regard, if such firms were held to strict stand-ards. An issue to be resolved is who would bearthe cost of third-party inspections. Industry cur-rently pays for third-party verification.

Whether safety levels can indeed be maintainedor increased within the Coast Guard’s budgetaryconstraints is uncertain. The Coast Guard believesthat savings resulting from delegating inspectionswill enable it to concentrate resources on the rigswith poor records. Improved data collection isessential to this goal, however.

OSHA does not conduct its own offshore inspec-tions. OSHA’s position is that if the Coast Guardexercised authority over workplace safety andhealth, OSHA authority is superseded. However,the Coast Guard does not have detailed workplacesafety rules, and it is unclear which, if any, OSHArules apply. The Coast Guard has a regulatory proj-ect to develop more detailed Coast Guard work-place safety standards. Review is also needed ofrespective OSHA and Coast Guard responsibilities.

Chapter 5

Economic Factors

Contents

Page

Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Costs of Offshore Exploration and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117Exploration Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118Development and Operating Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118Transportation Costs.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 118Lead-Times to Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 119

Profitability of Offshore Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120Economic Rent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 120Minimum Economic Field Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Government Lease and Tax Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123Fixed Royalties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123Other Lease Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Prices and Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124Market Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124Alaskan Oil Markets: Export of Alaskan Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124Alaskan Natural Gas Markets: Alaskan Natural Gas Transportation System . . . . . . . . . . . . . . . . 126


5-1. Comparative Offshore Exploration and Development Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . 1195-2. Profitability of Offshore Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122


5-1. Corporate Cash Flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1205-2. Profitability of Offshore Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1225-3. Alternative Lease Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1235-4. Flow of Alaskan Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1255-5. The Alaska Natural Gas Transportation System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 127

Chapter 5

Economic Factors

OVERVIEW

Exploration and development of oil and gas re-sources in the Arctic and deepwater frontiers de-pend largely on potential profitability. Economicincentives are needed for industry to develop thetechnology for resource development in the fron-tiers. Factors which influence project profitabilityinclude costs, timeframes, prices, markets, and gov-ernment lease and tax payments. In general, highercosts and longer lead-times to production tend tolower profit margins in offshore frontier areas. Asa result, the sensitivity of project economics tochanges in various factors is higher in frontier areasthan in mature producing regions such as nearshoreGulf of Mexico.

OTA has analyzed the economic attractivenessof oil and gas development in offshore frontier re-gions. Using a computer simulation model, cashflow profiles were developed for different types ofoffshore fields based on the technical scenarios pre-sented in chapter 3. Ten hypothetical fields are dis-cussed, consisting of representative large and smallfields in nearshorc Gulf of Mexico, California deep-water, and three Alaskan basins. The estimates ofcosts, timeframes, and other variablcs used in themodel are only approximations of those which maybe encountered with actual projects in these offshoreareas. The’ results of the simulations do not repre-sent the actual economics of prospects. They areused principally to illustrate how changes in eco-nomic factors can affect the profitability of oil andgas development in different offshore regions.

Remoteness, difficult operating conditions, andhigh engineering costs are characteristic of frontierareas. Extremely large oil and gas discoveries areneeded to offset the high costs and long timeframesof exploration and development. Small fields maynot yield adequate profits to justify development.The OTA analysis shows that while a 40- to 50-million barrel field may be profitable in the Gulfof Mexico, in the Alaskan offshore it may take adiscovery of 1 to 2 billion barrels of recoverable re-serves to make a project profitable.

Government lease and tax payments affect theprofitability of offshore fields differently in the fron-tiers than in other leasing areas. The OTA com-puter simulation indicates that leasing systemsbased on alternative types of lease payments ratherthan fixed royalties may increase the profits andreduce some of the risks associated with frontier-area fields. In general, the profitability’ of oil andgas development in offshore frontier areas will beincreased by real oil and gas price increases. In theAlaskan regions, the availability of economic mar-ket outlets for oil and gas—the development of ex-port markets for Alaskan oil and the developmentof processing and transportation systems forAlaskan natural gas—could improve the economicprofile of offshore fields.

COSTS OF OFFSHORE EXPLORATION ANDDEVELOPMENT

Harsh environments and difficult operating con- frontier regions. Costs are important determinantsditions, greatly increase the costs of’ oil and gas ex - of the economic feasibility of producing oil and gasploration and development in Arctic and deepwater in offshore areas. In general, offshore exploration

117


and development costs are influenced by the oceanenvironment (e. g., waves, ice, currents), waterdepth, field size and flow, proximity to support andtransportation infrastructure, and elapsed time toproduction start up. Long lead-times to first pro-duction also add to the risks and uncertainty offrontier-area oil and gas activities.

The major categories of project costs—explora-tion costs, development costs, operating costs, andtransportation costs—have been estimated forhypothetical small and large fields in five offshoreregions (see table 5-l). These estimates are basedon costs included in the National Petroleum Coun-cil study of U.S. Arctic Oil and Gas and othersources, and have been escalated to 1984 dollarequivalents. 1 hey are not exact figures, but areintended to be indicative of relative cost ranges indifferent offshore regions. More precise cost esti-mates can only be derived if and when a discoveryis delineated and a production system is designedfor a specific site and set of operating conditions.

Exploration Costs

Exploration costs include the cost of the drillingrig, logistical support, exploration wells, and de-lineation wells. They do not include the lease bonuspayment. In this analysis, it is assumed that thewildcat exploratory success rate is 1 in 10 and thateach successful discovery includes the cost of drilling10 exploratory wells. In addition, it is assumed thatfive appraisal or delineation wells are drilled intoeach oilfield before development begins, except inthe nearshore Gulf of Mexico where only three aredrilled. Additional delineation wells are needed forfrontier-area fields to justify the high costs of de-velopment.

Ocean environment and water depth account formost of the variation in exploration costs owing torequirements for specially designed drilling equip-ment in hostile environments and to operating con-ditions that may cause delays. Total explorationcosts are generally independent of field size. Theaverage cost of drilling exploratory and appraisal

‘National Petroleum Council, U.S. Arctic Oil and Gas (Decem-ber 1981); Dames and Moore, GMDI and Belmar Engineering, DeepWater Petroleum Exploration and Development in the California OCS,Report prepared for the Minerals Management Service (January1984).

wells in the more conventional Gulf of Mexico leas-ing area is estimated at $6 million per well. In com-parison, single exploratory wells are estimated tocost an average of $27 million in the Californiadeepwater scenario and $55 million in the NavarinBasin of offshore Alaska. In this analysis, the totalcosts of an exploration program are estimated at$78 million in nearshore Gulf of Mexico as com-pared to $825 million in the Navarin Basin.

Development and Operating Costs

Development costs include the cost of the drillingplatforms or islands and the development wells. Inmost regions, platforms and facilities account for65 to 70 percent of total development costs. Thesecosts vary not only with the harshness of the oper-ating environment and water depth, but also withfield size. In this analysis, it is assumed that thereare no economies of scale associated with platformconstruction or development drilling, except in thenearshore Gulf of Mexico scenario. There are econ-omies of scale associated with operating costs. Oper-ating costs are calculated on an average annual basisand include labor, repair and maintenance, fuel,power, water, and other support functions.

Development costs for a 50-million barrel oil fieldin 400 feet of water in the Gulf of Mexico are esti-mated at $168 million, including platform costs of$112 million and drilling costs of $56 million. Thesecosts escalate quickly with the depth of water andthe severity of ice, wind, and wave conditions. Totaldevelopment costs for a 300-million barrel field inCalifornia deepwater (3,300 feet) are estimated at$900 million. Development costs for a 2-billion bar-rel field in Alaska’s Harrison Bay, which has severeice conditions, are estimated at $6.3 billion, andin the Navarin Basin, with its greater water depthand harsher wind and wave conditions, at over $11billion. Operating costs range from $10 to $25 mil-lion per year in the more temperate and accessibleGulf 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 availabilityof 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 Productiondepth size cost cost cost cost lead-times

Area (feet) (mmb) ($ million) ($ million) ($ mill/yr) ($/bbl) (years)

Gulf of MexicoSmall field . . . . . . . . . . . . 400 15Large field . . . . . . . . . . . . 400 50

Cal. DeepwaterSmall field . . . . . . . . . . . . 3300 150Large field . . . . . . . . . . . . 3300 300

Norton BasinSmall field . . . . . . . . . . . . 50 250Large field . . . . . . . . . . . . 50 500

Harrison BaySmall field . . . . . . . . . . . . 50 1000Large field . . . . . . . . . . . . 50 2000

Navarin BasinSmall field . . . . . . . . . . . . 450 1000Large field . . . . . . . . . . . . 450 2000

7878

105168

712

$0.00$0.00

22

1624

$2.50$2.00

1010

400400

450900

435435

10382076

72102

$6.50$5.00

89

$12.50$10.00

1212

720720

31626324

120168

825825

546010920

132240

$6.50$5.00

1111

NOTE Costs refer to total, undiscounted outlays, in 1984 dollars.

SOURCE. Office of Technology Assessment.

of the operating environment. In this analysis, thesecosts are calculated on a per-barrel basis and includethe cost of transporting oil from the production fa-cility to the nearest U.S. market. Transportationcosts include pipelines, tankers, and transshipmentterminals. The costs of transporting oil to marketsvaries greatly among regions, but decreases withlarger field sizes in all regions due to economies ofscale.

Because of the availability of transportation sys-tems and processing facilities in nearshore Gulf ofMexico and the ability to share pipelines, trans-portation costs are assumed to be absorbed in de-velopment costs in the Gulf fields. Transportationcosts are estimated at $2 to $2.50 per barrel in thedeepwater California area, where it is assumed thatsubsea pipelines are layed in extremely deep waterto the West Coast. In the Norton and NavarinBasins of Alaska, where systems involve icebreak-ing tankers and transshipment terminals for trans-port 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 andto southern transshipment terminals through theTrans-Alaskan Pipeline System (TAPS), is assumedto have a transportation cost per barrel of $10 to$12. The transportation costs for the California andAlaskan scenarios could be reduced by shared orcommon 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 explora-tion and development in offshore frontier regionsthan in traditional areas. In the nearshore Gulf ofMexico scenarios, first production is assumed tooccur 2 years after the lease sale. In contrast, inthe California deepwater and Alaskan scenarios,first production does not begin until a minimumof 8 to 12 years after the lease sale. These schedulesmay underestimate the actual timeframes of activ-ity in frontier regions, because they assume mini-

38-749 0 - 85 - 5


mum time for obtaining necessary government ap-provals. The analysis also assumes that platformdesign will commence at the time of the discoveryand proceed concurrently with the approvalprocess.

For example, it is assumed in the Harrison Bayscenario that 5 to 6 years elapse between the timethe lease is acquired and the time when a discov-ery is made (see figure 5-1). It takes another 5 to6 years before permits are obtained and produc-tion facilities are designed and constructed. It istherefore a minimum of 12 years before the com-pany sees a return on a sizable investment and thediscovery contributes to cash flow. Peak produc-tion of 500,000 barrels per day occurs in the thirdyear after beginning production. The total life ofthe field is 27 years from first production.

Figure 5-1.—Corporate Cash FlowHarrison Bay — Large Field

Peak productionI

-4 I 1 I I3 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 forinvestments in offshore oil and gas exploration anddevelopment. In general, investments depend onfinding suffcient recoverable reserves of marketableoil and/or gas to justify costs. In this analysis, theeconomic returns to industry and government fromoffshore oil and gas development are estimated bya computer simulation model (see box). This modelcalculates the net present value of all expendituresand revenues associated with the 10 hypotheticalfields. By discounting these cash flows to thepresent, the analysis accounts for the time valueof money and lost opportunities for alternative in-vestments. The model includes a number of as-sumptions regarding prevailing economic condi-tions and the investment and production schedulesassociated with each oil field. It incorporates all rele-vant tax and leasing policies.

Economic Rent

The analysis of the net present value of in-vestments has implications for the profitability ofalternative investments and for the bidding be-havior of firms for offshore leases. The net presentvalue of offshore oil and gas development repre-sents the profits available after a firm has received

its normal return to capital, assumed in this anal-ysis to be 10 percent per year. These profits arereferred to as ‘‘excess profits’ or ‘ ‘economic rent.A firm’s estimate of its share of the economic rentwould be the upper limit to the amount it wouldbe willing to bid as a bonus payment for the rightto explore and develop an offshore tract. High com-petition in a lease sale might lead a firm to bid allof its economic rent as the bonus, leaving it witha normal return on its investment. If the estimateof a firm’s economic rent is negative, this indicatesthat a firm may not make a normal return on theinvestment.

The Federal Government receives its share of theeconomic rent from a field in the form of taxes, in-cluding corporate income taxes and windfall prof-its taxes, and lease payments such as productionroyalties. The tax and leasing system selected bythe government is intended to extract economic rentfrom offshore fields without destroying corporateincentives to undertake the required investments.In designing lease and tax payments, the govern-ment must balance the need to obtain fair marketvalue for offshore leases with the need to providethe necessary incentives for development.

The calculation of the net present value of the10 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 economicsof 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 fieldsin the Gulf of Mexico, deepwater California, and three Alaskan regions), the model calculates the net presentvalue of industry and government revenues based on prescribed parameters. Some of these parameterscan 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 table5-1. The simulation of each oil field is deterministic and follows field-specific investment and productionschedules. The estimated costs and schedules are intended to be representative of actual conditions thatoil companies may encounter in the offshore basins under consideration.

Other model inputs are financial parameters which describe the general economic environment in whichexploration and development take place. Fiscal parameters incorporate applicable governmenttax and leasingregulations. The sensitivity of field economics to changes in prices, leasing systems, or taxes can be assessedby altering these parameters. The financial and fiscal parameters given below are those used in the basecase model simulations.

Base Case Financial Parameters:Crude oil market price, mid-1984 ($ per barrel) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $29.00Growth rate of real oil price (annual) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . O percentGeneral inflation rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 percentCorporate discount rate (real terms) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 percentProject financing (debt/equity) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 percent

Base Case Fiscal Parameters:Production royalties (fixed) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12% percentRental fees (per acre) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3.00Corporate 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 intangibledrilling 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 assoon 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 drywildcat 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 developedrent (see table 5-2). However, the government takesmore than its share of the economic rent from twoof these fields-the small fields in the Gulf of Mex-ico and in the high-cost Navarin Basin. In this anal-ysis, Government payments include a royalty rateof 12½ percent and corporate income taxes on thedeepwater and Arctic fields. Windfall profits taxes,which should expire by the time frontier-area fieldsbegin production, are levied only on the near shoreGulf of Mexico fields. In addition, the Gulf of Mex-ico fields are assessed the traditional royalty rateof 16% percent. The fields which show a negative

under the assumed cost, price, and leasing con-ditions.

Minimum Economic Field Size

In high-cost offshore regions, very large field sizesare needed to offset exploration and developmentcosts and still yield a normal return on investment.The amount of recoverable reserves needed to yielda normal economic return after subtracting costsand government payments is termed ‘ ‘minimumeconomic field size. In the offshore frontier areas,


Table 5-2.—Profitability of Offshore Development(from base runs of OTA computer simulation)*

Water Field Governmentdepth size Net present value ($ million) share

Area (feet) (mmb) Total Corporate Government (percent)

Gulf of MexicoSmall field . . . . . . 400 15 62.9 -0.6 63.5 101Large field . . . . . . 400 50 563.0 211.9 351.1 62

Cal. DeepwaterSmall field . . . . . . 3300 150 223.2 28.2 195.0 87Large field . . . . . . 3300 300 807.2 264.1 543.1 67

Norton BasinSmall field . . . . . . 50 250 261.9 7.6 254.3 97Large field . . . . . . 50 500 978.0 264.4 713.6 73

Harrison BaySmall field . . . . . . 50 1000 735.2 81.8 653.4 89Large field . . . . . . 50 2000 2989.4 955.8 2033.6 68

Navarin BasinSmall field . . . . . . 450 1000 780.6 -149.9 930.5 119Large field . . . . . . 450 2000 2176.5 121.2 2055.3 94

.Government payments include 12½ percent royalties and corporate income taxes on frontier fields; 162/3 percent royaltiescorporate income taxes, and windfall profits taxes on nearshore Gulf of Mexico fields.


Figure 5.2.—Profitability of Offshore DevelopmentSmall and Large Fields

3.0

2.8

2.6

2.4

2.2

2.0

c— 1.0

0.8

0.6

0.40.2

0.0-0.2

Net present value

Corporate

Government

Corporate & government

Gulf California Norton Harrison Navarin

far greater reserves are needed to yield profitableinvestments because of the greater costs and longerperiod of time over which these costs must be car-ried before repayment begins.

The analysis shows that reserves of approx-imately 40 to 50 million barrels of oil would sup-port development in 400 feet of water in the Gulfof Mexico. However, a 100- to 150-million barrelfield must be discovered to justify development costsin a deepwater environment, as in the Californiascenario, In the Alaskan offshore scenarios, mini-mum economic field sizes are as great as 250 to 500million barrels of oil. In the difficult operating con-ditions of the Navarin Basin, even the l-billion bar-rel field may not be profitable for a company to de-velop (see figure 5-2).

SOURCE: Off Ice of Technology Assessment


GOVERNMENT LEASE

The combination of lease payments and taxeslevied on offshore fields by the government affectsthe degree of profit- and risk-sharing between in-dustry and government in oil and gas development.Activities in offshore frontier areas are differentiatedby their small profit margins and their higher levelof risk and uncertainty. For this reason, govern-ment payments affect frontier-area fields differentlythan those in other leasing areas.

Fixed Royalties

In addition to the initial cash bonus payment,lease payments in the United States traditionallyhave been fixed royalties based on the value of theresources produced. The royalty rate has been de-creased from the standard 162/3 percent (one-sixth)to 12½ percent (one-eighth) in offshore frontierareas to improve the economics of resource devel-opment. Fixed royalties are levied on gross incomeand are counted as an addition to development costsin analyzing the potential profitability of projects.With fixed royalties, there is no allowance for suchfactors as field size, production costs, and lead-timesto production when taking the government’s shareof the economic rent. In offshore frontier areas,where costs are higher and lead-times longer, fixedroyalties may overtax fields and remove the eco-nomic incentive for development.

In general, royalty rates can alter productiondecisions on small or marginal fields, which in fron-tier areas may contain substantial resources. In theOTA analysis, the small field in the Navarin Basinis unprofitable to develop under fixed royalties,even though it is assumed to have reserves of 1 bil-lion barrels of oil (see figure 5-3).

Other Lease Payments

Alternative lease payments may be more effec-tive in promoting oil and gas development in off-shore frontier areas. Profit-shares and sliding scaleroyalties are two types of payments believed to pro-mote greater profit- and risk-sharing between in-dustry and government. Eliminating lease pay-ments would provide an even greater incentive toexploration and development in frontier areas. In

AND TAX PAYMENTS

Figure 5-3.—Alternative Lease PaymentsEffect on Marginal Fields

250

200

150

100 I

Lease payment

1/8 royalty

uNet profit share

O royalty

I I ICalifornia Norton Harrison Navarin

Corporate net present value


this case, the government would receive its shareof the economic rent through cash bonuses andtaxes.

Although there are several types of profit-sharingsystems, the United States has used a ‘‘fixed capi-tal recovery’ profit-sharing system in tests in off-shore leasing. There have been 215 tracts sold withthis type of lease payment between 1980 and 1983.Firms share at least 30 percent of their profits withthe government, but first recover their initial in-vestment and the cost of carrying that investmentfrom year to year. Cost recovery is allowed accord-ing to a set formula or ‘‘capital recovery factor.

Because the lease payment is levied on net in-come, profit-sharing systems allow for the high costs


of production in frontier areas and can provide in-centives for the development of most field sizes. Thecapital recovery factor also takes into account thelong timeframes of frontier-area projects, so thata company is not taxed too early in the life of thefield. When profit-sharing with a 200 percent cap-ital recovery factor is used as the lease payment inthe OTA simulation, the small Navarin Basin fieldbecomes profitable to develop (see figure 5-3).

The major disadvantage of profit-sharing systemsis that they are more difficult to administer thanroyalty lease payments. In the fixed capital recov-ery system, profit share rates and capital recoveryfactors must be established prior to lease sales andcalibrated to the operating conditions of differentregions. Other types of profit-sharing systems, suchas a symmetric system where the government sharesin both profits and losses, could reduce the pre-leaseanalytic burden. Symmetric profit-sharing also hassuperior risk-sharing features. However, in most

profit-sharing systems, the costs and profits asso-ciated with individual fields must be calculated andverified, thus requiring government access to in-dustry cost information. Profit-sharing systems gen-erally require more extensive recordkeeping on thepart of both the industry and government.

The advantage of sliding scale royalties is thatthey vary with production rates, and thus extracta lower payment from smaller and/or less produc-tive fields. However, the OTA analysis showed thatsliding scale royalties perform no better than fixedroyalties as neither can be set below the legal min-imum of 12½ percent. Because of the low profitmargins in frontier areas, most fields cannot beara lease payment above the minimum royalty evenat higher rates of production. A zero royalty or asliding scale royalty which slides down to zero maybe appropriate to high-cost frontier regions. A zeroroyalty makes the deepwater and Arctic fields farmore profitable to develop (see figure 5-3).

PRICES AND MARKETS

Market Prices

Current and anticipated market prices are im-portant incentives to exploration and developmentactivities. Crude oil prices can have a major im-pact on the profitability of offshore frontier fields,particularly small or marginal fields, Fields whichare uneconomic under current market conditionsmay be profitable given an increase in real crudeoil prices. Similarly, decreases in real prices canremove the economic incentive to develop offshoreresources. Present predictions are for real oil pricesto decline in the short term and rise in the longterm. Investments made now in oil and gas proj-ects will be based on long-term views of energy mar-kets, real price trends, and technological devel-opments.

It is assumed in the OTA base case modelsimulations that there is no increase in the real priceof oil, and that any associated natural gas is notproduced because of low market prices or lack ofavailable markets. According to the OTA analy-sis, a 1-percent increase in the real price of oil could

substantially increaseas net present value)

corporate returns (measuredfor the oil field scenarios in

offshore frontier areas. The previously unprofitableNavarin Basin field in Alaska becomes economicto develop with the real price increase. Higher oilprices, however, simply change the size of the mar-ginal fields rather than eliminate them.

Alaskan Oil Markets: Exportof Alaskan Oil

Restrictions on the export of Alaskan oil can re-sult in increased costs of transporting offshore oilto U.S. consuming markets and reduce the profit-ability of Alaskan offshore fields. The Prudhoe Bayfield, discovered on Alaska’s North Slope in 1968,contains 10 billion barrels of oil reserves and is thelargest single source of oil in the United States. Inthe 1970s, concern about dependence on foreignoil imports prompted Congress to enact a series oflaws placing restrictions on the export of oil pro-duced on Alaska’s North Slope and in offshoreareas. The Alaskan oil export restrictions of the

Ch. 5—Economic Factors • 125

Export Administration Act of 1979 expired in Feb-ruary 1984. Currently, export of Alaskan oil is be-ing restricted by other statutes.

About half of the oil now produced on the NorthSlope is shipped to California and West Coast mar-kets, and the remainder is transported through thePanama Canal or the Trans-Panama Pipeline toU.S. markets on the Gulf Coast and Atlanticseaboard. Removing the ban on Alaskan oil exportsto allow shipment to Asian markets could reducethe transportation costs of the producers, if theseforeign markets could be developed. However, thiscould have negative impacts on the U.S. maritimeindustry now engaged in the Alaskan oil trade andon overall U.S. energy import requirements.

The cost of transporting Alaskan oil to the GulfCoast is high because of the long distance and therequirement under the Merchant Marine Act of1920 (the Jones Act) that this oil be carried in U.S.flag tankers. It is estimated that it costs $4.20 perbarrel to ship oil from Alaska to the Gulf Coast inU.S. flag tankers as compared to a cost of $0.90per barrel for shipment to Japan in U.S. flagtankers and $0.50 per barrel for shipment to Ja-pan in foreign flag tankers2 (see figure 5-4). A trans-

2Stephcn Eule and S Fred Singer, ‘‘Export of Alaskan Oil andGas, ‘‘ in ~ree Market Energy, S. Fred Singer (ed. ) (New York: Uni-verse Books, 1984), p. 123.

portation cost savings from exporting Alaskan oilto closer markets could increase the wellhead pricereceived for oil produced from onshore and offshorefields.3 The higher profits, which would be distrib-uted among the producers and Federal and Stategovernments, may have effects similar to a priceincrease in improving the development prospectsof marginal fields.

The North Slope tanker trade to the Gulf Coastcurrently engages approximately 40 percent of theships in the U.S. tanker fleet and 65 percent of theU.S. shipping capacity. The U.S. Maritime Ad-ministration estimates that the loss from eliminat-ing this trade would be 68 ships and over 4,000 jobs,and that it might also jeopardize $600 million inoutstanding Federal loan guarantees on the tank-ers.4 Many North Slope oil producers have in-vestments in tanker capacity and also are am-bivalent about exporting oil to markets outside theUnited States.

Small tankers needed by the Department of De-fense in times of emergency could be displaced byremoving 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 AlaskanNorth 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)


tankers used in the North Slope oil trade have po-tential military use because of their small size (lessthan 80,000 deadweight tons) which permits themto haul products into foreign harbors. It is estimatedthat removing the Alaskan oil export ban wouldeliminate about 13 percent of the supply of tankersavailable to the military for defense needs.5 In ad-dition, it would be difficult to ship Alaskan oil do-mestically in the event of a national emergency ifthis idle transportation capacity were eliminated.

Although exporting Alaskan oil to Japan couldsubstantially improve the U.S. trade deficit withthat country, it would somewhat increase the U.S.overall dependence on oil imports. Substitute oilfor U.S. refineries could be imported partly fromnearby sources such as Mexico and Venezuela, buta share also may be imported from Middle East-ern countries. This would decrease overall U.S.energy security, which the Alaskan oil export banis designed to increase. In addition, severe eco-nomic losses would be suffered by Panama, whichwould lose revenues from the transit of Alaskan oilthrough the Panama Canal and the Trans-PanamaPipeline.

. ..— — —5Congressional Research Service, <‘Exports of Domestic Crude Oil’

(Dec. 8, 1983), p. 7,

In the short-term, Japan is constrained in its needfor U.S. oil by world energy surpluses and contrac-tual commitments to other suppliers.6 However,in the long term, Japan might benefit from accessto a secure source of oil and might be more recep-tive to importing oil from Alaska. In addition, newoil reserves for throughput of the Trans-Alaskanpipeline will be needed as Prudhoe Bay productionbegins its decline in the late 1980s. Lifting the oilexport ban for offshore fields, which probably willnot come on stream until the mid-1990s or later,could provide an incentive to exploring and devel-oping costly Arctic areas and new reserves for thepipeline.

Alaskan Natural Gas Markets:Alaskan Natural Gas

Transportation System

A system for transporting Alaskan natural gasto U.S. consuming markets could also increase theprofitability of Alaskan offshore fields. Planning andfinancing of the Alaskan Natural Gas Transporta-

“’Japan Doesn’t Want Alaskan Oil Anyway,’ Business Week (Mar.12, 1984), p. 25.


tion System (ANGTS), the pipeline system in-tended to transport Alaskan natural gas to the lower48 States, is currently on hold. Alternative proc-essing and transportation systems have been pro-posed, but have the same cost and financing prob-lems as the ANGTS.

Construction of the Alaskan segment of the pipe-line has been postponed until economic and energymarket conditions allow project financing. TheANGTS is designed as a 4,800-mile pipeline net-work carrying natural gas from Alaska’s NorthSlope to the U.S. West Coast and the Midwest.

Plans were made for the construction of theANGTS during the domestic energy shortages andsharp oil price increases of the mid-1970s. How-ever, by the time ANGTS plans were completedin 1981, there were energy surpluses and depressedprices. The only sections of the pipeline which havebeen completed are the Eastern and Western legstransporting natural gas from Calgary, Canada, tothe U.S. West Coast and Midwest (see figure 5-5).

The potential high market price of Alaskan gasand associated marketing problems have been themain 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 CanadianNatural Gas Imports.

SanFrancisco

h

SOURCE Off Ice of the Federal Inspector, Alaska Natural Gas Transportation System, Washington, D C


the ANGTS. Current cost estimates of finishing theANGTS are $40 to $50 billion, with the Alaskansegment alone estimated at $25 to $30 billion.7 Thetariff which would be charged to cover the costs ofbuilding the pipeline makes the projected price ofAlaskan gas uncompetitive in its designated mar-kets, in the short term. Estimates of the deliveredprice of Alaskan gas in 1989-90 are about $7.50per thousand cubic feet, above the projected priceof about $6.00 per thousand cubic feet for lower48 gas in 1990.6

7Stephen Eule and S. Fred Singer, ‘‘Export of Alaskan Oil andGas, ” (New York: Universe Books, 1984), p. 140.

*General Accounting Office, “Issues Facing the Future Use ofAlaskan North Slope Natural Gas” (Washington, DC, 1983), pp.16-19.

Alternative proposals to ANGTS include usingAlaskan natural gas as raw material for a petro-chemical facility or a methanol industry, or con-verting it to liquefied natural gas (LNG) for exportto Japan. However, depressed world energy prices,marketing problems, limitations on Alaskan gas ex-ports, and government commitments to ANGTSmake these proposals unlikely alternatives to thepipeline system. A substantial increase in real gasprices may make the ANGTS or another Alaskannatural gas project economically feasible. A mar-ket outlet could be provided for natural gas nowbeing produced, and reinfected, on Alaska’s NorthSlope. In addition, the availability of natural gasprocessing and transportation infrastructure couldimprove the profitability of Alaskan offshore oil andgas development projects.

Chapter 6

Federal Leasing Policies

Contents

Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Rate and Extent of Offshore Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131Background ....... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131Area-Wide Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

The Role of the Coastal States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139Special State/Federal Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142Congressional Leasing Moratoria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

Military Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Disputed International Boundaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148Areas of Potential Dispute . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148Dispute Settlement Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Leasing Policies for Offshore Frontier Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154Bidding Systems.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154Lease Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158Tract Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159Joint Bidding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159


6-1. Five-Year OCS Leasing Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1336-2. State Role in Offshore Oil and Gas Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1416-3. Advantages and Disadvantages of Alternative Bidding Systems . . . . . . . . . . . . . . . . . . . . . . . . 155

FIGURESFigure No. Page’

6-1. Gulf of Mexico Bidding by Water Depth. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1376-2. Trends in Gulf of Mexico Average Bids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1386-3. Deferrals of Offshore Acreage for Military Uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1466-4. U.S.-Canada Boundary in Georges Bank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1496-5. U.S.-Canada Boundary in Beaufort Sea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1506-6. U.S.-U.S.S.R. Boundary in Bering Sea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1526-7. Gulf of Mexico Boundaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Chapter 6

Federal Leasing Policies

OVERVIEW

The Federal Government is the largest singleowner of energy resource lands in the United States.It controls approximately 730 million acres on-shore— mostly in western States—and nearly 1.9billion acres in the offshore U.S. Exclusive Eco-nomic Zone (EEZ). Industry access to the vast gov-ernment landholdings for oil and gas developmentis essential to meeting the country’s future energyneeds. However, energy development on Federallands must be balanced with other land uses andwith protection of the environment.

Federal leasing of offshore areas for oil and gasdevelopment is conducted under the Outer Conti-nental Shelf (OCS) Lands Act of 1953, as amendedin 1978. The 1978 amendments to the Act requirethat offshore leasing balance expeditious energy de-velopment with the interests of the coastal Statesand environmental concerns. The first Federal off-shore lease sale was held in the Central Gulf ofMexico in October 1954. Leasing in the more hos-tile environments of the Arctic began in 1979 andin the deepwater areas of the lower 48 States in1981.

At the same time that leasing in offshore fron-tier areas was growing, the rate of leasing wasgreatly accelerated. In the 1980s, the Departmentof the Interior implemented a system of ‘area-wideleasing, expanding the offshore acreage consid-ered for each lease sale. Interior also increased thenumber of lease sales held each year, Opposition

to the accelerated leasing schedule from coastalStates, environmental groups, and others resultedin several delays to the lease schedule and somemodification of the area-wide leasing approach.

Delays in the leasing schedule also resulted fromthe continuing dispute between the coastal Statesand the Federal Government over the appropriatedivision of power and revenues in offshore leasing.Although the controversies have primarily con-cerned issues in nearshore leasing—means of mit-igating adverse effects on coastal areas and meth-ods of dividing revenues from oil and gas basinscrossing State/Federal boundaries—they have cre-ated uncertainty in frontier-area leasing as well.The extent of leasing in offshore frontier areas hasalso been constrained by deferrals of offshore acre-age for military uses and controversies regardinginternational boundaries.

Some changes have been made in Federal leas-ing policy in recognition of the increased costs andrisks of oil and gas development in offshore fron-tier areas. The primary lease term has been ex-tended from 5 to 10 years and royalties have beenlowered for most frontier areas. However, addi-tional changes may be needed in bidding systems,the size of the lease tracts, and other leasing termsand conditions to provide the incentive for com-prehensive exploration and development of theenergy resources of Arctic and deepwater frontiers.

RATE AND EXTENT OF OFFSHORE LEASING

Background dustry had been developing oil and gas resourcesoffshore for many years prior to that under State

Federal leasing of offshore areas for oil and gas leases and permits. Offshore oil was first produceddevelopment began soon after the passage of the from piers off Summerland, California in 1896. TheOCS Lands Act of 1953,1 but the petroleum in- States of Louisiana, California, and Texas began

leasing in the 1920s. The first Federal offshore leasesale 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


The OCS Lands Act of 1953 provided the basicpolicy for the development of offshore oil and gasresources under Federal jurisdiction. It authorizedthe Department of the Interior to lease these areasto private persons for development, and it estab-lished general guidelines for managing the leasingprocess and post-lease activities. In 1969, an oil wellblowout in the Santa Barbara Channel off Califor-nia increased public awareness of the environmentalrisks of offshore leasing. This concern was coupledwith greater uncertainty about future U.S. energysupplies after the Arab oil embargo of 1973. In1974, Congress began to amend the 1953 Act to ad-dress these concerns, which culminated in the enact-ment of the OCS Lands Act Amendments of 1978.2

The 1978 Amendments made fundamental andsomewhat controversial changes in offshore leas-ing policy. The Amendments opened up the deci-sionmaking process for offshore leasing to give af-fected parties—primarily the coastal States—theopportunity for greater involvement. Stricter cri-teria and standards were included in considerationof environmental factors and competing land uses.New emphasis was placed on the public revenuefrom OCS development and the receipt of fair mar-ket value for oil and gas resources. From 1978 on,Federal offshore leasing for oil and gas developmenthad to balance energy policy goals with State, envi-ronmental, and revenue considerations.

In addition, the OCS Lands Act Amendmentsintroduced the requirement for a 5-year scheduleof proposed lease sales.3 The June 1979 leasingschedule, which was revised in June 1980, was thefirst prepared in accordance with the requirement.This schedule increased the number of sales to beheld in frontier areas; approximately one-half ofthe sales were scheduled for Alaskan and deepwaterregions. In October 1981, however, the U.S. Courtof Appeals ruled that the leasing program did notmeet the requirements of Section 18 of the OCSLands Act Amendments and remanded the pro-gram to the Secretary of the Interior for revision.

A 5-year leasing program drafted by the new Sec-retary of the Interior, James Watt, in mid-1981 didsubsequently withstand the legal challenge for ade-quacy.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 dramaticincreases in the acreage to be offered and leasedin an effort to increase domestic energy production.Approximately one billion acres of Federal offshorelands were to be offered for lease in the 5-yearperiod. This was far more than the 50 million acresoffered for lease in the entire period from October1954 through June 1982. Under the new conceptof ‘area-wide leasing, the acreage offered was in-creased from a previous average of 1 to 2 millionacres per sale to 20 to 50 million acres per sale. Inaddition, the leasing schedule itself was acceleratedto an average of eight sales per year, compared toan average of five sales per year in the previous 5-year period.

Most of the land to be leased under the 1982-87schedule was in the frontier areas. Out of a totalof 41 lease sales, there would be 16 offerings offAlaska, 12 in the Gulf of Mexico, 8 off the Atlan-tic Coast, 4 off California, and one reoffering sale.Several new Alaskan offshore areas would beopened to leasing for the first time. In total, over56 percent of the acreage to be offered was off theAlaskan coast and another 20 percent was in thedeepwater areas of the Gulf of Mexico, the Atlan-tic, and the Pacific.

Early opposition to the 1982-87 accelerated leas-ing program caused a number of delays in its im-plementation. Of the 21 lease sales scheduledthrough the end of 1984, only seven were held onthe originally scheduled date. Opponents, mostlycoastal States and environmental groups, chal-lenged several sales with litigation on the basis ofalleged violation of the requirements of the OCSLands Act Amendments, the Coastal Zone Man-agement Act, and relevant environmental laws. Inaddition to that opposition, Congress delayed salesby prohibiting the use of appropriated Interior De-partment funds for leasing and development of spe-cific OCS basins in the Pacific, Atlantic, and Gulfof Mexico. However, of the lease sales scheduledfor 1982-84, all but four—the two Georges Banksales in the North Atlantic and two Alaskan sales—had been held by the end of 1984,

In 1983 and 1984, record amounts of OCS acre-age were offered and leased. For the first time, sub-stantial acreage was leased in Alaska-in the DiapirField, and the Navarin, Norton and St. GeorgeBasins—and in the deepwater areas off the lower

Ch. 6—Federal Leasing Policies . 133

48 States. In the Gulf of Mexico area-wide leasesales of 1983-84, more than 26 percent of the tractsleased were in water depths beyond 2,000 feet and18 percent in water depths beyond 3,900 feet. Priorto 1983, leasing in water depths beyond 2,000 feetrarely exceeded 5 percent of the total acreage. Sim-ilarly, new deepwater acreage was leased in theAtlantic and Pacific regions.

In January 1984, the new Secretary of the In-terior, William Clark, announced his intention todecrease the acreage considered for leasing under

the 1982-87 leasing schedule because of State andenvironmental concerns. However, Secretary Clarkcontinued to support the general concept of area-wide leasing, particularly in the Gulf of Mexico.A revised leasing schedule issued in October 1984indicated that the six Gulf of Mexico area-wide leasesales to be held between May 1985 and April 1987would take place as scheduled (see table 6- 1). Sev-eral of the remaining Alaskan, California, andAtlantic sales, however, were delayed and somewere reduced in acreage. Despite these modifica-tions to the leasing schedule, the magnitude and

Table 6-1 .—Five-Year OCS Leasing Schedule (8/82-6/87)

Schedule dateRegion Sale # Location Original Current

AT, CA, AKRe-offering . . . . . . . . . . . . . . . . . . .

