Oil Production in the Arctic NationalWildlife Refuge: The Technology and the

Alaskan Oil Context

February 1989

NTIS order #PB89-169239

Recommended Citation:U.S. Congress, Office of Technology Assessment, Oil Production in the ArcticNational Wildlife Refuge: The Technology and the Alaskan Oil Context,OTA-E-394 (Washington, DC: U.S. Government Printing Office, February 1989).

Library of Congress Card Catalog Number 88-600565

For sale by the Superintendent of Documents U.S. Government Printing Office,Washington, DC 20402-9325

Foreword

This OTA assessment responds to requests from the House Committee on Merchant Marineand Fisheries and the Senate Committee on Energy and Natural Resources for an examinationof some technical issues concerning the potential future development of oil resources within thecoastal plain of the Arctic National Wildlife Refuge (ANWR) in northeastern Alaska. Becausegeologists suspected that large quantities of oil might lie beneath the coastal plain, Congress hadearfier exempted the plain from a Federal Wilderness designation given to about 8 million acreswithin ANWR. The U.S. Department of Interior has released a “legislative environmental impactstatement” recommending the immediate leasing of the entire coastal plain for oil explorationand development. Upon release of that report, the plain’s future became the focus of a high-stakes debate among a variety of environmental, business, Alaskan native, and governmentgroups with greatly conflicting views of the appropriate balance of commercial, environmental,and other values of the plain. Differing hopes for the plain’s future have emerged, ranging fromfull-scale oil development to wilderness designation and protection from man-caused change.

In deciding the future of the ANWR coastal plain, Congress must address a wide variety ofissues ranging from the environmental impacts of oilfield exploration, development, and produc-tion in an Arctic environment to the economic and national security benefits of potential addition-al oil production in Alaska. These issues have been explored in a wide-ranging series of congres-sional hearings sponsored by four House and Senate committees, reports issued by businessand environmental groups, executive branch reports, and a series of studies conducted by theCongressional Research Service and the General Accounting Office.

This report presents the results of an assessment of a subset of these issues focusing in par-ticular on: the oilfield technology being used to develop the Alaskan North Slope’s oil resourcesand the likely configuration of that technology as it might be applied in the future to the coastalplain; and the prospects for future North Slope oil production, especially the likelihood that theflow of oil through the Trans Alaskan Pipeline System will suffer a serious decline during the nextdecade.

A forthcoming OTA assessment, scheduled for release in the fall of 1989, will assist Congressin addressing a third issue--ANWR’s potential role in future U.S. liquid fuel supplies. The assess-ment (entitled Technological Risks and Opportunities for Future U.S. Energy Supply and Demand)will examine, among other subjects, trends in future U.S. oil production and use, and the poten-tial to reduce oil use by substituting alternative fuels and improving energy efficiency.

OTA is indebted to the numerous individuals who contributed substantial time to this report,providing information and advice and reviewing drafts.

OTA Project StaffOil Production in the Arctic National Wildlife Refuge

Lionel S. Johns, Assistant Director, OTAEnergy, Materials, and International Security Division

Peter D. BlairEnergy and Materials Program Manager

Steven E. Plotkin, Project Director

Project StaffPeter Johnson, Arctic Oilfield Technology

William Westermeyer, /Vorth Slope Production

ContributorsLynn M. Powers, Editor

Administrative StaffLillian Chapman, Administrative Assistant

Linda Long, Administrative SecretaryPhyllis Brumfield, Secretafy

iv

Reviewers of OTA’s Draft ANWR Report

ARCO Alaska, Inc. (Mr. U.J. Baskurt, Mr. D.V.Johnson, Mr. Victor Manikian, Mr. Rich Ogar,Mr. Steven B. Porter, Mr. J. M. Posey)

Mr. Dave Beecy, U.S. Department of EnergyMr. Earl H. Beistline, Fairbanks, AlaskaMs. Kristine Benson, Alaska Center for the

Environment

Mr. Jan Beyea, National Audobon Society

Mr. Rex Blazer, Northern Alaska EnvironmentalCenter

Mr. Mike Bradshaw, CONOCO, Inc.

Ms. Lynne Corn, Congressional Research ServiceMr. William Dietzmannl Energy Information Ad-

ministration, Dallas Texas

Mr. Roger Doughty, ARCO Oil and Gas CompanyDr. Daniel A. Dreyfus, Gas Research Institute,Mr. Brock Evans, National Audobon Society

Mr. Chris Flavin, Worldwatch InstituteMr. Don Forcier, General Accounting OfficeMr. Brad Fristoe, Alaska Dept of Environmental

ConservationDr. W. Tom Georold, Wilderness SocietyMr. Ozzie Girard, U.S. Geological Survey

Mr. W.A. Harms, Exxon Company U.S.A.Ms. Leone Hatch, Trustees for AlaskaDr. Robert Hirsch, ARCO Oil and Gas CompanyMr. Donald E, Hyer, Texaco U.S.A.Mr. R. Ken Knight, UNOCAL CorporationDr. David Lee Kulp, Ford Motor CompanyMs. Judy Lakind, U.S. Environmental Protection

Agency

Mr. J. E. Little, Shell Oil CompanyDr. Jessica Mathews, World Resources InstituteMr. Edward H. Mergens, Shell Oil CompanyMs. Sharon Newsome, National Wildlife FederationDr. Richard Rowberg, Congressional Research

ServiceMs. Lisa Speer, Natural Resources Defense

CouncilMr. Steven Taylor, Standard Alaska Production

CompanyMr. Bill Van Dyke, Alaska Department of Natural

ResourcesDr. John Wood, Energy Information AdministrationMr. Brooks Yeager, Sierra ClubDr. Robert Williams, Princeton University

Many other individuals reviewed and made comments on sections of the report. In particular, OTA wishesto thank Carl Behrens, Congressional Research Service, David Campbell, National Wildlife Federation,Paul Deissler, Houston, Texas, E. Kaarlela, Bureau of Land Management, Lawrence Kumins, Congres-sional Research Service, Helmut Merklein, Energy Information Administration, James Mielke, Congres-sional Research Service, John Moore, Congressional Research Service, John Pearson, Energy InformationAdministration, Joseph Riva, Congressional Research Service, Milton Russell, University of Tennessee, Wil-liam Sackinger, University of Alaska, Fred Sissine, Congressional Research Service, Arlon Tussing, ARTA,Inc., Seattle, Washington, Michael Utt, Unocal Corporation, and David Watts, Office of the Solicitor, U.S.Department of the Interior.

ANWR WORSKHOPNovember 4,1987Anchorage, Alaska

Mr. U.J. BaskurtARCO Alaska, Inc.

Ms. Lynn BillingtonStandard Alaska Production Co.

Mr. Wes BlackStandard Alaska Production Co.

Mr. Mike BradshawCONOCO, Inc.

Mr. Rod BranchStandard Alaska Production Co.

Dr. Max BrewerStaff Geologist/GeophysicistUS Geological Survey

Mr. Tom CookChevron USA, Inc.

Mr. Fred CroryResearch Civil EngineerU.S. Army Cold Regions Researchand Engineering Lab

Mr. Rob DragnichExxon

Mr. Brad FristoeAlaska Department of Environmental Conservation

Mr. Paul GrimmerCONOCO, Inc.

Mr. Stu GustafsonEXXON Co. USA

Mr. Victor ManikianARCO Alaska Inc.

Dr. Maureen McCreaMinerals Management ServiceAlaska OCS Region

Mr. Robert NagelAmoco Production Co.

Mr. Richard OgarARCO Alaska, Inc.

Mr. Lyle PerrigoArctic Environmental Information and Data CenterUniversity of Alaska

Mr. Steven B. PorterARCO Alaska, Inc.

Mr. J.M. PoseyARCO Alaska, Inc.

Mr. David PritchardStandard Oil Production Co.Executive Offices

Mr. Blair ReberExxon Production Research Co.

Mr. Dick RobertsMinerals Management ServiceAlaska OCS Region

Dr. William SackingerUniversity of AlaskaGeophysical Institute

Mr. Robin SennerSenior Vice PresidentLGL Alaska Research Assn.

Mr Rupert (Bucky) G. TartDames & Moore, Inc.