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-2715269-169-257707672787473798082838187848889

85929811110291100949596107104971059910110810911086

Diapir FieldGeorges BankTexas, LAMS, AL, FLNorton BasinSt. George BasinMid-AtlanticCentral GulfSouth AtlanticWestern GulfCentral CAEastern GulfSouthern CANorth AtlanticNavarinCentral GulfDiapir FieldWestern GulfGulf/Cook InletSt. George BasinSouth AtlanticBarrow ArchN. Aleutian BasinCentral GulfMid-AtlanticWestern GulfCent/North CANorton BasinEastern GulfSouthern CANorth AtlanticNavarin BasinCentral GulfDiapir FieldWestern GulfKodiakSt. George BasinSouth AtlanticBarrow ArchCentral GulfShumagin

Aug 1982Sept 1982Oct 1982Oct 1982Oct 1982Nov 1982Feb 1983Apr 1983May 1983JuIy 1983Aug 1983Sept 1983Nov 1983Jan 1984Feb 1984Mar 1984Apr 1984June 1984JuIy 1984Oct 1984Dec 1984Jan 1985Feb 1985Apr 1985May 1985June 1985Aug 1985Sept 1985Oct 1985Nov 1985Jan 1986Feb 1986Mar 1986Apr 1986June 1986JuIy 1986Oct 1986Dec 1986Jan 1987Feb 1987Apr 1987June 1987

As scheduledOct 1982PostponedNov 1982Mar 1983Mar 1983Apr 1983As scheduledAs scheduledAs scheduledAs scheduledDec 1983Jan 1984Oct 1984PostponedApr 1984As scheduledAug 1984As scheduledPostponedSept 1985PostponedPostponedDec 1985As scheduledOct 1985As scheduledDec 1987Dec 1985As scheduledApr 1987Nov 1987Sept 1986As scheduledDec 1966As scheduledPostponedJuly 1988July 1989May 1987As scheduledDec 1987

SOURCE: Minerals Management Service, 1985.


pace of OCS lease sales, still set at seven to eightper year, remain significantly greater than previ-ous schedules.

The Department of the Interior is now solicitingcomments from industry, coastal States and otherinterested parties on a new 5-year OCS LeasingProgram for the period mid-1986 through mid-1991. The overlap between the two schedules in1986/87 is intended to provide a transition periodfrom one program to the next. Eleven sales have

been carried over from the previous 5-year leasingschedule (see box).5

The new 5-year leasing schedule proposes a totalof 43 sales: 33 standard sales, 5 frontier explora-tion sales, and 5 supplemental sales. The frontierexploration sales are scheduled for areas of Alaskawhere resource assessment is incomplete and in-

5Department of the Interior News Release, ‘‘Secretary Hodel Re-leases Draft Proposed OCS Oil and Gas Program, (Mar. 21, 1985).

Proposed Five-Year OCS Leasing Schedule (7/86-6/91)

Region sale # Location Proposed dateGulf of Mexico . . . . . . . . . . . . . . . . . . . . . 105 Western Gulf July 1988

Supplemental 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Aug. 1986Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 Navarin Basin Sept. 1988Alaska ● . . . . . . . . . . . . . . . . . . . . . . . . . . . . Beaufort Sea Dec. 1988Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 Southern California Apr. 1987Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . 110 Central Gulf Apr. 1987Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Chukohl Sea May 1987Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1987

Supplemental 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Aug. 1987Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96 North Atlantic Nov. 1987Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86 Shumagin Dec. 1987Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91 Northern California Dec. 1987Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1988Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gulf of Alaska Mar. 1988Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Eastern Gulf May 1988Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 St. George Basin July 1988Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1988

Supplemental 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Aug. 1888Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mid-Atlantic Oct. 1988Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . North Aleutian Basin Dec. 1088Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1989Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Norton Basin Mar. 1989Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Central California May 1989Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108 South Atlantic July 1989Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1889

Supplemental 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1989Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Navarin Basin Sept. 1989Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Beaufort Sea Dec. 1989Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1990Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chukchi Sea Mar. 1990Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Southern California Apr. 1990Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . June 1990Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Western Gulf Aug. 1990

Supplemental 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aug. 1990Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shumagin Sept. 1990Atlantic . . . . . . . . . . . . . . . . . . . . . . . . . . . . North Atlantic Oct. 1990Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Northern CaliforniaAlaska*

Dec. 1990. . . . . . . . . . . . . . . . . . . . . . . . . . . . Kodiak Jan. 1991

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Central Gulf Feb. 1991Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . St. George Basin Apr. 1991Pacific . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Washington-Oregon Apr. 1901Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . Eastern Gulf May 1991Alaska* . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 presalestep, a Request for Interest, will be used prior tothese sales to determine if industry interest war-rants holding the sales. The supplemental sales willbe held in August of each year for selected drain-age, development, and/or rejected bid blocks out-side the Central and Western Gulf of Mexico.

Annual lease sales will still be held in the twomost prospective areas: the Central and WesternGulf of Mexico. Outside of these areas, the paceof leasing will be slowed from one sale every 2 yearsto one sale every 3 years. In addition, a ‘‘flexibilityprovision” has been added to allow the pace of leas-ing to be adjusted to economic conditions. Salesin certain areas (Northern, Central, and SouthernCalifornia; Eastern Gulf of Mexico; Navarin Basin;Beaufort Sea; North Aleutian Basin; and St.George Basin) may be accelerated if changes in oilprices or new geologic data warrant.

Area- Wide Leasing

The area-wide leasing system made fundamen-tal changes in the lease tract offering process. Priorto 1983, under what is called the ‘ ‘tract nomina-tion’ sale system, the Department of the Interioroffered a limited number of specific tracts for leas-ing based on the geological prospects for oil andgas as interpreted by the government. Between thefirst offering of offshore leases under the OCSLands Act Amendments in February 1979 and thebeginning of the area-wide sale system in April1983, about 23 million acres were offered forleasing.

Under area-wide leasing, the Department of theInterior offers an entire lease sale planning area forleasing. Tracts may be selected from every unleasedtract and from tracts where the leases have expired.Recommendations are still made by the States andother Federal agencies for exlusion of tracts fromthe sale. But under this system, industry is per-mitted to choose where its investments in explora-tion will be made without being double-guessed bythe Department of the Interior.

About 546 million acres have been consideredby the industry in the 11 area-wide lease sales heldthrough the end of 1984. This is actually an over-estimate, because it includes blocks previously sold

as well as double-counting for 35 million acres of-fered twice in the Gulf of Mexico. About 63 per-cent of this or 346 million acres was actually of-fered for leasing in the area-wide sales. Of this,industry leased 13 million acres. Based on thesenumbers, area-wide leasing is a misnomer. The sys-tem should more accurately be called ‘ ‘area-wideconsideration or ‘‘area-wide selection.

In theory, area-wide leasing was adopted to pro-vide the industry an opportunity for early selectionof tracts which offer the best prospects for discov-ery of oil and gas. In operation, it also has resultedin an increased rate of leasing. Industry faulted thetract nomination system because the Departmentof the Interior made its own determinations of re-source potential and often failed to include manyof the tracts nominated by industry. However,critics of the area-wide system maintain that a re-turn to a nomination system where the Departmentof the Interior assures that industry nomination willbe honored would allow sufficient freedom of tractselection.

Under revised area-wide leasing procedures an-nounced by Secretary of the Interior William Clarkin January 1984, firms make specific recommen-dations on selected tracts at the call for informa-tion stage (the initial phase of the leasing process).Secretary Clark requested that the industry targetthose tracts in which they are seriously interestedand reduce ‘‘scenery’ selections (those intendedto mask bidding strategy). In this way, environ-mental assessment can be focused on specific areasof interest to the industry. Better information canalso be provided to State and local governments andenvironmental groups early in the area identifica-tion process so that they may prepare for the laterconsultation phase.

Secretary of the Interior Don Hodel adopted amodified area-wide leasing system for use duringthe 1986-91 5-year leasing schedule. Althoughessentially the same as the Clark system, it is herecalled the ‘ ‘focused approach’ intended to focuslease offerings on promising acreage.

Both the industry and the Department of the In-terior defend the concept of area-wide leasing,noting that the United Kingdom and Canada havesuccessfully used this approach for offshore leasingfor a number of years. From the standpoint of tech-


nology development, the industry also asserts thatexpensive offshore technologies will only be devel-oped and financed if the industry has profitableleases.

The shift from tract nomination to area-wideleasing has raised opposition from some coastalStates and environmental groups, which allege thatarea-wide leasing is nothing more than a “fire sale’and giveaway of the Nation’s resources and, be-cause of the magnitude of the sales, a threat to theocean and coastal environments. The industry,however, defends the integrity of the area-wide ap-proach in terms of efficient resource development,fair value received for Federal leases, and environ-mental protection. The Minerals ManagementService (MMS) also denies that the environmentis receiving any less attention under the area-wideleasing system than under the tract nomination ap-proach.

The area-wide leasing debate has focused largelyon the Gulf of Mexico. About 70 percent of theacreage offered under the area-wide system throughJanuary 1985 has been in that region. Less atten-tion has been given to the potential impact and ef-fectiveness of area-wide leasing in deepwater andArctic frontier regions because of limited experi-ence with leasing in these areas. The Gulf of Mex-ico, being a mature producing region where thegeology and petroleum prospects may be estimatedmore accurately, is considerably different fromfrontier regions where little or no production hasoccurred and where each new well is considered awildcat. Analysis of the results of area-wide leas-ing in the frontier areas is difficult because few area-wide sales have been held in these regions.

Those critical of area-wide leasing have em-phasized two aspects of public policy: 1) receipt offair market value for government-owned resources;and 2) environmental implications of an accel-erated, broad-based leasing program.

Fair Market Value Concerns

The OCS Lands Act Amendments of 1978 re-quire that the government receive fair market valuefor offshore leases, although no precise definitionof fair market value is given. Controversy has re-sulted from the fact that the average bonus bid peracre has declined under the area-wide system, and

that fair market value may not be received for leasesunder area-wide offerings. The average bid per acreunder the tract nomination system between 1979and 1983 was $2,388. Since the beginning of area-wide leasing in 1983, bonus bids have averagedabout $529 per acre.

The debate over the receipt of fair market valueunder area-wide leasing has centered on economicanalyses done by National Economic ResearchAssociates, Inc. (NERA) for the State of Texas insupport of the State’s discussions with the Depart-ment of the Interior over disposition of escrowmoney from Federal/State tracts in the Gulf ofMexico.6 NERA’s analysis attributed the reducedbonus bids received in area-wide lease sales in theGulf of Mexico to several factors:

●

●

o

●

Supply and Demand: Based on classical eco-nomic theory of supply and demand, the moretracts offered in a lease sale, the lower the bidswill be as a result of less competition.Fixed Budgets: If firms have fixed budgets forlease acquisition, they will tend to bid loweron a larger number tracts offered in an area-wide sale than they would if fewer tracts wereoffered in a nomination sale.Bargain Hunting: If firms can acquire leasescheaply, they will be willing to accept higherrisks of dry holes.Time Value of Money: If production maybedelayed, firms will reduce their bids to offsetthe cost of discounting the investment.

The NERA study concluded that area-wideleasing will not accelerate energy production,because development is determined by theprofitability of individual leases and not therate and number of lease purchases.

In conducting its analysis, NERA also found thatwater depth had little relationship to the lower bidsreceived in the Gulf of Mexico. NERA did notundertake an analysis of data relating bids to tractdepths, but rather related bid levels to distance fromshore. Distance from shore and water depth aregenerally, but not consistently, related. By assum-

bLetter and attachments from Governor Mark White to Secretaryof the Interior William Clark (May 25, 1984) and afiidavit and ex-hibits of Jeffery J. Leitzinger, Senior Consultant, National EconomicResearch Associates, Inc.

Ch. 6—Federal Leasing Policies ● 137

ing a one-to-one relationship between distance off-shore and water depth, the NERA study may havemasked the true effects of water depth on bid levels.An OTA analysis of bonus bids and water depthin five area-wide leases sales in the Gulf of Mexicosuggests that a trend relationship may exist betweenlower bonus bids and leases in water depths of 600feet and greater (see figure 6- 1). Bids in deepwaterfrontier areas may be lower as a result of the in-creased risks and higher costs associated with ex-ploration and development of oil and gas.

The lower bids in the Gulf of Mexico area-widelease sales may also be due to a number of otherfactors. These include pessimism over future oilprices; the failure of the industry to find oil andgas in highly prospective areas of the Atlantic andPacific; the fact that the leased tracts in the Gulfof Mexico had been ‘ ‘picked over’ previously; andthe increase in the minimum bid from $25 to $250per acre by the Department of the Interior.7 In ad-

7Nat ionat Ocean Industries, Area-Wide Leasing: Nationaf Boonor Industry Boondoggle?, (Washington, DC: 1984).

dition, it has been pointed out that the downwardtrend in bids in the Gulf of Mexico actually beganunder the tract nomination system in 1980 and con-tinued under the area-wide system (see figure 6-2).

In general, fair market value is a difficult con-cept to define. The U.S. Court of Appeals upheldthe accelerated leasing program of the Departmentof the Interior, noting that the law does not requirethe maximization of revenues, only the receipt ofa fair return for Federal leases. The Departmentof the Interior points out that bonus payments rep-resent only about one-fourth of the revenues re-ceived from offshore oil and gas leases and thus arenot the only consideration in assessing fair marketvalue. Federal payments are also received in theform of taxes, royalties, and rentals.

Environmental Concerns

Environmental concerns related to area-wideleasing focus on the inability of the States and theFederal Government to evaluate potential environ-mental impacts from offshore development in lease

Figure 6-1 .–Gulf of Mexico Bidding by Water Depth

20

18

16

14

6

4

2

00

●

. High bonus bidsin Gulf of Mexicoarea-wide sales

Water depth (thousand feet)



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 dif-ficult for State and local governments to plan forand assess the impacts of OCS development underarea-wide leasing because of the extent of the areaconsidered and the uncertainty of which portionswill be offered for sale. In addition, environmentalgroups assert that general statements of environ-mental impacts are not useful, and detailed analy-ses of vast areas that will not be leased is wasteful.8

The Department of the Interior stresses that pre-lease and post-lease environmental regulations andState and local consultation are the same underarea-wide leasing as under the tract nomination sys-tem. The steps and procedures required by law toidentify, assess, and disclose possible environmental

8Department of the Interior, Final Supplement [o the F’ina/ En vi-ronmental Statement, Vol. 2, Comments from Industry and PublicInterest 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 gasdevelopment are being followed. The industrybelieves that environmental assessments under area-wide leasing are better. Consideration of largerareas may lead to a broader knowledge of geo-hazards, marine biology, physical oceanography,and environmental baselines.

Environmental information, however, is but onefactor considered by the Secretary of the Interiorin a leasing decision. Environmental interests arguethat mere pro forma adherence to legal require-ments is not sufficient. Environmental informationshould also be adequately considered by the Sec-retary in the decision process. Environmentalistsmaintain that the Secretary of the Interior is notassigning appropriate weight to environmental risksin balancing OCS oil and gas development withpossibilities of environmental harm.


THE ROLE OF THE COASTAL STATES

Background

Ownership of offshore oil and gas resources hasbeen the source of major disagreements betweenthe Federal Government and the coastal States fornearly 50 years. Realizing the extent of the petro-leum wealth that lay below the seabed off theirshores, California, Louisiana and Texas beganasserting their rights of ownership to the submergedlands as early as 1937. The spat between the Statesand the Federal Government over offshore petro-leum resources became known as the “TidelandsIssue. This issue figured prominently in the pol-itics of that era and influenced Federal-State rela-tionships for nearly two decades. Even today, thestruggle continues over the appropriate balance ofpower, authority, and revenue entitlements thatcoastal States should exercise over resources in theFederal portion of the Continental Shelf.

Prior to 1945, the seabed resources beyond theinternationally recognized 3-mile Territorial Seawere not owned by any nation or individual inaccordance with customary international law at thattime. On September 28, 1945, President Harry STruman by Executive Proclamation declared thatthe United States has exclusive control and juris-diction over the natural resources of the seabed andsubsoil of the Continental Shelf adjacent to theUnited States. g This unilateral claim to the re-sources of the Continental Shelf was not recognizedunder international law until it was ratified by theFirst Law of the Sea Conference held in Genevain 1958. The Convention on the Continental Shelfrecognized that a coastal nation ‘ ‘exercises over theContinental Shelf sovereign rights for the purposeof exploring it and exploiting its natural re-souces.” 10

Between President Truman’s proclamation in1945 and international recognition of coastal na-tions’ authority in 1958, intense disputes arose be-tween the coastal States and the Federal Govern-ment over who had the authority to regulatedevelopment and who would benefit from the richpetroleum 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 ownershipand control of the resources of the Continental Shelfcame in 1947 when the United States SupremeCourt in U.S. v. State of California decided thatthe Federal Government and not California had“paramount rights” and power over the 3-mileTerritorial Sea (recognized by international law atthat time), including full dominion over the re-sources of the submerged lands.11 In subsequentsuits filed by Louisiana, Texas, and Florida theCourt applied the same legal principle and awardedjurisdiction over the submerged lands to the Fed-eral Government. The Court allowed some ex-tended State claims in the Gulf of Mexico becauseof the special conditions under which Florida andTexas were admitted to the Union .12

Although the coastal States’ legal challenge forcontrol of offshore petroleum resources failed, a po-litical assault in the Congress paid off. In 1953,Congress enacted the Submerged Lands Act, whicheffectively reversed the Supreme Court’s decisionin U.S. v. State of California by conveying all rightsthat the Federal Government claimed in the near-shore submerged lands to the coastal States.13 Itgave the States the title and ownership of thesubmerged lands and natural resources seaward oftheir coasts out to 3 nautical miles. With the con-tentious issue of State claims to the ContinentalShelf resolved, the Congress simultaneously enactedthe OCS Lands Act of 1953, which established Fed-eral leasing authority in the OCS seaward of theState-controlled zone.

However, the conflict between the coastal Statesand the Federal Government over oil and gas be-neath the seabed did not abate with the enactmentof the Submerged Lands Act and the OCS LandsAct. Disagreements continued over drainage of oilfrom reservoirs beneath adjacent Federal and Stateproperties, and the apportionment of revenues fromoil in disputed areas. As the pace of offshore oil andgas development increased under the leasing pro-cedures 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.


their concerns over the adverse environmental andsocial impacts that could result from operations offtheir shores.

In response to concerns that unplanned devel-opment of the coastal region could lead to irrepar-able environmental damage, the Congress enactedthe Coastal Zone Management Act (CZMA) in1972. The CZMA authorized Federal grants to

coastal States as incentives to establish coastal zonemanagement plans. Once a State coastal zone man-agement plan is approved by the Secretary ofCommerce, all Federal actions within the coastalzone, or which ‘ ‘directly affect’ the coastal zone,are required to be conducted in ‘‘a manner whichis, to the maximum extent practicable, consistentwith approved State management programs. Inthe past, coastal States have asserted that the actof offering offshore leases ‘‘directly affects’ thecoastal zone and that leases should be subject toa determination of consistency with the adjacentState’s coastal zone management program. How-ever, in 1984, the United States Supreme Courtin Secretary of the Interior v. California held thatOCS oil and gas lease sales per se are not Federalactivities “d irect ly” affecting the coastal zonewithin the meaning of the CZMA, and thereforedo not require State consistency determinations atthe time leases are offered.14

The CZMA was amended in 1976 to establisha Coastal Energy Impact Program (CEIP).15 TheCEIP was designed to provide States and local gov-ernments with financial assistance to meet needsresulting from energy activities in coastal regions,including the development of OCS oil and gas.Enactment of the CEIP was predicated on the beliefthat coastal States are likely to encounter greaterimpacts from energy development than inlandStates because of their geographic location with re-gard to offshore petroleum, ports for energy im-ports and exports, and electric power generatingstations which require large volumes of coolingwater. The CEIP, although scheduled to continuethrough 1986, has not been funded since 1980.

The OCS Lands Act of 1953, as amended in1978, declares it national policy that:

. . . the outer Continental Shelf is a vital nationalresource reserve held by the Federal Government

for the public, which should be made available forexpeditious and orderly development, subject toenvironmental safeguards, in a manner which isconsistent with the maintenance of competitionand other national needs; .. .16

Although the congressional statement of nationalpolicy emphasizes the importance of offshore pe-troleum reserves and acknowledges that they should‘‘be made available for expeditious and orderly de-velopment, the Act concurrently recognizes that:

. . . exploration, development, and production ofthe minerals of the outer Continental Shelf willhave significant impacts on coastal and non-coastal areas of the coastal States .. .17

The Secretary of the Interior is therefore respon-sible for balancing what are sometimes conflictingnational policies: providing for secure domesticsources of oil and gas from the OCS while at thesame time protecting environmental values andrespecting the plans, goals and objectives of sov-ereign coastal States and local governments.

In response to concerns about the potential im-pact of offshore petroleum development on thecoastal States and local communities, Congress setforth as national policy in the 1978 Amendmentsthe principles that: 1) States and local governmentsmay require Federal assistance to protect theircoastal zones; 2) States and local governments areentitled to participate in the policy and planningdecisions of the Federal Government; 3) States andlocal governments have rights and responsibilitiesto protect the environment and the population fromadverse impacts of offshore petroleum activities;and 4) the petroleum industry has the responsibilityfor ensuring the environmental and personal safetyof offshore operations.

The OCS Lands Act as amended in 1978 isunique among Federal statutes which authorizeleasing, sale or disposal of public resources. Muchmore State and public involvement in lease plan-ning and Federal licensing and permitting is man-dated in the administration of the OCS leasing pro-gram than is required for similar leasing of coal,onshore oil and gas, or other minerals on Federallands. When considered in conjunction with the re-quirements of the CZMA, the National Environ-mental Policy Act of 1969, the Federal Water Pol-

i+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.


lution Control Act as amended, and the Clean AirAct, the OCS Lands Act provides an unprece-dented opportunity for coastal State involvementin the offshore oil and gas leasing program.

The 1978 OCS Lands Act Amendments call forState and local government consultation, com-ments, or coordination at six separate points in theplanning, leasing, exploration, and production-development sequence: 1) during the formulationof the 5-year leasing program; 2) at the time of re-view of environmental impact statements regard-ing the 5-year leasing program; 3) prior to a pro-posed lease sale; 4) with regard to oil and gas thatmay straddle adjoining Federal and State proper-ties; 5) at the issuance of exploration permits; and6) during the review of production and develop-ment plans. In addition, the Secretary of the In-terior is directed to provide the necessary informa-tion to State and local governments to assist themin responding to Federal actions (see table 6-2).

At no point in a lease sale can a State absolutelyveto lease planning or sale preparation. However,States can make recommendations through the con-sultation and commenting provisions. After leasesare awarded, the coastal States have the power ofapproval of exploration and development plans,which must be consistent with their coastal zonemanagement programs. Pipelines, ports, or stor-age and transfer facilities for supporting offshoreoil and gas operations that are located within the3-mile Territorial Sea or on the shore must also con-form with a State’s coastal zone management plansand other local zoning or land use laws within thepolice powers of the State. As a condition of Fed-eral approval of a State coastal zone managementprogram, provision must be made for giving ade-quate consideration to energy developments in thenational interest of the United States.

Notwithstanding the ample provisions made inthe OCS Lands Act and the CZMA for coordina-

Table 6-2.—State Role in Offshore Oil and Gas Leasing

Subject Action Authority

Outer Continental SheIfLeasing Program

Environmental Impacts

Proposed Lease Sale

Leasing Within 3 Miles ofState’s Territorial Sea

Geological and GeophysicalExploration Plans

Production and DevelopmentPlans

OCS Oil and Gas Information

State and local governmentcomments on proposed 5-yearplan and on Secretary’s annualreview of the plan.

Comments by the State on draftenvironmental impact statementsat time of revisions in the 5-yearleasing program and at sub-mission of exploration anddevelopment and productionplans.

Coordination and consultation withState and local officials con-cerning size, timing or locationof proposed lease sale.

Consultation with regard todevelopment of shared oil pools.

Certification of consistency withState coastal zone managementplans.

Coordination and consultation withState and local officials andcertification of consistency ofproduction and developmentplans with the State coastal zonemanagement program.

Secretary directed to provideinformation on proposed plans,reports, environmental impactstatements, tract nominations,and other information, includingprivileged information in thecustody 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. 25CZMA Sec. 307(c)(3)

OCSLA Sec. 26



tion and cooperation among Federal, State andlocal governments, a number of disagreements havearisen that add to the uncertainties facing the off-shore oil and gas leasing program. These controver-sies contribute to contentious relationships betweensome coastal States and the Federal Governmentregarding offshore resource development. The fail-ure of the Executive Branch to deal with these issuesto the mutual satisfaction of the States and the Fed-eral Government has prompted the Congress toseek legislative solutions.

Special State/Federal Problems

Coastal Zone Management Consistency

Coastal States consider the lease sale as a criti-cal point in the OCS oil and gas development proc-ess. At this point, contractual obligations areassumed and property rights are conveyed to suc-cessful bidders. The States believe that the act ofleasing is the beginning of a process that inex-tricably leads to exploration, and if commercial dis-coveries are made, to production and developmentby the lessees. For this reason, the States believe,lease sales themselves should be consistent withState coastal zone management programs.

The Department of the Interior insists that theact of leasing in Federal waters is not an action that“directly affects’ the coastal zone. Only whenphysical activities, such as exploration, begin ona lease are there activities that ‘‘directly’ affect thecoastal States. Haggling over the consistency issuehas resulted in several lawsuits that have delayedleasing decisions and introduced uncertainty in theleasing process for a decade.

In January 1984, the U.S. Supreme Courtdecided the question of whether a lease sale‘ ‘directly affects” the coastal zone, and thereforewhether the Secretary of the Interior must certifythat the lease sale is consistent with an approvedState coastal zone program. The case, Secretaryof the Interior v. California’8 reversed the decisionof the 9th Circuit Court of Appeals in Californiav. Watt.19 In Secretary of the Interior v. Califor-nia, the Supreme Court concluded in a 5-4 opin-ion that lease sales are not activities ‘‘directly affect-

1~78 L. Ed, 2d. 496; 52 USLW 4063 (1984).j 9683 F. 2d. 1253 (9th Circuit, 1982).

ing the coastal zone’ within the meaning of theCZMA. The State’s position with regard to the sig-nificance of the lease sale in the exploration anddevelopment sequence was dismissed by the Courtas a policy argument that had previously been re-solved by the Congress in enacting the legislation.

Response to the Supreme Court’s decision cameswiftly in the 98th Congress. Bills were introducedin both Houses of the Congress to overrule the deci-sion, but laws have not been enacted, 20 These pro-posals would substitute the term “significantlyaffecting’ for the term “directly affecting, ” whichwas judged by the court to exclude the Federal actof leasing OCS oil and gas. By substituting the term‘ ‘significantly’ for ‘‘directly, sponsors of the billshoped to invoke the liberal interpretation of theterm ‘‘significantly’ that has been used by theCourts in interpreting the National EnvironmentalPolicy Act.

Revenue Sharing

The immense value of the oil and gas that laybelow the seabed offshore the United States hasbeen the crux of a long-term battle between the Fed-eral Government and the coastal States over con-trol of the so-called submerged lands. Although theCongress transferred ownership of the natural re-sources in coastal waters out to 3 nautical miles tothe States in 1953, the States have never taken theireyes off the Federal revenues that have beengarnered from leasing OCS oil and gas.

In the 30 years between 1953 and 1983, the Fed-eral Government has received over $68 billion fromoffshore oil and gas leases. The coastal States claimthat they are entitled to share in these proceeds be-cause State and local governments endure fiscal,social and environmental impacts which result fromincreased oil and gas activity in the OCS. CoastalStates support their arguments for revenue shar-ing by noting that inland western States with Fed-eral lands within their borders share 50 percent ofthe proceeds received by the Federal Governmentfor minerals development on such lands.21 Equity,the coastal States claim, requires that the FederalGovernment similarly share offshore revenues withStates 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.


ment contends that, on balance, OCS developmenthas a net positive effect on adjoining coastal States.

The coastal States increased their efforts to con-vince the Congress to enact an OCS revenue shar-ing bill when funding cutbacks for support of Statecoastal zone management programs were proposedat the same time that OCS oil and gas developmentwas being accelerated and the National Sea GrantCollege Program 22 was zeroed by the ReaganAdministration in fiscal year 1982. As a result, leg-islation was introduced in the 97th Congress (H.R.5543) to establish an ‘‘ocean and coastal resourcesmanagement and development fund’ to be trans-ferred to coastal States from OCS revenues. Thebill passed the House of Representatives by a 260-134 vote in the 97th Congress, but no action wastaken in the Senate.

An identical bill (H. R. 5) was introduced in the98th Congress. Similar legislation has been intro-duced in the 99th Congress. The legislative pro-posals would set aside 10 percent of the OCSrevenues in any fiscal year when revenues exceededthe amount received during fiscal year 1982 ($7.8billion). It provided a cap of $300 million as themaximum amount that could be transferred to thefund in any year. All of the coastal States border-ing on the ocean, plus those on the Great Lakes,the U.S. affiliated Caribbean Islands, Pacific TrustTerritories, and U.S. protectorates in the PacificOcean would share in the fund. Money would bedistributed from the fund as block grants.

States receiving these block grants would be re-quired to spend specific proportions of the fundsreceived for coastal zone management, mitigationof impacts from coastal energy development, andenhancement and management of living marine re-sources and other natural resources. The entitle-ment for each State would be determined by for-mulae based on the level of leasing adjacent to theState, volume of oil and gas produced from the ad-jacent OCS, proposed oil and gas lease sales to takeplace within the 5-year leasing program, coastal-related energy facilities located within each coastalState, shoreline mileage of the State, and coastalpopulation 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. 5to a fisheries program authorization bill (Title I,S. 2463) and forwarded it to the Senate. The Sen-ate rejected the House amendment which includedprovisions for ocean and coastal block grants anddecided to resolve the disagreement in ConferenceCommittee. The Senate receded from its demandsto reject the block grant proposals and agreed tothe House amendment with modifications. TheHouse agreed to the conference report on S. 2463,but consideration by the Senate was delayed untilthe waning days of the 98th Congress. During thelast days of the 98th Congress, in the face of con-certed opposition by a number of Senators, the con-ference report was still pending when Congress ad-journed.

The Administration opposed the revenue shar-ing proposals introduced in the 97th and 98th Con-gresses because of their impact on the Federalbudget; the inclusion of territories, islands andStates that would have no OCS development offtheir shores; and the earmarking of the use of theblock grants for coastal zone management activi-ties. In general, the offshore oil and gas industrysupported the concept of revenue sharing with thehope that States which have a stake in the revenuesfrom the OCS would be more receptive to offshoredevelopment.

OCS Escrow Funds

Drilling in Federal waters within 3 miles ofseaward limits of State waters contained within

thethe

Territorial Sea stands a risk of tapping a commonpool of oil that straddles the Federal/State bound-ary. Section 8(g) of the OCS Lands Act providesfor agreements between the Secretary of the Interiorand the Governors of affected States to apportionthe proceeds of oil and gas removed from the Fed-eral side of the border area. If agreement is notreached between the State and the Secretary within90 days after an announced sale, the Departmentof the Interior may proceed with the lease sale pro-viding all revenues received from the sale are placedin escrow pending agreement between the partieson apportioning the monies. In the absence ofmutual agreement, Federal Courts may be calledon to decide the equitable division of the money.

Nearly $5.4 billion has accrued in the escrowaccount to date. The States of Texas, Alaska,


Mississippi, Florida, California, Louisiana, andAlabama are scheduled to share the escrow moneywith the Federal Government. Negotiations overthe apportionment of the escrow funds have pro-ceeded intermittantly between the States and theDepartment of the Interior.

As a result of the sharp disagreement over theStates’ share of the escrow fund, opposition to area-wide leasing in the Gulf of Mexico is building inStates that have up to now enthusiasticall y sup-ported offshore oil and gas development. Both Loui-siana and Texas filed lawsuits in early 1984, andAlaska joined them in December 1984. In August1984, Secretary of the Interior William Clark of-fered non-litigating States an arrangement whichincluded 162/3 share of bonus and rental receipts.The States are seeking a larger share of the escrowfunds plus an acceptable share of future income(e. g., royalties) from these tracts.

Congressional Leasing Moratoria

The Department of the Interior has been pro-hibited by Congress from offering certain areas inportions of the North Atlantic, Central and North-ern California, Southern California, and EasternGulf of Mexico planning areas during fiscal years1982-85. Congress placed restrictions in the annualInterior appropriations acts on spending funds forthe purpose of pre-lease preparation or holding cer-tain lease sales.

In fiscal year 1982, 736,000 acres were placedunder a moratorium in Sale 53 in the Central andNorthern California lease area. In fiscal year 1983,the moratorium was expanded to include 35 mil-lion acres off California and New Jersey. In fiscalyear 1984, 53 million acres were placed under amoratorium. This included 8.7 million acres inGeorges Bank in the North Atlantic, 35 millionacres in Central and Northern California, 1.6 mil-lion acres in Southern California, and 7.7 millionacres in the Eastern Gulf of Mexico .23 In fiscal year1985, moratoria were continued on the same saleswith the exception of the Eastern Gulf of Mexico.Secretary of the Interior William Clark assuredCongress that the Eastern Gulf of Mexico would

not be leased until problems with the Departmentof Defense and the State of Florida are resolved.About 45 million acres of the OCS are currentlyunder congressional moratoria.

The moratoria appear to have resulted from a

combination of several factors: 1) they were partlya political response to the intractable approach offormer Secretary of the Interior James Watt towardplacing one billion acres of OCS up for sale; 2)Members of Congress shared the frustration of thecoastal States with the reduction in funds for coastal

zone management and Sea Grant College pro-grams; 3) coastal States and environmental groups

continued to disagree with the MMS over tractdeletions and cancellation of pending OCS sales;4) the Administration continued to oppose sharingoffshore revenues with coastal States; 5) the De-partment of the Interior and the States failed toreach agreement on division of escrow revenuesfrom drainage tracts; and 6) Department of De-fense pressure to force agreement with the MMSon deferrals or deletions of lease tracts for militaryand national defense uses may have prompted someMembers to support the moratoria.

Several authorization bills were introduced in the98th Congress which also would have imposedlegislative moratoria on OCS leasing and explora-tion and development of offshore California andNew England .24 None of these bills were enacted.However, action within the House Committee onAppropriations Subcommittee on the Departmentof the Interior and Related Agencies achieved thesame objective through the less-visible appropria-tions process.

The Department of the Interior has objected tothe imposition of congressional moratoria, but tolittle avail. Factions within State and local govern-ments and environmental groups have supportedthe leasing moratoria. The offshore industry ac-tively opposes any moratoria. The industry citesits outstanding environmental safety record and thenational need for secure domestic energy resourcesas reasons why current leasing moratoria shouldbe lifted.

Zspublic Law 98-146.24s 760 H

. R. 2059, S. 1103, H. R. 2581. (98th Congress, 1 St. and2nd. sessijns 1983-1984).

Ch. 6—Federal Leasing Policies • 145

MILITARY OPERATIONS

Military strength and dependable energy suppliesare considered to be the foundations of U.S. na-tional security. Recognizing this fact, the Depart-ment of Defense has indicated its support for ex-pediting exploration and development of the energyresources in the OCS. However, as offshore oil andgas development expanded since 1953, there wasgreater interaction between military use of sea spaceand the offshore petroleum activities. As OCS de-velopment pushed further seaward into deeperwaters and expanded into frontier regions, the in-cidents of encounters, interference, and incom-patibility between the two uses of the ocean becamemore numerous.25

Conflicts between offshore oil and gas uses andmilitary uses will probably increase in the future.The Department of the Interior accelerated the rateand extent of leasing in the OCS as a means to has-ten the exploration and development of offshore oiland gas beneath the seabed. At the same time mil-itary exercises and activities offshore have increasedin response to greater emphasis on military pre-paredness, With the advent of sophisticated elec-tronic equipment for both military and industrialuse, there may be potential for electromagnetic in-terference which could present yet another hazardin addition to physical interference.

Agreements between the Department of Defenseand MMS over deferrals and exclusions of leasetracts for military reasons historically have been ne-gotiated quietly with little fanfare. Disagreementsbetween the agencies were well hidden. However,what was once handled on a routine case-by-casebasis seems now to be turning into a problem toobroad and complex to be dealt with ad hoc. Themost recent indication of this is the provision in theDepartment of Defense Authorization Act of 1984that directs the Secretary of the Navy to inform theCongress of the potential effects of offshore oil andgas operations on naval operations and to defineoffshore zones where oil and gas drilling could causeappreciable impacts on naval operations.26

ZSFOr ~ h~~tOV of conflicts between the military and the oil indus-

try in the offshore areas see, Norman Breckner et. al., The Navy andthe Common Sea, (Washington, DC: Ofiice of Naval Research, 1972).

Zcpub]ic Law 98-94, Section 1260 (Sept. 24, 1984).

The Navy transmitted the information requiredin the 1984 Defense Authorization Act to the Con-gress on May 29, 1984.27 In the memorandum, theNavy identified six operational areas with poten-tial for conflicts between military operations andoffshore oil and gas development. Air Force andNASA operations were also included in the Navy’sresponse. The identified activities include: 1) sub-marine transit lanes in the North Atlantic area; 2)fleet operations, missile flights, and high-perfor-mance aircraft testing, as well as classified uses inthe Mid-Atlantic lease area; 3) submarine transitlanes, ballistic missile testing ranges, and sonartesting as well as the NASA Cape Canaveral launchrange in the South Atlantic area; 4) aircraft car-rier flight operations, flight training, air-to-surfacemissile testing, and equipment testing in the East-ern and part of the Western Gulf of Mexico areas;5) fleet operations, missile testing, testing of sub-marine electronic systems, submarine transit lanes,and gunnery training in the Central, Northern, andSouthern California areas; and 6) classified uses ofan unspecified nature in part of one Alaskan plan-ning area. In addition, underwater listening postswhich probably require protection from industrialinterference are located on the Continental Shelfoffshore both the Atlantic and Pacific Coasts andadjacent to Alaska.

MMS and the Department of Defense have takensteps to minimize offshore conflicts in the militaryand NASA operating areas. Since 1979, between40 and 55 million acres have been set aside or de-ferred from OCS leasing, and perhaps as much as75 million additional acres maybe leased only withoperating restrictions included to protect militaryinterests28 (see figure 6-3). Estimates of acreage af-fected by military operations should probably be

ZTLetter of tmnsmitt~ from Under Secretary of the N=y JamesF. Goodrich to the President of the Senate George Bush, withenclosures (May 29, 1984).

ZBThe exact acreage which are subject to mi]itary operating restric-tions is not available from MMS. About 42 million acres in the East-ern Gulf of Mexico lease planning area is subject to density controlsand military clearance. Approximate acreage subject to control in otherlease sale planning areas is estimated as: North Atlantic area—12 mil-lion acres; Mid-Atlantic area—10 million acres; Western Gulf of Mex-ico area—7 million acres; Northern and Central California-678 thou-sand acres, Southern California-7 million acres.


Figure 6-3.—Deferrals of Offshore Acreage for Military Uses

Central andNorthernCalifornia

Charleston , .,

Tampa

NOTE: DOD areas not to scale,

SOURCE: US. Department of the Interior, Minerals Management Service.

considered conservative because some classified off-shore uses have not been identified for security rea-sons. TheOCS acreage deferred from oil and gasexploration and development, plus the OCS acre-age which requires approval by the Department ofDefense and therefore is constrained by operatingstipulations (1 15 million acres), is about 30 percentgreater than the total onshore area withdrawn forwilderness use on public lands in Alaska and thelower 48 States (88.6 million acres). Operating con-straints include review and military approval of tim-ing, placement, and location of rigs and platforms;provisions for suspension of operations at the re-quest of the military; restrictions on electromagneticradiation; and release of the military from liabilityfor harm resulting to oil and gas operations frommilitary operations .29

Z9Lease Sde 79, Federaf Reg3”ster (Dec. 6, 1983), p. 54796; LeaseSale 82, Feder& Register (Aug. 27, 1984), p. 33987; Lease Sale 80,Federaf Register, (Sept. 17, 1984), p. 36481.

Western II

Gulf of Mexico

On July 25, 1983, the process of minimizing con-flicts was addressed in a Memorandum of Agree-ment between the then Secretary of the InteriorJames Watt and Secretary of Defense CasperWeinberger. In the memorandum, the Departmentof Defense acknowledged that ‘ ‘The OCS (OuterContinental Shelf) leasing program of the Depart-ment of Interior is an integral part of the nationenergy security program . . . and thus importantto national defense. ’30 The two departments agreedto work together to assure that offshore develop-ment does not conflict with military training andother activities essential to the readiness of U.S.armed forces. Therefore, as a result of this Memo-randum of Agreement, instead of relying entirelyon leasing deferrals, the Department of Defense hasexpressed its willingness to promote compatible mil-itary and offshore oil and gas operations, whenever

sOMemorandum of Agreement between the Department of Defenseand the Department of the Interior on Mutual Concerns on the OuterContinental Shelf Uuly 21, 1983).


possible, through the use of time-sharing agree-ments. The Navy and Air Force have, in somecases, offered to modify their activities to accom-modate OCS exploration operations.

This policy, though workable, is not entirelysatisfactory to industry. For example, to regulatethe density of oil and gas operations in a portionof the Eastern Gulf of Mexico planning area, theAir Force adopted a policy that allows drilling oper-ations within a 30-by-36 mile area, This system ofdensity control over oil and gas operations has beentermed the ‘‘postage stamp’ approach. Eventually,the intent of MMS and the Air Force appears tobe to periodically relocate the ‘ ‘postage stamp’ soother areas in the Eastern Gulf of Mexico can beexplored. There is also the possibility that morethan one exploration area may be allowed at thesame time. Several companies are now planningto drill in the first ‘ ‘postage stamp. However, out-side of this ‘ ‘postage stamp, Shell Oil Co. wastentatively denied approval in November 1984 foran exploration permit to explore a previously leasedblock in the DeSoto Canyon of the ApalachicolaEmbayment of the Eastern Gulf of Mexico leasesale planning area off Eglin Air Force Base. Thiswas the first time the Department of Defense hadattempted to deny a qualified owner of an OCSlease access to that lease for exploration. As a re-sult, the policies and procedures for regulating thedensity of oil and gas operations in military con-trol areas are under review by the Department ofDefense and MMS.

The Department of the Interior is currently con-sidering the establishment of ‘ ‘military reserva-tions ‘‘ in offshore areas.

31 Authority for the with-drawal of OCS acreage from leasing is found in twostatutes: 1) Section 12 of the OCS Lands Act (Pub-lic Law 82-21 2); and 2) Withdrawal of Lands forDefense Purposes Act (Public Law 85-337). TheOCS Lands Act vests authority in the Secretary ofDefense, with the approval of the President, todesignate OCS areas off-limits for oil and gas de-velopment for ‘ ‘national defense’ purposes. In ad-dition, the Secretary of Defense may suspend oper-ations on a previously existing lease with provisionsfor buyback from the lessee. The Withdrawal of

~1 Testimony of Wi]liam llet~enberg, Director, Minerals Manage-ment Service, before the House Committee on Interior and RelatedAgencies Appropriations (May 10, 1984), p. 605.

Lands for Defense Purposes Act (Section 2) reservesthe authority for withdrawing OCS areas from leas-ing for military purposes to Congress. Under theAct, applications for withdrawal must be acted uponby Congress before military reservations in theOCS are created. The two laws seem to be inconflict.

Whether the Executive Branch or Congress hasauthority to effect withdrawal of OCS lands for mil-itary purposes remains a question. The Withdrawalof Lands for Defense Purposes Act, having beenapproved in 1958, is the most recent expression ofcongressional intent. Legal interpretation oftengives the latest statute preference over the one priorin time in the absence of an expressed repeal. Ifthis interpretation is accepted to resolve the con-flicts between the two laws, only Congress has theauthority to establish offshore military reservations.This would probably require the introduction of leg-islation and appropriate hearings in conjunctionwith action by both Houses of Congress. On theother hand, another line of legal reasoning is thatwhen Congress amended the OCS Lands Act in1978, it did not change the law and thus implicitlyreaffirmed the authority of the Secretary of Defense.MMS, in responding to the current concerns of theDepartment of Defense, has referred to military ex-clusions in OCS sales as ‘‘deferrals. This hasavoided facing the issue of whether Congress or theexecutive branch has final authority to withdrawacreage from consideration for OCS oil and gasleasing. If the OCS Lands Act governs, the Secre-tary of Defense, with the approval of the President,can unilaterally withdraw OCS acreage for mili-tary use without the direct involvement of the De-partment of the Interior in the decision.

The withdrawal of OCS lands from oil and gasdevelopment for military reservations could, forpractical purposes, remove a significant amount ofpotentially productive OCS acreage from future oiland gas development. In addition, operating restric-tions on oil and gas activities in other portions ofthe OCS that may be considered suitable for shareduses could result in additional costs to the lesseesand could delay the exploration-development se-quence. Congressional concerns over conflicts be-tween military use and oil and gas developmentmay have contributed to the moratoria imposed inthe appropriations process on OCS lease sales in


the North Atlantic, Central and Northern Califor- t ions , the oil and gas industry could be per-nia, Southern California, and the Eastern Gulf of manently denied access to an even larger area thanMexico during fiscal years 1982-85. If the current has been temporarily affected by the congressionallydeferrals of OCS acreage now honored by MMS imposed moratoria (about 45 million acres in fiscalresult in withdrawal of areas as ‘‘military reserva- year 1985).

DISPUTED INTERNATIONAL BOUNDARIES

National jurisdiction over most of the known orpotential resources on or under the U.S. Continen-tal Shelf is largely uncontested. On March 10, 1983,when President Reagan established an EEZ for theUnited States, resource jurisdiction over the Con-tinental Shelf within 200 miles of the U.S. coastlinebecame even more firmly established. However,in some potentially important resource-producingareas in proximity to Canada, Mexico, Cuba, andthe Soviet Union, international boundaries havebeen (or could be) contested. Settlement of thesedisputes may become of more concern as the UnitedStates—and these adjacent or opposite countries—improve capabilities to search for resources in morehostile environments and in deeper waters.

The primary responsibility for negotiating trea-ties to resolve these types of disputes lies with theU.S. Department of State. Typically, the Depart-ment of State consults with the Department of theInterior regarding subsea features and the resourcepotential of areas in dispute. Treaties must beratified by Congress.

Areas of Potential Dispute

Gulf of Maine and Georges Bank

Jurisdiction over the Gulf of Maine and GeorgesBank east of Cape Cod has been disputed betweenCanada and the United States. The region is a pro-ductive fishery and, although preliminary ex-ploratory efforts on Georges Bank have been disap-pointing, it is considered to have potential for oiland gas. Maritime jurisdiction was disputed overan area between 13,000 and 18,000 square nauticalmiles in size. The dispute was submitted to the In-ternational Court of Justice (ICJ) for arbitration,pursuant to a boundary settlement treaty betweenthe United States and Canada. The Court an-nounced its decision on October 12, 1984.

Both the United States and Canada presentedarguments to support their claims based on theecology of the region, socioeconomic factors, andhistoric practices. The Court rejected these argu-ments, noting that ‘‘the respective scale of activi-ties connected with fishing-or navigation, defense,or, for that matter petroleum exploration andexploitation— cannot be taken into account as arelevant circumstance or, if the term is preferred,as an equitable criterion to be applied in determin-ing the delimitation line. ’32 In determining anequitable line, the Court relied most heavily on geo-graphical arguments. Thus, of primary importancewas the notion that the delimitation should aim atan equal division of ‘areas where the maritime pro-jections of the coasts of the States between whichdelimitation is to be effected converge and over-l a p . As a second criterion, the Court consideredthe length of coastline of each country in the Gulfof Maine. Accordingly, the middle of the threesegments of the boundary line was adjusted in rec-ognition of the greater length of the U.S. coastlinein the region.

The Court gave Canada jurisdiction of the liv-ing and non-living resources of the northeast por-tion of Georges Bank (see figure 6-4). The UnitedStates had originally claimed the entire Bank whileCanada had claimed about one-half of it. Thus, inthis area, the line was established essentially mid-way between the claims of the two states. Canada,however, gained control over important fishingareas, most notably, scallop grounds.

As a result of this decision, Canada now mayissue oil and gas leases on its portion of GeorgesBank, The same, of course, is true for the UnitedStates in areas now under its jurisdiction. Thus,

szrnternation~ court of Justice. Case Concerning Delimitation ofthe Maritime Boundary in the Gulf of Maine Area: (CanaddUnitedStates of America), (Oct. 12, 1984), p. 102.


44°N

40“N

Figure 6-4.—U.S.-Canada Boundary in Georges Bank

68°W 64“W

44“N

EmeraldBank

LaHaveBank

\ & .

\

Boundary determined bythe International Court of Justice

‘\\ \

Boundary turning points

D A 4401 1‘12”N 67016’46”WB 42“53’14”N 67044’35”W

50 fathoms Canadian \\ C 42 031‘08”N 67‘28’05”WClaim \ D 40‘27’05”N 65 041‘59”W 40” N

68°W 64°W

oil and gas activities which occur on one side of theline could affect the other side. For instance, a gyrelocated over Georges Bank virtually assures thatoil spilled on either side of the line will drift to theother side, Although U.S. and Canadian CoastGuards have developed a joint marine pollutioncontingency plan for the area, neither the UnitedStates nor Canada currently has a formal processin its OCS leasing operations for dealing with theenvironmental and socioeconomic concerns of theother country. Transboundary coordination and co-operation regarding OCS development activitiesadjacent to common boundaries could avoid manypotential environmental problems.

Beaufort Sea

The offshore boundary between the UnitedStates and Canada in the Beaufort Sea also is indispute. The area in question is small relative tothe total continental shelf areas of both countries(6, 180 square nautical miles), but favorable geologicconditions suggest it is potentially rich in hydro-carbon resources. Canada contends that the 141stmeridian of longitude dividing Alaska and theYukon delimits the offshore boundary. The UnitedStates claims that the boundary should be estab-lished using the equidistance principle, thus plac-ing the boundary further east (see figure 6-5). The

.


Figure 6-5.—U.S.-Canada Boundary in Beaufort Sea

150 145 140 135 130I I 1 I

Beau fortSea

nm

I

70

145 140 135

legal basis for the Canadian claim is not altogetherclear, but appears to rely on ambiguous languagein the 1825 boundary agreement between theUnited Kingdom and Russia which specifies thatthe line of demarcation shall extend along the 141stdegree of west longitude ‘‘in its prolongation as faras the Frozen Ocean. ’33 Moreover, Canada hasused the line as a national offshore fence for sev-eral purposes (e. g., oil and gas exploration permitshave been issued up to the 141st meridian).

The United States does not agree that the UnitedKingdom-Russia Treaty of 1825 extended the landboundary into offshore areas, nor does the UnitedStates agree that any special circumstances exist thatwould justify such an extension. In the absence of‘‘special circumstances, the 1958 ContinentalShelf Convention calls for an equidistance line tobe drawn. At this time, the crux of the matter ap-pears to be what constitutes special circumstances,since the phrase is only vaguely defined in the 1958Convention, and the 1982 United Nations Conven-tion on the Law of the Sea does not provide anymore detailed guidance.

The Beaufort Sea dispute has been quiet since1975, and both countries have imposed an infor-mal moratorium on offshore exploration and licen-

ssD~vid v~derzwaag and Cynthia Lamson, ‘‘ocean Developmentand Management in the Arctic: Issues in American and CanadianRelations, unpublished paper for the United State-Canada ArcticPolicy Forum (Banff, Alberta, Oct. 20-22, 1984).

sing in the disputed area. Although the GeorgesBank ICJ decision supports the principle of equi-distance modified by the amount of coastline heldby each country—a finding which appears to fa-vor the United States position in the BeaufortSea—U.S. officials urge caution concerning the ap-plicability of the Georges Bank decision to theBeaufort Sea. It is held by both countries that thecircumstances of the Beaufort Sea dispute areunique and, therefore, the Georges Bank decisiondoes not necessarily set a precedent for the resolu-tion of the issue.

If an agreement locating the line cannot bereached, the United States and Canada may wishto consider other types of solutions to the problem.Joint exploration and development by Canada andthe United States may be possible even though thereare no specific provisions in the OCS Lands Actfor joint activity. An executive agreement, whichmany scholars agree can overrule existing law,might be utilized to allow joint exploration and/ordevelopment to take place. In the absence of suchan agreement, there still appears to be no legal rea-son why the United States, in concert with Can-ada, cannot hire a single firm or consortium to ex-plore the area for both countries. Section 11 of theOCS Lands Act does not prohibit exploration with-out leasing. If exploitable resources are discovered,both countries might consider offering the disputedarea for lease to one lessee while agreeing to decideat a later date how revenues are to be divided.

Bering Sea

The location of the line which separates Sovietand American resource jurisdiction in the BeringSea also has been disputed. The line was establishedwhen Alaska was ceded to the United States byRussia in 1867. However, the Soviet Union andthe United States have not been able to agree uponthe method to be used in locating the line. TheSoviets advocate use of the “rhumb line” method,a technique in use at the time the treaty was nego-tiated. The United States contends that the moremodern “great circle’ method of calculation bestreflects the intentions of the negotiators of the 1867Convention and should be used .34 The rhumb line

s4HarV Il. Marshall, “International Boundaries and the 5-YearOuter Continental Shelf Oil and Gas Leasing Program. ” Paper pre-sented at the meeting of the Outer Continental Shelf Policy Commit-tee, New Orleans, Louisiana, (Oct. 26, 1984), p. 11.


method places the line further east than the greatcircle method, and hence reduces the area assignedto the United States.

The 1867 line passes through the potentially oil-rich Navarin Basin; thus, there are important eco-nomic reasons for resolving the dispute. Upcom-ing sales in the Norton Basin and Chukchi Sea mayalso border on the 1867 line. The issue is even moreimportant because the United States leased NavarinBasin tracts in 1984. Bids were received on 17 tractswithin the disputed zone created by the two lines(see figure 6-6). However, these bids will not befinally accepted until the dispute is resolved. If itis later determined that it is not in the interest ofthe United States to accept these bids, deposits,which are being held in escrow, will be refundedwith interest. However, if the dispute is resolvedand the bids are accepted, bidders will be requiredto pay the remaining four-fifths bonus and the firstyear’s rental and execute the lease .35 Although fourrounds of discussions concerning this sensitive issuehave taken place since 1981, there is no indicationas to when an agreement will be reached. Not-withstanding agreement on the location of theboundary, petroleum deposits may straddle the line.The methods used for apportioning common de-posits in the North Sea between the United King-dom and Norway may also be useful in the U. S.-Soviet boundary area.

If the United States and the Soviet Union can-not agree to a division of the area, several otheroptions might be considered. A buffer zone couldbe created within which no oil and gas explorationwill be allowed. An interim regime could be estab-lished that would permit exploration and providethe framework for future development and shar-ing of petroleum resources.36 However, the possi-bility of joint U.S.-Soviet development of NavarinBasin resources in the foreseeable future is consid-ered remote. Among other problems would be thatof technology transfer, but that possibility, if suc-cessfully pursued, could have a positive effect onthe two countries’ relations .37

35’ Final Notice of Sate: Navarin Basin. Federal Register, (Mar16, 1984), 49(53): 10065.

sbRobert B. Krueger, ‘ ‘Bering Sea Petroleum: A New MeetingGround for the Soviet Union and the United States, unpublishedpaper (January, 1983),

sTW1lliam E, Westermeyer, “Aspects of Arctic Energy Develop-m e n t , Geopolitics of Energy (March 1984), 6(1 ):7.

Continental Shelf

Delimitation of the outer boundary of the exten-sive U.S. Continental Shelf is another type ofboundary issue. Given the vast amount of Con-tinental Shelf acreage over which the U.S. may beentitled to assert resource jurisdiction, Continen-tal Shelf delimitation is probably a more significantissue than delimitation of either opposite or adja-cent state boundaries. In principle, the UnitedStates could assert resource jurisdiction under the‘‘exploitability clause’ of the 1958 Geneva Con-vention on the Continental Shelf, which defines theouter edge of the shelf as the point at which ‘ ‘thesuperjacent waters admit of the exploitation of thenatural resources. The limits of exploitability arecontinuously being pushed into deeper and deeperwater. However, precise rules have been promul-gated in the 1982 Law of the Sea Treaty (Article76) which, in some cases, would enable coastalStates to extend Continental Shelf jurisdictionbeyond the 200-mile EEZ. Even though the UnitedStates has not signed the Law of the Sea Treaty,it has stated that its only objections to the Treatyare the Part XI provisions pertaining to exploita-tion of the deep seabed beyond the limits of nationaljurisdiction.38 The Uni ted States i n t e n d s t o a b i d e

by all other provisions, and, in particular, may usethe Article 76 criteria for delimiting its Continen-tal Shelf. Legislation introduced in the 98th Con-gress defined the Continental Shelf in terms con-sistent with Article 76.

The Law of the Sea Treaty is not yet in force.However, eventually it is expected to be operativefor those countries that have signed and ratified it.Moreover, the Treaty will be a major factor in thedevelopment of state practice even for those coun-tries that have not signed it. Many of its provisionsmay now be considered to be customary interna-tional law. Others will eventually be accepted ascustomary law, and thus generally become appli-cable even for non-signatories.

Gulf of Mexico

Delimitation of the Continental Shelf of theUnited States may involve conflicts with oppositeor adjacent countries. One such instance may be

SaStatement by the President The White House, OffIce of the pressSecretary, (Mar. 10, 1983). ‘

38-749 0 - 85 - 6


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 SiberianSea Wrangel

Island I.Chukchi Sea

Komandorskiye /

/

/

PribilofIslands

70”

65”

/ .: ● 4*$-

/\ . .

500

I 1 1 I I I I170 “ 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). Areais about 30 miles wide.

SOURCE: Minerals Management Service


in the Gulf of Mexico. The United States, Mexicoand Cuba border the Gulf, and their ContinentalShelf claims could overlap in several areas (see fig-ure 6-7). The United States has negotiated trea-ties with Mexico and Cuba delimiting boundariesin those areas where exclusive economic zonesoverlap. Neither treaty, however, has been ratifiedby the United States Senate. Some questions havebeen raised concerning Mexico’s use of certainuninhabited islands off the coast of the YucatanPeninsula as baseline points for the purpose ofdetermining its EEZ boundary .39 If these islandsare not used to fix the Mexican EEZ boundary, theUnited States may be able to extend resource juris-diction in some areas. However, the U.S. Depart-ment of State and many scholars regard the Mex-

40 Moreover , t h e U n i t e dican claim as legitimate.States uses islands as baseline points off its owncoast.

~gscnatc Committee on Foreign Relations, ‘‘Three Treaties Estab-

lishing Maritime Boundaries Between the United States and Mex-ico, Venezuela, and Cuba, Executive Report No. 96-49 (Aug. 5,1980), p. 7.

+OHarV R. Marshall, ‘‘ International Boundaries and the Fi~e-YearOuter Continental Shelf Oil and Gas Leasing Program, paper pre-sented at the meeting of the Outer Continental Shelf Policy Commit-tee (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 to12,000 feet) in the central Gulf of Mexico beyondthe 200-mile exclusive economic zones of the bor-dering countries. The ‘ ‘western hole’ is borderedby the EEZs of the United States and Mexico andthe ‘ ‘eastern hole’ is bordered by the EEZs of theUnited States, Mexico, and Cuba. Although therecurrently is little interest and no experience in ex-ploiting resources in these deepwater areas beyondthe EEZ, sediments do occur in both areas, andhence there is at least a possibility that hydrocar-bons may be found.

The United States has not yet addressed the ques-tion of jurisdiction within the two holes. Interestin doing so at this time is low. Prospects for oil andgas development in these areas are considered tobe remote, given the extreme depths and high costsof exploration and development. Nevertheless, allof the area within the holes can potentially beclaimed by the littoral states according to the cri-teria of either Article 76 of the Law of the SeaTreaty or the 1958 Continental Shelf Convention .41Since several methods exist for determining the ex-tent of the Continental Shelf, claims to these areascould overlap. Thus, bilateral or trilateral negotia-tions eventually may be needed to settle any dis-putes created by overlapping claims.

Dispute Settlement Mechanisms

Several mechanisms are available for resolutionof boundary disputes. Third parties may or maynot be involved in the process. A negotiated set-tlement without third-party intervention is usuallypreferable. Arbitration or mediation may also beconsidered. The Georges Bank dispute was settledby arbitration. This is a voluntary process, but theparties to an arbitration commit themselves to abideby the decision of the arbitrator. Mediation is alsoa type of arbitration, but the mediator of a disputehas no authority to impose a settlement. Themediator simply brings the parties together to helpfacilitate a solution to their problem. Numerousvariations of these basic strategies are possible.

Determination of the proper location of the 1867Convention Line in the Bering Sea will likely be

+ 1 Robert smith, Office of the Geographer, U.S. Department ofState, personal communication, (Oct. 30, 1984).


made through bilateral negotiations between theUnited States and the Soviet Union. Four meetingsalready have taken place, the most recent of whichoccurred in July 1984. It is unlikely that either theUnited States or the Soviet Union would submitany dispute to a third party for arbitration or media-tion if negotiations break down.

The United States and Canada will probablywish to give more thought to the advisability ofusing binding arbitration to settle the Beaufort Seadispute if they perceive that, as in the Georges Bankdispute, the arbitrator will simply split the differencebetween claims without considering special circum-stances. If bilateral negotiations are not successfulin determining a mutually acceptable boundaryline, mediation or some other conciliatory proce-dure may be needed. For example,

LEASING

tries could establish a joint U.S.-Canadian work-ing group to devise an equitable solution andsubmit it to both governments for consideration.

The Law of the Sea Treaty also provides for thesettlement of disputes through, for example, the In-ternational Tribunal for the Law of the Sea. Whenand if the Treaty comes into force, Mexico andCuba could conceivably request that ContinentalShelf delimitation in the Gulf of Mexico be deter-mined by Treaty arbitration or conciliation pro-cedures. Such mechanisms would be unavailableto the United States as a non-party. Presumably,if the issue becomes important to settle but cannotbe settled through negotiation, an international tri-bunal not established by the Treaty, such as theICJ, could be utilized.

the two coun-

POLICIES FOR OFFSHOREFRONTIER AREAS

Bidding Systems

The OCS Lands Act of 1953 authorized two bid-ding systems for use in offshore leasing: 1) cashbonus bid with a fixed royalty; and 2) royalty ratebid with a fixed cash bonus. The United States hastraditionally allocated offshore tracts on the basisof the highest cash bonus bid with a fixed royaltypayment based on the value of production. Thisbidding system is easy to administer, has appearedto promote efficient exploration and developmentof offshore tracts, and has been generally acceptedby both government and industry.

However, in the 1978 OCS Lands Act Amend-ments, Congress required the Department of theInterior to test alternative bidding systems on notless than 20 percent and not more than 60 percentof the offshore acreage offered for lease each yearfor a 5-year period ending in September 1983. Thefive alternative bidding systems specified for testingwere: 1) cash bonus bid with sliding scale royalty;2) cash bonus bid with freed net profit share; 3) cashbonus bid with fixed royalty and fixed net profitshare; 4) profit share bid with fixed cash bonus;and 5) work commitment bid with fixed cash bonus

and fixed royalty. Congress wanted to determinethe effect of these bidding systems on competitionfor offshore leases, government revenues, and oiland gas exploration and development.

At the end of the testing period, the Departmentof the Interior still prefers the traditional biddingsystem for offshore leasing. After evaluating thealternative bidding systems in theory and/or inpractice, the Department of the Interior concludedthat their disadvantages outweighed their advan-tages in offshore leasing, as outlined in table 6-3.In testing the alternative bidding systems, it wasfound that they had little effect on the level of com-petition for OCS tracts, which is more directly re-lated to an area’s resource potential than to themethod of leasing. No firm conclusions werereached regarding the development efficiency andrevenue effects of alternative bidding systems, how-ever, because most tracts leased under the alter-native systems had not yet begun production .42

42Mincr~s Management service, “Report to Congress on FiscalYear 1982 Outer Continental Shelf Lease Sales and Evaluation ofAlternative Bidding Systems, ” (April 1983), p. 57.


Table 6-3.—Advantages and Disadvantages of Alternative Bidding Systems (authorized by OCS Lands ActAmendments of 1978)

Bidding system

Bid variable Fixed payment Description Advantages Disadvantages

Cash bonus

Cash bonus

Cash bonus

Cash bonus

Royalty rate

Net profitshare

Workcommitment

Fixed royalty

Sliding scaleroyalty

Fixed netprofit share

Fixed royaltyand fixed netprofit share

Fixed cashbonus

Fixed cashbonus

Fixed cashbonus

Leases awarded on the basisof highest cash bonus pay-ment plus percent ofrevenues, not less than12½%. Usually 162/3%.

Leases awarded on the basisof highest cash bonus pluspercent of revenues, whichincreases with production.

Leases awarded on the basisof highest cash bonus pluspercent of profits aftercapital recovery. Profitshare not less than 30°/0.

Leases awarded on the basisof highest cash bonus pluspercent of revenues andpercent of profits.

Leases awarded on the basisof highest percent ofrevenues offered, plus fixedcash bonus.

Leases awarded on the basisof highest percent of pro-fits offered, plus fixed cashbonus.

Leases awarded on the basisof dollars to be spent onexploration, plus fixed cashbonus.

Generally accepted

bidding system inUnited States. Easyto administer.

May lower bonus bidsand increase compe-tition. Lease pay-ments vary with fieldproductivity.

May lower bonus bidsand increase com-petition. Leasepayments vary withfield profitability.

May lower bonus bidsand increase com-petition.

Lower upfront pay-ments may increasecompetition.

Lower upfront pay-ments may increasecompetition.

Provides for rapidexploration.

upfront cash bonuses maylimit competition. Fixedroyalties may overtaxsmall fields and constraindevelopment.

Royalties may still be toohigh for small fields. Maytry to avoid higher royaltyon productive tracts byslowing production.

Difficult to design andadminister. May cause“gold-plating.”

Regulations never writtenas too complex.

High royalty rate bids mayconstrain development.

High net profit share bidsmay constrain develop-ment.

Government must foregohigh bonuses. Explorationprogram may beinefficient.


Both theory and experience indicate that theroyalty bidding system and the profit-share biddingsystem may lead to the abandonment of small ormarginal fields and prevent efficient developmentof resources. These systems tend to promoteunrealistically high royalty rate bids or profit-sharebids in competitive lease auctions. The high leasepayments add to the costs of production and makedevelopment of some fields unprofitable. Royaltybidding in two offshore lease sales was found to leadto excessive royalty rate bids, which may discouragelater investments.43 Profit-share bidding was nevertested.

The cash bonus bidding systems with either afixed net profit share or sliding scale royalties have

43 Department of the Interior, Office of OCS program Coordina-

tion, ‘ ‘An Analysis of the Royalty Bidding Experiment in OCS SaleNo. 36, ” (1975) and Bureau of Land Management, “PreliminaryAnalysis of Royalty Bidding vs Bonus Bidding at the Cook Inlet Sate, ”(Nov. 13, 1977),

been more favorably evaluated in regard to devel-opment efficiency. Under both of these systems,lease payments vary with either field productivityor other factors. However, after it was tested in atotal of 13 lease sales, the fixed net profit share sys-tem was not proposed for further use because ofits complex accounting and administrative require-ments.44 While sliding scale royalty systems haveproved easier to administer, they may discouragegenerally higher levels of production in order toavoid higher royalty rates. Despite this drawback,the Department of the Interior preferred the cashbonus bid with sliding scale royalty system to otheralternative bidding systems .45

~+ Resource Consulting Group, “Issues Associated with the Use ofthe Net Profit Share System for Leasing Outer Continental Shelf Oiland Gas Acreage, report to the Minerals Management Service (Sept.27, 1982).

+5 Bureau of Land Management, ‘‘ Bidding System Design for OCSSale 71 ,“ (May 4, 1982).


Neither the work commitment bidding systemor the combined fixed royalty and profit share sys-tem were tested in offshore lease sales. It is believedthat work commitment bidding reduces govern-ment cash bonus revenues and may promote inef-ficient exploration efforts if not carefully designed.46

Regulations were never written for the cash bonusbid with fixed royalty and fixed profit-share sys-tem, which is seen as administratively burdensomeand complex.

The Department of the Interior has generallyused the cash bonus bid with a lower royalty of 12½percent (1/8) for leasing offshore tracts in frontierareas. This is the minimum royalty rate allowedby law and is used in recognition of the increasedcosts of developing oil and gas resources in hostileenvironments. The lower royalty rate is offered onblocks where analyses indicate that small discov-eries may not be developed under the standard 162/3

percent royalty. Starting in August 1981 throughthe end of 1984, the bonus bidding system with a1/8 royalty has been used for leasing a total of 1,041tracts in 19 lease sales. In general, the lower royaltyrate has been offered on tracts in difficult oceanenvironments off Alaska and in deepwater areas ofthe other OCS planning regions.

The traditional cash bonus bid with fixed royaltybidding system has appeared to work well in con-ventional leasing areas such as the Gulf of Mexicoin terms of assuring adequate competition for OCStracts, fair returns to the government, and efficientexploration and development .47 In frontier areas,the use of this system with a lower royalty rate hasincreased the economic incentive to explore in high-cost regions. In general, the cash bonus bid withfixed royalty bidding system has distinct advantagesin its administrative simplicity, incentives for rapidexploration, and immediate returns to the govern-ment in the form of cash bonuses.

However, there may be disadvantages to al-locating offshore frontier tracts by this biddingsystem. The requirement for upfront cash bonus

4GR~~OurCe planning Associates, Inc. and Resource consultingGroup, Inc., “Alternative Procedures for Managing the Leasing ofNonprospective OCS Acreage, report to the Department of EnergyfJan. 29, 1981).

47W. J. Mead et. al., ‘ ‘Additional Studies of Competition and Per-formance in OCS Lease Sales, 1954 -1975,” report to the U.S. Geo-logical Survey (1980).

payments may be a deterrent to comprehensiveexploration of frontier areas. Alternative arrange-ments and even government incentives may beneeded at some point to encourage continuing ex-ploration in high-risk deepwater and Arctic regions.In addition, the low profit margins in frontier areasmay cause fixed royalties (which are levied on grossincome) to overtax small or marginal fields and leadto non-development of resources (see economicanalysis in chapter 5). Even the lower 1/8 royaltyrate may be too burdensome on some Arctic anddeepwater fields.

Other countries, including the United Kingdom,Norway, and Canada, have generally used workcommitment systems rather than cash bonus bid-ding for offshore leasing in frontier areas. This sys-tem is discussed in the appendix to this study.Under this system, firms agree to carry out a pre-planned exploration program, drill a specified num-ber of wells, or make a minimum expenditure inexploring a lease area. Firms which fail to carryout the terms of the work program can lose leaserights or any collateral paid to the government. Incountries which use work commitment systems,lease tracts are far larger than those in the UnitedStates. In addition, the contract generally containsrelinquishment provisions for returning portions ofacreage to the government at a specified time. Thework program, large size of the lease area, and turn-back requirements jointly provide incentives forrapid exploration of vast offshore areas. Work pro-grams also can be used to encourage firms to assessnonprospective offshore regions or to reassess relin-quished acreage.

Other types of bidding systems which do not re-quire initial cash payments for exploration rightsmay also provide more incentives to high-risk ven-tures in offshore frontier areas. Deferred bonus pay-ments or cash bonuses payable only on commer-cial discoveries of oil would increase government/industry risk-sharing. These systems would retainthe cash bonus bid variable and the financial com-petition which have been the basis of our leasingsystem.

Bidding systems with other types of downstreampayments, such as sliding scale royalties, net profitshares, or even zero royalties, may be more effec-tive in providing economic incentives for develop-ing marginal oil and gas discoveries in offshore fron-


tier areas. Under the sliding scale royalty system,the royalty rate increases with the production rateand government and industry shares of income arebased partially on the productivity of the tract.Marginal resources and declining fields may bemore likely to be produced because of the lowerroyalty rate attached to this production. At present,the primary disadvantage of the sliding scale royaltybidding system is that the royalty rate does not slidebelow the legal minimum of 12½ percent and won’tgreatly improve the profitability of small or mar-ginal fields over the 12½ percent fixed royalty nowin use. Sliding scale royalties that slide to zero per-cent may be needed to encourage the developmentof resources in frontier areas.

Economic theory and empirical economic models,including the OTA computer simulation, indicatethat net profit share payments also may be well--suited to offshore frontier areas. 48 Under th is Sys-

tem, firms share the net income from tract devel-opment with the government at a specified profitshare 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-capitalrecovery), the United States has used the fixed-capital recovery system. Firms are allowed to re-cover their initial investment, plus a return on theinvestment, before sharing profits from oil and gasdevelopment with the government. Because thissystem takes into account the high costs, long lead-times, and other features characteristic of frontierareas, it provides for greater government risk-sharing. Small and marginal fields may not be ashighly taxed and, therefore, are more likely to bedeveloped.

Although work commitments, profit-sharing,and other leasing approaches have generally beenaccepted abroad, these bidding systems may be dif-ficult to implement in the United States. Offshoreleasing in the United States has always been basedon competition between companies. Any leasingsystem used in the United States has to award leaserights on the basis of defined, objective criteria. Inother countries, leasing conditions are often nego-

4’R. J, Kalter, W. E. Tymer, and D. W, Hughes, “AlternativeEnergy Leasing Strategies and Schedules for the Outer ContinentalShelf (Cornell University, Dept. of Agricultural Economics, Decem-ber 1975).

tiated directly between private firms and the gov-ernment,

In addition, effective design and administrationof alternative bidding systems would require ex-tensive testing and increased funding. The designof sliding scale royalty and profit-sharing systemsis based on certain types of tract-specific informa-tion and calibration that is difficult for the govern-ment to achieve.49 Post-production accounting inthese systems often involves complex proceduresfor verifying costs, profits, and/or flow rates asso-ciated with individual leases. Work commitmentbidding systems have administrative costs in ne-gotiating terms and conditions and monitoring in-dustry compliance. There has also been concernabout potential government intervention into in-dustry accounting and operational practices in theimplementation of these bidding systems.

Because of the inconclusive results of the 5-yeartesting of the alternative bidding systems specifedin the OCS Lands Act Amendments, the GeneralAccounting Office (GAO) has recommended thatthe requirement to test alternative bidding systemsin offshore leasing be extended by Congress .50 Fur-ther testing of alternative bidding systems, in-cluding some approaches not specified in the OCSLands Act Amendments, is especially needed in off-shore frontier areas. The effect of bidding systemson the level of competition is not particularly ger-mane in the Arctic and deepwater, where competi-tion will automatically be limited by the high-costand high-risk nature of the tracts. But the effect ofbidding systems on the rate of exploration and de-velopment in the frontiers is crucial in view of theneed to assess and develop the resource potentialof these areas.

The OCS Lands Act Amendments now gives theSecretary of the Interior great flexibility in design-ing bidding systems, which may consist of ‘‘ anyother system of bid variables, terms, and condi-tions . . . except that no such bidding system ormodification shall have more than one bid vari-

4gD, R. Siegel and J. L. Smith, ‘ ‘Does Profit-Sharing Leasing forOuter Continental Shelf Leases Need Finer Tuning?’ Oil and GasJournal (May 7, 1974), pp. 144-152,

sOGenera] Accounting Office, ‘ ‘Congress Should Extend Mandateto Experiment With Alternative 13idding Systems in Leasing OffshoreLands, ” (May 27, 1983).

—


able.” 51 As leasing and exploration proceed in off-shore frontier areas, new approaches and modifica-tions of lease conditions may be necessary to sustainthe search for oil and gas resources. Other coun-tries, such as the United Kingdom, have found itnecessary to adjust lease payments and taxes in laterstages of offshore activity to extend exploration andto encourage development of marginal resources.Through testing, the Department of the Interiorcould assess the advantages and disadvantages ofalternative bidding systems in promoting explora-tion and development in frontier areas. It could alsorefine different bidding approaches and would beprepared to implement them on a more widespreadbasis if needed as an incentive to a second-roundof leasing and development in the offshore frontiers.

Lease Terms

Other lease conditions may also need to be mod-ified to encourage oil and gas activity in offshorefrontier areas. For example, longer lease terms andlarger tracts coupled with relinquishment provisionsmay be appropriate to frontier areas in conjunc-tion with or apart from the implementation of newbidding systems.

As leasing in offshore frontier areas has in-creased, a greater number of OCS tracts have beenoffered and leased with 10-year rather than 5-yearlease terms. The OCS Lands Act, as amended, pro-vides for longer lease terms as an incentive to ex-ploration and development in areas of unusuallydeepwater or difficult operating conditions. Thelonger lease terms have been offered for tracts inthe Alaskan offshore, where weather and ice con-ditions may be severe, and for deepwater tracts inthe Atlantic, Pacific, and Gulf of Mexico regions.

The first tracts with 10-year lease terms were of-fered in the 1979 joint Federal/State lease sale inthe Beaufort Sea. This was the first Federal leasesale held in Arctic waters, and it resulted in the leas-ing of 24 Federal tracts which expire in 1990. Sincethat time, most of the lease sales held in the Alaskanplanning areas have included tracts with 10-yearleases. In 1984, the Navarin Basin sale (Lease Sale83) 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 percentof the tracts leased with longer lease terms havebeen in the Alaskan planning areas.

Ten-year lease terms also have been used fordeepwater tracts in the lower 48 states, althoughthe deepwater criteria have varied. The first trulydeepwater OCS sales were held in 1981 in the Atlan-tic, where all tracts in water over 400 meters deepwere offered with 10-year leases. However, a 900-meter criterion was used for Southern CaliforniaLease Sale 68 in June 1982, and 900 meters subse-quently became the deepwater marker for tractsleased in the Pacific, Atlantic, and the Gulf of Mex-ico.

In December 1983, the Department of the In-terior proposed increasing the acreage offered with10-year lease terms by reestablishing 400 metersas the deepwater criterion and making 10-year leaseterms automatic for all tracts in 400 meters of wateror deeper.52 The revision of the definition of deep-

water from 900 meters to 400 meters is based onthe increased amount of time needed to explore anddevelop energy resources in these water depths ascompared to nearshore tracts. Lease terms are nowdecided on a sale-by-sale basis, but an automatic10-year term tied to water depth could facilitate in-dustry and government planning.

Critics of the longer lease terms believe they allowcompanies to delay exploration and developmentin offshore areas. At present, the 5-year lease termensures that tracts are explored and developed ina timely manner, as leases are forfeited at the endof 5 years if they have not been drilled or declaredprospective. Extensions of lease terms or ‘ ‘suspen-sions of operations’ (SOPS) are available underspecial conditions. Critics of 10-year lease termsbelieve that the standard 5-year term and SOPSshould be continued to be used in Alaskan anddeepwater areas. However, SOPS are subject tochanging policy interpretations or regulations andcreate greater uncertainty for the industry infrontier-area leasing.

Exploration diligence generally has been pro-moted by the requirement that lessees submit ex-ploration plans and follow them. Holders of 5-year

52 Fe~er.d ~egister, (Dec. 20, 1983), 48 (245): 56279-56281.


leases are required to submit exploration plans orstatements of intentions to explore by the end ofthe fourth year of the lease term. However, holdersof 10-year leases have not been required to submitthese plans at a specified time, except as outlinedin the lease offering. This often has been as lateas the eighth or ninth year of the lease term. TheDepartment of the Interior is now considering arequirement that exploration plans be filed withina set time on 10-year leases, although a milestoneyear has not been proposed. A requirement forearlier submission of exploration plans on 10-yearleases could promote diligent exploration effortswhile reducing the risks of the shorter lease termfor the industry.

Tract Size

In addition to lengthening the lease terms,another proposal to improve the efficiency of ex-ploration and development in offshore frontier areasis to increase the size of offshore lease tracts orblocks. The OCS Lands Act limits lease tracts toan area of nine square miles or 5,760 acres, unlessit is determined that a larger area is necessary tocomprise a reasonable economic unit. An optionin frontier areas is to increase the average size ofthe tracts and to combine the larger tracts withrelinquishment provisions. 53 This is standard prac-tice in countries such as the United Kingdom, Nor-way, and Canada, where the average size of thetracts ranges from 90 square miles to 700 squaremiles.