Mr. Bill Van DykePetroleum ManagerAlaska Dept. of Natural Resources

vi

Workshop on North Slope Enhanced Oil Recovery TechnologiesHouston, TexasDecember 8, 1987

Mr. Roger DoughtyArco Oil and Gas Company

Mr. Lyle HendersonManagerEnhanced Recovery ResearchShell Development Company

Mr. Arshad KhanReservoir EngineerChevron USA, Inc.

Mr. R. Ken KnightSupervisor, Recovery MethodsUNOCAL Science andTechnology Division

Mr. J.M. PoseyManager, Issues AdvocacyARCO Alaska, Inc.

Mr. David PritchardVice President, TechnologyStandard Oil Production Co

Mr. W.D. SmithAlaskan InterestProduction CoordinatorExxon Company, USA

Dr. James SmithDirectorCenter for Public PolicyUniversity of Houston

Ms. Jill HafnerDirector of OperationsCenter for Public PolicyUniversity of Houston

Mr. Vello KuuskraaVice PresidentLewin/lCFFairfax, Virginia

Dr. Harry A. DeansProfessor of Chemical/PetroleumEngineeringUniversity of Houston

Dr. Elmond ClaridgeAssoc. Professor of ChemicalEngineering/Director ofPetroleum EngineeringGraduate ProgramUniversity of Houston

Dr. Paul F. Deisler, Jr.College of BusinessAdministrationUniversity of Houston

Mr. R.J. ByrdManager, Reservoir PlanningAmoco Production Company

Mr. Thomas A. HartingSenior Petroleum EngineerAmoco Production Company

Mr. Ed HolsteinReservoir EngineeringCoordinatorExxon Company, USA

Mr. Mike MorrisonDirector, Operations PlanningExploration, Productionand Natural Gas-North AmericaConoco, Inc.

Mr. Robert O. HubbellVice President ReservoirEngineeringGolden Engineering, Inc.

vii

ContentsPage

Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5

Chapter 1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Chapter 2. Technologies for Oiland Gas Development on the North Slope of Alaska . . . . . . . 31

Chapter 3. Oil and Gas Production on the North Slope of Alaska . . . . . . . . . . . . . . . . . . 71

Appendix A. Methods of Estimating Discovered In-Place Resources and Reserves . . . . . . . . . .109

Appendix B. Estimation Methods for Undiscovered Resources . . . . . . . . . . . . . . . . . . . .113

Appendix C. Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .121

,..!/1//

List of Figures

Figure No. Page No.

1.

2.3.1-1.

2-1.

2-2.

2-3.2-4.2-5.2-6.2-7.2-8.2-9.2-1 o!2-11,

3-1.

3-2.3-3.3-4.3-5.3-6.3-7.B-1 .B-2.

The Arctic National Wildlife Refuge . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . 5Projected TAPS Throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14North Slope Oil fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16The Arctic National Wildlife Refuge: Its Relationship to Alaska and Location of the CoastalPlain . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Alaskan North Slope Producing Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33Prudhoe Bay Facilities Map . . . . . , , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35Individual Facilities at Prudhoe Bay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36Drilling Mud Flow Pattern in a Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Reserve Pit Operations During Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46Reserve Pit Operations During Production . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . 47

Outline of a Prudhoe Bay Horizontal Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48Transportation Options Associated With Changing North Slope Physical Environment . . . . . . 49A Comparison in Road Length Between Prudhoe Bay and Kuparuk . . . . . . . . . . . . . . . . 51

Development Scenario for Three Major Prospects on the ANWR Coastal Plain . . . . . . . . . . 65OTA ANWR Development Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67North Slope Oil Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Projected TAPS Throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78Alaska North Slope Production: Prudhoe Bay and Kuparuk . . . . . . . . . . . . . . . . . . . . 80Alaska North Slope Production: Lisburne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82Alaska North Slope Production: Endicott and Milne Point . . . . . . . . . . . . . . . . . . . . . 82Alaska North Slope Production: West Sak and Seal Island . . . . . . . . . . . . . . . . . . . . . 85Exploratory Wells in the Beaufort and Bering Seas . . . . . . . . . . . . . . . . . . . . . . . . . 97Flow Chart of Simulation Method for Play Analysis . . . . . . . . . . . . . . . . . . . . . . . . .116Flow Chart of Analytic Method of Play Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . .118

List of Tables

Table No. Page No.

1.

2-1.2-2.2-3.2-4.3-1.3-2.3-3.3-4.3-5.3-6.3-7.3-8.3-9.

Summary Field Data . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . 17North Slope Petroleum Development Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . 34Arctic Oil and Gas Technology: Composite List . . . . . . . . . . . . . . . , . . . . . . . . . . . 41Typical Development Schedules , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64OTA ANWR Development Scenario . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . 66Minimum Remaining In-Place Oil of Major North Slope Fields . . . . . . . . . . . . . . . . . . . 74Estimated Recoverable Gas in Known North Slope Fields . . . . . . . . . . . . . . . . . . . . . 75Estimated Remaining Recoverable Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77Projected TAPS Throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78Some Enhanced Recovery Techniques Possibly Applicable to North Slope Fields . . . . . . . . 91Problems Limiting North Slope Recovery and Technologies Which May Improve Recovery . . . 92Proposed Alaska OCS and State of Alaska Sales . . . . . . . . . . . . . . . . . . . . . . . . . . 98Estimates of Undiscovered, Economically Recoverable Oil in Alaska . . . . . . . . . . . . . . . 97Comparison of Estimates for Undiscovered In-place Oil in ANWR . . . . . . . . , . . . . . . . . 99

“—

Summary and Conclusions

ContentsIntroduction . . . . . . . . . . . . . . . . . . .

Arctic Oilfield Development and Technology .Overview . . . . . . . . . . . . . . . . . .Conclusions . . . . . . . . . . . . . . . .

North Slope Oil Production . . . . . . . . . . .Overview . . . . . . . . . . . . . . . . . .Conclusions . . . . . . . . . . . . . . . .

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141414

Summary and Conclusions

INTRODUCTION

The coastal plain of the Arctic National WildlifeRefuge (ANWR), in the extreme northeast cornerof Alaska (see Figure 1), has become the focalpoint of a major debate among interest groupsseeking either to promote or to block the leasing,exploration, and development of the area for itssuspected massive oil resources (see Box A).Those groups opposing the development ofANWR oil resources view the coastal plain as aunique and invaluable Arctic ecosystem andwilderness area. They fear that development willdestroy the plain’s wilderness character andseriously damage its wildlife and other environ-mental values in return for a small potential tocapture an amount of oil that will make only atemporary dent in the United States’ liquid fuels

dilemma. They believe that previous North Slopedevelopment has damaged the Arctic environ-ment and serves as a warning against expansionof development into the coastal plain.

Pro-development interests view the coastalplain as the most promising remaining area in theUnited States for finding supergiant oilfields, andthey believe that the oil industry can explore anddevelop the area without significantly com-promising its environmental values. In contrastto the views expressed by the environmentalgroups opposing ANWR development, thosefavoring ANWR development characterize exist-ing North Slope oil development as a convincingexample of sound environmental management

Figure 1 .—The Arctic National Wildlife Refuge: Its Relationship to Alaska and Location of the Coastal Plain

ALASKA

BOX ATHE COASTAL PLAIN OF THE ARCTIC NATIONAL WILDLIFE REFUGE

●

●

●

●

●

●

●

●

●

●

●

Comprises 1.5 million acres of the19-million-acrw Arctic National Wdlife Refuge, established by theAlaska National Interest Lands Conservation Act of 1980 (ANILCA). Known as the “1002 area,” areference to Section 1002(b) of ANILCA, defining the coastal plain

Located in the extreme northeast corner of Alaska; western edge 60 miles east of Prudhoe Bay, theNation’s largest oilfield; eastern edge 160 miles east of Prudhoe Bay and 30 miles west of theCanadian border

Climate characterized by long, extremely cold winters and short, cool summers; persistent windsthroughout the year; frequent blizzards in winter; precipitation light but frequent

Not included in the 8 million acres of ANWR desinated as wildemess in 1980, but set aside by Con-f gress for additional study by the Department o the Interior of oil and gas potential and of wildlife

resources of the area

Leasing or other activities leading to oil and gas production must be authorized by the U.S. Con-gress

The Department of the Interior released its report in April 1987, recommending orderly oil and gasleasing of the area

Knowledge of subsurface geology very limited, but located between known petroleum provinces inthe United States and Canada, and the petroleum-bearing strata of both maybe present in the refuge

Considered by the oil industy to be the most promising unexplored area in the United States fordiscovering supergiant oilfietds

The Department of the Interior estimates there is a 19 percent chance of finding economicallyrecoverable oil; if any recoverable oil is found, there is likely to be a mean of 3.23 billion barrels.