Leasing larger tracts in offshore frontier areascan promote more rapid and efficient explorationstrategies. Firms may be more willing to bid onlarge areas, which increase the probability that oildiscovered by the lessee would be contained withinits tract rather than on an adjoining lease. Firmswould have less incentive to delay exploration inhopes that information from nearby drilling effortsreduces uncertainty about the value of a tract. Ingeneral, larger tracts increase the likelihood thatowners will fully benefit from drilling informationand thus may induce increased investment and ex-ploratory activity.

SsResource planning Associates, Inc. and Resource ConsultingGroup, Inc., Report to the Department of Energy, “Alternative Pro-cedures 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 canprovide for the surveying of vast amounts of acre-age and the selection of prospective areas fordrilling. The addition of relinquishment or turn-back requirements could help assure the early iden-tification of high quality acreage. Under this sys-tem, firms would relinquish a percentage of theiracreage with exploration information at a specifiedtime to the government, which could then lease theland again in smaller tract sizes. The UnitedKingdom, Norway, and Canada require that firmsrelinquish 50 to 65 percent of the lease tract after3 to 5 years of exploration. The government bene-fits from the information generated by the broad-scale exploration efforts.

Joint Bidding

The extremely high costs of exploration in fron-tier areas may prompt a need to allow joint bid-ding by the major oil companies on offshore leases.In October 1975, the Department of the Interiorbanned oil companies with worldwide productionin excess of 1.6 million barrels per day of oilequivalent from participating in the same joint bid-ding group for offshore leases. This restriction be-came law with the enactment of the Energy Policyand Conservation Act of 1975, The OCS LandsAct Amendments modified the ban by allowing theSecretary of the Interior to authorize joint biddingby the majors on lands with extremely high explora-tion costs or where activity might not occur other-wise. The joint bidding ban so far has not beenlifted for any sale,

Joint bidding has played a key role in OCS leasesales since the start of leasing in 1954. In the 35pre-ban lease sales, about 10 percent of the bidswere joint bids among the seven or eight largestoil companies. Recently, the majors not affectedby the ban have frequently bid together on the moreattractive and expensive tracts. The list of U.S.companies affected by the ban is updated every 6months by the Department of the Interior and hasincluded such firms as Exxon, Texaco, Mobil,Shell, Standard Oil of California, and Chevron.

A variety of concerns has prompted the contin-uance of the ban on joint bidding and even initi-ated political pressures in the early 1980s for ex-tension of the ban to the 16 largest U.S. oil and


gas companies. A major purpose of the ban is tofacilitate the participation of smaller firms in off-shore lease sales. Joint ventures among the majorsmight preclude their bidding with smaller firms,who would otherwise not gain entry to OCS activ-ity. Joint bidding by the majors may also be a sub-stitute for individual participation and reduce thenumber of competitors for OCS tracts and govern-ment cash bonus revenues. Greater competitionand diversification of tract ownership are believedto provide for increased capital availability andmore efficient exploration.

Joint bidding by the majors also prompts fearsof collusion in other offshore areas and markets.At joint bidders’ conferences, the majors maydiscern tracts on which other firms are not plan-ning to bid, allowing them to lower their bids onthese tracts. Joint ventures by the majors on OCSleases might also foster collusion in refining, proc-essing, or related markets and increase their down-stream market power.

A number of statistical analyses of OCS biddingand leasing data have tested the various hypothe-ses concerning the effects of the joint bidding ban.It is argued that the joint bidding ban itself is an-ticompetitive because the average number of bidsper tract has actually decreased since the imposi-tion of the ban.54 Similarly, it has been shown that

stB~ian Sul]ivan and Paul Kobrin. “The Joint Bidding Ban: Pro-and 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 increasesas the concentration of joint bids increases and thatthe ban results in government revenue losses.55

However, the percentage of offshore leases won bynon-major oil companies and the number of suc-cessful bidders in offshore lease sales have increasedsince the ban was put in place.56 All of these ef-fects could be due to causes other than the joint bid-ding ban. In general, it is difficult to draw anystrong conclusions based on these studies about theeffect of the ban on OCS participation rates, bid-ding rates, or government revenues.

Removing the ban on joint bidding by the ma-jor oil companies would allow them to share thefinancial burdens and risks of investments in off-shore frontier areas and might provide an additionalincentive to exploration and development. Thecompetitive effects of the joint bidding ban are lesssignificant in Arctic and deepwater areas, wherethe number of firms which may participate islimited by the high costs of exploration. The jointbidding ban eventually may have unwanted nega-tive effects in frontier areas in discouraging par-ticipation and in lowering bids.

55Alan Rockwood, “The Impact of Joint Ventures on the Marketfor OCS Oil and Gas Leases, ‘Journal of Znc/ustria/ Economics (June1983), pp. 453-468.

sGLes]ie Grayson et. ~., ‘ ‘Issues of Competition on the Outer Con-tinental Shelf, ” Journal of Natural Resources Law, (spring 1983),p. 97,

Chapter 7

Environmental Considerations

Contents

Page

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163

Environmental Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164Expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165Types of Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168Trends in the Environmental Studies Program. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170

Biological Resources. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173Overview. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173Affected Species . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174Bowhead Whales: A Case Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176

Oil Spills . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 185Limits to Effective Countermeasures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 186Countermeasures Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188Government/Industry Responsibilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197Technology Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200


7-1. Use of Environmental Information in Leasing Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1667-2. Oil Spill Probabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1857-3. Oil Spill Technology Research Needs. . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . 201


7-1. Expenditures for Environmental Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1677-2. Expenditures for Environmental Studies by Region . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1677-3. Recent Trends in Environmental Studies Funding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1687-4. Funding for Alaskan Environmental Studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1687-5. Funding for Alaskan Environmental Studies by Type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169

Chapter 7

Environmental Considerations

OVERVIEW

The development of petroleum resources in fron-tier areas of the Outer Continental Shelf (OCS) hasbecome an important strategy in meeting the Na-tion’s future energy needs. At the same time, a na-tional consensus exists that protecting the environ-ment from the effects of OCS development isequally important. Several laws are in force whichaddress the potentially conflicting goals of environ-mental protection and resource development:

● The Outer Continental Shelf Lands Act (OCSLands Act) of 1953 (amended in 1978) man-dates, among other things, that environmentalstudies be done ‘ ‘in order to establish infor-mat ion needed for assessment and manage-ment of environmental impacts on the human,marine, and coastal environments of the OuterContinental Shelf and the coastal areas whichmay be affected by oil and gas development.”1

● The National Environmental Policy Act(NEPA) of 1969 requires that all Federal agen-cies ‘‘utilize a systematic, interdisciplinary ap-proach which will insure the integrated use ofthe natural and social sciences and the envi-ronmental design arts in planning and in deci-sionmaking which may have an impact uponman’s environment. The NEPA requiresthat an Environmental Impact Statement beprepared for major Federal actions.

● The Marine Protection, Research and Sanc-tuaries Act prohibits the unregulated dump-ing of waste materials into coastal and oceanwaters and authorizes the Secretary of Com-merce to designate offshore marine sanc-tuaries. 3

‘Public Law 83-212, 67 Stat. 462 (1953), 43 USC 1331-1356, asamended 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, asamended 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; 16USC 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 en-dangered and threatened species of fish, wild-life, and plants (and the ecosystems on whichthey depend) be determined and conserved,and it authorizes issuance of regulations nec-essary for protection of these species.4

The Marine Mammal Protection Act providesfor the conservation and management ofmarine mammals.5

The Coastal Zone Management Act (CZMA)provides for management and protection of thecoastal zone in cooperation with states. b Underthe CZMA Federal actions must be consist-ent with approved state coastal zone manage-ment programs.The Federal Water Pollution Control Act(FWPCA) provides for the restoration andmaintenance of the quality of the Nation’swaters. 7 Among other things, the FWPCA re-quires discharge permits for OCS activities.

Several important environmental concerns arerelated to oil and gas development in frontier areas.If OCS exploration and development is to proceedwith due regard for environmental protection andif sound lease management decisions are to bemade, a large quantity of environmental informa-tion is needed. This is particularly true in Arcticfrontier areas where relatively less is known aboutmarine ecosystems and the manner in which theymay be affected by OCS activities. Given fundingconstraints for environmental research, it is par-ticularly important that such information be basedon sound scientific procedures, provided in a timelymanner, available to all interested parties, and rele-

4Public Law 93-205, 87 Stat. 884 ( 1973), 16 USC 1531-1543, asamended 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, asamended 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 PublicLaws 93-612 (1975), 94-370 (1976), and 95-372 (1978).

‘Public Law 845, 62 Stat. 1155 ( 1948), 33 USC 1251-1367, asamended.

163


vant to the pre-and post-lease decisions that mustbe made. The major program for developing theinformation necessary for predicting, assessing, andmanaging the effects of OCS development is theDepartment of the Interior’s Environmental StudiesProgram (ESP).

It is beyond the scope of this assessment to doan exhaustive study of all biological resources thatpotentially may be affected by OCS oil and gas de-velopment. Some endangered species and some spe-cies of commercial importance which may be af-fected by oil and gas activities in Arctic areas arebriefly considered. In lieu of a thorough analysisof all species, a detailed case study of bowheadwhales is presented. Although not the only Arcticmarine mammal listed as endangered, this specieshas received considerable attention in recent years.The possible vulnerability of bowhead whales to oiland gas activities has been the subject of intensedebate among groups with different values and dif-ferent objectives for Arctic development. Organi-zations including the Minerals Management Serv-ice (MMS), the National Marine Fisheries Service(NMFS), the Alaska Eskimo Whaling Commission,and the oil and gas industry have funded bowheadwhale research in an effort to better understand thelife history of the species and to determine the po-

tential effects of OCS oil and gas activities on thespecies’ behavior, survival, and reproduction.

Technology and techniques for oil spill contain-ment and clean up in frontier areas are an impor-tant environmental consideration. While the oil andgas industry is genuinely concerned with prevent-ing oil spills, the industry’s capability to containand clean up spilled oil in hostile environments hasnot been proven under actual conditions. Thisassessment focuses on the evaluation of the state-of-the-art of Arctic oil spill countermeasures. Lessattention is given to deepwater spills. Althoughsome deepwater oil spills may occur as the oil andgas industry moves further offshore, and althoughcurrent capability to clean up such spills is limited,the equipment and methods for combating deep-water spills are essentially no different than thoseused for nearshore areas. Most deepwater spills willlikely be of less concern than shallow water, near-shore spills because: 1 ) they generally occur in lessbiologically sensitive areas; 2) natural processes mayoften work to dissipate and degrade deepwater spillsbefore significant damage can be done; and 3)greater distance from shore allows more lead timein which to consider what (if anything) is to bedone.

ENVIRONMENTAL INFORMATION

OverviewThe Department of the Interior (DOI) is respon-

sible for leasing and managing OCS lands. As man-ager of the OCS leasing program, it is DOI'sresponsibility to ensure that environmental safe-guards are employed. Specifically, DOI mustensure that OCS operations are

. . . conducted in a safe manner by well-trainedpersonnel using technology, precautions and tech-niques sufficient to prevent or minimize theliklihood of blowouts, loss of well control, fires,spillages, physical obstruction to other users of thewaters or subsoil and seabed, or other occurrenceswhich may cause damage to the environment orproperty, or endanger life or health.8

8Section 3(6), Supra note 1.

In order to meet this responsibility, DOI mustbe able to assess the environmental impacts ofproposed offshore development, to delineate sen-sitive and unique areas, and to determine environ-mental hazards. The need for scientific informationto accomplish these tasks led to the establishmentof the Environmental Studies Program in 1973.This is the major scientific program designed toacquire information for OCS leasing.

ESP was initially administered by the Bureau ofLand Management (BLM). However, in 1982,then Secretary of the Interior James Watt createdMMS in order to streamline the administration ofthe leasing process, and the responsibility for theESP was transferred to MMS. The environmentalinformation generated by ESP research projects isused by the Secretary of the Interior and by the

Ch. 7—Environmental Considerations . 165

environmental assessment and leasing managementdivisions of the MMS in order to carry out theirresponsibilities under the NEPA and the OCSLands Act. The Secretary of the Interior uses ESPinformation (as presented in NEPA documents andin the Secretarial Issue Document for each sale) forsale-related decisions.

The studies program is divided among the fourMMS regional offices—the Alaska, the Atlantic,the Gulf of Mexico, and the Pacific regions—andthe headquarters office. Alaska studies have re-ceived the most attention because the Alaska OCSis the largest OCS area (comprising about 74 per-cent of OCS lands) as well as the least explored andleast studied area.

Relatively little information was available priorto 1973 to assess the potential impacts of oil andgas development, and data gaps were especiallylarge 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 theAlaskan OCS. Therefore, in 1974, BLM contractedwith the National Oceanic and Atmospheric Ad-ministration (NOAA) to design and manage anenvironmental studies program for the Alaskan re-gion. NOAA initiated the Outer Continental ShelfEnvironmental Assessment Program (OCSEAP)for Alaskan studies, OCSEAP has become one ofthe most comprehensive programs for the collectionand evaluation of Arctic environmental informa-tion. It is also the largest single segment of the envi-ronmental studies programs funded by the MMS.

MMS directly manages all environmental studiesin the Atlantic, Gulf, and Pacific OCS regions andsome of the Alaskan OCS studies (including sometransport studies and endangered species and mon-itoring studies). MMS also manages the AlaskaSocial and Economic Studies Program. This pro-gram, begun in 1976, funds studies which investi-gate the impact of offshore oil and gas developmenton economic, social, and cultural systems of coastalresidents, communities, and regions. Seventy-fivepercent of MMS funds for social and economicstudies have been spent in Alaska.

The assessment of environmental informationneeds and the development of environmentalstudies occur annually through the MMS Regional

Studies Plans. Assistance in developing RegionalStudies Plans is given by Regional TechnicalWorking Groups in each OCS area. In the Alaskaregion, this group is composed of representativesfrom the MMS, the State of Alaska, the Fish andWildlife Service, t h e N M F S , t h e U . S . C o a s tGuard, the Environmental Protection Agency, in-dustry, and private groups. The OCS AdvisoryBoard Scientific Committee also comments on theplans during development.

Studies are ranked according to: 1) the impor-tance of the research to decision-makers; 2) the dateof the decision for which the study results are tobe used; 3) the generic applicability of results ortechniques from the study; 4) the availability andcompleteness of existing information; and 5) theapplicability of the information to issues of regionalor programmatic concern.9

With respect to the Alaskan OCS, informationneeds identified by MMS are utilized by NOAAto prepare an annual Technical Development Planfor OCSEAP research.10 OCSEAP research is per-formed at universities, State and Federal agencies,private firms, and research institutions. Privatefirms currently receive the greatest proportion ofESP funding in Alaska, and that proportion hasbeen increasing.

The results of research projects are utilized inthe OCS leasing decision process at various stages.The steps in which scientific information is incor-porated into leasing decisions are described in table7-1. Results from the studies program and otherscientific information are also utilized in post-leasepermitting, post-lease environmental analyses, and(if necessary) development environmental impactstatements.

Expenditures

MMS spent approximately $370 million on theESP between 1973, the year in which the programwas initiated, and 1984, the latest year for whichdata are available (see figure 7-l). About half of

‘Minerals Management Service, Alaska Outer Continental ShelfRegion, FY1985 Alaska Regional Studies Plan: Final (October 1983),

lo~ation~ Oceanic and Atmospheric Administration, Outer Con-tinental Shelf En\’ironmental Assessment Program: FY 84 TechnicalDevelopment Plan (August 1983).


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 OCStific results into OCS leasing process. Scientists andscience managers discuss research results, identify Environmental Impact Statement (DEIS).data gaps, determine how results answered OCSmanagement questions. Full synthesis meeting nowheld only for first generation lease sales. Smallermeetings held for second or third sales in an area,

Draft Environmental Impact Statement Endangered Species Consultation

MMS prepares the Draft Environmental Impact State-ment based upon available research results from a biological opinion.variety of sources, including, when applicable, theOCSEAP Synthesis Report (or results from theSynthesis Meeting if report not yet available). DEISmust address major issues related to the proposed

Secretarial Issue Document

action.

Final Environmental Impact Statement

Required to address proposed alternatives discussedin DEIS; incorporates public comment received onDEIS. 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 environ-


these funds have been expended in the Alaska OCS office. Program expenditures increased dramaticallyregion (see figures 7-2). The other half of the budget in 1975 and doubled again in 1976, in response tohas funded studies in the Atlantic, Gulf, and Pa- the decision to lease offshore areas for oil and gascific regions and in the Washington headquarters exploration in Alaska.


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 Studiesby Region (1973-84) (millions of dollars)

Pacific

$185Alaska(50°10)

However, since 1980, when expenditures forenvironmental studies totaled more than $45 mil-lion, budgets for the program have declined, and,in 1984, yearly funding dropped below $30 million(without accounting for inflation) for the first timesince 1975. This trend is consistent with reducednon-defense spending throughout governmentunder the 1981 through 1984 budgets.

Since 1980, ESP funds for the Alaska region havedecreased more rapidly than funding for studies inother areas (see figure 7-3). Although the Alaskaregion budget is still the largest, it has decreasedfrom 55 percent of the budget in 1980 to 45 per-cent in 1984, Funds for Alaska OCS studies havebeen reduced some 49 percent since 1980, from$25.3 million to $12.9 million in 1984 (see figure7-4). Funding for Gulf of Mexico studies has alsodecreased, from 19 percent of the budget in 1980to less than 14 percent in 1984. The proportion ofthe total budget spent for Atlantic and Pacific re-gion studies has increased since 1980, although totaldollar amounts have declined. Funding for theWashington, D.C. headquarters office also in-creased in this period, and in 1984 accounted for5.3 percent of the total ESP budget.

Over the 1 l-year period from 1973 through 1983about 86 percent ($148 million) of Alaska environ-mental studies funds have been used for NOAA/OCSEAP studies. The relationship between NOAAand MMS has changed in recent years. MMS hasgradually upgraded its technical capabilities whichit lacked in the early years of the program, and hasassumed more responsibility for managing Alaskanenvironmental research. The budget for MMS(non-OCSEAP) Alaskan studies has increased–but not dramatically— since 1980, but funding forOCSEAP studies has decreased more than 50 per-cent, from just over $21 million in 1980 to less than$8 million in 1984. Thus, the relative importanceof MMS inhouse and directly contracted environ-mental studies has increased significantly.

SOURCE: Minerals Management Service, Branch of Environmental Studies


Figure 7-3.—Recent Trends in Environmental Studies Figure 7-4.—Funding for Alaskan EnvironmentalFunding (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

Alaska1 1

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 in-vestigation of seismicity and volcanicity; determina-tion of the character of bottom sediments andsubsea permafrost; quantification of the nature, in-tensity, and frequency of sea ice hazards; and deter-mination of wave heights. The objective of thesestudies has been to acquire information useful fordetermining hazards to drill ships, platforms, andpipelines, and for determining the probability ofaccidents caused by environmental hazards.

Transport Mechanisms

The objective of transport studies has been to de-termine the mechanisms involved in transport,weathering, and dispersion of spilled oil, oiledsediments, and other contaminants. A major partof this program has involved physical oceanogra-phy studies, including development of a sophisti-

Types of Studies

ESP and OCSEAP studies maybe classified intoseven categories. These are:

Contaminant Distribution Baseline Studies

These studies were designed to learn more aboutthe background levels of hydrocarbons and heavymetals in the Alaskan OCS in order to establisha baseline for predicting changes if these kinds ofcontaminants were released during oil and gas de-velopment. Funding for baseline studies in theAlaska region was greatest in 1976, 1977, and 1978(see figure 7-5).

Biological Studies

Biological studies have investigated the distribu-tion and population dynamics of birds, mammals,fish, littoral biota, benthic biota, and plankton.These studies have received the largest total amountof funding since the inception of the program.


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 ver-sion of which the MMS now uses for risk analysis.Such models are important because they help tofocus impact assessment on identified vulnerablecoastlines and marine biological resources at risk.They also can lead to local site-specific modelswhich could allow assessment of OCS activitiesaffecting circulation patterns, or whose impact isdistributed regionally by circulation (e. g., causewayconstruction, sand and gravel extraction, hydro-carbon production byproducts, and marine con-struction siting).

Effects Studies

Effects studies investigate the interactions ofspilled oil and other contaminants on individualspecies and ecosystems. For example, effects studieshave been done for salmon, herring, and king andtanner crabs.

1979 1981 1983

Year

Ecosystem Processes

The purpose of process studies is to investigateand understand aspects of community structure andfunction. Although some biological process studieshave been undertaken in specific ecosystems, thereare still other ecosystems for which processes needto be better understood. Studies of ecosystem struc-ture and processes tend to involve many scientistsin different disciplines, all collecting field data con-currently. Thus, these studies are expensive andsite specific. Ecosystem studies have been conductedat Simpson Lagoon and Pearl Bay, and studies ofthe Yukon Delta and the North Aleutian Shelf arein progress.

Socioeconomic Studies

The objective of these studies is to assess thesocial costs of OCS operations, e.g. , the impacts


of coastal development, tanker traffic, and marinepollution associated with OCS development; effectson local cultural systems; damages to personal prop-erty and property values; and costs to recreationaland/or subsistence uses.

Trends in the EnvironmentalStudies Program

Scope and Direction

Baseline studies. Baseline characteristics and con-taminants in Arctic regions have been extensivelystudied. However, this class of background studywas criticized by scientists in the 1978 National Re-search Council ESP review because the natural geo-graphic and temporal variability of the marine envi-ronment is so great, both in space and time, thatuseful baselines could not be established withoutprior information on the types and specific loca-tions of the development to be undertaken. Thus,the studies would be of little use either for predict-ing changes or for quantifying change during andafter development. Consequently, funding for thesestudies was cut significantly in 1979, and, begin-ning in 1982, no funds were allocated for baselinestudies. Now that development in specific ArcticOCS areas may occur, concern about monitoringthe effects of OCS activities has increased, and moresite-specific work will be necessary.

Biological studies. Funding for biological studieshas decreased in the last several years by a greaterproportion than decreases for the ESP as a whole.Basic information about Arctic biota is now rela-tively well known. However, data are still lackingfor many geographic and subject areas (e. g., areasoutside the fast ice zone in the Beaufort Sea). TheInteragency Committee on Ocean Pollution Re-search, Development, and Monitoring considersthe Beaufort Sea living resources studies importantbecause they are process oriented. ” These studieshave proven more effective than studies whichsimply enumerate and catalog biota. For example,the results of ecological process studies in SimpsonLagoon provided the nucleus for biological stip-ulations attached to the joint State/Federal BeaufortSea lease sale in 1979 and for other lease sales.

111~teragency Cornrn it[cc on Ocean Pollution Research, Develop-ment, and Monitoring, Marine Oil Pollution: Federzd Program Re-view (April 1981 ).

Funding for endangered species studies has in-creased significantly since the beginning of the ESP.In fiscal years 1982 and 1983, endangered speciesstudies accounted for the largest percentage (about35 percent) of Alaska ESP expenditures. The en-dangered species most studied have been bowheadand gray whales. The Endangered Species Act isa major reason that studies of endangered whaleshave been emphasized. Federal agencies mustensure that actions which they authorize, fund, orcarry out are not likely to jeopardize the existenceof any endangered “or threatened species. The em-phasis on bowhead whale studies, in particular, isalso motivated by regional political concerns. Sev-eral interest groups have important, but not nec-essarily compatible, interests concerning thespecies.

Hazards studies. In the early stages of the ESP,there was a large geological hazards assessmentprogram. Funding for environmental hazardsstudies peaked in 1980 at $12.6 million per year(of which two-thirds was allocated to Alaska OCSstudies). Since then, funding has been reduced sig-nificantly. In 1983, total ESP funding amountedto only $1.4 million. The decrease in funding hascorresponded to an evolution in DOI policy con-cerning the appropriate scope of the Federal Gov-ernment’s research responsibilities relative to thoseexpected of the private sector. It is the MMSposition that most hazards studies should be under-taken by industry. In particular, industry mustundertake site-specific hazards studies in order toproperly design offshore structures, pipelines, etc.,and must provide the data to the MMS OffshoreField Operations for exploration plan and permitapprovals.

Reduced ESP funding for geological hazardsstudies has been controversial. Some groups believethat the government should have an independentlyacquired, public body of information in order toproperly perform its oversight role of assessing theperformance of the industry in their proposed futureOCS activities, and that the current program doesnot provide the government with this capability.Thus, it is contended that government needs astronger capability to evaluate offshore hazards andthe measures that industry is developing to respondto them. This would require more Federal involve-ment in hazards studies and more funding.

Ch. 7—Environmental Considerations ● 171

Transport mechanism studies. Transport studiesgenerally have been of high quality, especially inAlaska where relatively less was known. Neverthe-less, regional gaps remain, such as the need forbetter information about sediment transport in theBering Sea (e. g., for designing gathering pipelinesand subsea completions) and the need for weatherand ice data in the Bering and Chukchi Seas. Mosttransport studies require data acquisition over peri-ods of years, requiring many instruments andrepetitive surveys. However, risk analysis is con-ducted using simulation models which project prob-able transport based on physical and chemical prop-erties and available field data.

Effects studies. Although research needs remain,funding for effects studies has decreased by morethan 50 percent since 1980. Knowledge of effectsof offshore development (e. g., the effects of oil spills,the effects of artificial structures on living orga-nisms, the effects of coastal modifications on thenatural 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 pos-sible exception of noise) would be too localized toplay a major part in formulating large-scale researchpolicy. Several effects studies have been completedor are underway.

Socioeconomic studies. In comparison to otherstudies areas, relatively little money has been spentby MMS on socioeconomic studies (e. g., $2.0 mil-lion in 1983), Social and economic studies are oftenless expensive than equipment-intensive environ-mental studies. Hence, although less money hasbeen spent, the number of socioeconomic studiesfunded through 1983 (133) is large relative to thenumbers of studies funded in other categories. Mostof these funds have been spent in Alaska. On theother hand, the 1981 report of the InteragencyCommittee on Ocean Pollution Research, Devel-opment, and Monitoring notes that higher priorityis generally assigned to studies which are legallymandated or which are designed to avoid lawsuitsor to accommodate political concerns. Thus, studiesaddressing economic and social issues may havegreater difficulty meeting the criteria for funding.

Management

Funds allocated to the OCSEAP program havedecreased since 1980, and MMS has increased its

capability to manage environmental studies. Therelationship between OCSEAP and MMS is chang-ing, and some critics have argued that the largerrole for MMS in directly managing Alaskan envi-ronmental studies may not be the optimum situa-tion. The argument against MMS’s involvementis that the agency responsible for OCS leasingshould not also be in charge of determining whatenvironmental research is necessary and of super-vising subsequent research efforts. Thus, a continu-ing OCSEAP role is seen by some as desirable inorder to help ensure that scientific knowledge is pro-duced which is needed to achieve a balance betweenoffshore oil and gas development and environ-mental protection, thus safeguarding the public in-terest. Conversely, the OCSEAP program hasalways been supported by interagency transfer ofBLM/MMS funds, and OCSEAP managers haveworked under the guidance of the MMS. MMSis legally required by the OCS Lands Act andNEPA to acquire information relevant to poten-tial environmental impacts, and is increasing its ca-pability to do this itself.

In 1978, a National Research Council review ofthe ESP concluded that the program at that timedid not effectively contribute to leasing decisionsor to the accrual of sound scientific information ade-quate for OCS management. The National Re-search Council cited several reasons for poor pro-gram design, including low priority within DOI andthe paucity of professional experience within thestaff. 12 Many of the important issues raised by theNRC have been addressed, and, in particular, thecreation of MMS, improvements in staff, and re-design of the program have produced informationmore directly related to the management of OCSactivity. However, despite the fact that MMS isnow conducting the post-lease monitoring requiredby the OCS Lands Act, MMS’s research efforts—given its leasing mission—have mostly been focusedon immediate rather than long-range informationneeds. Approaches should be considered that helpensure that important longer term studies, notmotivated by near-term leasing decisions, areundertaken.

1 ZNationa] Research Council, OCS Oil and Gas: An Assessmentof the Department of the Interior Environmental Studies Program(Washington, DC: National Academy of Science, 1978).


Funding

Each year less money is available for environ-mental studies, and fewer such studies are funded.This raises the fundamental question of what levelof funding is adequate for OCS decision makingand management, and, related to this, what infor-mation base is adequate for decision making. Onthe one hand, a large body of OCS environmentalinformation has been acquired in the past 10 years.The current information base is increasingly suffi-cient for most pre-lease decisions in all OCS re-gions. This is a major reason why MMS is nowshifting the focus of environmental studies towardresearch designed to answer operational questions.

Nevertheless, the stated national objective is toincrease reliance upon domestic petroleum re-sources, and at the same time minimize environ-mental disturbance. To do this properly, a signifi-cant research effort is still required—particularlyfor post-lease studies and in Arctic and deepwaterareas—and research in OCS frontier areas is ex-pensive. Adding to the expense of Arctic and deep-water studies is the fact that opportunities for con-ducting research are constrained by weather andother variables.

The Federal budget is under scrutiny, and it maybe difficult to increase funding for OCS environ-mental studies. However, the size of the AlaskanOCS and the amount of estimated oil and gas re-serves, the frontier character of the Alaska region,and the high costs of logistics and support opera-tions may warrant the continued emphasis on fund-ing for this area relative to the other OCS areas.It is not necessary, however, to rely entirely on re-search funded by the ESP/OCSEAP program toanswer all important research questions. Some re-sults from other research programs, both Arctic andnon-Arctic (e. g., the National Science Foundation’sArctic Research Program, MMS’s TechnologyAssessment and Research Program, etc. ) may beuseful.

Emphasis

The main thrust of the ESP, until recently, hasbeen to gather information useful primarily for theleasing decision itself. In 1978, the National Re-search Council criticized BLM’s (now MMS) in-adequate program design for post-lease environ-

mental studies. Increasing emphasis is now beingplaced on post-lease management and monitoringstudies. For instance, in 1984, MMS implementeda long-term monitoring program for the BeaufortSea to determine if any trends can be observed inconcentrations of heavy metals and other contami-nants. Such studies are expensive and require con-tinuous funding.

Both the MMS and NOAA are chartered to doocean monitoring studies. MMS is specificallycharged with monitoring the effects of OCS oper-ations while NOAA has a more general mandateto study long-range effects of pollution and man-induced changes of ocean ecosystems. This overlapof responsibilities is sometimes confusing and hasfostered occasional competition between MMS andNOAA. In this regard, the Biological Task Forcesthat have been organized for the Bering andBeaufort Seas may be able to play a larger role infostering coordination and cooperation among theFederal environmental monitoring programs.These task forces are composed of agency repre-sentatives from MMS, the Environmental Protec-tion Agency (EPA), Fish and Wildlife Service, andNMFS (State and local observers participate as wellin Alaska). They were created to give these agen-cies an opportunity to advise MMS’s RegionalSupervisor of Field Operations on the biologicalaspects of the lessee’s proposed activities and to rec-ommend appropriate actions for protecting biologi-cal resources.

Public Participation

Environmental groups are concerned that pub-lic input to the decisionmaking process has de-creased since 1981. Environmentalists perceive thatless scientific information related to the oil and gasleasing program is being disseminated, and that thepublic is therefore less informed than it was imme-diately after the OCS Lands Act Amendments wereimplemented in 1978. For example, environmen-talists contend that Synthesis Reports, which arehelpful to the public in evaluating environmentalimpact statements, are not available sufficiently inadvance of lease sales. DOI is attempting to respondto the criticisms of the environmental groups withregard to dissemination of study results. Beginningin July, 1984, for instance, DOI began publishinga list of offshore scientific and technical publica-

Ch. 7—Environmental Considerations • 173

tions available to the public. A list of OCSEAP-supported publications has been available since1980, In addition, the ESP has begun a project tomake available abstracts of most prior environ-mental studies, and MMS now conducts annualInformation Transfer meetings to help disseminatethe results of studies. Nevertheless, funding for pub-lication of research results has declined, and it doestake longer to get information published.

Public participation and input to the process ofdetermining research needs has also decreased,according to environmental groups monitoringDOI’s OCS program, and it has thus become more

difficult for the public to participate in framing theresearch questions to be addressed by the environ-mental studies program. The MMS argues thatthere are ample opportunities for public participa-tion, including Scoping Meetings, which are heldat an early stage in the lease process to give citizensa chance to express their concerns. However,another useful forum for involving the public at anearly stage of the research planning process, theOCSEAP Users Panel, no longer exists, and theRegional Technical Working Group in Alaska hasbeen meeting less frequently.

BIOLOGICAL RESOURCES

Overview

Since the Torrey Canyon and Santa Barbara oilspills in 1967 and 1969, the effects of oil spill ac-cidents have been studied intensively.13 Despite thisstudy, there is still a great deal of controversy re-garding the effects of oil in the marine environment.A major problem in assessing the effects of pollu-tion is that natural variation of biological popula-tions and water quality in the ocean is very greatand poorly understood. It is difficult to detectchanges and to relate these changes to a specificpollution event. MMS has made some attempt torank the OCS planning areas in terms of their po-tential vulnerability to spilled oil (see box).

There have been few documented effects of oilin the water column, even from such massive spillsas 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. Whenfresh oil reaches the bottom, effects including deathamong sensitive benthic species may occur. Sub-lethal contamination of zooplankton and benthicinvertebrates is common. Studies have shown (e. g.,of the Arrow spill off the coast of Nova Scotia) that

J1 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 ofthe OCS Planning Areasa

Overall totalPlanning area score● . . . . . . . . . . . . . . . . 345

● . . . . . . . . . . . . . . , , , . . 307. . * . * . . . . . . . . . . . . . . . . . . . . . 303

Kodiak . . . . . . . . . . . . . . . . . . . . . . .Gulf of Alaska . . . . . . . . . . . . . . . . . . . 283St. George Basin . . . . . . . . . . . . . . . . . 278

. . . . . . . . . . . . . . . . . . . . . 278North Aleutian Basin . . . . . . . . . . . . . 264Cook lnlet. . . . . . . . . . . . . . . . . . . . . . . 255Central Gulf of Mexico . . . . . . . . . . . . 253North Atlantic . . . . . . . . . . . . . . . . . . . 245Central California . . . . . . . . . . . . . . . . 244Northern California . . . . . . . . . . . . . . . 234

Hope Basin . . . . . . . . . . . . . . . 231Southern California . . . . . . . . . . . . . . . 222

Chukchi Sea. . . . . . . . . . . . . . . . . . . . . 212 South Atlantic . ● . . . . . ● . . . . . . . . . . . 208Eastern Gulf of Mexic o . . . . . . . . . . .Washington-Oregon . ● . . . 203

. . . . . . . . . . .Mid-Atlantic. . . . . . . . . . . . . . . . . 185

Beaufort Sea . . . . . . . . . . . . . . . . 183 Navarin Basin. . . . . . . . . . . . . . . . . . . .

Aleutian Basin . .. . . . . . .

-3@MI&M ofconM UWI mdno h@blt@$ In ~nlng8r@a

.@ * t@*~9et9 of 6plnod 01{.**r

Mwqpm8nt $91vke, Dfaft Pfopo8ed Progm,4w)8fGn?tihonta/ I$hw al ma Q# bnlng Plvgfam for

M&f- 7Wuu@ MiUDl&UH, -?! 1*.


oil contamination can decrease the abundance oforganisms and the diversity of species of benthiccommunities. However, there are striking differ-ences in sensitivities among these species. Persist-ent effects have been found in soft sediments inshallow, protected waters, where natural recoverymay take 6 to 12 years or more. Rocky headlandsare much more quickly cleansed, and generally re-cover within a few years, at least to the extent ofrecolonization of the substrate. Where initialrecolonization is not by the normal dominant spe-cies, however, time for return to initial conditionsthrough succession may be much greater.

Affected Species

Fish

The commercial fish stocks of the Bering Sea andGeorges Bank are world-renowned. Importantcommercial fisheries exist in most other U.S. OCSareas as well, and subsistence fishing is importantin the Beaufort, Chukchi, and Bering Seas and theGulf of Alaska. In the Bering Sea, for example,lease sales have been held or are being planned insuch productive fishing grounds as the North Aleu-tian Shelf, St. George Basin, and Navarin Basin.Important commercial fish species in these areasinclude: sockeye, chinook, chum, Pacific, pink, andcoho salmon; Tanner and king crabs; Pacific her-ring; Pacific halibut; yellowfin, flathead, and rocksole; walleye pollack; Pacific cod; Greenland tur-bot; sablefish; Pacific Ocean perch; atka mackerel;arrowtooth flounder; sidestripe, pink, and humpyshrimp; and Alaska plaice. In addition to theUnited States, Japan, the Soviet Union, South Ko-rea and several other nations regularly fish thesewaters. The 1983 ex-vessel (before processing) com-mercial value of the Bering Sea catch was about$409 million dollars.

The regional effects of oil spills on most speciesof fish are likely to be minor. It has been noted that:

. . . although there is a widespread public percep-tion of impending environmental degradation andresulting loss to harvestable populations coincidingwith possible oil spills, this does not appear to bejustified for relatively small oil spills . . . [b]ecausemost species are widely dispersed in the BeringSea and because stocks exhibit high annual vari-ability in year class strengths. [E]ven the largest

estimated oil-induced mortalities from spills occur-ring under open-water conditions would probablybe undetectable in regional fisheries.14

However, species which spawn in nearshore areasin relatively few locations—for example, salmon,herring, capelin—could be particularly vulnerableto a large spill. A large oil spill in Bristol Bay, forinstance, during a period in which salmon weremigrating to their spawning grounds could havesubstantial effects on a large portion of a year class.Kills of adult fish probably pose less of a threat tocommercial fisheries than do damage to eggs andlarvae, or changes in the ecosystem supporting thefishery. The greatest potential effect on fish popu-lations would probably occur if oil were spilled inspawning or nursery areas where larvae and eggswere abundant, or if local populations of food spe-cies of adults, juveniles, or larvae were reduced oreliminated.

Birds

Birds are particularly susceptible to the effectsof oil spills and human interference. Depending onthe time of year, large numbers may be present inArctic areas. For example, at least six millionmarine birds breed on the Pribilof Islands and onSt. Matthew and St. Lawrence Islands adjacent tothe Navarin Basin.

Birds most vulnerable to oiling are those whichare gregarious, spend much of their time on thesurface, and dive rather than fly when disturbed.These include murres, puffins, and diving duckssuch as eiders, scoters, and oldsquaws. Oiling ofplumage may cause death from hypothermia,shock, or drowning. In addition, death of embryosmay result from the transfer of oil on feathers toeggs. The physiological stress accompanying migra-tion may reduce birds’ ability to survive the addi-tional stress resulting from oiling. Oil ingestionthrough preening could possibly reduce reproduc-tion in some birds and causes various pathologicalconditions.

l+ Fredrik V. Thorsteinson and Lyman K. Thorsteinson, ‘‘FisheryResources, ‘‘ in Lyman K. Thorsteinson, Ed., Proceedings ofa Syn-thesis Meeting: The North Aleutian Shelf Environment and PossibleConsequences of Offshore Oil and Gas Development (Juneau, Alaska:Outer Continental Shelf Environment Assessment Program, March1984), p. 153.