Considered by environmentalists to have outstanding wilderness values and to be an especially im-portant habitat for caribou, polar bears; musk oxen, and migrating birds

The area is a prime calving ground for the approximately 200,000 caribou of the Porcupine caribouherd, which is present on the coastal plain from about mid-May to mid-July

Summary ● 7

Photo credit Arctic Slope Consulting Engineers

Winter on the coastal plain of the Arctic National Wildlife Refuge,

8 ● ANWR

and proof that the Nation can obtain oil from theANWR coastal plain without unduly disturbingits environmental values.

Through the terms of the legislation that estab-lished the Refuge, Congress has the finaldecision over whether the coastal plain can beleased for oil development. The ongoing con-gressional debate over the coastal plain’s futurehas been informed by extensive hearing tes-timony as well as by a variety of analyticalreports from executive and congressionalbranch agencies, industry, academia, and en-vironmental organizations. Much of the tes-timony and reporting has focused on thepotential environmental impacts that develop-ment would cause and the nature of the environ-mental “record” of previous oil development onthe Alaskan North Slope.l

In this report, the Office of Technology As-sessment (OTA) has not attempted to duplicate

this information or to produce a complete assess-ment of all of the issues involved in Congress’decision about ANWR’s future. In particular, wehave not produced an environmental assess-ment of ANWR oil development. Instead, at therequest of the Senate Committee on Energy andNatural Resources, the House Committee onMerchant Marine and Fisheries, and the OTATechnology Assessment Board, we have focusedon two issues that will form a part of the congres-sional decision:

1.

2.

The nature of ANWR oilfield technology. Towhat extent would ANWR development looklike existing development on the NorthSlope? Would the basic technologies andpractices be the same or different?

ANWR’s potential role in Alaskan oilproduction. How credible are recent projec-tions of large declines in North Slope oilproduction in the 1990s?

1. Opposing views of the environmental record are presented in: ‘(Oil in the Mctic: The Environmental Record of Oil Developmenton Alaska’s North Slope,” Natural Resources Defense Council, Inc., January 1988; and “Current ANWR Environmental Issues, ” TheStandard Oil Co., August 1987.

.——

Summary ● 9

ARCTIC OILFIELD DEVELOPMENT ANDTECHNOLOGY

Overview analytical techniques to design against welldamage from permafrost thawing, allowing

The technology and practices of Arctic oilfieldcloser well spacing and thus smaller gravel padsand less coverage of the tundra; and improve-

exploration and development have undergone ments in the use of enhanced oil recovery tech-important changes in the years since the Prud- nologies. These changes in technology andhoe Bay oilfield was discovered and develop- practices stemmed from three sources:ment began (see Box B for a brief description ofthe process of extracting oil and gas resour- 1.ces). Some important examples of technologi-cal changes include improved drilling rig designand operation, improved use of directional drill-ing (drilling at an angle off the vertical) to allow 2.multiple wells on single gravel “pads” to drainoil from a greater area of the field; improved

the pressure of designing to solve uniqueArctic problems and adapting to the harshArctic environment,

the industry-wide technological changesstemming from the constant drive to improvecapabilities and performance and reduce

BOX BTHE OIL Production CYCLE

The extraction of oil resources is commonly divided into three phases: (1) Exploration, (2)Development, and (3) Production. Exploration Includes seismic (acoustic) and other surveys tomap the possible underground petroleum reservoirs as well as drilling exploratory wells to confirmthe existence and location of an actual oil pool (the pool, or reservoir, is actually a mass of porousrock, with the oil stored in the rock pores)+ If oil is found,1 further drilling is also necessary todelineate the size and extent of a reservoir and to determine whether it can be economicallyproduced. Exploration is compieted when a decision is made to produce an oilfield or pool.Development is the process of building and installing all of the facilities, machinery and pipelinesneeded to produce whatever oil is discovered. On the North Slope, development begins withbuilding airfields, roads, drilling pads, and construction camps. This is followed by drilling produc-tion wells; building modules containing machinery and processing plants and installing them onthe site; building and installing pipelines and flow control equipment; and installing a myriad ofmachinery to support a complex network through which oil flows from a pool deep beneath theground to the surface, is processed to yield crude oil and is pumped long distances to terminalsfor loading on tankers, Production begins when all development is completed and the facilitiesbegin producing oil for the market. The production phase also jncludes maintenance of thefacilities and the wells, drilling more wells to keep oil flowing and to keep the underground reser-voirs operating smoothly, and installing special equipment for “enhanced oil recovery” to extractthe oil left behind by the conventional production wells.

When the oilfields are large, as they are on the North Slope of Alaska: the machinery and facilitiesare large and extensive; thousands of people are invoived in both development and production;the development resembles a major industrial complex; and the process spans at least a fewdecades.

1, Or qas k found, Often, resewoirs contain both oil and Qas, with the as both in solution in the oil and in a separate“gas oap. On the North Slope, most of the produced gas is remjected into xe reservoir, both to maintain reservoir pressure(whioh helps the oil to flow) and to avoid having to dispose of the gas by flaring –at current prices, it is not economical toship the gas to markets.

10 ● ANWR

costs, as well as from fortuitous scientific ad-vances in other industries (such aselectronics), and

3. the special urgency to improve efficiencyand reduce costs associated with thedecline in oil prices beginning in 1981, espe-ciallythe large price drop initiated in Decem-ber 1985.2

OTA believes that the rate of change inArctic technology and practices likely to beused for ANWR oil development may be moregradual in the future, primarily because someof the pressure for change has lessened. Inparticular, industry knowledge of how tooperate efficiently in the onshore Arctic en-vironment has matured considerably, andfurther advancement in knowledge shouldslow from its previous pace. In addition,basic physical conditions on the ANWR coas-tal plain, while not identical to the currentNorth Slope development area, are quitesimilar and do not represent a new challengeto industry technology per se. Unlesseconomic or regulatory conditions change,the industry is more likely to deploy systemsthat have been tried and tested under similarconditions than to take substantial risks inthe development of new technologies.Therefore, we conclude that, in the absenceof new pressures, ANWR oilfield technol-ogy and pract ices wi l l most l ike lyresemble the technology and practicesused at Kuparuk and Endicott, the latestNorth Slope fields, modified to fit the par-ticular field characteristics encountered.

Of course, the constant incentive to lowercosts will continue to drive innovation in the in-dustry, and Arctic technology will continue toevolve. Promising areas for technologicalchange include directional drilling, where ad-vances continue to be made in offshoredevelopments such as the North Sea, and en-hanced oil recovery, where innovation will be

driven by industry desire to boost the economicpotential of fields throughout the United Statesand, on the North Slope, in fields such as WestSak. Also, an additional motivation for tech-nological change could come from mw regulatorypressures. For ANWR oil exploration anddevelopment, this pressure could arise from dis-satisfaction with current environmental perfor-mance at Prudhoe Bay and the other developedNorth Slope fields, or because the State andFederal authorities seek a higher standard of en-vironmental protection at ANWR because of itsstatus as a wildlife refuge. If this type of pressurearises, the most likely focus for changes in tech-nology and practices would be in the area ofwaste management and habitat protection.

Conclusions

1. The major differences between North Slopeand Lower 48 conditions that affect thechoice and use of oilfield technologies arethe very cold weather, the presence of per-mafrost (ground which is permanentlyfrozen except at the surface, which thawsduring the Arctic summer), and the remote-ness of the area. Designs for technologiesfor operating at sub-zero temperatures drawheavily on advanced concepts in metallurgy,elastomers (elastic substances), lubricants,and fuels. The harsh and extremely cold en-vironment also has demanded developmentof new survival systems and procedures toassure personnel safety. All drilling rigs andproduction facilities where people work areenclosed, insulated, and heated. Exteriorsteel structures are built from a special arctic-grade steel to prevent brittleness at very lowtemperatures. Most pipelines and flowiinesare insulated, either to prevent water fromfreezing, to avoid increased viscosity of thecrude oil, or to avoid permafrost melting.Shut-in flowlines are freeze-protected orevacuated and then filled with inert gas.

2. See U.S. Office of Technology Assessment, U.S. Oil Production: The Effect of Low Oil Prices - Special Report, OTA-E-348,(Washington, DC: U.S. Government Printing Office, August 1987).

3. In evaluating Arctic technology, OTA had to relyprimarilyon industry sources of data; there are few truly “independent” analystswith extensive knowled e of Arctic oilfield technology and production, and analysts in the Alaskan State agencies and Federalagencies such as the 8inerals Management Service are also dependent on industry as their primary information source. Thiscomment applies, as well, to our analysis of future North Slope oil production.

2.

3.

4

To prevent the permafrost from melting andto provide a stable surface during the sum-mer thaw, roads, buildings, pipelines, drill-ing pads, etc. are built atop thick gravelpads and/or elevated on supports. And be-cause the harshness and remoteness of theNorth Slope make normal on-site construc-tion methods difficult and expensive, majorfacilities are built in huge modules in theLower 48 States, barged to the slope, andinstalled on prepared foundations.

Although the technologies and practicesused on the North Slope today haveevolved considerably from those of theearly ’70s during the beginning of Prud-hoe Bay development, the majority ofchanges have involved the adaptation ofavailable practices and technologies to anew environment rather than the development of new technologies and practices.The adaptations address the unique Arcticenvironment, as described above. Althoughthis conclusion does not negate the impor-tance of what the oil industry has achievedin Alaska – it has made tremendousstrides– it is important in projecting futuretechnological development, because it im-plies that future changes may come moreslowly.

Most of Prudhoe Bay and the Trans AlaskaPipeline System (TAPS) have been in routineoperation for some time. The industry nowbelieves that it has ascended most of theway up the “Arctic learning curve,” that itstechnologies and practices for Arcticdevelopment are mature, efficient, and ef-fective. Therefore, they see little need tochange them for ANWR except to modifythem to fit specific conditions found onthe coastal plain (for example, the size,shape, depth, and location of any oil-bearing reservoirs discovered), and manyin the industry foresee little likelihood thatthe technologies and practices willchange significantly for ANWR development.

Although the ANWR physical environmentis not precisely the same as that of Prud-hoe Bay and the surrounding area, the dif-ferences do not appear to be large. ANWRhas more topographic relief than PrudhoeBay, producing less standing water but

5.

6.

more potential problems with channeling anderosion; there are fewer deep lakes there toserve as sources of fresh water; gravel condi-tions are about the same; and ANWR containsa few more port sites with deeper water nearshore. None of the differences appear tochallenge industry capabilities per se.

At least a portion of the environmental ef-fects associated with existing North Slopeoil development should not automaticallyapply to ANWR. The capability now existsfor reducing or eliminating some of the im-pacts reported for early Prudhoe Baydevelopment. Newer North Slope fieldssuch as Kuparuk and Endicott incorporateimprovements in environmental manage-ment such as reduced requirements forsurface usage and gravel, improved han-dling of oilfield service operations, andmore attention to waste management.These and other improvements are also like-ly to be used in any ANWR development and,if necessary, regulatory agencies could stipu-late use of desirable practices as a conditionof development. Critics, however, have ex-pressed continued serious concerns aboutseveral environmental issues becausethey believe that even the newest opera-tions are still causing significant environ-mental damage. Their principal concernsinclude disposal of resewe pit waste and ofother solid and liquid wastes, air pollution,fresh water supply, monitoring of industry ac-tivities by resource agencies, and wildlifehabitat alteration or destruction. Also, manygroups argue that the environment of theANWR coastal plain deserves greater protec-tion than Prudhoe Bay because the coastalplain is part of a wildlife refuge. Thesegroups either oppose development out-right or conclude that oilfield technologiesand practices must change significantlyfrom those used for current North Slopedevelopment if environmental values areto be protected properly. OTA has notevaluated these issues in this report.

If ANWR is leased and commercial quan-tities of oil are discovered, the period ofdevelopment and production is not likelyto be brief. Examination of the developmentcycle of oil regions in the Lower 48 andaround Prudhoe Bay shows that the life

Photo credl( Standard A/aska

The Arctic National Wlldllfe Refuge Coastal Plal n. The terrain is rolling, whereas Prudhoe Bay to the west IS quite flat.

7.

cycles of such regions are long and com-plex. Development of ANWR is likely tobegin with exploration and development oflarge oilfields. With the development of anextensive infrastructure, however, furtherdevelopment will become economic, andexploration will focus on smaller fields. AIso,

opportunities for enhanced oil recovery, forthe development of fringe areas of the largereservoirs, and for development of smallerreservoirs will extend high activity levels atthe larger fields. In the long term, gasresources may be developed. This scenarioimplies an extensive and elaborate in-frastructure, and thus a significant visual im-pact, coverage of the surface, andaccompanying ecosystem impacts for atleast 25 to 30 years. Although the industryargues--correctly--that actual coverage ofthe surface is likely to be less than 1 percentof the coastal plain, the physical coveragewould be spread out somewhat like a spider-web, and some further physical effects, likeinfiltration of road dust and changes indrainage patterns, will spread out from theland actually covered.

The detailed form of any future ANWR oilfielddevelopment cannot be predicted. Never-theless, it is useful to postulate a hypotheti-cal scenario for the ANWR coastal plain:

●

●

●

●

●

●

●

●

Two fields would be discovered anddeveloped:— one large: 3.0 billion barrels of oil

recoverable– one small: 0.5 barrels of oil

recoverable

The Iargefield is one-third the size of the Prud-hoe Bay oilfield, and the small field roughlythe size of the Endicott oilfield.

Production from these two ANWR oilfieldswould total 800,000 bbl/day -or 40 percent ofcurrent North Slope oil production.

Facilities for two ANWR oilfields would in-clude:

- 800 wells on 14 gravel pads;- 3 major and 4 satellite production facilities;

and- 2 airfields, 2 ports, 2 seawater treatment

plants, and one industrial support center.

Total gravel coverage including pads, roads,etc. is 3,000 to 4,000 acres.

Total “footprint’ ’-including pipelines andother disturbances – is 5,000 to 7,000 acres.

Total “sphere of infiuence” –denoting areawhere some secondary effects occur on cer-tain sensitive species – is 150,000 to 300,000acres.

Hypothetical schedule:

14 ● ANWR

NORTH SLOPE OIL PRODUCTION

Overview

Today, the North Slope of Alaska providesabout 2 million barrels per day (mmbd) of oil tothe United States, nearly a quarter of total U.S.domestic crude oil production. Most projec-tions of future North Slope production show amarked decline beginning around 1990 to 1991,with production falling to half of current levels orbelow by the year 2000 (see Figure 2). Ifproduction is not to fall, then it must come eitherfrom more intensive development of existingfields, from discovered but undeveloped fields,or from undiscovered resources. Based on theavailable evidence, additional productionfrom more intensive development of existingfields and development of discovered butcurrently undeveloped fields is unlikely toreverse the expected decline in North Slopeoil production. Production from undis-covered resources is highly uncertain andwould likely be more than a decade awayeven if discoveries were made this year.

OTA notes, however, that the Prudhoe Bayoperators have been able to push back the ex-pected date for the onset of field decline severaltimes, Although it is not clear how a strongproduction decline can be delayed for much

Figure 2.-Projected TAPS Throughput

longer, history suggests caution in entirely writ-ing off the possibility.

Conclusions

1.

2.

3.

The current low oil prices raise the possibilitythat the oil companies on the North Slopemight be foregoing opportunities for addinglarge increments of production and/or addedrecovery, waiting for economic conditions toimprove. If this were true, then existingforecasts of future North Slope productionmight be missing the production boost thatan improvement in economic conditionscould bring about.

Although low oil prices have affected thelevel of investment in new development onthe North Slope, in general the large produc-ing fields continue to be developed inten-sively. Despite the low prices, we could notidentify any development opportunitiesbeing foregone that would make a large dif-ference in future North Slope production.Thus, higher oil prices may slow but areunlikely to stop the expected declines inNorth Slope oil production.