Oil spills occurring near colonies or along migra-tion corridors could have substantial effects onseabirds and waterfowl. Oil reaching coastal wet-lands could persist for a long period of time, andlarge numbers of birds could be contaminated. TheMMS estimates, for instance, that important re-gional seabird populations on St. Matthew and ad-jacent islands could sustain major losses if spills oc-cur in the area during the breeding season. MMSestimates that seabirds and waterfowl wintering inthe Navarin Basin lease area may sustain losses of10,000 or more birds in each of the several spillsprojected over the life of the field.15 A tanker spillin Unimak Pass, one of the major migration cor-ridors for bird and mammal populations enteringand leaving the Bering Sea, could be particularlyserious, since oil could potentially affect major por-tions of regional populations of both birds andmarine mammals. However, long-term populationresponses of sea-birds to oil-induced mortalities areuncertain due to incomplete data. For example,Great Britain’s seabird populations appear to beincreasing in spite of incremental mortalities in-duced by OCS oil and gas operations in the NorthSea. 16

Marine Mammals

Impacts of potential oil spills on marine mam-mals have received considerable attention. Effectscould include coating of animals with oil, ingestionof oil, and irritation of eyes. Contact with oil mayalso contribute to or alter susceptibility to existingphysiological and/or behavioral stresses. However,‘‘unequivocal evidence for mortality of marinemammals caused by oiling in the wild has not beenobserved.” 17 The potential for adverse effects onmost marine mammals from large and small oilspills is perceived to be low. Adverse effects in theimmediate vicinity of a spill would be unavoidable,but, given the mobility and widespread distribu-tion of most species, the low occurrence rate of largespills, 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., TheNat’arin Basin Environment and Possible Consequences of PlannedOffshore Oil and Gas Development (Juneau, Alaska: Outer Continen-tal 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 areunlikely.

Some species are probably more vulnerable thanothers, and some species may be particularly vul-nerable at certain times of the year or while occu-pying certain habitats. Research to date suggeststhat the animals most at risk are those vulnerableto oiling of fur, such as furred seals, sea otters, andpolar bears. A number of endangered and threat-ened species occur in prospective OCS developmentareas. Other cetaceans inhabiting subarctic seasduring all or part of the year include right, fin, sei,blue, humpback, gray, and sperm whales. Someof these whales (for example, gray whales) migrateconsiderable distances, and may potentially comein contact with oil in several OCS regions.

Several examples of areas where marine mam-mals would be particularly vulnerable include:

St. Matthew Island. In addition to large seasonalconcentrations of nesting birds, St. Matthew Island(and nearby Hall Island), is the location of numer-ous haulout sites for Stellar sea lions, spotted seals,and walruses. Several species of endangered whalesalso inhabit the vicinity. A support facility forNavarin Basin exploration and development hasbeen proposed for this Bering Sea island; however,recent court action denied the facility. In additionto the possible impact of oil spills, marine mam-mals and birds in the area may be exposed to fre-

Photo credit: American Petroleum Institute

Offshore energy production must be balanced withprotection of seals and other wildlife


quent vessel movements, helicopter flights, and con-struction activities.

The Prihilof Islands. In addition to their impor-tance to nesting birds, from May through Augustthe Pribilof Islands are home to over 70 percent ofthe world’s population of northern fur seals, whichbreed and bear their pups there. Fur seals may beparticularly sensitive to oiling since they rely ontheir fur for thermal protection, and oil can destroyits insulative properties. Oil spill trajectory modelsindicate that a St. George Basin spill could possi-bly reach the Pribilof Islands.18

Unimak Pass. Unimak Pass through the Aleu-tian Islands is a major migration corridor for en-dangered gray, fin, and humpback whales, north-ern fur seals, and several species of birds (e. g.,shearwaters and tufted puffins). Although it is pre-dicted that strong currents would likely rapidly washaway spilled oil, a spill large enough to significantlyoil the pass in early spring or late fall could exposegreat numbers of whales, birds, and fur seals tohydrocarbons, and could seriously impact regionalpopulations. In the event of oil and gas discoveriesin the Bering Sea, increased vessel traffic (includingtankers) is expected through the Pass.

Bowhead Whales: A Case Study

Introduction

Bowhead whales are listed as an endangered spe-cies and could be adversely affected by offshore oiland gas operations in the Arctic. The degree of theirvulnerability remains uncertain at this time; how-ever, bowheads are a subject of concern and thetarget of several expensive research projects. As aconsequence of their endangered status, the En-dangered Species Act places specific legal con-straints on all Federal agency activity affecting thespecies. Thus, the potential impacts of offshore oiland gas activities on the bowhead population mustbe considered fully. If these activities are found tojeopardize the continued existence of bowheads orother endangered species, the law requires that ac-

tions 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 Envi-ronment and Possible Consequences of Planned Offshore Oil and Gasllevek~prnent (Juneau, Alaska: Outer Continental Shelf EnvironmentalAssessment Program, March 1982).

to protect bowhead whales could take the form ofrestrictions on or curtailment of Arctic oil and gasdevelopment. Thus, the potential for conflict ex-ists between the competing national objectives ofenergy production and the preservation of an en-dangered species.

Bowhead whales are also highly prized by the in-digenous people of the Arctic (the Inuit) as a sup-plementary source of food and as a part of theircultural heritage. Activities which threaten bowheadwhales are considered by the Inuit to be a threatto their culture and their subsistence lifestyle. Atthe same time, the annual bowhead harvest by In-uit whalers may also be a threat to the existenceof the species. The national effort to protect en-dangered marine mammals competes, to some de-gree, with the local interest in Arctic subsistencehunting. Protection of bowhead whales is thus com-plicated by competing national interests in the pro-duction of domestic energy and the desire to pro-tect endangered species as well as by the interestsof Native Alaskans to pursue their traditionallifestyle. The debate surrounding the bowheadwhale involves complex scientific, political, andsocioeconomic issues for which there are no totallysatisfying answers.

Compared to a pre-exploitation whaling stock(estimated by the International Whaling Commis-sion to be approximately 20,000 animals during the1800s), the minimum population is now believedto be about 3,900, Census taking has improved inrecent years, so that this number is larger than thenumber of whales believed to exist in 1977 (between800 and 1,200 animals), but the figure is still im-precise. For hundreds of years, until about the turnof the century, bowheads were one of the most im-portant commercial whale species. Commercial ex-ploitation of bowheads has ceased, but whaling inseveral coastal Arctic native communities is still animportant cultural activity.

Bowhead whales winter in the Bering Sea, gen-erally south and west of St. Lawrence Island (thefull extent of the area they use is unknown). InMarch and April they begin their northward migra-tion, using the lead systems that develop in the icecover. The whales follow nearshore open leads pastPoint Hope, Cape Lisburne, and Point Barrow andthen move further offshore en route to their sum-mer range in the eastern Beaufort Sea off Canada.


After about mid-September the whales begin theirreturn migration to the Bering Sea. The migrationcorridor is bounded on its landward side by approx-imately the 20-meter isobath and extends on itsseaward side to at least the 50-meter isobath. It isduring the migration periods when the whales areclosest to the coast that they are hunted by Inuit(Eskimo) whalers and, at the same time, may bemost vulnerable to potential disturbance by theactivities of the oil and gas industry.

Concerned Groups

Among the groups with a stake in the future ofthe bowhead whale are the indigenous people of theArctic (the Inuit Eskimos of Alaska), environmen-talists, industry, the Federal Government, and theState of Alaska.

Inuit. For the Inuit, the bowhead whale is an im-portant element of cultural identity. Despite theongoing changes occuring in Alaska whalingvillages, many traditional activities remain impor-tant, and the annual hunting cycle remains essen-tially the same as practiced for generations. Cur-rently, ten Inuit villages participate in bowheadhunting. Eight of these ten villages take part in thespring hunt, and three participate in the fall hunt.Barrow, given its strategic location, is the onlyvillage to participate in both hunting seasons.

A recent survey indicates that most Inuit con-tinue to value hunting and fishing highly and toview these activities as an important source offood. 19 Data from the same survey also suggest thatInuit still prefer locally harvested foods (especiallywhale meat, although seal and walrus are probablyconsumed in greater quantity) despite the influenceof western culture. Inuit maintain that the ‘Eskimoway of life’ would be severely jeopardized if theycould no longer hunt bowhead whales. In additionto the food that the whales provide (which is sharedamong the members of the community), a suc-cessful hunt is an occasion for celebration, a sym-bol of initiation into manhood, and brings prestigeto successful whalers.

Inuit are concerned about potential adverse im-pacts that offshore oil and gas activities could have

1 gAlaska Consultants, inc. , Subsistence Study of Alaska EskimoWhaling Villages report prepared for the U.S. Department of the In-terior (’January 1984).

Photo credit: National Marine Fisheries Service

The endangered bowhead whale is important to theInuit culture

on bowhead whales. They are concerned aboutmaintaining a pollution-free marine environment,about protecting bowhead feeding and nurseryareas, and about preventing seismic survey andother noise-making activities that may interfere withthe annual hunt or with the health of the species.Increasing industrial activity in the Arctic highlightsthe fact that whale hunting now must compete withnational, and even international, interests. Theseconcerns have stimulated an active Inuit-sponsoredresearch program to learn more about the factorswhich affect bowhead whales. This research focuseson bowhead population dynamics (size and growthrates) and on the possible susceptibility to distur-bance from various industrial activities.

Environmentalists. The primary concern of en-viromentalists is for the protection and stewardshipof an endangered species and its marine habitat.Environmentalists are particularly concerned thatthe projected increase in offshore oil and gas activ-ities may be detrimental to the bowhead whale pop-ulation. Offshore exploration and development in-troduces increased levels of industrial noise into themarine environment and raises the potential formarine oil pollution, both of which may be harm-ful to whales. Environmentalists assert that the ef-fects of noise (particularly noise generated bymarine seismic exploration) and of oil pollution onbowhead whales should be fully studied, and thatsteps should be taken to reduce impacts as muchas possible.


Most environmental groups are not enthusiasticabout subsistence whaling, but tend to view it asa legitimate activity so long as vigilant oversightof bowhead stocks is maintained and traditionalmethods are used. A few groups have advocatedthe complete prohibition of native whaling of en-dangered whales. These groups contend that theresult is the same whether the whale is taken bycommercial whalers or native whalers. If the spe-cies is endangered, they reason, no whaling shouldbe allowed.

Between 1970 and 1977, there was about a three-fold increase in the bowhead whale harvest. In1977, the International Whaling Commission notedthis trend with alarm, and established a quota fornative whalers which has been in effect since the1978 harvests, reducing the hunt to approximatehistoric levels. This quota system is considered animportant management tool by environmentalistsand by the Federal Government.

Industry. The oil and gas industry acknowledgesthat under certain circumstances bowhead whalesdo respond to offshore hydrocarbon activities, butdoes not believe that normal operational activitiesconstitute a major problem for the health of thewhale stock. Even if some limited, localized, short-term impacts (e. g., flight response to nearby seismicactivities) are unavoidable, the industry does notbelieve that long-term effects from oil and gas activ-ities will be significant.

Seasonal drilling restrictions have been imposedand protective buffer zones established to mitigatethe possible adverse impacts to bowhead whales.Industry’s consistent opposition to these costlyrestrictions that reduce operating efficiency is basedon their belief that they are not warranted by thescientific evidence. However, industry wishes toavoid unnecessary interruptions in its long-termoperations, and has therefore participated in somebowhead research projects (for instance, by dedi-cating geophysical ship time to assess seismic im-pacts on bowhead whales).

The industry is convinced that, given currenttechnology and personnel training, the possibilityof a major blowout in the Arctic is remote, and thateven if such an accident were to occur, the capa-bility to recover most spilled oil and thus to avoidharm to whales, is adequate. Since the first stipula-

tions attached to the 1979 joint Federal/State leasesale in the Beaufort Sea, lease stipulations insidethe barrier islands have become less stringent. How-ever, industry is still unhappy with seasonal drillingrestrictions.

The Federal Government. The Federal Govern-ment is responsible for promoting OCS develop-ment, protecting endangered species, and ensur-ing that Native interests are considered. The desireto stimulate domestic petroleum production was theprimary reason for the Administration’s decisionto accelerate leasing of OCS lands. In addition, thesale of leases for OCS energy exploitation is thesecond-ranked source of Federal revenues, andOCS resources are seen as insurance against po-tential international energy supply disruptions.

Federal development and protection objectivesare potentially in conflict, particularly since leas-ing is now taking place at a faster pace in Alaskanoffshore areas. However, several Federal laws pro-vide for the protection and management of bow-head whales. The Endangered Species Act of 1973prohibits the taking, harassing, importing, export-ing, or interstate trading of any endangered spe-cies, their parts or products. However, the take byAlaska natives is exempted. The Marine MammalProtection Act of 1972 protects all marine mam-mals from any undue influence or exploitation byU.S. nationals and forbids importation of anymarine mammal products into the country. ‘‘Sub-sistence’ hunting is permitted as long as the stockscan support the harvest, and specific conditions aremet.

The Endangered Species Act specifies that it isthe responsibility of all Federal agencies to conserveendangered species. Each Federal agency is re-quired to ensure, in consultation with the Fish andWildlife Service or the NMFS (as appropriate, forspecies under their respective jurisdictions), thatany action it authorizes, funds, or conducts is notlikely to jeopardize the continued existence of anendangered or threatened species or result in theadverse modification of its critical habitat. Thus,MMS must consult with the NMFS on the prob-able impacts to bowhead whales that might resultfrom many OCS activities for which it issues per-mits. NMFS then issues a biological opinion con-cerning the likelihood that these impacts will jeop-


ardize the survival of the species. If so, NMFS alsodescribes ‘‘reasonable and prudent alternatives’to the activity that would avoid jeopardy.

In practice, NMFS also includes in its biologi-cal opinions recommendations and suggestions thatit feels would help conserve the species, althoughthe Act does not require that they be included.MMS is not legally required to adopt these recom-mendations, suggestions or alternatives to avoidjeopardy so long as the mitigating measures it doesadopt are consistent with the alternatives, wouldeffectively preclude jeopardy, and satisfy the intentof the law.

Some dispute the right of the MMS not to ac-cept all parts of biological opinions. DOI's ‘vetopower’ has been criticized by those who contendthat NMFS recommendations should be binding.However, biological opinions carry weight in thecourts, so DOI must have good reasons for not im-plementing every NMFS recommendation or riskbeing litigated. The biological opinion process hasevolved over the years, and NMFS recommenda-tions for avoiding jeopardy to the species are lessspecific than they once were.

In 1981, the NOAA and the Alaska EskimoWhaling Commission signed a cooperative agree-ment to implement the limited bowhead quotaallowed by the International Whaling Commission(IWC). For calendar years 1981, 1982, and 1983,a quota was established by the IWC for the Ber-ing/Beaufort/Chukchi Sea stock of 45 bowheadslanded and 65 struck, with a maximum of 17 tobe 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 theestimated population per year), but no more than27 can be made in either year. The agreementspecifies whaling techniques, monitoring proce-dures, and division of responsibilities.

Alaska. The State must consider the welfare ofits citizens, and, in this particular case, the wel-fare of those engaged in native whaling. Similarly,the State is concerned with environmental protec-tion. Moreover, since the State derives a major pro-portion of its revenues from the oil and gas indus-

Zowl]]iam F. Gu5ey, ~ow~ea~ (Houston, Texas: Shell Oil Com -

pany, June 1983), p. 87.

try (although none at the present time from FederalOCS leases), it has a major stake in fostering re-sponsible oil and gas development. These interestsmay be conflicting if oil spills or industrial noiseassociated with development adversely affect theenvironment or Native hunting.

The State believes that further research shouldbe undertaken. The State also is concerned aboutthe capability of industry to clean up oil spills andabout the effects of such spills on bowhead whales.For these reasons, in responding to the Draft Envi-ronmental Impact Statement for the 1984 DiapirField Sale No. 87, the State of Alaska recommendedthat sensitive blocks in the eastern and western partsof the sale area be deleted and that all proposedstipulations in the DEIS be adopted. In general,the State believes that mitigating measures arepreferable to tract deletions if adequate scientificinformation is available or if existing technologi-cal capabilities are adequate; however, it was notfelt at that time that these concerns had been ade-quately studied.

More recently, the State’s position regardingbowhead whales was addressed in its decision toallow exploratory drilling in the Beaufort Sea wherethe capability to clean up oil spills in broken icecan be demonstrated. However, in reaching itsdecision to allow longer drilling periods in certaincircumstances, the State reviewed existing bowheadwhale and related knowledge and concluded that:1) the likelihood of a large oil spill from exploratorydrilling was small; 2) the probability that migratingbowhead whales would encounter spilled oil wasalso small; 3) oil spill countermeasures for com-bating spills from artificial islands are now ade-quate; and 4) prohibition of exploratory drilling andother downhole activity during whale migrationsis an adequate measure to ensure that bowheadsare not unduly disturbed by industrial noise. TheState recognizes that information gaps still exist andthat its decision was based on a large amount ofprobabilistic data, but it is satisfied that exploratoryactivities in nearshore areas can be conducted with-out significant impacts on bowhead whales.

Potential Impacts

The June 1984 Diapir Field Final EnvironmentalImpact Statement for Sale No. 87 and accompa-nying comments on the Draft Environmental Im-


pact Statement provide an overview of the currentstate of knowledge concerning the impacts of oil andgas development on the bowhead whale.

Noise. Bowheads may react to noise associatedwith offshore activities. The ocean is naturally noisyowing to sounds created by rain, wind, ice, andthe animals themselves. However, noise pollutionhas been of concern in recent years because somemarine mammal species seem to rely heavily uponsound for communications with one another andfor acquiring information about their surroundings.Since many offshore industrial activities create in-tense sounds, there has been concern that suchsounds may disturb marine mammals and alsomask the ‘‘natural’ sounds that are apparently im-portant to these mammals. In evaluating the po-tential effects of noise from industrial operations,it is important to consider ambient noise levels, thecharacteristics of noise from industry sources andfrom marine mammals, the propagation of soundin water, hearing by marine mammals, the ‘ ‘zoneof influence’ of noise from industry sources, anddocumented reactions of marine mammals to in-dustrial noise.21

Sound can be generated by passing boats andships, by open-water geophysical seismic explora-tion, and by on-ice activities or onshore installa-tions. The intermittent sound generated by seismicsurveys is the most intense type of sound. Short-term behavioral reactions to seismic activity andvessels may include flight from the area, changesin surfacing and dive times, and temporary changesin direction. However, responses of bowheads toseismic activity have been much less clear-cut thanresponses of bowheads to moving vessels.

Evidence demonstrates that bowheads react tolow-flying aircraft by diving suddenly and thus aresensitive to aircraft disturbance. Other sources ofnoise include drilling activities and dredging andgravel island construction, none of which is ex-pected to be as disturbing to whales as vessel noise.Adding the small effects of all these noise distur-bances together, MMS has concluded that duringthe spring and fall migratory period, noise fromseismic activity on leased tracts or from vessels or

“W. J. Richardson et. al., Effects of Offshore Petroleum Opera-tions on Cold Water Marine Mammals (American Petroleum Insti-tute, October 1983).

aircraft could have moderate impacts on bowheads.That is, a portion of the regional population couldchange in abundance and/or distribution over morethan one generation, but is unlikely to affect theregional population. The North Slope Borough andmany environmental groups disagree with this over-all conclusion, and believe that MMS has tendedto downplay evidence suggesting greater effects.

Oil pollution. Few observations of the responsesof bowhead and other whales to oil spills have beenmade. It is unknown whether or not large cetaceansare able to detect hydrocarbon pollution. Dolphins,however, have shown an ability to detect and avoidoil. The rough nature of bowhead whale skin sug-gests that bowheads maybe more vulnerable to af-fects of surface contact with oil than most cetaceans.Concern has also been expressed that bowhead skinand eyes may be sensitive to oil contact, but it isunknown whether contact would be harmful. In-halation of toxic substances and plugging of blow-holes by oil have also been cited as possible, butunlikely, threats.

The potential effect of oil on bowhead feedingis another type of adverse impact. Bowheads maynot be able to differentiate between hydrocarbon-contaminated and uncontaminated food. If thebaleen plates of bowhead whales become fouled byoil, feeding efficiency is decreased, although recentexperiments have shown only minor and short-livedreductions in efficiency. Indirectly, bowheads maybe adversely affected if food sources are reducedby acute or chronic hydrocarbon pollution, but suchpollution would have to be very widespread in or-der to have a serious effect.

The impact of an oil spill on the bowhead whalepopulation would vary depending upon the volumeof oil spilled, the amount of oil in the water col-umn, the extent of weathering of the oil, the pro-portions of habitat affected, the numbers of whalespresent, and other factors. The MMS considers theprobability that oil from an accidental spill willcome in contact with whales in the offshore leadsto be very low, particularly “since whales are notpresent in the lease offerings at all times, and if cer-tain tracts are deleted from lease consideration. ’22

ZZMiner~s Management &rvice, Diapir Field Lease Offering: FindEn\’ironmental Impact Statement (March 1984), p, IV-1OO.


MMS concedes that localized effects of spills couldoccur, but believes that the probable degree of re-gional impact from oilspills within the lease areawill be minor. Other groups believe the impactcould be severe in the case of a major oil spill, andthe NMFS, as noted above, has concluded that anuncontrolled blowout or major oil spill could jeop-ardize the continued existence of the species ifwhales are present and encounter spilled oil.

In the Final Environmental Impact Statementfor the August 1984 Diapir Field lease sale, MMSconcluded that the overall regional impact of thecombined effects of noise and oilspills resulting fromthe original proposal was not expected to exceed‘‘moderate. Moreover, if sensitive tracts in thewestern and eastern portions of the Diapir Fieldsale area were deleted, the combined potentialadverse effects on bowhead whales were expectedby MMS to be minor. Both the State of Alaska andthe North Slope Borough supported these tract dele-tions in order to reduce potential disturbances tothe whales in the spring ice lead system and dur-ing the fall migration offshore of Point Barrow. Asa result, a 20-mile buffer zone was establishedaround Barrow, where the Inuit conduct their hunt;and, although no tracts were deleted in the east-ern Beaufort Sea, a study has been initiated to de-termine whether this area is an important habitatwhere oil and gas exploitation should be restricted.Borough residents believe this is a major improve-ment over the original lease plan. 23

While the MMS bases its conclusions on the bestavailable information, there are still gaps in knowl-edge about bowhead whales. Hence, despite the factthat bowhead whales have been one of the moststudied of the endangered species, there is stilldisagreement concerning the probable effects of oil,noise, and other aspects of human intervention onthe behavior, survival, and reproduction of in-dividuals and populations.24

23’ ‘Plans for Oil Leases Would Protect Whales, The New YorkTimes (August 5, 1984), p. 27.

Z4L, Lee Eberhardt and R. J. Hofman, ‘‘Existing Programs, Tech-nology, and Requirements Relati~.e to the Conservation and Protec-tion of Marine Mammals in the U, S. Fishery Conservation Zoneand in the Southern Ocean, in Technology and Oceanography,(Washington, DC: Office of Technology Assessment, 1981).

Research Priorities

Four general areas for future research appear tobe especially important.

Population studies. There is a continuing needfor more precise information about the status of thebowhead whale population. Shore-based censuses,aerial surveys, and/or acoustical detection meth-ods have been employed in bowhead whale popu-lation studies for about 8 years, yet scientists stillhave not satisfactorily defined population param-eters. Reliable information is needed about the cur-rent and the historic distribution, abundance, andproductivity of the population. Currently, it isbelieved that calves account for at least 7 percentof the population, and that the distribution amongage classes is about normal. However, it is not yetknown whether the bowhead population is grow-ing, stabilized, or decreasing or what the naturalmortality rate is. Such information is important inorder to determine population status and trends toaid in conserving the species. It is also importantto facilitate setting quotas for Native whalers. Thus,if the yearly increment in the bowhead populationcan be accurately determined, it will be possibleto allocate, with a much larger degree of confidence,a portion (e. g., one-half) of this increment to nativehunters.

One hypothesis that has been put forth recentlyis that the Beaufort Sea bowhead whale populationmay be a distinct sub-population or feeding group.While feeding groups in the Chukchi and BeringSeas have been decimated, the Beaufort Sea stockmay, in fact, be healthy and possibly as numerousas before commercial whaling began. This hypoth-esis will be difficult to test; however, historical datamake it clear that large numbers of bowheads onceexisted in the Bering and Chukchi Seas in June,July and August. Thus, of an original western Arc-tic bowhead population of perhaps 20,000 animals,it has been suggested that only one-quarter to one-third of these animals comprised the Beaufort Seasub-population. Since there are now known to bea minimum of 3,900 bowhead whales, the presentstock may be very near historical levels. Thus, asa corollary of this hypothesis, until the Bering andChukchi stocks can be repopulated, one cannot ex-pect the bowhead population to recover, becauseit involves distinct sub-populations. If this hypo-


thesis can be proven, rethinking of bowhead whalestock management would be in order.

Effects of noise. Better understanding of theseeffects will aid in establishing appropriate ‘‘zonesof influence, thereby enabling better protectionof the whales from noise associated with industrialactivities. If one knows the noise levels of an in-dustrial activity and the propagation characteris-tics of the surrounding waters, then it is possibleto determine how far the sound travels and its levelof impact at various distances from the source. Itis much more difficult to determine the effect ofnoise on the whale, in large part because it is diffi-cult to control all aspects of experiments. Resultsfrom the most recent study have shown that whalesdo not exhibit avoidance behavior beyond fourmiles from seismic activities, and that behavioralchanges between about 2 and 4 miles are only tem-porary. 25 Although the presence of whales in thevicinity of industrial activities in the CanadianBeaufort has declined since 1980, evidence prov-ing a cause and effect relationship between indus-trial activities and the decline has not been estab-lished. Canadian efforts to address this question arecurrently underway.

If bowhead whales have a threshold level abovewhich noise causes detrimental effects, then a zoneof influence— generally delimited by a circle—canbe calculated. The zone delimits the area withinwhich activities (e. g., seismic activity) may be re-stricted when whales are present. Several zones maybe postulated, the size of which vary according tothe level of sound and/or the degree of disturbance;however, with currently available information,determining zones of influence may be a theoreti-cal exercise. MMS has established a 5-mile zoneof influence, pending receipt of new data. TheNMFS concurs with this decision. Both agenciesfeel that more information is necessary, however,and MMS has established an experimental programwith cooperating oil and geophysical explorationcompanies to obtain more data concerning whalereactions to seismic activities.

Cumulative effects of industrial activities. Sucheffects are extremely difficult to assess, particularlyin the absence of development. However, it is im-

ZsMiner~S Mmagernent service, “Observations on the Behaviorof Bowhead Whales in the Presence of Operating Seismic Explora-tion Vessels in the Alaskan Beaufort Sea” (Technical Report, 1985).

portant to know whether whales are likely to per-manently vacate oil and gas development areas orwhether they might, in fact, become accustomedto development activities as seems to be the casewith gray whales in Southern California. In addi-tion, as offshore Arctic development increases,whales are likely to encounter more industrial activ-ity. Thus, it is possible that noise and pollution ef-fects, which, in isolation, may not be detrimental,may have a cumulative impact as whales encounterthese effects along their migratory route.

Identification of sensitive habitats, including pri-mary feeding areas and nursery areas within U.S.and Canadian waters. Migrating bowheads inspring do not feed extensively. However, there isnew, but as yet unsubstantiated evidence that thearea between Barter Island and the Canadian bor-der is an important habitat area where bowheadwhales feed on their westward fall migration. Con-cern has been expressed by the North Slope Bor-ough and other groups that seismic and oil activi-ties in this area may adversely affect bowheadfeeding at a critical time and, hence, that thebowhead population may be affected. Scientistswould like to be able to correlate the distributionof organisms in these areas with whale feedinghabits. In 1985, MMS plans to study the impor-tance of the area east of Barter Island to bowheadwhale feeding. Better knowledge of feeding areaswill aid understanding of migratory patterns andin conservation of the whale’s ecosystem.

Some specific tasks have been identified by theInterorganization Bowhead Whale Research Plan-ning and Technical Coordination Group.26 Thegroup agreed that the highest priority short-term(1983) research needs included:

●

●

●

Continuation of studies of recruitment usingphotography.Completion of the evaluation of the sourcesof bias in census taking and improvement ofthe accuracy of the census count (at PointBarrow).Study of the distribution of bowheads in sum-mer to facilitate estimating total abundanceand migratory behavior.

zbNation~ Marine Fisheries Service, ‘‘Report of the Second In-terorganization Bowhead Whale Research Planning and TechnicalCoordination Meeting” (Washington, DC: NOAA Technical Memo-randum, April 1983).

Ch. 7—Environmental Considerations Ž 183

●

●

●

Identification and evaluation of possiblefeeding areas in the Beaufort Sea in summerand autumn.Determination of the effects of seismic opera-tions (through a boat-whale interaction study).Initiation of a review of the state-of-the-art ofbowhead knowledge.

This last task is important because there has beena rapid accumulation of information in the past fewyears, but a much slower rate of synthesis. More-over, it could be a very useful exercise in order toreach a scientific consensus on the key issues. Otherimportant but less pressing studies were also iden-tified by the group.

Current Research

Research on bowhead whales is conducted byseveral organizations, but primarily MMS. MMSis conducting surveys to detect when whales arepresent in areas where they could be disturbed byseismic activities. They are also doing basicbehavior and perturbation studies, and, in the Ber-ing Sea, distribution and abundance studies. Since1980, MMS has funded four studies related totallyor in part to the effects of noise on endangeredwhales. The funding for these studies through 1983was about $4.3 million.

NMFS is responsible for the management ofbowhead whales. The National Marine MammalLaboratory in Seattle, Washington, is involved inbowhead whale research. NMFS research focuseson understanding the life history and populationdynamics of bowhead whales. During the springmigrations, bowheads are counted from ice camps,and during the summer photo-identification sur-veys are conducted.

The North Slope Borough and Alaska EskimoWhaling Commission receive much of their re-search funds from the Alaska Legislature. Their re-search focuses on biological studies of animals takenin harvest. They have also conducted populationcounts of bowheads as they move north in thespring. Recently, hydrophones have been used atthe counting stations to try to account for the whaleswhich pass beyond the view of visual counters ortravel when the leads are closed. The North SlopeBorough has organized and convened severalbowhead whale symposia.

The oil industry also has contributed to thebowhead whale research effort. Particularly valu-able was the large research effort undertaken in1981 which led to the discovery of a better meansto estimate the rate of calf production.

In comparison to the funds spent on other en-dangered species, a large proportion of availablemoney has been spent on bowhead research. Inlarge part, this is due to expensive logistical require-

ments, and to the necessity of using ships and air-planes. Despite the large sums of money that havebeen spent, most scientists are reluctant to makeunqualified statements concerning bowhead whalepopulation, reproduction, or the effects of noise andoil contamination.

The reasons for large bowhead whale researchbudgets are at least in part political. Native Alas-kans hope that research results will help them bothto justify a continued, if not expanded, whale huntand to protect the health of the species. The oil in-dustry hopes that research results may lead to lessrestrictive stipulations, and the Federal Govern-ment must try to balance competing national andinternational objectives. In addition, the specialstatus of bowhead whale research stems in part fromthe legal mandate granted by the 1973 EndangeredSpecies Act and the 1972 Marine Mammal Pro-tection Act.

Operational Restrictions

MMS can mitigate potential adverse impacts thatoil and gas activities may have on bowheads bydeleting tracts or by specifying lease stipulationsand conditions in operating permits, some of whichNMFS suggests in its biological opinion. These maytake the form of drilling restrictions during migra-tion or broken ice periods, restrictions on seismicactivities when whales are within the vicinity (e. g.,within a 5-mile zone of influence), and/or direc-tions to vessel operators on how to comport them-selves in the presence of whales. For instance, inthe 1979 Federal/State Beaufort Sea Lease Sale therecommendations of scientists were followed anda 7-month seasonal drilling closure effective for 2years was proclaimed. In the 1982 Diapir Field leasesale, drilling restrictions were reduced so as to applyonly to specified tracts and only during the 2-monthfall whale migration. Moreover, MMS did not

38-749 0 - 85 - 7


adopt NMFS’s recommendations in its biologicalopinion calling for drilling restriction periods to beextended so as to ensure that areas occupied bymigrating whales are free of oil by the time thewhales arrive. MMS did not believe that the lowlevel of risk of a major oil blowout or spill duringexploration justified such a precaution. In the 1984sale, drilling and other downhole activity has beenrestricted in the periods of April 15 through June15 and September 1 through October 31 in thewestern blocks and between August 1 and October31 in the eastern blocks,

MMS may also publish a “notice to lesees andoperators. This is advisory and applies to thoseactivities which take place after the lease sale butbefore development or production plans are sub-mitted. For instance, MMS may advise lessees touse aircraft to ensure that no bowhead whales arewithin 5 miles of seismic operations.

The findings of bowhead whale researchers haveinfluenced Federal OCS lease decisions and stipula-tions in the past. Differences of opinion exist, how-ever, concerning whether science or political con-siderations are more important in determiningmitigating measures. Some scientists have sug-gested that “political issues and [especially] the de-sire to accelerate development on the OCS pre-dominated over scientific considerations in the[1982] sale. ”27 For instance, bowhead whale migra-tion data were collected between 1979 and 1982,but, in the view of these scientists, the new datadid not justify relaxing the seasonal drilling restric-tion. Conversely, much more data were availableby 1982—it was clear by then, for instance, thatthe spring migration takes places well offshore andthat the fall migration corridor lies in water from20 to 50 meters deep—and restrictions were re-duced in light of this new information.

27JaCqUeline G’ebrneie’, “The Role of Science in the Alaskan OuterContinental Shelf Oil and Gas Leasing Decision Process’ (Master’sThesis, Institute for Marine Studies, University of Washington, August1983).

Stipulations currently in place to mitigate impactson bowhead whales are operational in nature, i.e.,they affect operating procedures. Alternatively, onemight consider stipulations requiring the design ofoffshore structures and ships aimed at reducing in-dustrial noise to an acceptable level. Rather thanbeing required to curtail activities in the presenceof whales, industry could be offered an opportunityto design, for example, quieter ships. This regula-tory approach is favored by some environmen-talists, but they admit that far too little informationis currently available for designing appropriatelyquiet technology, particularly given the lack ofknowledge on the effects of noise on marine mam-mals. Moreover, designation of this type of stipu-lation would probably be beyond the current au-thority of the MMS. However, if such designregulations proved to be less costly to the oil in-dustry than operating restrictions, industry may bereceptive.

Current policies regarding protection of bowheadwhales from the impacts of oil and gas activities andnative whaling include limited and closely con-trolled Inuit hunting, stipulations controllingdrilling and other activities during specified peri-ods, and continuation of relevant scientific research.The aim of these policies has been to balance com-peting national interests. However, differences ofopinion persist concerning their adequacy. Both theNorth Slope Borough and the environmentalistshave pushed for greater bowhead whale protection,while the oil and gas industry believes drillingrestrictions to be unwarranted based on the infor-mation available concerning whale migrations andon the safety record of OCS operations. Somealteration and/or finetuning of existing policies(e.g., alteration of whale quotas, changes in the ra-dius of the zone of influence, or further tract dele-tions) may be necessary, depending upon the re-sults of further scientific research. However, nosignificant changes of policy are likely to be neces-sary in the near term.


OIL SPILLS

Introduction

As the U.S. oil and gas industry begins explora-tion of deepwater and Arctic OCS areas, questionsare being raised concerning the effectiveness of tech-niques and equipment for combatting oil spills infrontier areas. Industry argues that it is preparedfor the possibility of spills in both Arctic and deep-water areas, and that the risk of catastrophic spillsis very low. Although the petroleum industry hasnot had a drilling or production-related oil spill inU.S. waters as large as the Santa Barbara blowoutsince 1969, major spills in other parts of the world(for example the 1979 Ixtoc 1 blowout in the Gulfof Mexico) and a number of sizeable tanker casual-ties have heightened the public’s awareness of therisks and consequences of oil spills.

The offshore oil and gas industry has a good oilspill prevention record. However, the industry haslittle experience producing oil in Arctic and deep-water frontier areas. With the exception of Cana-dian and North Sea operations and Cook Inlet oper-ations in State waters in Southern Alaska, theindustry’s offshore operating experience and oil spilldata are derived largely from operations in tem-perate regions, such as the Gulf of Mexico and Cali-fornia. Notwithstanding the oil and gas industry’splans and preparations for oil spills, it is still un-certain whether the industry will be able to makeeffective use of currently available equipment andcountermeasure strategies to recover significantamounts of spilled oil in frontier areas. Althoughindustry has equipment on hand and can airlift ad-ditional equipment to a spill site if necessary, thisequipment has never been proven under realistic,at-sea conditions.

Most oil spill containment and cleanup technol-ogy has been developed for nearshore and tem-perate regions and may be unsuitable for Arctic ordeepwater areas. Arctic oil spill countermeasuresmay be complicated by extremely cold tempera-tures, the presence of ice, long periods of darkness,intense storms, and lack of support facilities in mostareas. Hence, the risk of oil spills in the Arctic maysometimes be greater than the risk in temperateareas. At least partially offsetting this factor, how-

ever, is the higher level of engineering in the Arc-tic and the significant attention paid to safety fac-tors. Risks have been analyzed and are carefullyconsidered in the planning process, but there is littleoffshore Arctic operating experience on which tobase risk estimates. In deepwater areas, high sea-states may be encountered, and the greater distancefrom shore may create logistical problems for oilspill cleanup. Existing cleanup technologies haveproven effective only in placid, protected waters.

The number of frontier area spills that may oc-cur, and, therefore, the total amount of oil that maybe spilled is related to the amount of oil that willbe found and produced. Predictions concerning theamount of oil frontier areas will yield are consid-ered highly speculative, and thus the possible dan-ger of oil spills is also uncertain. MMS uses oil spillrisk analyses to estimate the probability of oil spillsoccurring in offshore areas it proposes to lease.Based on historic data from the U.S. OCS, MMShas determined that 3.9 spills of 1,000 barrels orgreater and 1.8 spills of 10,000 barrels or greatercan be expected for each billion barrels of oil pro-duced and transported. Predicted spill types andcorresponding rates are shown in table 7-2. Al-though no oil has yet been produced from the Fed-eral Arctic OCS, and the United States has onlyrecently begun production from areas of about1,000-foot water depths, the probability that oneor more spills of both 1,000 barrels or greater and10,000 barrels or greater will occur over the pro-ductive life of each lease sale area is considered tobe 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-barrelSource of spills oil spills oil spills

Platforms . . . . . . . . . . . . . . . 1.0 0.44Pipelines . . . . . . . . . . . . . . . . 1.6 0.67Tankers at sea . . . . . . . . . . . 0.9 0.50Tankers in port . . . . . . . . . . 0.4 0.15

Total . . . . . . . . . . . . . . . . . 3.9 1.76SOURCE: Minerals Management Service, Navadrr 6as/n Lease Offering: final Err-

virorrrnenta/ hrrpact Statement, November 1983


Industry’s capability to effectively deal withspilled oil in the frontier regions depends on twofactors: 1) preparedness with regard to counter-measures strategies, logistical support, equipmentavailability, and planning; and 2) performance, ef-fectiveness, and suitability of the containment andcleanup equipment. Industry has met current Stateand Federal requirements for pre-spill preparation.The major uncertainty, however, is how equipmentwhich is currently available will actually performunder the conditions commonly encountered inArctic and deepwater areas. Although the state-of-the-art of cleanup technology has advanced in re-cent years, for the most part, only rough qualitativemeasures of its effectiveness exist. Little quantitativedata about equipment performance exists, and mostof that which does exist is derived from relativelyinexpensive and easily controllable simulations andsmall-scale tank tests rather than from expensivetesting under real-life conditions. In many in-stances, the manufacturer’s claims and the vendor’sspecifications are all the information available togauge the effectiveness of the equipment.