Prospects for enhanced oil recovery (beyondthat already in place or scheduled) in the dis-covered fields are good, but the incrementsof recovery and production from the availableenhanced oil recovery (EOR) technologieswill be small and will accrue over a longperiod. In other words, there are no avail-able or readily foreseeable technologiesthat promise to “turn around” expectationsof declining production at Prudhoe Bayand other North Slope fields. Table 1describes the conditions affecting oilrecovery in the discovered North Slope fields;Figure 3 shows the location of these fields,

Aside from additional recovery from theproducing fields, increments of productionmust come from discovered but non-produc-ing fields or from the undiscovered resourcebase.

.

Phofo credit .4merican Pefroleum Institute

A quarter of the United States’ domestic production of crude oil flows through the Trans Alaska Pipeline System (TAPS)

16 ● AIWVR

Summary ● 17

a.

b

Field

The discovered but non-producing fields c. As for the undiscovered resources, recent ex-do not have large volumes of recoverableresources and cannot be expected toreverse the impending decline in oil flowthrough the Trans Alaska Pipeline System(TAPS).

Although the West Sak field contains large 4

in-place resources (at least 15 billion bar-rels), there are, as yet, no available tech-nologies that can economically recovermore than a small fraction of these resour-ces. ARCO, the majority owner of this field,plans to begin a pilot drilling program soon,and hopes eventually to produce a fewhundred thousand barrels per day from WestSak. Given the substantial technicalproblems remaining, however, large scale oilproduction from West Sak must be viewedas highly uncertain.

ploration on the North Slope and offshore hasbeen extremely disappointing. Afthough newlarge discoveries cannot be ruled out, theprospects for such discoveries seem tohave dimmed considerably.

The industry appears to have made significantstrides in controlling and reducing oilfieldcosts over the past few years. Part of thereduced costs are associated with reducedprices for basic oilfield services, and theselower prices are unlikely to be sustained formore than a few years. Part, however, ap-pears to be the result of improved practicesand design, and this should be sustained per-manently. The industry now appears to beable to bring new fields on line and developolder fields more intensively at lowerbreakeven oil prices than just a few years ago.To the extent that production projections are

Table 1 .—Summary Field Data

Remaining Estimatedrecoverable recoverable Recovery Daily 011oil-1 /88 gas-1 /88 factor production Present EOR Factors Iimiting production

Prudhoe Bay 4,100-6,000 23 trillion cubic 42-45% of 1,550,000 barrels Waterflood, miscible Although a good per-million barrels feet original in-place per day gas injection infill former, production will

resources and horizontal ultimately be limited bydrilling residual 011 saturation to

waterflood— —Kuparuk 600-1 100 million 600 billion cubic Approximately 300,000 barrels Waterflood, mlsctble Faulting, thin pay, and

barrels feet 30% of original per day gas injection residual 011 saturationin-place resources waterflood

Lisburne 280-580 million 900 billion cubic 7-22% of original 50,000 barrels Small waterflood Difficulty of producingbarrels feet in-place resources per day pilot IS being tested fractured limestone reser-

voir, low porosity andpermeability

Endicott - - 270-445 million 800 billion cubic 35% of original Waterflood Faulting, gas handlingbarrels feet In-place resources 100,000 barrels ability in future

per dayMilne Point O-95 million None Approximately N/A: currently Waterflooding Extensive faulting

barrels 33% of original shut-in due to lowIn-place resources price of oil

West Sak O-1 ,200 million None O-5% of original N/A Test only of heated Poor (shaly) rock, uncon-barrels In-place resources waterflood solldated. fine-gralned

sand, VISCOUS , low tem-perature 011

Seal ‘lsland– 0-300 million ? Approximately N/A N/A 7

barrels 33%

Niakuk 55-75 million ‘? Approximately N/A N/A ?barrels 33%

Point Thomson 350 million bar- 5 trllion cubic 7 NIA N/A 7rels condensate feet(light grawtyhydrocarbons)—.

SOURCE Off Ice of Technology Assessment 1988 –

18 ● ANVVR

5

6.

based on older costs, they maybe pessimis-tic. Also, because reserve projections andproduction rates are oil price dependent,higher oil prices in the mid to late 1990scould be expected to stimulate additionalproduction. Thus, the more optimistic ofthe current projections for North Slopeproduction over the next 15 to 20 yearsare more likely to be accurate, especiallyif higher oil prices prevail. However, eventhe optimistic projections still foresee alarge decline in the flow of oil throughTAPS during the next decade and a half.

The oil industry has over time tended to beoverly pessimistic about prospects for futureoil production, not only in Alaska but for theUnited States as a whole. Projections for theonset of decline in Prudhoe Bay production,for example, have been pushed back a num-ber of times. And U.S. production, althoughdown substantially since the oil price dropof 1985-1986, has not fallen nearly as severe-ly as the industry had predicted immediate-ly following the price drop. Although OTAcould not identify a likely means to maintainNorth Slope production at levels muchhigher than the “high” curve in Figure 2, OTAis reluctant to totally rule out this possibility.

Estimates of the resource potential of ANWRare highly speculative, given that they arenot based on extensive drilling data. 001’s“best guess” of AlNWR’s economicallyrecoverable resources is based on availablegeologic and geophysical data and on anumber of economic assumptions. Several

7.

factors lead OTA to conclude that DOI’s es-timate of the likelihood of finding economi-cally recoverable quantities of oil in ANWRmay be conservative. These factors are: 1)In its analysis, DOI assumed that the costs todevelop ANWR will be similar to costs asdetailed in the 1981 National Petroleum Coun-cil report on the Arctic. The oil companieshave reduced their costs substantially since1981, and these reductions do not appear tohave been captured by the DOI assessment;42) DOI did not include the possibility thatANWR oil could be developed with two orthree moderate-sized fields, even though nosingle field exceeds the minimum economicfield size for a stand-alone field; and 3)Smaller potential oil prospects were not in-cluded in DOI’s analysis. Even though thesesmaller prospects are not large enough todevelop alone, some would likely bedeveloped in association with a largeprospect.

Many groups have either misinterpreted ormisused DOI’s estimate of ANWR’S economi-cally recoverable resource potential. WhatDOI has concluded is that there is an 81 per-cen t chance tha t no economica l l yrecoverable oil will be found in ANWR, but ifANWR contains any recoverable oil, a meanof 3.23 billion barrels is likely to exist. Es-timates will change with acquisition of addi-tional data, but geologic conditions for findingoil in ANWR are favorable, and industry con-siders a 19 percent probability of findingeconomically recoverable oil in any region tobe good odds.

4. Although some of the cost reduction may not be permanent, OTA believes that much of the savings will be retained even ifdrilling activity levels pick up.

Chapter 1

Introduction

ContentsPage

overview . . . ● . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

The OTA Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Chapter 1Introduction

OVERVIEW

The coastal plain of the Arctic National WildlifeRefuge, in the extreme northeast corner of Alaska(see Figure 1 -l), has become the focal point of amajor debate among interest groups seekingeither to promote or to block the leasing, explora-tion, and development of the area for its sus-pected massive oil resources. Because of theperceived oil and gas potential of the area, the1.5 million acre coastal plain, or so-called “1002area” named after Section 1002 of the Alaska Na-tive Interest Lands Conservation Act (Public Law96-487), was left out of the Federal wildernessdesignation that protected 8 million acres in theRefuge. Instead, Congress asked the Depart-ment of the Interior (DOI) to study the area and torecommend an appropriate development coursefor it. Oil and gas development was forbiddenwithout explicit congressional approval. DOI hasnow completed its study and has recommendedto Congress that the entire 1002 area be openedto leasing and development. 1 This recommenda-tion is fully supported by the oil industry and avariety of other pro-development interests (in-cluding the entire Alaskan congressional delega-tion), is vigorously opposed by a number ofenvironmental groups and some Native groups,and is supported with conditions by the AlaskanState government and other interests. Thevariety of proposed Federal legislation dealingwith the Refuge – summarized in Box 1 -A –reflects these different positions.

The 1002 area is the focus of a variety of seem-ingly conflicting values. On one side, there isunanimous agreement that the area represents ahigh value as a wildlife refuge–the 1002 coastalplain is, in most years, the primary calvingground and summer home for the nearly 200,000caribou of the Porcupine herd, as well as thenesting habitat for millions of birds and the home

of polar and grizzly bears, an expanding herd ofmusk oxen, and numerous other arctic species.Also, there is widespread agreement – supportedeven by the DOI report that recommended itsdevelopment –that it has a high value as a wilder-ness area. Further, the area provides wildliferesources – particularly caribou – supporting thesubsistence lifestyle of a number of native lnuit.On the other side, there is essentially unanimousagreement that the 1002 area has a high poten-tial – by industry standards – for containing mas-sive oil and gas deposits, although variousinterest groups differ on the value of thesedeposits to the Nation (see Box 1 -B).