There are two major types of oil spills: blowoutsand tanker spills. The sudden, uncontrolled escapeof hydrocarbons from a well is known as a blow-out. Oil well blowouts differ from tanker spills inthat the discharge rate of a blowout is often slowerand usually occurs over a longer period of time.Tanker spills could involve the release of a largeamount of oil over a relatively short period of time.The behavior of the discharge, countermeasuresstrategies, and the potential impact of a blowoutspill are thus different than for tanker spills.Countermeasures strategies vary for blowouts de-pending upon the depth of the blowout (e. g.,whether it is a surface blowout from an artificialisland or a shallow or deepwater blowout resultingfrom a drillship accident), the amount and stabilityof ice cover (e. g., moving pack ice, broken ice, oropen water), and the sea state.

If a blowout cannot be controlled quickly, largequantities of oil and gas may be released. If theblowout occurs on the sea floor, the difficulties ofcontrol are compounded; and if it occurs under-water and under moving ice, it can be extremelydifficult to control. It has been estimated that anuncontrolled sub-sea blowout in the Beaufort Sealasting one year (although improbable) could re-lease about 500,000 barrels of oil.

Some characteristics of blowouts make themeasier to handle than tanker spills. First, potentialspill locations are known; thus, spill containmentand cleanup equipment can be prepositioned andvariables affecting the spill’s behavior (currents,wind patterns, etc. ) can be studied before the event.Second, the release rates of blowouts are generallylower than release rates of tanker spills. If a blow-out can be quickly controlled, relatively less equip-ment may be needed to clean up this type of spill.And third, oil from a blowout is often initially ina fresh, fluid state. This characteristic makescleanup easier. However, the oil does not remainfresh for long, and once it has weathered, it is moredifficult to recover.29

There have been several proposals to transportArctic hydrocarbons by ice-strengthened or ice-breaking tankers. The proponents of these proposals(e.g., Dome Petroleum) have designed tankers tominimize the risk of a spill. Nevertheless, the pos-sibility of a tanker spill in the Arctic—if and whentankering becomes viable—cannot be discounted.It is impossible to predict the exact location oftanker spills. Equipment cannot be positioned inadvance, and it is therefore very difficult to imple-ment a fast response before extensive oil spreadingand weathering occurs. Tanker spills may result inthe release of a large amount of oil during a shortperiod of time. Responses to such spills would re-quire a large amount of equipment and manpower.

Limits to Effective Countermeasures

Environmental Variables

Whether a spill is from a blowout or a tanker ac-cident, a number of environmental variables willaffect the response effort. One of the most impor-tant is the amount of ice present. Spills may occureither in open water, under conditions of partialice coverage, or in solid landfast or pack ice. Thosewhich occur in complete ice cover are probably theeasiest to control. In such instances, the most prac-tical countermeasures technique currently available

Zgsee S, L, Ross EnVirOnrnent~ Research Limited, Potentia/ LargeOil Spills Offshore Canada and Possible Response Strate~”es (Envi-ronment Canada, March 1982), oil Spill Countermeasures: TheBeaufort Sea and the Search for Oil (Canadian Department of Fish-eries and the Environment, 1977), and Evaluation of Industry OilSpill Countermeasures Capability in Broken Ice Conditions in theAlaskan Beaufort Sea (Alaskan Department of Environmental Con-servation, September 1983).


probably is to burn the oil on the surface of the iceor, if spilled under the ice, to burn it as it ac-cumulates in melt pools during the spring breakup.Open water spills, particularly in the high sea statescommon in the Bering Sea, are much more diffi-cult to clean up. For instance, contamination froma summer tanker spill is not likely to be significantlyreduced using currently available cleanup technol-ogy. High sea states would, however, promote nat-ural dispersion.

In many ways, however, the most difficult spillsto clean up may be those which occur in partial icecover. Most oil spill containment and cleanup tech-nology has been developed for temperate regionspills and may not be sufficiently effective whenused in partial (or broken) ice. Some promisingtechniques have been developed recently, but allrequire further development, testing, and integra-tion into an overall response strategy. The broken-ice period varies by year and by location. In theBeaufort Sea and Chukchi Seas, this period lastsapproximately 3 to 7 weeks during breakup and 3to 6 weeks during freezeup. Thus, the most diffi-cult conditions in which to clean up spilled oil lastfrom 6 to 13 weeks each year. A generalizationabout the Bering Sea is not possible since the Ber-ing varies in climate from north to south. Someareas of the Bering Sea may have broken ice at anytime of the year.

Other environmental variables also affect the per-formance and efficiency of equipment and the over-all response effort. The velocity of the ice is im-portant, since it is much more difficult to operatein moving ice than in stationary (or landfast) ice.The characteristics of the ice are also important.Solid ice, for instance, provides an excellent plat-form from which to stage countermeasures, but itis extremely difficult to maneuver equipment (suchas barges or skimmers) when ice coverage is ex-tensive, Conversely, the operation of equipment inold ‘‘rotten ice or in thin, early season ‘‘grease’ice is probably easier than in solid ice, but thesetypes of ice cannot be used as a countermeasuresplatform.

Inasmuch as the wind speed, sea state, and cur-rent strength affect both the rate at which oil isdispersed and the deployment and operation ofcountermeasures equipment, cleanup efficiency is

also influenced by these variables. Water temper-ature also plays a role because colder temperaturesincrease the viscosity of the oil, thus reducingspreading. However, in very viscous oil mechani-cal cleanup is difficult, and the effectiveness ofchemical dispersants is reduced.

Lack of Support Facilities

The absence of roads and support facilitiesthroughout much of the North Slope and WesternAlaska will make oil spill countermeasures difficulteven if appropriate cleanup technology is available.There are few roads in these areas. Thus, land ac-cess to staging areas for offshore spills and/or threat-ened shorelines is rarely possible, and extensive useof aircraft is required. In addition there are norefineries, little manpower, few housing facilities,and few disposal sites. Some of the resources whichcould be mobilized in more populated areas in theevent of a major spill simply do not exist in the Arc-tic. Conversely, industry argues that because Arc-tic areas are so remote, they must be self-sufficient.Located in the Prudhoe Bay area are fixed wingaircraft, helicopters, air cushion vehicles, roligons,trucks, boats, barges and personnel which could bemobilized rapidly in a local emergency.

Difficult Working Conditions

Difficult working conditions pose a generallimitation on the capability of industry to clean upoffshore Arctic oil spills. Although techniques,equipment, and clothing have been developed tominimize the effects of intense cold, and person-nel have received specialized training, human effi-ciency is reduced in cold climates, and safety is cor-respondingly more difficult to ensure. Even withthe best of protection, it is not possible to work out-side for long periods of time. Generally, responsesto accidents in cold environments take more timeand equipment problems are greater, although lit-tle reliable data exists concerning the precise effectsof cold on either human or equipment efficiency.The possibility that a spill may occur during thelong Arctic night or during times of persistent fogalso poses problems of efficiency industry will beable to make effective use of currently availableequipment and countermeasure strategies to re-


cover significant amounts of spilled oil in frontierareas.

Response Time

Of all the difficulties associated with containingand cleaning up spilled oil in the Arctic, two ap-pear to be especially troublesome. The first is theproblem of response time. Although inventories ofoil spill cleanup equipment are located at PrudhoeBay and at Dutch Harbor, response time is a prob-lem because Arctic spills may occur in remote areasand because human efficiency is less in cold envi-ronments. If response to a spill is not prompt, theeffectiveness of countermeasures is reduced, some-times markedly. The response time problem willbe particularly difficult in the case of tanker spills,since a spill may occur anywhere. Although tankersare not currently being utilized, their use in the Ber-ing Sea can be foreseen, and their future use in theBeaufort and Chukchi Seas is being considered. Ithas been suggested that the major countermeasuresquestion in the case of open water spills is how todeliver the technologies to the spill site prior to theoil’s spreading and weathering beyond control.

In the Bering Sea, a distressed ship could be 400or more miles from any point in Alaska and a muchgreater distance from a base that could support aspill response effort. For instance, it would take aCoast Guard icebreaker stationed at Kodiak Islandat least 4 days to reach the site of a Bering Sea spill.It may be possible, if the safety of the crew is notat risk, to use the tanker itself as a working plat-form for countermeasures operations. A portableresponse system may be developed to be carriedon tankers that would include booms that could bedeployed by a small boat, skimmers that could beoperated remotely or from the ship, and some kindof vehicle capable of operating in the water and onall kinds of ice. The United States has no require-ment at this time that ships be equipped for counter-measures activities.

While the response time problem for remotetanker spills is of particular concern, responses toall Arctic spills will, on average, take more timethan responses to temperate spills. The difficultyof detecting oil spills compounds the problem.Detection is most difficult for spills which occurunder the ice or in broken ice, but it can also be

a problem in more controllable situations, such asin the June 1981 Challenge Island oil spill in theBeaufort Sea. In this case a spill of approximately3,000 gallons went undetected for an indeterminatelength of time because of sustained inclementweather conditions .30

The industry treats the response problem seri-ously. Individual oil companies as well as indus-try cooperatives have stockpiled spill counter-measures equipment as required by the MMS. Thecompanies prepare oil spill contingency plans forall exploration activities, and they conduct periodicdrills to improve their response capability. In ad-dition, the U.S. Coast Guard has established a na-tional strike force equipped to respond to spills onshort notice.

The broader countermeasures challenge is to de-velop a comprehensive and integrated spill responsesystem. Such a system is composed of many com-ponents, including detection and surveillance, lo-gistics operations, containment, recovery, storage,and disposal. In addition, the response operationdepends upon timely weather and ice informationand on other contingency plans (e. g., when con-ditions become hazardous, evacuation of person-nel must be provided). If attention to any of thesystem components is less than adequate, the ef-fectiveness of the overall response is likely to belimited. Thus, even with the best recovery tech-nology, the response may be ineffective if the equip-ment can not be transported to the site fast enoughor if recovery efforts must be terminated due tosafe conditions.

Countermeasures Technology

Mechanical Recovery

un-

In some Arctic spill situations oil can be removedfrom the surface of the water by mechanical skim-ming devices. Many different types of skimmershave been developed, but few of these have beendesigned specifically to recover oil from Arcticwaters. Moreover, although mechanical oil skim-ming technology continues to advance, little testinghas been done under at-sea Arctic conditions. Even

gosohio Alaska petro]eum Company, Challenge zd~d SPJ1 Repofl(March 1982).


the most effective skimmers have limited capaci-ties for recovering oil in stormy and/or ice-coveredArctic waters. Considering the relatively low per-centage of spilled oil they may be able to recoverin most Arctic spill scenarios, skimmers are seenby some to be a second-order countermeasuretechnique.

The effectiveness of skimming devices dependsupon a number of different variables. For one, thethickness of the oil layer to be recovered affectscleanup efficiency. Thus, skimmers are usually usedin conjunction with booms which prevent the oilfrom spreading and becoming too thin to recover.In this respect, ice may sometimes be used toadvantage. If ice is present, but not extensiveenough to limit skimmer deployment, it may serveas a natural barrier to spreading and thinning. Theviscosity of the oil is a second important variable.The mechanical recovery of viscous oil, which mayquickly form in cold Arctic waters, is a problemrequiring specialized equipment. Skimmer per-formance is also reduced by high sea states, strongcurrents, and the presence of debris and/or ice.Skimmers for Arctic spills must be easily main-tainable, easy to transport to the spill site, and sim-ple to operate. Skimmer designs which may beuseful in certain Arctic spill situations include weir,suction, and sorbent surface devices. Each type ofdevice is available in the Arctic.

Weir skimmers. Weir type skimmers depend ongravity to drain oil off the surface of the water. Theyoperate by allowing the oil to fall over a lip sus-pended at the surface of the water into a sumpplaced in the slick. The oil is then pumped out ofthe sump to a storage facility. The main advantagesof this type of skimmer are portability and sim-plicity. They have proven most useful for recover-ing light oil in calm water. They are not useful inwaves because large volumes of water will enter thesump with the oil (a ratio of 10 percent oil recov-ery to 90 percent water is not atypical). In largerwaves, smaller weir skimmers may be swamped.Weir skimmers can be used in calm, open waterArctic spill situations; however, the presence of iceor other debris may clog the weir openings and ren-der the equipment temporarily inoperative.

Suction devices. Suction devices, if mounted ona suitable operating platform and if used withsuitably powerful positive displacement pumps,

may prove to be useful in some instances. Sincelow ambient temperatures predominate in the Arc-tic, spilled oil is likely to become very viscous;water-in-oil emulsions also may be formed. Themain advantage of suction skimmers is their abilityto vacuum heavier oil. Even suction pumps, how-ever, will have problems recovering semi-solid oil.Other types of skimmers have difficulty efficientlyrecovering viscous oil because the oil will not readilyflow toward the equipment.

Disc skimmers and rope mops. Sorbent surfacedevices, including rotating disc skimmers and ropemops, seem to hold promise for efficient operationwhere small amounts of ice are present. The disctype skimmer collects oil on rotating oleophilicdiscs. The oil is scraped from the discs, transferedto a screw auger at the axis of the discs, and pumpedto storage containers. The advantages of this typeof skimmer for Arctic use are its ability to pick upviscous oil and to function amidst limited ice, de-bris, and waves. However, disc skimmers may be-come quickly overloaded in heavy oil.

Rope mop skimmers use continuously moving,absorbent, polypropylene ropes to sop up oil. Thistype of device has relatively good potential as a sec-ondary collection system in broken ice conditions.Rope mop skimmers range in size from very smallportable units capable of being mounted on ice-strengthened barges or other platforms to largeboats specially designed for skimming operations.

The ARCAT. The largest and most importantrope mop skimmer currently on hand in the Arc-tic is the ARCAT, a 65-foot catamaran dedicated

Photo credit: EPA OHMSETT facility

Testing the effectiveness of a rope mop skimmer incleaning up oil spills in broken ice


to spill cleanup in the Beaufort Sea and operatedby Alaska Clean Seas. A distance of 6 feet sepa-rates the ARCAT’s two hulls. However, usingdiversionary booms and support from two small towboats, the ARCAT can increase its swath width andthus its oil encounter rate by a factor of 20 or more.By offloading recovered oil into auxiliary oil stor-age containers, it is hoped that ARCAT will be ableto operate continuously for days or even weeks ata time, recovering oil at the average rate of 5 to30 barrels per hour. Other features of the ARCATinclude oil dispersant booms, oil storage capacity,and equipment to break down recovered emul-sions. 31

The maneuverability of the ARCAT has beenevaluated in broken ice coverage up to 7 oktas (anokta is equivalent to 12.5 percent—one-eight—coverage). In 2 oktas (25 percent) or less ice cov-erage, it is able to maneuver through broken iceat speeds of from 5 to 7 knots. In 3 to 5 oktas itsspeed is reduced to one to 2.5 knots, and, in 6 to7 oktas to about one-half knot. Industry is satisfiedthat the ARCAT has been sufficiently tested todemonstrate its utility for recovering oil in brokenice conditions. Industry argues that further testingis not necessary since other skimmers very similarto the ARCAT have been tested with good resultsin oil, and it is reasonable to conclude that AR-CAT mops will behave in the same way. Othersare not so sure, since it has not been tested in oiland ice, and believe that the device should be putto the test recovering the type of oil that it will mostlikely encounter—viscous crude that has weatheredfor about 3 days in water at 0°C. Even if ARCATcan handle these tests, special operating proceduresmay have to be developed. Tests may indicate thatdifferent types of mops are necessary, or that it maybe necessary to adjust wringer speed, rope speed,or even the vessel speed. These operating proce-dures could be tested and developed before a spilloccurs.

The Force Seven type mop. The Force Seventype rope mop has also been considered in connec-tion with Arctic spill response. This system uses aseries of mops deployed from the stern of a vessel.

31R. E, Wi]]iams, s. J. Bowen, and D. H. Glenn, ‘‘Field Trialsof the ARCAT 11 in Prudhoe Bay, Proceedings of the Seventh an-nual Arctic Marine Oilspill Technical Seminar (Edmonton, Alberta,June 1984).

It is attractive because: 1) the area covered can beincreased by increasing the number of mops; 2) thedevice is likely to have some utility in broken icesince the mops are drawn over the surface of theice; 3) there is no problem of a catamaran hull be-coming jammed with ice; and 4) the device can bequickly installed on the stern of any available vessel.This last feature is particularly important. The AR-CAT is an expensive vessel, and although it maybe used for other purposes, it is dedicated solelyto oil spill response. When it isn’t recovering oil,it sits unused. As a result, only one ARCAT hasbeen built and deployed to date. If a large spill doesoccur, however, the use of as many vessels as areavailable probably will be required if a significantamount of oil is to be recovered. Therefore, avail-ability of equipment that can be mounted on vesselsof opportunity probably will be more feasible thandedicated single-purpose vessels.

Few skimmers have been independently testedto evaluate how well they perform in broken iceconditions. In most cases it is simply not knownhow well they will operate in the different ice con-ditions which could be encountered. Manufacturershave made optimistic statements about the effi-ciency of their skimmers for Arctic conditions, butwhat little independent testing has been done hasshown many of these claims to be overstated.

Industry has been using conventional barges andtugs for some time for supporting offshore and near-shore oil spill cleanup operations. One innovationwould be an icebreaking barge. Barges providemobile and stable platforms from which to conductcountermeasures operations. Recent industry dem-onstrations have shown that rope mop skimmerscan be effectively deployed from barges in deteri-orating heavy pack ice. The recovery capability ofbarge-mounted skimmers, however, has not beendemonstrated. The oil-encounter rate for theseskimmers may not be high; nevertheless, this ap-proach constitutes one more countermeasures toolthat may be useful in some situations.

Booms. Booms are used to contain oil. They mayeither be employed in conjunction with skimmingoperations (in which case their function is to cap-ture and concentrate oil slicks so that recovery canbe as efficient as possible) or for deflecting or ex-cluding oil from particularly sensitive areas. Boomswork best in calm water, free of ice or other de-


bris. However, in strong currents (above one knot)and high sea states, the efficiency of containmentbooms is impaired. In heavy sea states, for instance,oil may either splash over the top of the boom orescape under the skirt. In addition, scattered icecan cause boom damage. In general, booms do notyet seem to have the endurance necessary for con-tinuing performance during a long-term cleanupoperation, and booms used in open ocean condi-tions have not proved to be very effective. In roughenvironments, the use of booms and skimmersprobably would not make a significant differencein the ultimate environmental impact of a spill.

MMS recommends that booms be able to per-form in wave heights of 8 to 10 feet. These per-formance guidelines have not been met. However,it is still unclear what constitutes adequate boomperformance under real conditions, and under highwave conditions, oil will usually be quickly dis-persed, Although booms are an indispensablecountermeasures tool, their use is clearly limited.A promising addition to containment technologyis the high pressure water jet barrier, which cur-rently is being developed. It is used for the samepurposes as conventional booms. The water jet sys-tem is designed to herd oil in waves, ice, and marshareas, and can be mounted on and used in con-junction with skimming devices. It has not yet beenevaluated in high sea states, however. In addition,the jets create a considerable amount of fine mist.In subfreezing air temperatures, the resulting icemist could be a health and safety hazard.

Disposal. The ultimate disposal of recovered oilor oiled debris generally takes the form of eitherlandfilling or incinerating the material. Both ofthese alternatives have drawbacks in a northern ap-plication.

The burial or landfilling of oil and oiled debrisis possible only if suitable sites are available to con-struct either subsurface pits or above-grade bermsto contain the material. Such sites are not plentifulin the Arctic; where available, they may be diffi-cult to access due to the complete absence of roadsand the presence of shallow water at the shore. Ice-rich soils, common in the Arctic, also pose a prob-lem in summer operations since excavation in per-mafrost can create sloppy, unworkable conditions.Landfilling operations also require the use of heavyequipment which is not plentiful in the North and

which would be difficult to transport to specific dis-posal sites. The major advantage of land filling inthe Arctic is the ability to permanently encapsulatethe oil and debris in a frozen surrounding.

The state-of-the-art for oil spill disposal by in-cineration has advanced from earlier attempts atburning oil and debris in oil drums or open pitsto a technology including air-transportable in-cinerators and reciprocating kiln beach cleaners.A transportable flare burner capable of burning6,000 barrels of light oil per day and 3,000 barrelsof heavy oil per day is available in Anchorage. Theindustry on the North Slope has access to a rentalburner that is theoretically capable of incinerating13,000 barrels of oil per day.32

Oiled beach materials such as sand and rockcould be cleaned in simple reciprocating kiln de-vices but such equipment at present has a very lowthroughput. A larger number of these kilns, alongwith their manpower and logistical support, wouldtherefore be required to carry out an extensivebeach cleaning. It is also apparent that any pro-posed landfill operation would involve seriouslogistical problems. This is also the case for any pro-posed labor-intensive spill control operation in theNorth, either beach cleaning or debris disposal.

The disposal problem is mainly of concern forlarge spills. Small spills can be stored until adequatedisposal is available. For the Beaufort Sea, the in-dustry points out that it would be technically fea-sible to transport skimmed oil by barge or possi-bly over ice to Prudhoe Bay where it could beoffloaded into a ‘‘slop tank’ at one of the flow sta-tions of the Prudhoe Bay Unit. These flow stationshave the capability to treat skimmed oil to TransAlaska Pipeline specifications. Likewise, in the Ber-ing Sea, it may be technically possible to transportskimmed oil in a large oceangoing barge to Kenai,Alaska or Seattle, Washington for deposit into arefinery slop tank.

In Situ Burning

For many Arctic marine oil spills, in situ burn-ing is considered to be one of the most practicalmethods available for removing oil from the envi-——

jzshell oil Company, Sohio Alaska Petroleum Company, ExxonCompany, and Amoco Production Company, Oil Spill Response inthe Arctic (Three parts, April 1984).


ronment. This countermeasure method may beused in combination with other techniques to re-duce water pollution. The oil that escapes combus-tion, either as residue or as a partially burned oillayer, might be recovered downstream with skim-mers. When burning can be used as an oil spillcountermeasure, the problems of disposal en-countered with mechanical recovery techniquesmay be reduced.

In situ burning may be practical for both con-tained and uncontained spills. In an uncontainedslick, such as one from a tanker spill in open water,burning may be the only feasible method of signif-icantly reducing the amount of oil in the water.Even if mechanical recovery equipment could bedeployed to a remote spill site, it probably couldnot be expected to remove more than a small frac-tion of the oil from a large batch spill, and the prob-lem of disposal of recovered oil would remain.Dispersants might be used to counteract some ofthe adverse effects of uncontained spills, but theireffectiveness may be reduced in cold environments.

If spilled oil can be contained, in situ burningmay be the most efficient removal technique. Oilmay be contained naturally or by man-made, fireresistant booms. Winter tanker accidents or win-ter subsea blowouts are two situations in whichspilled oil would be naturally contained and inwhich in situ burning may be successfully used. Ineither situation, most of the spilled oil would betrapped under the ice for the duration of the win-ter, and no countermeasures would be possible untilbreakup begins. Within a very short time, the oilwould be encapsulated in the growing ice sheet. Ifthe spill were in the landfast ice zone, the oil wouldnot likely travel very far. However, if the spill werebeyond this zone in the moving pack ice, the oilcould eventually be spread along a narrow trackunder the ice for many miles. As the ice begins todecay, the oil would migrate to the surface (whereit would emerge in a relatively fresh and unweath-ered state) and collect in melt pools. Dependingupon the size and type of the spill, thousands if nottens of thousands of separate oiled pools could ap-pear. Like spills resulting from open-water tankeraccidents, there may be no practical solution otherthan burning for spills resulting from either win-ter tanker accidents or winter subsea blowouts.

Photo credit: EPA OHMSETT facility

Testing the effectiveness of in situ burning as anoil spill countermeasure

Spills which occur during the broken ice periodcan also be contained naturally for in situ burn-ing, if the ice coverage is adequate (the ice edgestend to limit the spreading tendency of the oil). Forsome open water or broken ice situations, fire resis-tant containment booms, although still in the de-velopment stage, may provide a way for reducingmarine oil pollution.

The major technical issue associated with in situburning is the problem of igniting the oil and keep-ing it burning. When oil is allowed to spread andthin, it is difficult to burn efficiently. Oil which isthicker than about 2 or 3 millimeters can be ignitedand burned. Since oil thins as it spreads, unduedelays in ignition result in reduced burn efficien-cies. Moderate wind may be helpful if it works toherd the oil against an ice barrier. However, lowerburn efficiencies can normally be expected in highwind and low ice concentrations. Weathered oilwhich has remained in the water is likely to be un-burnable because the lighter fractions quicklyevaporate, and the remaining oil breaks into win-drows. Minimum conditions for burning are cur-rently unknown.

For in situ burning of uncontained slicks to beeffective, the spreading of the flame must keep upwith the spread of the oil itself. The flame spreadingvelocity is related to the type of oil burned, windspeed, and water temperature. Recent laboratoryand test-tank oil burn tests have shown that in mostcases the flame spreads as rapidly as the burning


oil until the thickness of the leading edge of the slickdrops below that necessary to support combustion.Beyond this point, only the thick portions of theslick burn, However, certain ignition patterns, suchas igniting the circumference of the slick, may beable to overcome this problem. Combustion effi-ciencies vary proportionally with spill size, windspeed, amount of ice, water temperature, oil type,ignition delay, and pattern of ignition. Efficienciesof up to 80 percent by volume can be achieved, withlower efficiencies expected, for instance, in highwinds and low ice concentrations. If adverse con-ditions persist, cleanup efficiencies could drop below20 percent.

The 1983 Alaskan Tier 2 field demonstrationsof industry’s ability to clean up oil in broken iceincluded industry demonstrations of in situ burn-ing. Task 1 consisted of a series of burns of oil ingrounded and floating ice. Although the demon-strations were less successful when the ice wasfloating rather than grounded, they clearly showedthat burning is an important component of Arcticoil spill response and cleanup if the oil enters mov-ing broken ice. In its evaluation of the demonstra-tion, the State of Alaska noted that the relativelyhigh efficiency of in situ burning depended on thecrucial assumption that burning must take placeclose to the spill source while the oil layer is rela-tively thick and easily combustible. In many situ-at ions, however, a safe burn near the source of ablowout may be impossible, and therefore the burnefficiency will be significantly reduced. It is sug-gested that more work on the ignition and in situburning of crude oil among 3 to 5 oktas of movingice is necessary to determine the limits of thiscountermeasure approach with respect to oil weath-ering, thickness, and environmental conditions.

Wellhead ignition. When in situ burning andother countermeasures techniques are not feasible,wellhead ignition is another possibility. This tech-nique has been considered for dealing with blowoutsfrom gravel islands. Combustion and skimmingtechniques employed in the vicinity of an unignitedblowout can be dangerous and countermeasurestaken far downstream of a blowout may not be veryeffective, Therefore, well ignition may be the onlyway that artificial island blowouts can be rapidlyand effectively controlled. It has been roughly esti-mated that if the wellhead is ignited, approximately

95 percent of the oil would be burned immediatelyand another three percent could be removed byother cleanup processes, regardless of whether theblowout occurred in broken ice, landfast ice or openwater.

However, there are some important unansweredquestions concerning the feasibility of wellhead ig-nition as an oil spill countermeasures technique.Oil companies may be reluctant to ignite blowoutsand thus destroy their wells unless there is no alter-native. When possible, rapid control of the well maybe more effective in minimizing pollution than earlyignition of the blowout. Wellhead ignition preventsthe use of equipment which could otherwise be usedto reduce the flow.

If a blowout were to occur, wellhead ignitionwould probably not be ordered immediately. Therewould inevitably be some delay as experts evaluatedthe best course of action to take, during which timeoil would continue to flow. It has been suggestedthat 24 to 48 hours would be required to analyzethe blowout situation. If experts determined thatthe well could be brought under control within a‘ ‘reasonable’ time period, the well would not bepurposely ignited, and alternative well control ef-forts would commence. The decision would dependon the rate of flow, the likely damage to the rig andequipment if the well were purposely ignited, thepotential environmental damage with and withoutwell ignition, and the safety, cost, and efficiencyof cleanup options.

The State of Alaska’s decision to grant year-round exploratory drilling on and inside the bar-rier islands to qualified lessees (the Tier 2 decision),was based, in part, on the viability of wellhead ig-nition as a countermeasures option. A major ques-tion, however, is whether government authorities(either the Alaska Department of EnvironmentalConservation or the United States Coast Guard)would be willing to order a blowout ignited, rec-ognizing the possible legal problems which mightensue if industry claimed that the well could havebeen saved and that other techniques could havebeen used. If ignition is ordered by these author-ities, it is not altogether clear who would pay forthe damage to equipment. There is also some con-cern about the safety of ignition. On offshore struc-tures, for instance, it is possible that igniting a blow-


out could destroy blowout preventers which mightbe used to bring the blowout under control. In thissituation, the capability to drill a relief well becomesvery important. Depending upon the area in ques-tion and the availability of rigs, a relief well couldtake from one to three months to drill. Hence, abuffer period would be required so that relief welldrilling could be completed before the fall freezeup.Wellhead ignition should probably not be consid-ered a preferred countermeasure, but rather as alast resort to use in the absence of any bettertechnique.

Ah--deployable igniters. Any approach to deal-ing with spills beneath ice must take into accountthat the size of the area that might have to becleaned could be extremely large, that there couldbe numerous unconnected pools of oil to clean up,and that putting cleanup personnel on the ice sur-face is potentially unsafe. To overcome these prob-lems, a considerable amount of effort has gone intodeveloping igniters which are inexpensive and safefor use from helicopters. One of the requirementsspecified by Alaska’s Department of EnvironmentalConservation in order for a lessee to obtain ap-proval of its contingency plan is that the lessee mustbe able to obtain 500 in situ igniters within 6 hoursof a spill and an additional 1,000 igniters within48 hours of a spill. Still, this number of ignitersmight be inadequate for certain types of spills. Ithas been estimated, for instance, that up to 30,000igniters could be needed to ignite the oil from alarge spill from a tanker. Research is continuingon developing more efficient igniters, and one ofthe more promising techniques currently under in-vestigation is that of airborne laser ignition. 33

Collection and disposal of residue. Although insitu burning is considered the most practicalcountermeasure for oil spills on solid or in brokenice, little attention has been given to collection anddisposal of the residue from a burn, which couldbe as much as 35 percent of the volume of the oilspilled. Such residue will be viscous and difficultto handle. While flare burners could be used to dis-pose of oil and oil/water mixtures recovered by me-chanical devices, residue from in situ burning may

331. A. BuiSt, R. c. llelore, and L. B. Solsberg, ‘‘Countermeasuresfor a Major Oil Spill from a Tanker in Arctic Waters, ‘Proceedingsof the Seventh Annual Arctic Marine Oilspill Technical Seminar (Ed-monton, Alberta, June 1984).

be too viscous to burn. Field tests have shown thatburn residue can be removed using sorbents. How-ever, burn residue and sorbent material must firstbe collected and then transported to an incinera-tion site, which may not be an easy task if the spillis distant from onshore facilities.

Air pollution. In situ burning in many places inthe United States would be considered unaccept-able because of the smoke and products of com-bustion. On the North Slope it may be less objec-tionable because it is remote from populated areas.Environment Canada conducted a brief study ofthe characteristics of atmospheric emissions fromin situ burning in 1979 and concluded that ‘‘in theimmediate vicinity of the fire, the concentration ofparticulate (soot) will be undesirably high and suchareas should be avoided. The concentrations at dis-tances of 10 to 40 km and beyond are judged tobe sufficiently low that no adverse air quality prob-lem exists. ’34 The study further notes that poly -nuclear aromatic hydrocarbons in the oil soot havebeen established as potent carcinogens and areregarded as being only slowly biodegradable. Thetoxicity of the amounts of these substances likelyto be present in the soot has not yet been estab-lished, but the Canadian report recommends thatit is prudent to minimize human exposure to thesesubstances. This could probably be accomplishedby careful planning of the burning operations, tak-ing into account short range weather forecasts.

More recently, the Alaska Department of Envi-ronmental Conservation and the Alaska Depart-ment of Natural Resources have noted that it isunlikely, given the remoteness from populationcenters of Arctic oil and gas activities, that concen-trations of the byproducts of in situ burning of oilwill reach levels in which a hazard to humans andwildlife will be present. They plan to use a disper-sion model to analyze the air quality impact beforedeciding to order a blowout ignited or burn largequantities of oil in situ. Despite possible air con-tamination, it is generally believed that in balanceit may be more advantageous to burn the oil ratherthan allow it to remain in the marine environment.

t+Tom Day, et. ~., characteristics of Atmospheric Emissions froman In-Situ Crude Oil Fire (Ottawa: Environment Canada, October1979), p. 58.

Ch. 7—Environmental Considerations Ž 195

Finally, although it will be possible to burn oilthat surfaces in melt pools in the spring, if largequantities of oil are involved, it may be desirableto take action sooner. The Alaskan Beaufort SeaOilspill Response Body (ABSORB) has sponsoredresearch investigating the possibility of drillingthrough the ice to reach oil pooled beneath. Sinceoil from a winter subsea blowout would be trap-ped in cavities under the ice, it may be possible toput personnel and heavy equipment on the ice inwinter to drill down to oil trapped in the largerpools—if it can be located—and pump it out. Thisapproach would not require developing any newequipment.

Dispersants

Dispersants are chemical agents used to elimi-nate oil from the surface of the water and distrib-ute it though the upper few meters of the watercolumn. Used on an oil slick, dispersants decreasethe interracial tension between oil and water, thusreducing the cohesiveness of the slick and promot-ing the formation of small droplets, which, with theaid of wind and waves, move downward into thewater column. Natural degradation by oil consum-ing bacteria and other processes eventually takesplace. The use of dispersants as an oil spill counter-measure may be appropriate if: 1 ) sea conditionsare too rough for deployment and/or efficient oper-ation of collection and recovery equipment; 2) thespill is too large; 3) the spill site is too remote forefficient mechanical recovery or in situ burning;4) it is necessary to stop the movement of a slicktoward shore; 5) the oil slick presents a fire haz-ard; or 6) the probability of contaminating wildfowlis high. 35

There are several problems associated with theuse of dispersants. For one, dispersants may ad-versely affect marine organisms. The first dispers-ants used for oil spills were hydrocarbon-basesolvents. In response to the Torrey Canyon spillit was found that, when applied in large doses, thesefirst-generation dispersants were lethal to marineorganisms. Dispersants thus acquired the reputa-tion of being compounds too harmful to marine lifeto be used as an oil spill countermeasure. More

tsAmeric~ petroleum Institute, Oil Spilf Cleanup: A Primer (Wash-ington, DC, 1982).

recently, “third-generation" dispersants have beendeveloped. For these dispersants, the water onwhich the oil is floating serves as the reactant inthe dispersing process. This eliminates the need forhydrocarbon solvents, and greatly reduces the bio-logical toxicity. The most effective dispersants arethose which maximize dispersal of oil at sea buthave a minimal impact on key organisms living inthe water column and sediments. Although the mostrecent generation of dispersants are relatively non-toxic, there may still be problems associated withplacing dissolved and particulate oil in the watercolumn. It is believed that sub-lethal effects (e. g.,tainting of marine species) are the main biologicalconcern.

The decision to use or not to use chemical disper-sants relates to the expected severity of oil spill im-pacts on wildfowl, beaches, or wildlife. The safeuse of dispersants requires an understanding of thefate, behavior, and effects of treated and untreatedoil spills. Since the potential exists for improper use,dispersants must be thoroughly tested before be-ing placed on the EPA approved list.

A second problem concerns the effectiveness ofdispersants in cold climates. Dispersants formulatedfor use in temperate regions may not be well-suitedfor use in the Arctic, since cold temperatures in-crease the oil’s viscosity, thereby reducing theability of the dispersant to break down the slick.Since dispersants require relatively high surfacemixing, their use would probably not be effectivein broken ice conditions. Currently available dis-persants are less effective in acting on water-in-oilemulsions. Another temperature-related problemis the potential for the dispersant to separate, freeze,or gel at low temperatures which might cause prob-lems in spraying. Also, the amount of mixing, thedegree of weathering of the oil, the dispersant-to-oil ratio, uniformity of coverage, the size of the oildroplets (they must be small enough to create apermanent dispersion), the presence of slush ice,and the degree of salinity affect dispersion. Forinstance, dispersants require mixing to be effective,and sufficient wave energy is often not present offthe North Slope. In addition, since current oil andgas operations in the Alaskan Beaufort Sea are invery shallow water, the use of dispersants may notbe an effective way to degrade the oil and may notbe desirable from an environmental point of view.


On the other hand, dispersants could be effectivein the Navarin Basin, where there is more waveenergy and deeper water, and where marine lifeand wildfowl are more dispersed.

Dispersants have been developed in the last fewyears which apparently require little mixing i naddition to normal wave action, and this develop-ment has stimulated research and development inaerial application techniques. Dispersant effective-ness, toxicity, and logistics support requirementsprobably should be examined in light of the muchgreater slick thicknesses associated with fresh oilfilms in the Arctic. Ultimately, it could be possi-ble to rank dispersants according to their effective-ness in specific types of situations.

The effectiveness of dispersants as a counter-measure in Arctic waters has yet to be adequatelydemonstrated under cold marine conditions. Ques-tions remain, for instance, about whether aeriallyapplied dispersants work the way they are supposedto or merely ‘herd’ the oil to either side of the spraypath. The two largest dispersant manufacturers,British Petroleum and Exxon, are actively involvedin developing chemical dispersants that will be moreeffective in treating Arctic oil spills, or other viscousspills.

Logistics problems and high costs of using dis-persants as a countermeasure for large, remote Arc-tic spills may ultimately prove to be the factors mostlimiting their use. Since dispersants must be appliedfrom either ships or aircraft, their use depends uponthe availability of expensive equipment. Moreover,for major spills, large quantities of dispersants willbe required. Long distances require large amountsof fuel. However, aerial dispersant operations couldbe carried out in all Alaska OCS areas from existingaircraft landing facilities.

For use in remote Arctic locations (e. g., to applyto oil from a tanker spill), aircraft may be the onlypractical means of delivery, because for dispersantsto be effective, they must be applied as soon as pos-sible after a spill. It has been estimated that a re-sponse effort for remote spills could require threeto four days to mount. By this time, however, theincreased viscosity of the oil would make currentlyavailable dispersants much less effective. Thus, un-til more effective dispersants are developed, aerialapplications will not likely be a useful counter-

measures technique for remote tanker spills. More-over, expensive stockpiling of sufficient quantitiesof dispersants at strategic locations and a well-rehearsed logistics plan for delivering the chemi-cal to the spill site probably will be crucial if futureapplications are to be successful. More promising,perhaps, is the use of dispersants to combat oil fromblowouts which is thin and fresh, and for fresh spillsin choppy seas which can be reached quickly. Otherapplications might include small batch spills andprotection of nearshore areas.

Shoreline Cleanup

Conventional shoreline cleanup in the south in-volves the containment of oil at shore, the removalof oil and oiled debris by manual and mechanizedmeans, and the cleaning of rocks and man-madestructures by high-pressure water and steam.Northern cleanup and restoration operations willutilize techniques and equipment much as in thesouth. The northern shoreline cleanup operationwill, however, likely be complicated by severalfactors.