It seems unlikely that all of these values can besupported simultaneously. For example, accord-ing to the DOI report, the successful explorationfor and development of the 1002 area’s potentialoil resources would damage and possiblydestroy the area’s wilderness character. Al-though some interests have argued that thewilderness character can be restored over time,at our current state of knowledge this outcomeshould be viewed as extremely uncertain, andprobably unlikely. Thus, the true “value” of thecoastal plain as a wilderness area, though largelya subjective measure, is an important part of thedevelopment decision.

In addition, there is substantial disagreementabout the potential conflict between large-scaleoil development and the wildlife and other en-vironmental and subsistence values of the area.Generally, the oil companies vigorously defendtheir environmental record in previous AlaskanNorth Slope development and assert that ANWRoil can be extracted with little damage to wildlifeand other values. Environmental groups aretaking the opposite view that previous develop-

1, N,K. Clough, R.C. Patton, and A..C. Christiansen (eds.), Arctic National Wldlife Refuge, Alaska, Coastal Plain ResourceAssessment-Report and Recommendation to the Congress of the United States and Final Legislative Environmental Im actStatement, (Washington, DC: U.S. Fish and Wildlife Service, U.S. Geological Survey, and Bureau of Land Management, .S.EDepartment of the Interior, 1987).

21

22• ANWR

ment has caused substantial damage and that These conflicting viewpoints have been the sub-any future oil development in ANWR also will sub- ject of a number of congressional hearings asstantially damage wildlife and other environmen- well as studies by a number of groups. The is-tal values. sues raised during the hearings are summarized

in Box 1-C.

Figure 1.1 .—The Arctic National Wildlife Refuge: Its Relationship to Alaska and Location of the Coastal Plain

Barrow

SOURCE Arctic Slope Regional Corp ,“The Arctic National Wildlife Refuge Its People, Wildlife Resources, and 011 and Gas Potential," revised May 1987,

Chapter 1 ● 23

24 ● ANWR

BOX 1-AARCTIC NATIONAL WILDLIFE REFUGE BILLS

More than a dozen bills have been introduced in the IOOth Congress that address issues relatedto the Arctic National Wildlife Refuge. Two pro-leasing bills, S 2214 and HR 3928, have emerged asthe leading bills around which debate is currently centered.

S 2214, which Incorporates some of the provisions of a pro-leasing bill introduced by SenatorsMurkowski and Stevens of Alaska, was reported by the Senate Energy and Natural Resources Com-mittee on February 25, 1988. The bill provides for a phased-in leasing program governed by exist-ing State Federal environmental law, and subject to further environmental regulations to bedeveloped by the Interior Department. S 2214 would permit Interior to exciude from leasing areas ofparticular environmental sensitivity. Interior would be required to determine whether an activitymay result in “significant adverse effect” and to modify, suspend, or terminate the activity to preventthat adverse effect. Royalties would be divided equally between the State and Federal Government.The bill also calls for an energy policy study to be conducted while leasing and developmentproceed.

HR 3601 was approved by the House Merchant Marine and Fisheries Committee on May 3, 1988.The bill is generaily similar to S 2214 in providing for a phased-in leasing program. However, unlikeS 2214, it establishes a 260,000-acre protective management zone in the “we calving area” of thePorcupine caribou herd and does hot require an energy study. The bill will also be considered bythe House Interior Committee, which is headed by Congressman Morris Udall, Chairman Udallfavors a wilderness designation for the ANWR coastal plain and has introduced legislation (HR 39)to accomplish that purpose. A similar bill (S 1804) has been introduced in the Senate,

Four committees, House Merchant Marine and Fisheries, House Interior and Insular Affairs,Senate Energy and Natural Resources, and Senate Environment and Public Works have held morethan 25 hearings since the debate on ANWR’s future began in 1987.

1. Environmental and Energy Study Conference, “Merchant Marine to Mark Up New Arctic Refuge Leasing Bill,” SpecialReport, Apr. 13, 1988. p. 2.

2. Environmental and Energy Study Conference, “Interior Sets ANWR Hearings,” Weekly Bulletin, May 16, 1988. pp.B10811.

Chapter 1 ● 25

BOX I-BWHAT DID THE DEPARTMENT OF THE INIERIOR CONCLUDE ABOUT THE

MAGNITUDE OF ANWR OIL RESOURCES?The Department of the Interiors conclusions about the magnitude of oil resources in the ANWR coastal

plain have been the source of confusion since the DOI ANWR Legislative Environmental Impact Statementwas released. The actual conclusion was:

1. There is a 19 percent chance that oil is present in the coastal plain under conditions that wouldallow commercial recovery (Le., large quantity in one place, good quality oil, permeable reservoirrock).

2. If oil is present in commercially recoverable form, its estimated mean volume is 3.23 billion bar-rels of recoverable oil.

in terms of the decision to allow or block leasing of the coastal plain, the DOI assessment means that:

1. There is an 81 percent chance that no commercially recoverable oil will be discovered, In thatcase, the total impact of leasing will be restricted to the impacts of the exploratory program, Nopermanent facilities will be built –no pipelines, no production facilities, and no permanent crewquarters.

2. There is a 19 percent chance that commercially recoverable oil will be found. In that case, the ex-pected vaIue of the magnitude of the oil Iikely to be recovered is 3.23 billion barrels. The value ofthis oil must be weighed against the effects, negative and positive, of building and operating thepipelines, production facilities, and other extensive infrastructure involved in producing thisvolume of oil in an Arctic environment.

A number of misinterpretations of the DOI conclusions have been communicated to Congress and to themedia by both proponents and opponents of ANWR 011 development. The following two examples appearto represent the extremes:

● ‘The Arctic Refuge coastal plain...is estimated to contain more than 9 billion barrels ofrecoverable oil, an amount approximately equal to Prudhoe Bay. ” Secretary Hodel in the coverletter accompanying the DOI ANWR assessment, April 21, 1987. According to the DOI assess-ment, the chance of recovering this amount or greater is about 1 percent... it represents the 5percent probability mark for economically recoverable oil, and the latter occurs with only a 19percent probability.

● “There is about a 7 percent chance of finding 3.2 billion recoverable barrels, a 200 day supp-ly (of U.S. oil consumption requirements). ” John Woodwell, Group for Good Government,“Oilscam, ” January 28, 1988. This value is arrived at by misinterpreting the probability distribu-tion for resource magnitudes in the DOI report. The author notes that the 3.2 billion barrelresource is situated at the 34th percentile on the probability curve, and interprets this to meanthat there is a 34 percent chance of obtaining 3.2 billion barrels of oil. Thus, he multiplies .34by .19, the conditional probability of finding any recoverable oil, to obtain “the probability offinding 3.2 billion barrels, However, the proper interpretation is that there is a 7 percent chanceof finding at least 3.2 billion barrels; this probability includes the potential of finding 8 billion,9billion, or even more barrels of recoverable oil. In OTA’s view, the most useful interpretationstill is that there is a 19 percent chance of recovering oil at ANWR, and if oil is recovered, themean volume is 3.2 billion recoverable barreis.

Also, a number of leasing opponents have presented the leasing decision as a choice between 600 mil-lion barrels of oil –the “risked mean” volume of oil, obtained by multiplying 3.2 billion barrels by the 19 per-cent probability of finding any recoverable oil in ANWR -and the environmental costs of full development,e.g., hundreds of miles of roads and pipelines, thousands of acres of gravel pads, etc. This is an unfaircomparison, because full development will occur only if recoverable amounts of 011 are found, and the ex-pected volume of this oil is the full 3.2 billion barrels. As noted above, If no commercial oil is found, the im-pacts will be far less.

“Risked mean” volumes are useful when assessing the Iikely oil resources of an area that includes a num-ber of unexplored regions. For example, in assessing the total oil resources remaining in all unexploredregions of the United States, the best estimate of the total resource is the sum of the risked mean oil volumes.However, for these estimates, the risked mean estimates for the individual regions have little meaning.

Box 1-CISSUES AFFECTING THE MM/F? DEVELOPMENT DECISION

1. To what extent would development of ANWR oil resources improve U.S. national security andoffer significant economic benefits? Are the likely levels of ANWR oil production, if cotnmer-cial quantities are found, of real significance to U.S. liquid fuels supply? Are predictions of ex-pected decfines in North Slope and U.S. oil production levels correct? Is it Iikelythat world oilmarkets will be under the tight control of the Middle Eastern OPEC countries at the time whenANWR oil could be flowing into the TAPS pipeline?

2. Are there alternatives to developing ANWR 011 that likely would prove more effective at lowercost (including environmental cost)? Could improving the efficiency of the automobile fleetsave significantly more oil than ANWR could supply? Would pursuit of alternative liquid fuelssuch as methanol be preferable to investing in marginal U.S. oil resources? What are the risksof foregoing the development of any one alternative, assuming others are pursued?

3. What might be the benefits of delaying the leasing of ANWR, with or without first determiningthe extent of its oil resources? Is it likely that an accurate determination of its resources couldbe made without promising that any commercial quantities of oil would be allowed to bedeveloped immediately after discovery? Are ANWR’s potential oil resources worth more to theUnited States in the ground than they are under timely development?

4. Is the ANWR coastal ptain truly a unique and irreplaceable wilderness? To what extent are itswilderness values duplicated elsewhere in Alaska? In other words, is developing the coastalplain truly the same league as developing the Grand Canyon, Yellowstone, or the other“jewels” in our National Parks and Wilderness systems?

5. Could ANWR oil resources be developed without significant damage to the coastal plain’swildlife and other natural resources?

● How have Prudhoe Bay and other North Slope development damaged the natural environ-ment? What are the long-term effects of the hundreds of small oil spills that have occurred?What long-term changes to drainage patterns have occurred because of the extensive roadnetwork? What solid and liquid waste problems exist, and what has been their effect? Doesthe growth of the Central Arctic caribou herd reflect Its long-term health, or is the appropriateinterpretation less optimistic? What have been the effects of increased air emissions on theRNorth Slope?

● Does current Arctic oilfieid technology and practices offer significant environmental improve-ments over those used earlier on the North Slope? Would probiems that existed at the &idYPrudhoe Bay developments be significantly less of a problem at ANWR because of thesechanges?

● What differences exist between ANWR and the North Slope/Prudhoe Bay area, and how willthese affect the environmental impacts that might accompany development at ANWR?

6. Could ANWR oil resources be developed without foreclosing the eventual return of the coas-tal plain to a wilderness state? How Iikely is it that drilling sites can be rehabilitated, roads dis-mantled, and other physical effects of development successfully removed? Woulddevelopment be likely to be temporary, or would the building of the needed infrastructure leadto more permanent development and exploitation of other ANWR resources? Would oildevelopment be followed by natural gas development, extending the timeframe of petroleumdevelopment well past 20 or 30 years?

Chapter 1 ● 27

THE OTA STUDY

At the request of the Senate Committee onEnergy and Natural Resources and the HouseCommittee on Merchant Marine and Fisheries,the Office of Technology Assessment has under-taken a study of technologies for Arctic oilproduction and their effect on future oil produc-tion in Alaska and, particularly, in the 1002 area.The OTA study focuses on a subset of the issuesrelevant to Congress’ decision on the fate of thearea (the full set of issues are listed in Box 1-C),and does not provide guidance on a number ofissues critical to the decision. OTA hopes thatCongress, in making its decision, will draw onthis study in conjunction with an extensive hear-ing record, several analyses by the Congres-sional Research Service, the Department of theInterior’s Legislative Environmental Impact State-ment (LEIS) and its supporting documents, andnumerous reports and presentations from Alas-kan State government, industry groups, AlaskanNative associations, environmental organiza-tions, and other interest groups and technical or-ganizations.

In addition, a forthcoming OTA study (Tech-nological Risks and Opportunities for Future U.S.Energy Supply and Demand, scheduled for Fall,1989) will examine topics associated withANWR’s role in future U.S. liquid fuels supply anddemand--including future domestic oil produc-tion; alternative liquid fuels; the potential forreducing oil requirements by increasing energyefficiency; and the security implications of grow-ing oil imports.

In Chapter 2, this report examines the state-of-the-art of Arctic oilfield technology and attemptsto project the nature of technology that might beused in the future to explore, develop, andproduce oil in the 1002 area. As part of thisevaluation, the report attempts to show how suchtechnology may resemble or differ from the tech-nology used to develop the Prudhoe Bay oilfield,

which is the oldest, largest, and most intensivelystudied of the North Slope oilfields. During ex-tensive congressional testimony on ANWR, advo-cates and opponents of oil development haveargued strenuously about the likelihood thatANWR development would raise many of thesame environmental concerns associated withPrudhoe Bay development, and about the impor-tance and accuracy of such concerns. Becausethe nature of the technology is an importantdeterminant of environmental impacts, this por-tion of the report should help Congress under-stand how the impacts of possible futuredevelopment at ANWR might resemble or differfrom the impacts of existing development atPrudhoe. However, the report does not com-ment on the accuracy of the various claims madeabout the absolute magnitude of environmentalimpacts at Prudhoe Bay.

In Chapter 3, the report examines the availableestimates of total Alaskan North Slope oil resour-ces and reserves and the projections of future oilproduction, and evaluates the potential for shiftsin future production rates with technologydevelopment and changing economic condi-tions. This evaluation includes an examination ofenhanced recovery technologies that might beused to boost North Slope production in the fu-ture. The purpose of this portion of the report isto place any future oil production from the 1002area into a better overall Alaskan and U.S. oilperspective. The report tries here to determinewhether or not ANWR oil production representsthe only feasible means of maintaining a highthroughput through the Trans Alaska PipelineSystem to the Lower 48 States for the year 2000and beyond. Although projections of NorthSlope production made available to OTA portraysharply declining production in the 1990s, someMembers of Congress are skeptical of theseprojections.

-. -—.

Chapter 2

Technologies for Oil and GasDevelopment on the

North Slope of Alaska

ContentsIntroduction . . . . . . . . . . . . . .

Four Environmental Questions .

Technology Development to Date . .History . . . . . . . . . . . . . .Current North Slope Development .Arctic Conditions Affecting Technologies .Status and Trends of Arctic Technologies .

● ✎ ✎ ☛ ☛ ✎ ☛ ✎ ✎ ✎ ✎ ✎

Technology Applications for the ArcticANWR Special Conditions . . .

National Wildlife Refuge. . . . . . . . . . . . . .

Overview: ANWR Techndogiesand Practices . . . . . .impacts: ANWR Technologies and Practices . . . . . . .Technological Change . . . . . . . . . . . . . . . . . . .schedule . . . . . . . . . . . . . . . . . . . . . . . . . . .ANWR Development Scenarios . . . . . . . . . . . . . . .

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Chapter 2Technologies for Oil and Gas Development

Aon the North Slope of Iaska

INTRODUCTION

If oil and gas leasing is permitted in the ArcticNational Wildlife Refuge (ANWR), the explorationfor and development of any resources dis-covered there would likely follow the pattern es-tabl ished over the last two decades ofcommercial petroleum activities on the NorthSlope of Alaska. The basic oil exploration andproduction systems for the Arctic have beenadapted from technologies used by the industryin less severe environments. These adaptationsmake it possible to work successfully in the uni-que Arctic environment of extreme cold tempera-tures and harsh weather, and to cope withremoteness and the difficulty of transportation.The need to work on permafrost, tundra, and icealso forced some major technological changes.Substantial engineering development was under-taken by the petroleum industry to produce effi-cient and effective systems for Arctic use. By theearly 1980s, after most of Prudhoe Bay and TAPShad been in routine operation for some time, theindustry considered that the technology for on-shore Arctic operations was proven and mature. 1

Four Environmental Questions

The debate about whether or not to allow leas-ing and petroleum development in ANWR in-cludes four key questions about the impact oftechnologies and practices on the environment:

1. To what extent will the physical presenceof infrastructure associated with oildevelopment disturb ANWR? How manygravel pads, gravel roads, pipelines, fac-ilities, etc., will cover the tundra? What willbe the effect of erosion, disruption ofdrainage patterns, dust, etc, on localecosystems? How long will the facilitiesoperate? What is the potential for long-

2.