Outside the Prudhoe Bay area, a large work forceis not available in the Arctic. Since many cleanupsteps require manual labor, responses to northernspills may face labor shortages. Heavy equipmentwill have to be used sparingly due to the sensitivenature of the northern shorelines and their slowrecuperative abilities. In many instances, beach ma-terial will not support heavy loads. In addition, thepresence of boulders and other irregular featureson the surface preclude the use of any large mech-anized vehicle. The lack of road access in the Arc-tic means personnel and equipment will have to betransported to the spill site by water or air. Coldtemperatures much of the year and periods of pro-longed darkness will also complicate northernshoreline cleanup operations. While all of the south-ern shoreline cleanup techniques are generallyapplicable to the Arctic study area, the remotenature and harsh but fragile environment of theNorth will make their application more difficult andless efficient. In most cases, beaches and shorelineswill likely be left to regenerate by natural means.

Conversely, shoreline response may not be astime sensitive as offshore or nearshore cleanup;thus, there would be more time to import additional


labor from Fairbanks, Anchorage, or elsewhere. Inthe northernmost areas, the shoreline would be ina frozen or semi-frozen condition most of the year,which would limit the amount of oil that wouldpenetrate the surface. Industry expects that mostshoreline cleanup operations would take place dur-ing the summer when there is much more daylightthan in the lower latitudes.

Monitoring and Surveillance

The effectiveness of many control operations de-pends on the ability to monitor the position, direc-tion of drift, and size of oil slicks. The vast areasand remoteness of the Arctic, as well as long peri-ods of darkness, complicate this task. The most ob-vious method of tracking the oil is by visual obser-vation from aircraft. In many cases this will notbe possible in the Arctic because of prolonged peri-ods of poor visibility due to either weather or sea-sonal daylight conditions. Many other methodshave been developed for this purpose which will im-prove surveillance under northern conditions.

Radio tracking buoys monitored from land, shipsor aircraft have been constructed to simulate thebehavior of specific oil types. Tracking distancesof 15 kilometers from the water and 45 kilometersfrom the air for periods of up to three weeks arepossible with the present equipment.

The use of both passive and active airborneremote-sensing packages for tracking and locatingpurposes has been advanced in recent years. Pic-tures of spill extent and location can be madethrough color or filtered black and white photo-graphs. Low-light television systems can differen-tiate oil slicks from wind and wave patterns but areineffective in the dark and are unable to discrimi-nate oil from foam, slush ice or brash ice, A dayor night system—the laser fluorosensor-is able todetect oil on water, on ice, and in ice-infested con-ditions. It is limited to the detection of oil at, orvery near the surface of the water or ice. Dual, in-frared/ultraviolet, line scanners have been suc-cessful in locating oil on a real-time basis duringthe day. Side Looking Airborne Radar (SLAR) isable to cover a larger area in one pass from an air-plane or satellite. These SLAR systems are effec-tive, day or night, in detecting oil only in ice-freewaters. None of the sensors currently available have

been proven to detect oil in broken ice, with theexception of the laser fluorsensor, which is still be-ing tested.

Satellite imagery is another means of locating andtracking oil slicks during daylight hours. Currently,the LANDSAT series of satellites scan the Arcticwith sensors in the red, green, and near infrared.This information can be used to identify the posi-tion and extent of an oil slick. Plans to mount im-proved sensors in these orbiting stations will un-doubtedly enhance the use of satellites for futuremonitoring.

Government/IndustryResponsibilities

Primary responsibility to cleanup oil spills restswith industry, and, although industry has treatedthe oil spill issue seriously, it has developed onlylimited capability to contain or clean up a spill inthe Arctic. It is the responsibility of Federal andState governments to ensure that industry is ade-quately prepared to respond to oil spills and to pro-vide backup assistance when necessary.

Federal Government

Since the Santa Barbara blowout, improvementsin the regulations governing OCS oil and gas ex-ploration and development have been made by theDepartment of the Interior. New regulations re-garding subsea blowout preventers, worker train-ing programs, oil spill contingency plans, and in-spections have been implemented since 1970. Inaddition, several laws establish penalties for spill-ing oil and assess liability for polluters. For exam-ple, amendments to the FWPCA in 1972, 1977,and 1978 have increased civil and criminal penaltiesthat may be incurred for polluting. Polluters maynow be fined up to $10,000 for failure to report anincident, and up to $50,000 for each offense (andmore if willful misconduct or negligence can beproved). Under the FWPCA, vessel owners are lia-ble for cleanup costs of up to $150 per gross tonand owners of offshore facilities may be liable forcleanup costs up to $50 million. The Administra-tion supported recent congressional attempts to fur-ther increase pollution penalties and liability limits.


Federal responsibilities in the event of offshoreoil spills are specified in the National Oil and Haz-ardous Substances Pollution Contingency Plan, de-veloped in response to the FWPCA. The plan des-ignates the Coast Guard and the MMS as the leadgovernment agencies with responsibilities for off-shore oil spill mitigation and cleanup. The respec-tive responsibilities of these two agencies have beenclarified in several memoranda of understanding.

In general, the Coast Guard is responsible forcoordinating and directing measures to contain andremove pollutants from the water, while the MMSis responsible for coordinating and directing meas-ures to abate the source of the pollution. In theAlaska coastal region, responsibilities are furtherdelineated by the Alaska Coastal Region Multi-Agency Oil and Hazardous Substances PollutionContingency Plan. Although the primary respon-sibility for pollution response lies with the CoastGuard, the MMS does have the authority to sus-pend response operations within a 500-meter ra-dius of the pollution source to facilitate abatementmeasures.

Supervising and monitoring is the Coast Guard’snormal role in managing a cleanup operation. Itis Coast Guard policy to encourage the responsi-ble operator to undertake proper removal actions.However, the Coast Guard is prepared to directthe response if the responsible operator is either un-known or not taking satisfactory action. When theCoast Guard is simply monitoring the cleanup oper-ation, removal is done by commercial cleanup con-tractors and industry cooperatives. Historically, theCoast Guard has been directly involved in only oneout 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 Guardprovides an On-Scene Coordinator (OSC) (theCaptain of the Port within a specific area of thecoastal zone). The OSC coordinates or directs theFederal response to actual or potential pollution in-cidents. If the OSC decides that cleanup is inde-quate or cannot find anyone to immediately assumeresponsibility for directing an action which is con-sidered necessary, he or she will declare a Federal

B6Coast Guard capabilities for Oilspill Cleanup, Hearing beforethe House Committee on Government Operations (August 26, 1982).

response and take over actual management of thecleanup. Commercial contractors are used when-ever possible, since it is the Coast Guard’s policynot to compete with private industry. However, theCoast Guard has developed a modest inventory ofequipment for use where commercial sources areeither not available or do not have the necessaryamount or type of equipment. Much of the CoastGuard’s equipment is for use to combat open waterspills and was designed specifically for its use, sincethere are fewer commercial sources for this type ofequipment.

The OSC has a number of resources availableto expand the amount of equipment, personnel, andexpertise available. The Regional Response Team(RRT) can be convened at the request of the OSCfor advice or assistance in obtaining equipment orother support. The RRT is also responsible forplanning and preparedness prior to spills. The teamconsists of regional representatives of the Depart-ments of Agriculture, Commerce (NOAA), De-fense, Energy, Health and Human Services, In-terior, Justice, Labor, State, and Transportation,EPA, the Federal Emergency Management Agency,and representatives of State governments. The Na-tional Response Team (NRT), composed of Fed-eral agency representatives at the national level, isalso available to assist the OSC. The NRT is con-sulted for major policy decisions or when large scaleor specialized support not available to the RRT isneeded.

The National Strike Force (NSF) is a key CoastGuard resource available to the OSC. When com-mercial resources are not adequate, the NSF isemployed. The Strike Force consists of severalteams specially trained and equipped to respondto oil spills. The Pacific Strike Team of the NSF,located in Marin County, California, is the unitcharged with responding to spills in the Arctic. TheNSF maintains a stock of specialized equipmentthat can be deployed anywhere in nation. It is alsoinvolved in testing and evaluation of equipment andresponse methods. Other resources upon which theOSC can draw are the Scientific Support Coor-dinator provided by NOAA, EPA, State and localgovernments, and the academic community.

The Coast Guard has developed regional andlocal contingency plans in preparation for spills.These plans include data on possible pollution


sources, location of environmentally sensitive areas,available contractors/cooperatives and their equip-ment, and plans for protecting vulnerable resourceswithin the area. An Environmental Atlas for theAlaskan Beaufort Sea, which contains informationconcerning general oceanography, meteorology,ice, and climatology recently has been compiled foruse by the OSC. By compiling available informa-tion on environmental conditions and variables, theOSC is better able to understand the environmentalconditions one could expect to encounter in theevent of a spill. If the atlas proves useful, the CoastGuard plans to develop atlases for other lease saleareas of the Alaskan OCS.

Industry

The offshore oil and gas industry must complywith OCS regulations and orders. Regulations aregeneral rules applicable to OCS operations every-where. OCS orders are published by the MMS andrefer to particular areas. These orders expand uponthe regulations and provide more detailed guidanceon regulatory requirements. OCS Order No. 7stipulates the pollution prevention and controlmeasures required of industry. This order specifiesthat lessees shall submit a description of procedures,personnel, and equipment to be used in reporting,cleaning up, and preventing oil spills which mayoccur during exploration or development activities.The order also requires lessees to maintain (or tohave readily available) pollution control equipment,including booms, skimmers, cleanup materials, andchemical agents. In addition, requirements for drillsand training procedures are also stipulated.

In addition to other requirements, OCS OrderNo. 7 requires that all companies that propose todo work in the Arctic submit an oil spill contingencyplan. Contingency plans are reviewed annually andmust contain information concerning: 1 ) amount,type, and location of all countermeasures equip-ment and time required for its deployment; 2) alter-native responses for spills of varying severity; 3)plans for protection of areas of special biologicalsensitivity; 4) procedures for early detection andtimely notification of an oil spill, including namesand telephone numbers of people to notify; and 5)the necessary steps to be taken to assess the seri-ousness of the spill, plan the response, and begincleanup actions. Oil companies must specify an oil

spill response operating team consisting of trained,prepared, and available operating personnel; an oilspill response coordinator; a response operationscenter and reliable communications system for co-ordinating the response; and provisions for disposalof recovered spill materials.

The Coast Guard reviews and advises the MMSas to the adequacy of industry oil spill contingencyplans submitted to MMS. Criteria for evaluatingplans have been defined jointly by the two agen-cies. The Coast Guard and MMS consider: 1) theadequacy of the risk analysis; 2) the adequacy ofrecovery equipment; 3) equipment availability; 4)the estimated response time; 5) provisions for peri-odic practice drills; 6) adequacy of support vessels;7) dispersant equipment; 8) decision procedure forordering ignition of an uncontrollable well; 9) dis-posal methods and sites; and 10) detection andmonitoring provisions.

Oil spill contingency planning efforts of individ-ual companies are supplemented by a statewide co-operative organization, Alaska Clean Seas (ACS).ACS has been organized to assist member com-panies in dealing with the possibility of a major spill.ACS maintains spill response equipment and sup-plies, provides staff assistance for contingency plan-ning and training, and conducts research and de-velopment projects to advance the state of the artof oil spill containment and cleanup. ACS is dividedinto five cost-participation areas: the Beaufort Sea,Norton Sound, St. George Basin, the Gulf ofAlaska, and the Navarin Basin. In all, sixteen com-panies have joined ACS, although memberships ofeach area vary according to company interests.

ABSORB, the Alaskan Beaufort Sea Oilspill Re-sponse Body, is under the ACS umbrella, and isthe regional response organization for the BeaufortSea. Equipment for use by members has beenstockpi led at ABSORB’s main warehouse inPrudhoe Bay. As far as equipment staging is con-cerned, industry preparations seem to be very good.In addition to providing supplemental equipmentand expertise, ABSORB has studied the biologyand shoreline characteristics of the Beaufort Sea,and has recently assembled an oil spill response con-siderations manual which synthesizes knowledge ofthe biological resources of the area. Industry pointsout, with some pride, that it has not yet been nec-essary to use ABSORB equipment. However, since


there have not been any spill incidents, the capa-bility of personnel to respond to spills under real-istic conditions, remains unknown. Moreover, forlarge Arctic spills, it is likely that contractors fromoutside the region would have to be used. The CookInlet Response Organization could possibly alsoprovide support for spills in the Arctic.

The Alaska Cooperative Oilspill Response Plan-ning Committee functions in addition to the indus-try cooperative organizations. It consists of bothindustry (ACS) and government (State and Fed-eral) representatives. Its purpose is to foster shar-ing of resources and technical expertise and to fa-cilitate cooperative oil spill response.

State of Alaska

The Alaskan Department of EnvironmentalConservation requires that an oil spill contingencyplan be approved (and renewed at least once everythree years) for operations within State waters.Moreover, concurrence of the State in the adequacyof oil spill contingency plans must be obtained tothe extent required the CZMA. Like the CoastGuard, if the State determines that containmentand cleanup activities are not adequate, the depart-ment may undertake cleanup itself and/or may issuea contract for the cleanup. Where the Coast Guardhas primary authority, the State may still author-ize supplemental cleanup or containment efforts.

State contingency plans are similar in mostrespects to Federal requirements. Of special note,for Tier 2 approval the State requires that 500 insitu igniters be available within 6 hours of a spill,and that an additional 1,000 be obtainable within48 hours of spill. The state also requires that 1,000feet of fire resistent boom be stored on site, andthat an additional 2,500 feet be available within sixhours. In addition, plans must be submitted fordrilling a relief well, and the decision process nec-essary to ignite a well must be outlined .37

sTAlaska Departments of Environmental Conservation and Natu-ral Resources, ‘ ‘Final Finding and Decision of the CommissionersRegarding the Oil Industry’s Capability to Clean Up Spilled Oil Dur-ing Broken Ice Periods in the Alaskan Beaufort Sea’ (June 1984).


Under the OCS Lands Act, the Federal govern-ment requires that the oil industry use the bestavailable and safest technologies (BAST) in theirdrilling and production operations. Criteria existfor evaluating the adequacy of most equipment orprocesses, but there are as yet no standards forevaluating offshore oil spill cleanup technology.One problem is that it is difficult to determine whatproportion of spilled oil is “adequate” to clean upor how much can reasonably be expected to becleaned up in spill situations. The definition of‘‘adequacy ‘‘ is as much a political issue as a tech-nological one. Neither the government nor the oiland gas industry is currently required to demon-strate which oil spill technology is best.

Three Federal agencies have small inhouse oilspill research and development programs: theMMS, the Coast Guard, and EPA. Total Federalfunding for oil spill technology research has aver-aged less than $1 million per year over the past fiveyears, One million dollars per year is consideredsmall in view of: a) the unknown and/or inadequatecapabilities of oil spill containment and cleanuptechnologies for frontier areas; b) the Administra-tion’s objective of accelerating OCS development;and c) the fact that the total economic costs of ma-jor spills may reach several hundred million dollars.Suggestions of the kinds of oil spill technology re-search needed are given in table 7-3.

Representatives from the U.S. agencies, alongwith the U.S. Navy and the Environmental Pro-tection Service (EPS) of Canada, comprise theOHMSETT (Oil and Hazardous Materials Simu-lated Environmental Test Tank) Interagency Tech-nical Committee (OITC). Although the CoastGuard has funded some Arctic and offshore spilltechnology research since the early 1970s, theOITC did not become involved in Arctic or off-shore oil spill technology research until 1984. Theobjective of the OITC program is to evaluate oilspill countermeasures equipment and methods forOCS conditions. The OHMSETT test tank, lo-cated in Leonardo, New Jersey, has been used toevaluate Arctic oil spill technology. However, be-cause this program is new and because there have


Table 7-3.—Oil Spill Technology Research Needs

Assessment of capabilities of existing oil spill equipmentand techniques under realistic conditions

Field or large-scale tank tests of behavior of North Slopecrude oil in cold water and in ice

Assessment of behavior of oil in a moving, broken icefield

Development of a portable oil spill response system tobe used on tankers

Development of a containment boom that can be used inbroken ice conditions

Development of better techniques for oil spill cleanup inshallow, nearshore waters

Development of better techniques for containing oil inscattered ice floes outside the protection of the barrierislands

Development of more effective ignitersDevelopment of an oil spill recovery system that can be

used on vessels-of-opportunity (vessels used to supplyoffshore operations)

Determine and record the properties of air and water-borne residues of in situ burning

Determine minimum boundary conditions for effective insitu burning (thickness, degree of weathering,containment requirements)

Refine fire resistant containment boomsReview dispersants for cold and open water applicationsSOURCE: Office of Technology Assessment

been funding limitations, little testing of equipmentfor use in Arctic or deepwater areas has been ac-complished to date.

The OITC has recently proposed a 5-year pro-gram for testing OCS booms and skimmers. Thisprogram would consist of three phases: 1) tanktesting; 2) assessment of equipment capability atsea for seakeeping and durability (in accordancewith a rigorous, pre-determined test protocol); and3) exposure of the equipment under OCS condi-tions to intentional oil spills. The OITC also pro-poses to continue tests, begun in 1984, on the po-tential for mechanical recovery and in situ burningof oil in broken ice as a mitigation measure; to con-tinue investigation of new technologies; and to takeadvantage, when possible, of spills-of-opportunityto 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 fund-ing at this level is considered unlikely in light ofthe budget constraints of the participating agencies.EPS participation is considered very important,since the Canadian agency also conducts spill re-search, the results of which are available to theOITC. The Coast Guard also contributes logisticalsupport. Although the MMS has spent about $372million (or an average of approximately $31 mil-lion per year) for OCS environmental studies since1973, none of this money has been allocated for oilspill equipment research.

Since the 1970s, little industry or governmenteffort has been given to developing technology ormethods for the specific purpose of combatting oilspills in deepwater. As oil and gas activities increasein deeper and more distant waters, the continueduse of conventional recovery equipment in theseareas may need further analysis. In particular, tech-nologies for open-ocean rough sea recovery anddeepwater sea floor containment may need furtherdevelopment. However, the major difference be-tween countermeasures problems in deepwater andspill problems nearshore is logistical rather thantechnological. Logistical concerns include how totransport the equipment needed to contain, recover,store, and dispose of oil to the spill site in a timelyway.

The MMS is currently funding two engineeringstudies to deal specifically with deepwater subseablowouts: 1) the feasibility of deploying a large self-contained collection ship capable of remaining on-station while collecting oil and gas from a blowingwell using a subsea collector similar to that usedin the Ixtoc 1 blowout (the ‘ ‘sombrero’ ‘); and 2)the feasibility of deploying a collection ship equippedwith skimming booms to collect and separate oilin close proximity to a blowing well. Such a shipwould have to be large enough to remain on-stationin heavy weather and to store two to three weeksof recovered oil. The availability of such self-contained ships could possibly overcome many ofthe logistics problems related to deepwater spills;however, costs may be extremely high.

Appendixes

Appendix A

Offshore Leasing Systems

U.S. Federal Leasing System forOffshore Areas

Description

Federal offshore leasing is conducted according to theguidelines contained in the Outer Continental Shelf(OCS) Lands Act of 1953, as amended in 1978, whichauthorizes the Secretary of the Interior to grant mineralleases for OCS lands and to prescribe any necessary reg-ulations. Currently, the Minerals Management Serv-ice (MMS) within the Department of the Interior is re-sponsible for implementing the offshore leasing systemand the operating regulations.

In general, the Interior Department identifies an areafor leasing in accordance with a pre-set lease schedule.It surveys the hydrocarbon potential, calls for informa-tion, and prepares a draft environmental impact state-ment. After filing a final environmental impact state-ment with the Environmental Protection Agency, thelease sale is announced and comments are solicited fromthe States and other interested parties. With appropri-ate modifications, the lease sale takes place and firmsare awarded offshore tracts according to a competitivebidding process. In the post-lease phase, companiesmust submit extensive safety and environmental pro-tection plans with each stage of exploration, develop-ment, and production. The post-lease managementfunctions of the Department of the Interior involve ap-proval and enforcement of the plans and collection ofgovernment revenues. The pre-lease and post-lease stepsof the leasing process are outlined in table A-1 and fig-ure A-1.

LEASE SCHEDULE

Prior to the enactment of the OCS Lands Act Amend-ments of 1978, the Department of the Interior was notrequired to develop a prospective leasing program orplan. Between the start of leasing in 1954 and 1967,nearly all offshore tracts nominated by the industry wereoffered for leasing. However, in 1967, the Departmentof the Interior instituted a formal nomination and selec-tion system that required a resource evaluation anddetermination of industry interest before tracts were of-fered for sale. Subsequent to the passage of the OCSLands Act Amendments of 1978, leasing programs havebeen developed in accordance with Section 18 of the Act,which requires that the Secretary of the Interior pre-pare and periodically review a 5-year leasing schedulewhich is consistent with the principles of the Act.

The selection of areas to be included in the leaseschedule is influenced by initial assessments of oil andgas potential, environmental concerns, economic con-ditions, location of commercial fisheries, availability oftechnology, and other factors. Geological and environ-mental information on the Outer Continental Shelf iscollected and evaluated by the Department of the In-terior. Companies may obtain permits for preliminaryoffshore exploratory activity, including broad areareconnaissance to identify promising geologic formationsand requirements for more detailed seismic surveys. Incertain circumstances, permits may be granted to firmsto take bottom samples or cores (COST wells) to ob-tain additional geologic information. The governmentmay request the submission of all pre-lease geologicaland geophysical data and information.

Final approval of the 5-year OCS leasing programtakes approximately 2 years. Comments are solicitedfrom the States, industry, Federal agencies, and otherinterested parties at several points in the developmentof the plan. After comments are received and appro-priate modifications are made, the final schedule is sub-mitted to the President and Congress for review.

CALL FOR INFORMATION

The initiation of individual lease sales begins with theidentification of areas of hydrocarbon potential by theDepartment of the Interior. A Call for Information isissued for a large area, usually consisting of several mil-lion acres, and is published in the Federal Register witha 45-day comment period. Potential bidders are askedto identify areas they wish to have offered for lease.States and other interested parties may identify and rec-ommend areas which should be excluded from oil andgas leasing or only leased under special conditions be-cause of conflicting resource values or environmentalconcerns. At the same time, a Notice of Intent to pre-pare an Environmental Impact Statement (EIS) is pub-lished, which invites public assistance in determiningsignificant issues. The information received from thepublic, as well as the resource, environmental, and tech-nical information collected by the Department of the In-terior, are used to identify an area for further analysisin the EIS.

In the proposed 1986-91 5-year leasing schedule, anadditional lease sale step has been added for selectedfrontier-area sales. A Request for Interest will be madefour months prior to the Call for Information. This re-quest will help determine industry interest in leasing inthese areas and whether the 2-year sale process should

205


Table A-1.–Steps in Offshore Leasing (1984)

Timeframe: monthActivity Lower 48 Alaska Action

Pre-lease phase:Five-Year

Leasing Program

Identify area ofHydrocarbon Potential

Call for Information;Publish Notice ofIntent to Prepare EIS

Area Identification

Draft EnvironmentalImpact Statement

Final EnvironmentalImpact Statement

Proposed Notice ofLease Sale

Final Notice ofLease Sale

Lease Sale

Leases Issued

Post-lease phase:Exploration Plan

EnvironmentalAnalysis

ExplorationDrilling

Development andProduction Plan

EnvironmentalAnalysis

DevelopmentDrilling

PipelinePermits

Production

Relinquishment

2-5 years prior toto call

At least 2 monthsprior to call

1 1

4 4

12 15

18 21

19 22

22 25

23 26

25 28

Within 4 years oflease issue (for5-year terms)

For all explorationwells

Within 5 years oflease issue/orreceives SOP

For all explorationwells

For duation ofproduction

Cancellation orshutdown

Prepare schedule of proposed leasesales, to be revised annually.Industry, states, and other partiescomment prior to final approval.

Identify area of hydrocarbon potential(AHP) for upcoming sale.

Request bidders to indicate areasof interest and solicit comments fromall interested parties. Due in 45 days.Also announce initiation of EISscoping.

Identify areas for detailed environ-ment analysis.

Draft EIS issued for planning areaand notice published in FederalRegister. Comments requested andhearings held during 60-day commentperiod.

Revised EIS submitted to EPA forreview and made available to public.

Proposed notice of sale, with termsand conditions, sent to States forcomment for a 60-day period.

Final notice of sale published inFederal Register at least 30 daysprior to sale.

Regional office holds public openingand reading of sealed bids.

Leases issued not later than 90 dayslater, after bid review and anti-trustreview.

Lessee submits exploration plan andenvironmental report. States evaluatefor CZM consistency.

MMS conducts environmental analysis,prepares EIS if necessary, andapproves or rejects plan.

Lessee submits application to drill(APD) and applies for permits fromother agencies. After analysis, MMSapproves or rejects.

Lessee submits development andproduction plan and environmentalreport. States review for CZMconsistency.

MMS conducts environmental analysis,prepares EIS if necessary, andapproves or rejects plan.

Lessee submits APO and requiredpermits, State CZM ruling, and plat-form verification and certification.MMS approves or rejects.

Lessee applies for pipeline permitsfrom MMS and other relevantagencies.

Lessee submits monthly productionreports and royalty payments.

Wellheads plugged and equipmentremoved.


App. A—Offshore Leasing Systems • 207

Figure A-1 .—Offshore Leasing Process: Pre-Lease

OtherFederal

Public Industry States agencies I FWS/NPS MMS Secretary

FederalRegister

Input

FederalRegister

Hearinqs

FederalRegister

FederalRegister

FederalRegister

● 5-year OCS Oil-and-gas leasing schedule

InputGeology and

resource reports1

[

Defin area ofhydrocarbon potential Approve

Call for reformation

Notice of intent to45-day comment period prepare EIS

4 Step 1 Approve

Call closes– Evaluate comments– Evaluate multiple uses

in EIS process

Area IdentificationStep 2 Approve

— — . — — Draft EIS(regional office)

60 day comment period●- ~

Final EIS

Governors — — Secretarial issue document

saledecision

*Governors

Governors 60 day comment period on proposed notice of sale Dec ision● meeting on

areas termsConditions

Publi shed 30 days prior 10 sale— Final notice of sale

Step $ Approve

Bids ● sale

Just IceDepartment/

Federal TradeCommission review

[Sale results I

Bid acceptance decisions

Lessee — — Lease IssuanceJ

SOURCE Minerals Management Service


—Offshore Leasing Process: Post-Lease

Public

Federalregister

Public hear

Federalregister

Public hearing

III

● Regs Corps● construction

Pipeline Ipermit

I II construction I I

Monthlyprod reports ●

& royalties

Product Ion

1 1 1

I I I

1 1 Official recordtitle actions

Secretary

Cancellation

SOURCE: Minerals Management Service

App. A—Offshore Leasing Systems ● 209

proceed. The Request for Interest will be made for thefollowing Alaska sales: Gulf of Alaska (1988); Cook In-let (1990); Shumagin (1990); Hope Basin (1991); andKodiak (1991).

ENVIRONMENTAL ASSESSMENT

The National Environmental Policy Act (NEPA) of1969 requires the analysis, assessment, and disclosureof environmental impacts that may result from Federaloffshore leasing. The environmental assessment proc-ess for offshore lease sales involves the preparation ofpreliminary and final environmental impact statements,public hearings, and consultation with affected Statesand all interested parties.

The first step is the preparation of a Draft Environ-mental Impact Statement (DEIS) by the Departmentof the Interior. For the first sale in a planning area, theDEIS is prepared for the entire area; abbreviatedstatements are prepared for subsequent sales. The DEISincludes a description of the lease proposal, a descrip-tion of the marine and nearby onshore environment,a detailed analysis of possible adverse impacts on theenvironment, the technology to be used, the socioeco-nomic impacts, mitigating measures proposed, alterna-tives to the proposal, and the records of consultation andcoordination with others in preparation of the statement.The DEIS is published in the Federal Register with a60-day comment period, and public hearings on theDEIS are held within the vicinity of the proposed leasesale.

A Final Environmental Impact Statement (FEIS) isthen prepared taking into account the comments re-ceived during the review period and at the public hear-ings. The FEIS is filed with the Environmental Protec-tion Agency and made available to the public.

NOTICE OF LEASE SALE

At least 30 days after the submission of the FEIS tothe Environmental Protection Agency, a final decisionis made by the Secretary of the Interior as to whetheror not the proposed sale will be held. A Secretarial IssueDocument (SID) is first prepared which analyzes theissues and options pertaining to the sale area, and in-cludes information on alternative terms and proceduresto be used in the lease sale. If the decision is to hold asale, the SID and the final EIS are submitted to the af-fected States for comment within 60 days. A ProposedNotice of Lease Sale is published in the Federal Regis-ter identifying the blocks to be leased and the leasingstipulations, terms, and procedures.

After the 60-day comment period, the Final Noticeof Lease Sale is published in the Federal Register. Tak-ing into consideration public comments and State con-cerns, 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 par-ticular tracts. It also gives at least a 30-day notice ofthe date, place, and time that bids are to be opened.

LEASE SALE

All leases are sold through a competitive bidding proc-ess with firms submitting separate sealed cash bids foreach individual tract. All bids are opened and read ata public sale, after which the bids are checked for tech-nical and legal adequacy. In addition, a determinationof the adequacy of the high bids is conducted. Theacceptance or rejection of each bid occurs within 90 daysafter the lease sale is held.

LEASE CONTRACT

The oil and gas lease contract grants the right to thelessee to conduct necessary operations to explore, drilland produce oil and gas from a specific tract. The pri-mary term of the lease contract is usually 5 years, al-though 10-year terms are granted for special conditions,such as ice-prone areas or deepwater sites. During thistime, oil and gas in commercial quantities must be foundor approved drilling or well reworking operations mustbe conducted, or the lease is forfeited. Leases may beextended beyond the initial lease terms as long as pro-duction is occuring, drilling or well reworking is under-taken, or a special suspension order is obtained.

EXPLORATION

The lessee is obligated to proceed diligently to exploreand develop the tract and must submit an explorationplan to the Department of the Interior for approval bythe fourth year of a 5-year lease. Details of drilling tech-nology, geophysical equipment, location of exploratorywells, oil spill contingency plans, an air quality analy-sis, and other relevant geological and geophysical in-formation must be included in the plan. The explora-tion plan must be accompanied by an environmentalreport, and certifications of consistency must be ob-tained from coastal States under the Coastal Zone Man-agement Act. After an environmental assessment, anenvironmental impact statement if necessary, and atechnical review, the Department of the Interior ap-proves, rejects, or modifies the exploration plan.

Before exploratory drilling can be initiated, an Ap-plication for Permit to Drill (APD) must be submitted.This includes detailed information on equipment design,well location and depth, and potential geophysicalhazards. Additional approvals are required each timea well is deepened, reworked, redrilled, or plugged back.In addition to the Department of the Interior permit todrill, appropriate permits must be received from the

.


U.S. Coast Guard, U.S. Army Corps of Engineers,Environmental Protection Agency, and other federalagencies to satisfy environmental or safety requirements.

DEVELOPMENT AND PRODUCTION

The planning, environmental assessment, and ap-proval process starts anew when oil and gas is discov-ered on a tract. A detailed Development and Produc-tion Plan and accompanying environmental report mustbe submitted by the lessee to the Department of the In-terior for approval. Certifications of consistency alsomust be obtained from the coastal zone managementprograms of the affected States. The plan and environ-mental report are reviewed by a number of Federalagencies and affected States, and the Department of theInterior prepares its own environmental evaluation andtechnical review. In addition, a separate platform veri-fication and certification process, involving third-partyverification agents, is initiated for the evaluation andmonitoring of platform design, fabrication, and in-stallation.

An APD must be received prior to drilling any de-velopment well, and any reworking of development wellsalso must be approved. All other necessary Federal per-mits, such as for offshore structures, navigation aids,and pollution discharge, must be obtained prior to ap-proval of the APD by the Department of the Interior.Permits and approvals also must be received for the con-struction and operation of offshore pipelines and for anysignificant modification of production equipment andprocedures. As production proceeds, the Departmentof the Interior is responsible for on-site inspection andmonitoring of offshore operations. The lessee must sub-mit monthly reports of operations and royalty paymentsto the government.

RELINQUISHMENT

Leases expire at the end of their initial term unlessactual production is occurring or a suspension of pro-duction or operation (SOP) is received for developmentactivities or approved drilling or well reworking opera-tions. Leases may also be relinquished by a lessee orcancelled by the Department of the Interior for non-compliance with OCS regulations. At the time of aban-donment, the operator must plug the wells in accord-ance with Interior requirements. All oil and gas zonesmust be isolated by the installation of cement plugs toensure a permanent seal. All pipe casings must be cutoff below the ocean floor and the well location must becleared.

Offshore Leasing Revenues

LEASE PAYMENTS

Revenues from offshore leasing consist of bonuses,rents, and royalties in addition to taxes. Bonuses areadvance cash payments made by companies for the rightto explore and develop particular tracts. Rents are an-nual fees, now set at $3 per acre, paid on leased acre-age. Royalties are pre-set percentages of the value ofoil and gas production paid after production begins. Thestandard royalty rate on offshore production has been162/3 percent, although some tracts have been leasedwith 12½ percent and 331/3 percent royalties. A fewtracts also have been leased with profit share paymentsand sliding scale royalties rather than fixed royalties.

From the start of the OCS leasing program in 1954to the end of 1983, bonuses, rents, and royalties fromoffshore leases have totaled approximately $68 billion(see table A-2). OCS receipts increased from an aver-age of $280 million per year in the 1950s and 1960s toan average of $3 billion per year in the decade of the1970s. In the early 1980s, OCS receipts averaged morethan $8 billion per year. In general, the level of receiptshas increased with the quantity of acreage leased, theamount of oil and gas produced, and increases in energyprices.

Bonuses have comprised the largest share of govern-ment lease payments (69 percent) other than taxes andaccount for most of the variation in annual OCSreceipts. Bonus receipts increased substantially in 1973-74, as a result of the Nixon administration initiativesto increase offshore leasing, and in 1979-83 as leasingwas again accelerated. In 1981, bonus receipts reacheda high of $6.6 billion for over 2 million leased acres.Bonus revenues declined from the 1981 level in 1982and 1983, due to depressed oil prices, the more costlyand risky nature of the deepwater and Alaskan tractsbeing leased, and other factors.

From 1953 to 1983, a total of 6 billion barrels of oiland 62 trillion cubic feet of gas were produced in Fed-eral offshore areas. Although offshore oil production de-clined every year between 1971 and 1980, it againturned upward in 1981 when 286 million barrels of oilwere produced. In 1983, Federal offshore hydrocarbonproduction represented approximately 11 percent of theoil and 24 percent of the natural gas produced in theUnited States, The cumulative value of the oil and gasproduced offshore between 1953 and 1983 is estimatedat $128 billion, of which $20 billion or 16 percent waspaid to the Federal Government in royalties. Lease pay-ments 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 . . . . . . . . . .

310002203121323321224442463758

77

1384238674095

000

5398131632339

03718115669777

1124102947520265886988484

1315984355758666845

55872970711

1514940500688172473272827342184311631406963413352256345276797405815872

120094037

176456294

486870402567

000

171300707026

01929177312945613524

72000141768746951934164114282598540

37222826195

10325701762158167987712779371100734129727417674431134238223700518863606593517

29863644

137

11162536506490

105123145189222269313361419412395361330317304292286277286321341

6371

0.0200.0560.0810.0830.0830.1270.2070.2730.3180.4520.5640.6220.6461.0071.1871.5241.9542.4192.7773.0393.2123.5153.4593.5963.7384.3854.6734.6414.8804.6793.940

62.157

0.0000.1410.1080.0000.0000.0000.0900.2830.0000.4890.0130.0960.0340.2090.5101.3460.1120.9450.0962.2513.0825.0231.0882.2431.5681.7675.0794.2056.6023.9875.749

47.116

0.0010.0030.0050.0080.0110.0180.0270.0370.0480.0670.0780.0890.1040.1440.1600.2030.2420.2850.3520.3660.4040.5620.6180.7020.9211.1521.5172.1393.2743.8153.376

20.728

0.0010.0040.0030.0040.0030.0020.0020.0040.0030.0080.0080.0100.0090.0070.0060.0080.0090.0090.0080.0080.0090.0140.0180.0230.0200.0220.0200.0190.0210.0200.0370.339

0.0020.1480.1160.0120.0140.0200.1190.3240.0510.5640.0990.1950.1470.3600.6761.5570.3631.2390.4562.6253.4955.5991.7242.9682.5092.9416.6166.3639.8977.8229.161

68.182‘Includes minimum royalties, shut-in gas, etc.


about 53 percent of the total value of oil and gas pro- production and 96 percent of all oil production in Fed-duction 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 Califor-been from the Gulf of Mexico (see table A-3 and figure nia. As a result, the Gulf of Mexico has accounted forA-2). The Gulf of Mexico, predominantly offshore Loui- 77 percent of bonus revenues, 97 percent of oil and gassiana, 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 GasRegions (mbbl) (bcf) Bonuses Royalties Rents Total

Gulf. . . . . . . . . . . . . . . . . . 6,096 62,037 36,076 20,196 269 56,541Pacific . . . . . . . . . . . . . . . 275 120 3,840 532 31 4,403Alaska . . . . . . . . . . . . . . . 0 0 4,360 0 22 4,382Atlantic . . . . . . . . . . . . . . 0 0 2,840 0 17 2,857

Total . . . . . . . . . . . . . . . 6,371 62,157 47,116 20,728 339 68,183

mbbl - million barrelsbcf-billion cubic feet

SOURCE: Minerals Management Service,


Figure A-2.—Federal Revenues From OCS Regions1953-1983

A

Pacific (6

Atlantic (4.2°/0)

Alaska (6.4°/0)

.5%)


in the Alaskan and Atlantic offshore regions began in1976, and while they have contributed some bonusrevenues and rents, there is as yet no oil and gas pro-duction or royalty revenues from these regions.

FEDERAL TAXESIn addition to lease payments, companies also pay

Federal taxes on offshore oil and gas production. In gen-eral, the oil and gas producing industry in the UnitedStates benefits from special tax provisions designed toencourage domestic energy exploration and production.In recent years, this tax advantage has been reducedby the Crude Oil Windfall Profits Tax. Offshore oil andgas producers may currently expense and deduct cer-tain costs, including intangible drilling costs (up to 80percent) and dry hole costs, which would normally berecovered through depreciation. Oil and gas producersalso benefit from two general provisons of the Federaltax code available to all business: the depreciationdeductions under the Accelerated Cost Recovery Sys-tem and the regular 10 percent investment tax credit.

In 1980, Congress enacted the Crude Oil WindfallProfits Tax, an excise tax per barrel on the differencebetween the crude oil market price and an establishedbase oil price. The rate varies between 15 and 70 per-cent depending on the oil tier (e. g., old oil, stripper oil),type of producer, and year of production. The tax onnewly discovered oil is to be phased down from the cur-rent 22.5 percent to 20 percent in 1988 and to 15 per-cent in 1989 and thereafter. The Windfall Profits Taxdoes not apply to oil production from Arctic areas. TheWindfall Profits Tax should not apply to oil producersin other offshore frontier areas, as the base price should

exceed the market price before fields come on streamin these regions.

REVENUE TRENDS

Owing to the substantial funds received by the Fed-eral Government from offshore leasing, there has beencontroversy regarding the relationship between offshoreleasing and revenue policy. It is widely believed thatthe pace of leasing has been partly dictated by budgetconcerns. In the early years of leasing, the Departmentof the Interior was accused of maintaining a deliberatelyslow rate of leasing in order to keep the demand forleases and bonus revenues high. In the 1970s, the Gen-eral Accounting Office (GAO) charged that the govern-ment accelerated leasing in order to increase revenuesfor the general Treasury. Similarly, the accelerated leas-ing schedule which began in 1982 is believed by someto stem partly from the need to generate revenues andreduce the large Federal budget deficit.

Budget concerns may have also influenced govern-ment forecasts of future revenues from OCS leasing. Itis difficult to project OCS receipts because of the sub-jective nature of resource estimates, unpredictability offuture prices and development costs, and unforseenchanges to lease schedules. The Office of Managementand Budget (OMB) has overestimated—by a factor of2 or more—projected receipts from offshore leasing inthe 1980s. The original OMB budget estimates for fiscalyear 1984 were for $18 billion in receipts from OCS leas-ing; this was later revised downward to $12 billion; how-ever, actual fiscal year 1984 OCS leasing revenues werein the area of $8-9 billion. For fiscal year 1985, OMBhas again projected $12 billion in OCS revenues, ascompared to a Department of the Interior estimate of$6 billion.

The Department of the Interior projects that royaltyrevenues will surpass bonus revenues for the first timein 1985-86 (see figure A-3). Interior forecasts show thatannual bonus revenues will decline to an average $2 to$3 billion per year while royalties level off at $3 to $4billion per year during 1985-89. At the same time, thecosts of post-lease management activities will rise as aresult of the increases in leased acreage and the diffi-culty of operating conditions in frontier areas. The bal-ance between income from offshore leasing and the costsof management programs may change as leasing pro-ceeds in offshore frontier areas.

State Offshore Leasing Policies

The offshore leasing systems used by the coastal Statesare similar to that used by the Federal Government.Certain aspects of the Federal leasing process were


Figure A-3. —OCS Revenues ForecastBonuses and Royalties

c

9 n Bonuses

O Royalties8

7

I

5

3

2

1

01953 1960 1965 1970

SOURCE Off Ice of Technology Assessment,

adapted from the State experience, such as the one-sixthroyalty rate which was that traditionally used for off-shore tracts by the State of Louisiana. Louisiana, Cali-fornia, and Texas leased offshore lands under their juris-diction prior to the enactment of the Submerged LandsAct of 1953, which established offshore State/Federalboundaries, and the 1953 OCS Lands Act, which pro-vided guidelines for the Federal system. Through 1983,the States accounted for 39 percent of the oil and 19 per-cent of the natural gas produced in the offshore areasof the United States. Currently, State offshore oil andgas production is decreasing. Production in Federalwaters now accounts for about 80 percent of total off-shore oil production and 88 percent of total offshore gasproduction.

Although Florida, Alabama, Mississippi, and Wash-ington State have leased offshore tracts, the States ofLouisiana, California, Texas, and Alaska have ac-counted for most of the State offshore activity and arethe only States to have offshore hydrocarbon produc-tion (see table A-4). Since the start of State leasing inthe 1920s, Louisiana has accounted for most of the wellsdrilled and hydrocarbons produced in State waters. Cali-fornia, which has not issued any leases since 1969, ac-

1975 1980 1985 1990

Year

Table A-4.—State Offshore Leasing Statistics(cumulative through 1983)

Production

Wells Oil* GasState dr i l led (mbbl) (bcf)Louisiana . . . . . . . . . . . . . . . . 4,688 1,338 9,654California . . . . . . . . . . . . . . . . 3,598 1,884 716Texas . . . . . . . . . . . . . . . . . . . 1,451 26 2,877Alaska . . . . . . . . . . . . . . . . . . 379 816 1,126Other . . . . . . . . . . . . . . . . . . . 29 0 0

Total State , . . . . . . . . . . . . 10,145 4,064 14,373Total Federal . ..........22,095 6,371 62.157

“Includes condensate.mbbl - million barrels.bcf - billion cubic feet,


counts for the highest percentage of oil and condensateproduced in State offshore areas. Currently, most Statedrilling activity is centered off Louisiana and Texas.

The leasing process used by the States is generallysimilar to the Federal system in its administrativeframework, competitive bidding system, and lease terms(see table A-5). AS does the Federal Government, the


Lead Leasing Agency

Permitting Agencies

Frequency of Sales

EIS Requred

Lease Term

Primary BiddingSystem

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 NaturalService

EPA, Coast Guard,Army Corps ofEngineers

5-8 year

Yes

5/10 years

Cash bonus bid/fixed royalty

12½% or162/3 0/0

$3 per acre annually

Corporate Income TaxWindfall Profits Tax

(except in Arctic)

Board

Office of Conser-vation, Depts.of Natural Res.,Env. Quality, andWildlife & Fish

Monthly

No

5 years

Cash bonus androyalty bid

Estimated 21 -26°/0

1/2 cash bonus

Severance Tax(12.50/,)


States receive revenues from offshore leasing in the formof cash bonuses, royalties, and other types of lease pay-ments, and from various tax levies. The States havetypically set higher royalty rates on production than theFederal Government, largely because State offshoreareas are nearer to shore and less costly and risky toexplore and develop than Federal waters.

Louisiana

Most oil and gas activity in State offshore areas hasbeen off the coast of Louisiana, which has developeda sizeable onshore support, service, and refining base.The first offshore tract was leased in the 1920s, andthrough 1983, almost 4,700 wells had been drilled inLouisiana waters. Oil and gas production from offshoreLouisiana has been declining since the early 1970s. In1983, Louisiana produced 24 million barrels of oil and316 million cubic feet of natural gas. In contrast, pro-duction in Federal waters offshore Louisiana in 1983was about 290 million barrels of oil and almost 3 bil-lion cubic feet of gas. Approximately 40 percent of Loui-siana’s 1 million acres of State offshore lands was underlease as of 1983.

Louisiana conducts monthly lease sales, and Staterevenues have depended heavily on offshore leasing. Thebidding system used in Louisiana is a hybrid with boththe cash bonus amount and the royalty rate open to bid.In addition, companies may submit several bids on thesame tract. Each bid is considered if it meets the mini-mum royalty rate of 12½ percent and any specified min-

Commission

Coastal Commission State Railroad(in dispute)

Not since 1969

Yes

20 years

Cash bonus bid/sliding royalty

Estimated 25%

$1 per acreannually

Corporate IncomeTax (9%)

Commission

Twice a year

No

5 years


250/o

$1 per acreannually

Severance Tax(4.6°/0 oil/7.50/0 gas)

Resources

Oil and Gas Cons. Comm.Dept. of Env. Cons.Dept. of Fish and GameOffice of the Governor

At least 3 per year

Yes (for major sales)

10 years


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 thatthe average royalty rate has been 21 to 26 percent. Therental fee is set at one-half of the cash bonus amountfor each tract. Louisiana has no corporate income tax,but has a severance tax of 12.5 percent on oil and 7 centsper cubic foot of gas.

California

From the start of leasing in 1929 through 1969,the State of California issued 62 offshore leases. Amoratorium was placed on offshore leasing in 1969as a result of the Santa Barbara Channel blowout.However, drilling on previously leased lands wasallowed to continue and some leases were extended.The State is currently planning to resume leasingin the Point Conception/Point Arguello offshoreareas, pending the settlement of jurisdictional ques-tions with the California Coastal Commission.From the start of leasing through 1983, approx-imately 1.9 billion barrels of oil and 700 billioncubic feet of gas have been produced in the Cali-fornia offshore. This is far more than has been pro-duced in Federal waters offshore the State, repre-senting almost 90 percent of the total oil and gasproduced off the coast of California to date.

California traditionally has awarded leases on thebasis of a cash bonus bid with a sliding scale royaltyrate, set at a minimum of 162/3 percent. It is esti-


mated that the sliding scale royalty system has re-sulted in an overall effective royalty rate of 25 per-cent. Several other types of bidding systems areauthorized by California regulations, and the Stateplans to experiment with net profit share paymentsin future lease sales. The other lease payment isan annual rental fee of not less than one dollar peracre, Taxes on offshore operators include a 9 per-cent corporate income tax, which is applicable tothe worldwide income of the company. Althoughthe State does not have ait does levy a small fee onin order to finance offshoreulatory activities.

severance tax as such,oil and gas productionadministrative and reg-

Texas

Texas issued its first offshore lease in 1922, drilledthe first well in State waters in 1938, and recorded thefirst production in 1940. Until the 1980s, oil and gasproduction from State waters remained about equal withthat from Federal waters offshore the State. However,oil production in Federal waters has now increased toabout 90 percent of total oil produced offshore Texas,while Federal offshore natural gas production increasedto 78 percent of the total in 1983. It is estimated thatmore than two-third’s of the State’s offshore area hasbeen leased, and that State offshore oil and gas produc-tion will continue to decline. In 1983, approximately2 million barrels of oil and 148 million cubic feet of gaswere produced in State waters.

Texas holds lease sales twice a year and leases mostoffshore tracts by a cash bonus bid/fixed royalty bid-ding system. However, Texas also has used royalty bid-ding for 10 to 15 percent of its offshore tracts, primar-ily those where hydrocarbon prospects were high. Inboth types of bidding systems, the minimum royalty rateis now 25 percent, Texas also has a graduated rentalfee system which increases with the number of yearsacreage is held, amounting to $1 per acre after the fourthyear. The Texas severance tax consists of 4.6 percenton oil production and 7.5 percent on natural gas pro-duction, 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 produc-tion, Alaska has as yet no oil or gas production in Fed-eral waters off the State. However, a probable commer-cial discovery was announced at Seal Island in theBeaufort Sea in 1984. In 1983, Alaska produced 22 mil-lion barrels of oil and 90 million cubic feet of gas fromoffshore State leases. Offshore gas production has con-

tinued to increase, while offshore oil production has de-clined since the 1970s. There is still substantial activityin State waters where 14 drilling platforms were sta-tioned and 18 wells drilled in 1983, as compared to 3structures in Federal waters in that year.

Prior to 1978, Alaska used the Federal bidding sys-tem of cash bonus bid and 162/3 or 12½ percent royaltyin leasing State offshore tracts. Amendments to Alaska’soil and gas leasing laws in 1978 broadened the State’sbidding methods. Since 1978, Alaska has leased agreater number of tracts with sliding scale royalties aswell as with profit share and royalty rate bidding. Inaddition, the minimum royalty rate was increased to 20percent. This was due to concern about declining oilproduction and the desire to increase revenues from po-tentially large oil and gas discoveries, particularlydownstream revenues. Alaska is one of the few Stateswhich collects more revenues from oil and gas produc-tion in the form of taxes than in the form of lease pay-ments. These taxes include a corporate income tax, aproperty tax, and a severance tax, which increases from12.5 percent to 15 percent of the value of oil and gasproduction after 5 years.

Foreign Offshore Leasing Policies

Comparison of U.S. and Foreign Systems

The offshore leasing systems used in other countriesdiffer from that used in the United States. Canada, theUnited Kingdom, and Norway, as well as the UnitedStates, are currently leasing offshore tracts in high-risk,high-cost regions of the Arctic and the North Sea. Theseareas are characterized by harsh operating environmentsthat require complex planning, long lead-times to firstproduction, high capital outlays, and the use of inno-vative technologies. In the design of its leasing systemfor offshore frontier areas, the United States differs fromthese countries in several aspects (see table A-6).

ALLOCATION OF LEASE RIGHTS

The United States is one of the few countries to grantleases solely on the basis of financial competition. Mostother countries rely on governmental discretion andindustry-government negotiation to award lease rights.Foreign lease allocation is by subjective comparison ofthe qualifications and terms being offered by applicants.After negotiation with the firm, foreign governmentsmay include stipulations in the leases to ensure rapidexploration and development of specified areas, providefor government participation in oil and gas production,protect the environment, provide for local employment,or further other national goals. While discretionary al-location provides greater scope for government influ-


Table A-6.—Comparison of United States and Foreign Offshore Leasing Policies

Leasing ProvisionsAllocation

Lease terms

Work program

Relinquishment

Average tract size

Financial ProvisionsGovernment

participation

Lease payments

Incentivepayments

Taxes

United States Canada United Kingdom Norway

Competitive

5/10 years or asas producing

None

None

25 sq. km

None

long

Cash bonus, 12½%or 162/s O/0 royalty

None

Corporate Tax: 46°/0Windfall Profits Tax

(except in Arctic)

Discretionary

Exploration: 5 yearsProduction: 10 years,

renewable for 10years

Yes

50 percent of acreage

2000 sq. km

25 percent (optional)

100/0 royalty, plusincremental royalty

Up to 80% forCanadian firms,25°/0 for foreignfirms (explorationonly)

Corporate Tax: 46°/0Petroleum Revenue

Tax: 12°/0

Discretionary



Yes

Up to 2/3 of acreage

250 sq. km

None

12½% royalty(none for frontierareas)

None

Corporate Tax: 52°/0Petroleum Revenue

Tax: 75°/0

Discretionary



Yes

50 percent of acreage

550 sq. km

>50 percent (optional)

Sliding scaleroyalties

None

Corporate Tax: 50.8°/0Special Petroleum

Tax: 35°/0


ence than competitive bidding, it is also more expen-sive to administer.

LEASE STAGES

The United States is unique in jointly granting leasesfor offshore exploration and development. Other coun-tries make a greater distinction between exploration anddevelopment lease rights. In these countries, explora-tion leases are granted for large areas for terms of 3 to5 years, specify the work to be completed, and requirethat all data be shared with the government. If a dis-covery is made, the terms of a production lease are thennegotiated. The advantage of the two-stage system isthat it provides for rapid exploration of large offshoreareas and gives the government greater flexibility inestablishing production lease terms.

WORK PROGRAMS

In the United States, lease rights are obtained throughthe payment of upfront bonuses, which provide an in-centive for firms to engage in efficient exploration anddevelopment so as to recover the initial investment. TheU.S. government only requires the submission of ex-ploration and development plans and diligent explora-tion. The discretionary allocation method used by other

countries usually entails a mandatory work program ne-gotiated in conjunction with the lease rights. This mayconsist of detailed exploration and development plans,drilling of a certain number of wells, and/or a minimumexpenditure. Firms which fail to carry out the terms ofthe work program can lose lease rights or any collateralpaid to the government. Work commitments ensurerapid exploration and development, but also can be ex-pensive to administer.

RELINQUISHMENT

Other countries usually have relinquishment require-ments for nonproductive acreage in conjunction withmuch larger tract sizes. Canada, the United Kingdom,and Norway have stipulations in their explorationand/or production leases that firms relinquish, at speci-fied times, a certain percentage of their tracts. Thisrequirement forces companies to explore rapidly to de-termine the most premising acreage for further explora-tion and development. In addition, the initial tractsleased for exploration are 10 to 80 times larger thantracts in the United States, which are limited to 25square kilometers. The United States has an indirectincentive for relinquishment of nonproductive acreagein its tax system, which allows companies to write offexpenses related to dry holes or nonproductive tracts.


FINANCIAL PROVISIONS

The United States relies primarily on lease paymentsfor government income from offshore oil and gas de-velopment. In Canada, the United Kingdom, and Nor-way, the primary revenue source is government partici-pation and/or taxation. The United States is also oneof the few countries to require an upfront cash bonuspayment for lease rights, rather than stretching out alllease payments over the life of the field. The UnitedStates uses a fixed royalty on production, rather thana sliding scale or incremental royalty linked to field pro-ductivity. The United States, like other countries, givessome incentive to exploration through its tax system,but does not offer direct exploration subsidies as doesCanada.

Foreign Leasing Systems

CANADA

Canada began offshore leasing in the late 1950s andinitiated leasing in the frontier Arctic areas (with as yetno production) in the 1960s. After the introduction ofthe National Energy Program in 1980, these leases wererenegotiatied into exploration agreements and over ahundred new agreements were entered into for explora-tion in frontier areas. In recent years, Canada’s offshoreleasing program has been focused on rapid explorationand development of resources, achievement of nationalenergy self-sufficiency, and increased government par-ticipation in the oil and gas industry. Since the 1984national elections, the offshore leasing and financialterms have been under government review.

Canada has a two-stage leasing system, where ex-ploration and production licenses are granted separatelyand different procedures govern each. Explorationagreements are made on a discretionary basis, usuallywith provisions for work commitments. They aregranted for large areas, averaging 2000 square kilo-meters, and include measures for relinquishment of 50percent of the acreage at the end of the initial 5-yearterm. The remaining lease area may be retained by re-negotiating the exploration agreement. Productionlicenses may be obtained by lessees at any time and arerenewable in 10-year increments.

Since 1980, Canada has increased government par-ticipation in oil and gas development and enacted anexploration subsidy program which favors Canadian-owned firms. The Canadian national oil company,Petro-Canada, has the right to a 25 percent working in-terest in any commercial discovery on offshore tracts.The Petroleum Incentives Program initiated in 1982 re-imburses Canadian-owned companies for up to 80percent and foreign companies for up to 25 percent of

eligible exploration costs. This program replaced thefavorable “superdepletion” provisions allowed againstthe Corporate Income Tax, which still allows the im-mediate deduction of both tangible and intangibledrilling costs. In addition, Canada has a Petroleum andGas Revenue Tax levied since 1981 at an effective rateof 12 percent on gross income. Together with a fixed10 percent royalty, this tax makes the Canadian reve-nue system on offshore fields somewhat regressive. Can-ada also has a progressive incremental royalty on netincome from offshore production.

UNITED KINGDOM

The United Kingdom has leased offshore tracts sincethe mid-1960s, but leasing in the northern North Seatracts did not begin until the early 1970s. The UnitedKingdom has relied on frequent adjustments to a com-plicated tax system to influence the level of offshoreactivity and the flow of government revenues. In 1983,the financial terms for offshore leasing were liberalizedto encourage exploration in frontier areas and the de-velopment of marginal fields.

The United Kingdom has held eight oil and gas ‘‘leas-ing rounds, each characterized by different leasing andfinancial provisions. The government has generally useda discretionary system for offshore leasing, but has ex-perimented with competitive bidding and offered 15North Sea blocks for cash bonus bids in the eighth leas-ing round in 1982-83. Exploration licenses are grantedfor periods of 3 years and specify a schedule of geologi-cal and geophysical surveys and well drilling. All dataare to be relinquished to the government. Productionlicenses also involve negotiated work programs and aregranted for initial terms of 6 years. Tracts are ten timeslarger than those in the United States, averaging 250square kilometers in size, but up to two-thirds of thetract must be relinquished at the end of the initial term.

The United Kingdom traditionally has relied on gov-ernment participation and taxation for the major shareof revenues from offshore leasing. However, companiesno longer have to take the British National Oil Corpora-tion as a partner in offshore development, althoughsome licensing preference is still given to groups whichinclude government participation. In 1983, the govern-ment changed the lease terms and tax provisions to spuroffshore exploration and development. Royalties wereeliminated for northern North Sea fields, although a12½ percent production royalty is still charged for otherareas. Firms now may recover all exploration and de-velopment costs prior to paying the Petroleum Reve-nue Tax, which is field specific. They also receive specialallowances for small fields. In addition, the Corpora-tion Tax, which is ‘‘ringfenced” to offshore fields, isbeing decreased gradually from a rate of 52 percent to

35 percent in 1986-87.


NORWAY

Norway began offshore leasing after the passage ofthe Continental Shelf Act of 1963, and oil from NorthSea areas is now being produced under some of the mostdifficult operating conditions in the world. Leasing pol-icy has changed emphasis from encouraging rapid ex-ploration and development to increasing governmentreturns from oil and gas development. Norway gainssubstantial income from offshore hydrocarbon produc-tion from an excess profits tax and a requirement thatat least a 50 percent equity interest in every tract begiven to the Norwegian State Oil Company, Statoil.

Norway uses a discretionary, two-stage system forallocating lease rights, with initial exploration licensesgranted for large offshore areas. The licenses are forperiods up to 3 years and contain provisions for data-sharing with the government. Production licenses withmandatory work programs are valid for initial terms of6 years for initial tracts averaging 550 square kilometers.

Production licenses can be renewed for an additional30 years for 50 percent of the original area.

The Norwegian government obtains oil and gasrevenues from state participation, taxation, and mod-erate royalties on production. Since 1972, Statoil hashad at least 50 percent equity in all production licensesand has been appointed operator for more than one-third of these licenses. Norway has a Corporate Tax andalso a Special Petroleum Tax on net income. TheSpecial Petroleum Tax is calculated on the basis of totaloffshore operations, and unlike the British PetroleumRevenue Tax, does not contain any exemptions forsmall fields. As a result, the Norwegian marginal taxrate is extremely high for all fields and has causedNorwegian authorities to undertake a review of the cur-rent tax system. In addition, Norway has a system ofsliding scale royalties on petroleum production and aflat 12½ percent royalty on natural gas.

Appendix B

Glossary

Bidding System: Combination of bid variable and otherlease payment(s) used for allocation of lease rights,e.g., cash bonus bid and fried royalty.

Blowout Preventer: The equipment installed at thewellhead to prevent the escape of pressure.

Break-up: The period in the Arctic during which icein water bodies thaws and breaks up (late May tomid-June for river ice, early July to mid-August forocean ice. )

Cash Bonus: Money paid by a lessee for the executionof an oil and gas lease.

Casing: Steel pipe placed in an oil or gas well as drillingprogresses to prevent the wall of the hole from cav-ing in during drilling and to provide a means of ex-tracting petroleum if the well is productive.

Commercial Accumulation: An occurrence of oil andgas that meets the minimum requirements for sizeand accessibility to be of commercial interest to acompany. The term commercial is frequently synon-ymous with economic.

Deferral: Temporary exclusion of specific offshore areasfrom leasing.

Development Well: A well drilled in proven territoryin a field to complete a production pattern.

Directional Drilling: Drilling at an angle from the ver-tical. Directional drilling makes it possible to reachsubsurface areas laterally remote, from the pointwhere the bit enters the earth.

Discovered Resources: That portion of the oil and gasin the earth whose presence has been physically con-firmed through actual exploration drilling.

Discovery Well: The first oil or gas well drilled in anew field; the well that reveals the presence of a petro-leum-bearing reservoir. Subsequent wells are devel-opment wells.

Drill Ship: A ship constructed to permit a well to bedrilled from it at an offshore location. While not asstable as other floating structures, drill ships are ca-pable of drilling exploratory wells in relatively deepwaters.

Dynamic Positioning: A method by which a floatingoffshore drilling rig is maintained in position over anoffshore well location. Several motors called thrustersare located on the hulls and are activated by a sens-ing system, which maintains the rig on location.

Economic Rent: Profits from oil and gas developmentin 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 pro-duction.

Environmental Impact Statement (EIS): A documentrequired by the National Environmental Policy Act(NEPA) of 1969 or similar State law in relation toany action significantly affecting the environment.

Fair Market Value: Price a property brings in a com-petitive market where either party to the transactionhas 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 currentlyproducible but cannnot be estimated accuratelyenough to qualify as proved.

Inferred Reserves: Reserves that are producible but theassumption of their presence is based on limited phys-ical evidence and considerable geologic extrapolation.This places them on the borderline of being undis-covered. The accuracy of the estimate is very poor.

In Place: All of the oil and gas in the reservoir, com-bining both the recoverable and nonrecoverableportions.

Ice Leads: Large openings in sea ice.Jack-up Drilling Rig: An offshore drilling structure

with tubular or derrick legs that support the deck andhull. When positioned over the drilling site, the bot-toms of the legs rest on the surface. A jack-up rigis 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 shoreand consisting of two sub-zones: bottomfast ice,where sea ice is frozen to the bottom, and floatingfast ice, seaward of the bottomfast ice and extendingoutward from shore.

Lease: A contract authorizing exploration for and de-velopment and production of oil and gas in a spe-cific offshore tract.

Lease Sale: Competitive auction for offshore leases bysealed bid.

Leasing System: Combination of bidding systems andother leasing conditions (terms, tract size, etc. ) usedin offshore leasing.

Lease Term: Period of time granted for offshore leaserights.

Lease Tract: Geographical and legal extent of a singleoffshore lease area.

Lessee: Firm or group of firms holding lease rights.

219


Marginal Field: Recoverable reserves of oil and gaswhich are barely profitable to produce.

Minimum Economic Field Size: Recoverable reservesof oil and gas which are needed to assure profitableproduction.

Moratoria: Temporary exclusion of specific offshoreareas from leasing.

Net Present Value: Total combined value in currentdollars of future costs and revenues associated witha project.

Oil Basin: A large basin-like geologic structure in whichoil and gas fields will be found.

Oil Field: A geologic unit in which one or more indi-vidual, structurally and geologically related reservoirsare found.

Oil Region: A large oil-bearing area in which oil basinsand fields are found in close proximity.

Pack Ice Zone: The area in which sea ice consists pre-dominantly of multi-year floes; the area in which icedoes 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 estima-tion are specified so that the average error will nor-mally be less than 20 percent, May also be calledmeasured reserves.

Rent: Money paid by a lessee for the right to occupyan offshore tract.

Reservation: Offshore area permanently withdrawnfrom leasing.

Reservoir: A natural underground container of hydro-carbons.

Reserves: Oil and gas that has been discovered and isproducible at the prices and technology that existedwhen the estimate was made.

Resource Base: The total amount of oil and gas thatphysically exists in a specified volume of the earth’scrust.

Resources: The total amount of oil and gas includingreserves that is expected to be produced in the future.

Royalty: Lease payment based on percentage of grossincome or total value of oil and gas produced.

Semi-submersible Drilling Rig: A floating offshoredrilling structure that has hulls submerged in thewater but not resting on the seafloor, Semi-submersi-ble rigs are either self-propelled or towed to a drillingsite and either anchored or dynamically positionedover the site or both. Semi-submersibles are morestable than drill ships and are used extensively to drillwildcat wells in rough waters such as the North Sea.

Shorefast Ice Zone: Two subzones of ice; bottomfastice, where sea ice is frozen to the bottom, and floatingfast ice, seaward of bottomfast ice.

Sliding Scale Royalty: Lease payment based on aroyalty rate which increases with the amount of oiland gas production.

Subeconomic Resources: Oil and gas in the ground thatare not producible under present prices and technol-ogy but may become producible at some future dateunder higher prices or improved technology.

Submersible Drilling Rig: An offshore drilling struc-ture with several compartments that are flooded tocause the structure to submerge and rest on theseafloor. Most submersible rigs are used only inshallow waters.

Tundra: A rolling, treeless, often marshy plain.Undiscovered Resources: Resources which are esti-

mated totally by geologic speculation with no physi-cal evidence through drilling available.

Windfall Profits Tax: Tax on profits from oil and gasdevelopment brought about by increased priceswhich are not accompanied by increased costs.

Withdrawal: Permanent exclusion of specific offshoreareas from leasing.

Work Commitment: Extent of exploration on an off-shore lease to be carried out by the lessee.

Index

Index

Abyssal Plain, 27, 36, 38Agriculture, U.S. Department of, 198Air Force, 93, 94, 109, 145, 147Alabama, 34, 144

Mobile, 101Alaska, 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, 197Beaufort 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, 42Brooks Range, 54Camden Bay, 54Cape Halkett,Chukchi Sea, 3, 5, 6, 16, 31, 54, 56, 72, 94,

101, 151, 171, 174, 179, 181, 187, 188Cold Bay, 66Colville Trough, 54Cook Inlet, 42, 50, 54, 185, 200Diapir Field, 52, 57, 132, 158Duck Island, 51Dutch Harbor, 66, 188Ellesmere Island, 59Fairbanks, 197Gulf of Alaska, 6, 11, 15, 30, 42, 50, 199Gull Island, 51Harrison Bay, 5, 8, 51, 54, 59, 64, 65, 66, 119,

120Hope Basin, 42Inuit, 177Kenai, 191Kodiak, 42, 111, 188Kuparuk Field, 42Mikelsen Bay, 54Muklak, 52Navaron 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, 51North 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, 176Prudhoe Bay, 4, 24, 42, 44, 50, 54, 66, 124, 126,

187, 188, 191, 196St. George, 6, 12, 30, 31, 32, 42, 44, 55, 56, 57,

72, 132, 135, 176, 199St. Lawrence Island, 174, 176St. Matthew Island, 66, 174, 175St. Paul Island, 66Seal Island, 30, 44Smith Bay, 54Steffenson Sound, 51Yakataga, 42Yukon, 65

Alaskan Beaufort Sea Oilspill Response Body, 195,199

Alaskan Clean Seas, 190, 199Alaska Oil and Gas Association, 72Alaska Eskimo Whaling Commission, 164, 180,

181, 183Alaskan Natural Gas Transportation System, 126,

127, 128Aleutian Basin, 6, 33, 42, 55, 56, 59, 61, 66, 72,

135Unimak Pass

Alexander Kielland, 103, 111, 112American Bureau of Shipping, 107, 114American Petroleum Institute, 56, 107American Society of Mechanical Engineers, 107Anadyr Basin, 54Anchorage, 93, 197Arab, 3, 132Arctic, 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, 92Army, U. S., 90, 91Atlantic Coast, 14, 47, 125, 132, 145, 148Atlantic Ocean, 6, 11, 28, 30, 32, 33, 36, 38, 75,

76, 77, 132, 133, 137, 144, 145, 158, 166, 167Australia, 47

Barter Island, 182Bay of Campeche, 76Beaufort 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


Blake Plateau, 38Borderland Basin, 40Bowers Basin, 42Brazil, 47, 103Bristol Bay, 174British Petroleum, 196Brooks Range, 54Bureau of Labor Statistics, 105, 109Bureau 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, 40Long Beach, 76, 101Point Arguello Field, 4, 40, 76Santa Barbara, 38, 40, 76, 78, 132, 173, 185,

197Santa Maria, 40Santa Ynez, California, 40Summerland, 131

California Institute of Technology, 95Camden Bay, 54, 59Canada, 12, 30, 47, 54, 65, 92, 95, 98, 103, 111,

135, 148, 149, 150, 154, 156, 159, 176, 194Cape Canaveral, 1 45Cape Cod, 38, 148Cape Halkett, 51Cape Hatteras, 38Cape Lisburne, 176Caribbean Islands, 143Carolina Trough, 38Challenge Island, 188Chesapeake Bay, 27Chevron, 74, 80, 159Chukchi Sea, 3, 6, 31, 32, 33, 42, 54, 56, 72, 94,

101, 151, 171, 174, 179, 181, 187, 188Civil Air Patrol, 109Clark, William, 133, 135, 144Climatic Atlas, 56, 57Coast 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, 112National Strike Force, 198

Coastal Energy Impact Program, 140Code for the Construction and Equipment of

Mobile Drilling Units, 107Cold Bay, 66Colorado School of Mines, 32Colville Trough, 54

Commerce, U.S. Department of, 140, 198Congress, 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, Subcom-mittee of the Department of Interior andRelated Agencies, 144

House of Representatives, U. S., 143Senate, U. S., 143, 153

Congressional Research Service, 4, 24Conoco, 47, 74, 80Continental Offshore Stratigraphic Test Wells, 24,

30Continental Shelf, 27, 31, 32, 34, 36, 38, 42, 139,

148, 151, 153, 154Continental Shelf Convention, 150Continental Slope, 27, 32, 36, 38, 40, 77Continental Rise, 27, 38, 40Cook Inlet, Alaska, 42, 50, 54, 185, 200Corporate Average Fuel Economy, 22Crystal River, Florida, 34Cuba, 12, 148, 153, 154

Deep Oil Technology, 47Deepsea Drilling Project, 47Defense, U.S. Department of, 9, 12, 101, 109, 125,

144, 145, 146, 198Air Force, 93, 94, 109, 145, 147Army, 90, 91

Corps. of Engineers, 91Coast 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, 147Navy, 90, 93, 94, 96, 98, 145, 147, 200

Office of Naval Research, 90, 91Weinberger, Casper, 146DeSota Canyon, 147Diapir Field, Alaska, 52, 57, 132, 158Duck Island, 51Dutch Harbor, 66, 188

economic factors, 117cost of offshore exploration and development, 117government lease and tax payments, 123prices and markets, 124profitability of offshore development, 120

Eglin Air Force Base, 147Ellesmere Island, 59Energy, U.S. Department of, 4, 22, 23, 24, 90, 91,

198environmental considerations

biological resources, 173

Index ● 2 2 5

environmental information, 164oil spills, 185

Environmental Protection Agency, 15, 16, 165, 172,195, 198, 200

Eurasina Basin, 56European Space Agency, 95, 97exclusive economic zone, 3, 24, 27, 33, 36, 38, 42,

74, 131, 148, 151, 153Exxon, 40, 44, 51, 74, 78, 80, 159, 196

Fairbanks, 197Federal Emergency Management Agency, 198Federal services and regulations

Federal services, 92research and development, 89safety, 103

Federal leasing policies, 131disputed international boundaries, 148Fish and Wildlife Service, 178leasing policies for offshore frontier areas, 154military operations, 145

rate and extent of offshore leasing, 131

Florida, 34, 36, 38, 109, 139, 144Cape Canaveral, 145Crystal River, 34Straits, 36

Gas Research Institute, 4, 22, 23, 24General Accounting Office, 157Geneva, 139Geneva Convention, the Continental Shelf, 151, 153Geological Survey, U. S., 3, 4, 24, 27, 28, 29, 30,

31, 32Georges Bank, 38, 132, 144, 148, 149, 150, 153,

154, 174Georgia, 38global positioning system, 8Glomar Jova Sea, 103Great Britain, United Kingdom, 112, 135, 150,

151, 156, 158, 159, 175Great Lakes, 143Gulf of Alaska, 6, 11, 15, 30, 42, 50, 174, 199Gulf Coast, 76, 125Gulf of Maine, 148Gulf 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, 36Port Isabel, 36

Gulf stream, 38, 77Gull Island, 51

Harrison Bay, 5, 8, 51, 54, 59, 64, 65, 66, 119,120

Hawaii, 95Health and Human Services, U.S. Department of,

109, 198Hodel, Don, 135Hope Basin, Alaska, 42Hudson River, 27

Illinois, 109Scott Air Force Base, 109

IMODCO, 47Interagency Arctic Research Policy Committee, 92Interagency Committee on Ocean Pollution

Reserch, Development and Monitoring, 170,171

Interagency Technical Committee, 15Interior, 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, 144Geological Survey, U. S., 3, 4,

31, 32Hodel, Don, 135Mineral 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, 146International Association of Drilling Contractors,

104, 105International Court of Justice, 12, 13, 148International Labor Organization, 107International Maritime Organization, 107International Tribunal for the Law of the Sea, 154International Whaling Commission, 176, 178, 179Interorganization Bowhead Whale Research Plan-

ning and Technical Coordination Group, 182Inuit, 177, 184

Japan, 14, 95, 125, 126, 127, 174Justice, U.S. Department of, 198

Kenai, 191Kodiak, Alaska, 42, 111, 188Kuparuk Field, 42, 54


Landsat, 93, 95, 110, 197Labor, U.S. Department of, 109, 198Law of the Sea Conference (Convention), 139, 150Law of the Sea Treaty, 151, 153, 154legislation

Arctic Research and Policy Act, 8, 92Clean Air Act, 141Coastal Zone Management Act, 132, 140, 141,

142, 163Department of Defense Authorizations Act of

1984, 145Endangered Species Act, 163, 170, 176, 178Export Administration Act, 125Federal Water Pollution Control Act, 140-141,

163, 197, 198Marine Mammal Protection Act, 163, 178, 183Marine Protection, Research and Sanctuaries Act,

163Merchant Marine Act (the Jones Act), 125National Environmental Policy Act, 140, 142,

163, 165, 171Occupational Safety and Health Act, 109Outer 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, 159Submerged Lands Act, 139Withdrawal of Lands for Defense Purposes Act,

12, 147Library of Congress, 91Long Beach, California, 76, 101Louisiana, 3, 34, 131, 139, 144

Maritime Administration, U. S., 90, 91, 125Marine Board, 103, 106, 111Marine Board of Investigation (Coast Guard), 112Mediterranean Sea, 6, 47, 86Mexico, 76, 126, 148, 153, 154, 185

Bay of Compeche, 76Mikelsen Bay, Alaska, 54Minerals 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, 34Mississippi, State of, 34, 144

canyon, 36delta, 36

Mohole Project, 47Mobil, 159Mobile, 101Muklak, Alaska, 52

National Aeronautics and Space Administration, 93,95, 145

National Economic Research Associates, 136, 137National Environmental Satellite, Data and Infor-

mation Service, 93National Institute of Occupational Safety and

Health, 107, 109National Marine Fisheries Service, 164, 178, 179National Marine Mammal Laboratory, 183National Ocean Service, 93National Oceanic and Atmospheric Adminstration,

15, 16, 17, 90, 94, 95, 109, 165, 167, 172,179, 198

Outer Continental Shelf Environmental Assess-ment Program, 165

National Oil and Hazardous Substances PollutionContingency 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, 111National Response Team, 198National Science Foundation, 90, 91, 92, 101National Sea Grant College Program, 143National Strike Force, 198National Transportation Safety Board, 112National Weather Service, 93Navarin 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, 200Navy/NOAA Joint Ice Center, 16, 93New England, 38, 144New Jersey, 144, 200Niakuk Island, Alaska, 51North Sea, 47, 65, 74, 77, 80, 86, 103, 151, 185North 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, 199Norway, 112, 151, 156, 159

Occupational Safety and Health Administration,107, 108, 109, 114

Ocean Ranger, 103, 104, 111, 112,Office of Naval Research, 90, 91Office 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, 5economic factors, 8Federal leasing policies, 9environmental considerations, 10issues and options, 11

oil and hazardous material simulated environmentaltest tank, 15

Oregon, 29, 30, 40Outer 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, 145Pacific Ocean, 3, 6, 29, 32, 38, 40, 75, 95, 132,

133, 137, 143, 158, 166, 167Pacific Trust Territories, 143Panama Canal, 125, 126Point Arguello Field, California, 4, 40, 76Point Conception, California, 40Point Barrow, Alaska, 8, 63, 111, 176Port Clarence, 111Potential Gas Committee, 25, 32Pribilof Islands, 174, 176Prudhoe Bay, Alaska, 4, 24, 42, 44, 50, 59, 66,

124, 126, 187, 188, 191, 196

Rand Corp., 25Reagan, (Ronald) (President) Administration of,

143, 148role of offshore resources

energy outlook, 21exclusive economic zone, 27resource project problems, 24

Safety of Life at Sea convention, 107St. George Basin, Alaska, 6, 12, 30, 31, 32, 42, 44,

51, 55, 56, 57, 72, 132, 135, 176, 199St. Lawrence Island, 174, 176St. Matthew Island, 66, 174, 175St. Paul Island, 66Saipem, 86Santa Barbara, California, 38, 40, 76, 78, 132, 173,

185, 197Santa Maria, California, 40Santa Ynez, California, 40Scott Air Force Base, 109

Sea Grant College Program, 144Seal Island, Alaska, 30, 44Seattle, Washington, 93, 101, 111, 183, 191Shell, 30, 44, 78, 86, 147, 159

Seal Island Field, 30Shell/Esso, 84Siberia, 54, 55

Anadyr Basin, 54Smith Bay, 54Sohio Alaska Petroleum Co., 44, 51

Mukluk, 44Sonat, 74, 98South Carolina, 38South China Sea, 103South Korea, 174Soviet Union, Russia, 12, 110, 148, 150, 151, 154,

174Spain, 80Standard Oil of California, 159State, U.S. Department of, 13, 148, 153, 198Steffenson Sound, Alaska, 51Summerland, California, 131Supreme Court, U. S., 139, 140, 142

Technology Assessment and Research Program, 90Texaco, 159Texas, 3, 109, 131, 136, 139, 143Torrey Canyon, 173, 195Transportation, U.S. Department of, 90, 198Tunisia, 85

Underwriters Laboratories, 107Unimak Pass, 176United Nations Law of the Sea Convention, 150

Venezuela, 126

Washington, State of, 29, 30, 38, 40, 93, 111, 166,183

Long Beach, 76, 101Seattle, 93, 101, 111, 183, 191

Washington, DC, 167Watt, James, 3, 9, 132, 144, 146Wilmington, 101Wilmington Canyon, 74

Yakataga, Alaska, 42Yukatan Peninsula, 153Yukon, 65, 149