3.

4.

term growth? What regulations could limitenvironmental disturbance?

To what extent will gravel mining andother construction practices disruptANWR? How much gravel will be needed?What regulatory limits should there be?

How much waste discharge from drillingand production operations will there be?Will the practices of (and regulation for)managing those wastes be acceptable inANWR? Is deep well injection a soundpractice? To what extent will environmen-tally benign muds be used? Will reserve pitcontainment practices be adequate? Willhigher environmental standards than nor-mal be necessary for a wildlife refuge?

Will the fresh water needs for ANWRdevelopment and standard industrypractices for obtaining water be accept-able, feasible, and controllable byregulation?

This report has focused attention on the firsttwo areas above because they relate most close-ly to our main objective of characterizing thetechnological developments likely to occurshould ANWR leasing be permitted. The reportonly briefly discusses the second two areasabove. In addition, air quality issues are not ad-dressed. In commenting on the draft report, en-vironmental groups have called attention to theirserious concerns about many environmental is-sues, but most importantly to questions aboutwaste disposal and fresh water supply. Thescope of this study has precluded significant en-vironmental analysis. However, if ANWR leasinggoes forward, it is clear that all of these issues willcontinue to be of concern and will need to be ad-dressed in future environmental studies.

1. National Petroleum Council, U.S. Arctic Oil and Gas, NPC, U.S. Department of Energy Advisory Cemmittee, 1981,

31

320 ANWR

TECHNOLOGY DEVELOPMENT TO DATE

History

Both the present technology in place and theevolution of Arctic oil and gas technology andpractices on the North Slope yield importantclues to any likely development of the ANWRcoastal plain. The Prudhoe Bay oilfield wasdeveloped during the 1970s. During that time,the petroleum industry invested in major en-gineering projects to enable it to modify tech-nologies developed in other areas for Arctic use.Although the Prudhoe Bay field did not beginproduction until 1977, pioneering efforts on whatwas then called the Naval Petroleum Reseme inAlaska (now the National Petroleum Reserve-Alaska [NPRA]) at least 20 years before provided

much basic information about drilling in per-mafrost, use of ice roads and platforms, buildinggravel pads, and other techniques for working inthe Arctic. Other fields were discovered in thevicinity of Prudhoe Bay and put into productionusing the experience at Prudhoe, to advancetechnology even further.

All of the producing North Slope fields feed intothe Trans Alaska Pipeline System (TAPS). TAPSdelivers oil in an elevated pipeline along an 800-mile route from Prudhoe to Valdez, an ice-freeterminal in southern Alaska. Research on per-mafrost along the TAPS route was done duringthe 1950s and 1960s, and TAPS pipeline technol-ogy was developed during the 1970s.

.

Chapter 2 ● 33

Current North SlopeDevelopment

Existing North Slope oil and gas development isextensive and still growing.2 It is concentrated infive fields: Prudhoe Bay, Kuparuk River, Lis-burne, Endicott, and Milne Point (Figure 2-l).Currently, all but Milne Point are producing. As agroup, the fields are supported by 1,123 miles ofpipeline (excluding TAPS) and 346 miles ofroads. Some 7,035 acres of land are covered bygravel for facilities, drill sites, roads, and camps.Nine river crossings and three airfields are usedfor petroleum-related activities. A 370-milegravel haul road, the Dalton Highway, connectsDeadhorse (the operations base for most of thecontractors who support the major operations),

at the southern end of Prudhoe Bay, with Fair-banks. All the oil is transported via the TransAlaska Pipeline from Prudhoe Bay to Valdez. Thecurrent rate of North Slope oil production isabout 2 million barrels per day (mmbd).

Table 2-1 summarizes development activities atthe five North Slope sites. Overall, the Dead-horse industrial complex serves as the prima~support base for North Slope and Beaufort Seaexploration and development. Deadhorse hasliving quarters, warehouse facilities, and a paved,State-operated airport. It is located in thesouthern portion of the Prudhoe oilfield. By itself,the Prudhoe Bay field, the Nation’s largest, hastwo adjacent operating areas, one run by Stan-dard Alaska Production Company (SAPC) andthe other run by ARCO Alaska. Production

Figure 2-1. –Alaskan North Slope Producing Oil Fields

Milne Point unit

I

SOURCE Exxon Co USA, 1988

State of Alaska oiland gas unit boundary

2. The following description was excerpted from “Fwe-Year Oil and Gas Leasing Program, ” a repoR of the Alaska Department ofNatural Resourcesl Division of Oil and Gas, January 1988.

34 ● ANWR

Table 2-1 .–North Slope Petroleum Development Summary (as of October 1987)—

Field name Prudhoe Bay Lisburne Kuparuk Milne Point Endicott

Discovery date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12/67Size of oil pool (sq. ma.) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 400Production start-update . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6/77Production to date (million bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,9181986 average production rate (barrels/day) . . . . . . . . . . . . . . . . . . . 1,554,000Remaining reserves:

million barrels (oil) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,672billion cubic feet (gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,000

Existing wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 881Drill sites/pads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38Production centers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Base camps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Construction camps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Power plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Topping plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Gas compression plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Seawater treatment plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Enhanced oil recovery plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Docks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Causeways . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Water injection centers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2Associated support and industrial sites . . . . . . . . . . . . . . . . . . . . . 1Airports and company operated airstrips . . . . . . . . . . . . . . . . . . . . 2Pipelines (miles) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63’Roads (miles) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218e

Acreage covered (acres) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,374 e

River crossings (number) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3e

12/67125

12/865

40,000

395625

5151101010000000e

e

e

e

4/69400

12/81292

257,000

1,308565557

343111111110d11

41894

1,4095

10/6945

11/855’

12,900

550

294111101000:

o0

151954

1

317840

10/87b

100,000

37573030’

21111011011do0

2815

1981

NOTE: The above does not include the considerable numberof support sites and acreage covered at Deadhorsea Fleld shut in January 1987b prod u ctlon commenced October 1987C80-100 wells planneddwater injection system Included In production centerseLlsburne numbers Included with Prudhoe Bay

SOURCE Alaska Department of Natural Resources, Division of Oil & Gas and Exxon comments, Apr. 26, 1988.

began in 1977. Today, Prudhoe Bayfacilhies arehuge. They are located within a 200-square-milearea of the 400-square-mile Prudhoe Bay Unit,and include six oil/gas separation plants, gather-ing centers or flow stations, 38 drill pads with atotal of 828 wells, a central gas facility, a centralcompression plant, a central powerplant, afieldfuel gasunit, a crude topping plant (refinery), awaterflood seawater treatment facility, a gravelairstrip, 200 miles of roads, permanent livingquarters, a dock, two construction camps, of-fices, and two water injection plants.

Figures 2-2 and 2-3 illustrate the large scale ofdevelopment at Prudhoe Bay. Figure 2-2 depictsthe major field production facilities only (drillpads, airstrips, operations center gas plant,docks, and connecting roads). Figure 2-3 showsmore detail of sizes and shapes of facility padsand pipeline networks. while it is difficult toportray the development on this scale, both the

extent of coverage and the diversity of the sys-tems in place are evident. Whether (in total) thisis a major industrial complex defacing the naturalLandscape or whether it is only a small, incidentaldisturbance in a vast wilderness depends mainlyon one’s values and perception.

The Kuparuk River field, located about 30 mileswest of Prudhoe Bay, is operated by ARCO Alas-ka. Production began in December 1981. About500 people will be ultimately employed at thefield. Facilities currently include three centralproduction facilities, about 500 wells (800 areplanned), the Kuparuk Operations Center (officesand housing for 384 people), the Kuparuk ln-dustrial Center a gasplant, a seawater treatmentplant, pipelines (a 26-mile-long, 24-inch-diametercrude oil line, built in 1984, connects to TAPS atPump Station 1, and a 26-mile-long, 16-inch-diameter converted oil line carries natural gas toPrudhoe Bay for fuel), 94 miles of roads and a

Chapter 2 ● 35

4

r I I

1

I I

{{

t

. . I

. .

300-foot bridge across the Kuparuk River, a top-ping plant, two construction camps (one accom-modates 650 people and the other 360), and onegravel airstrip.

The Lisburne resewoir was discovered directlybeneath Prudhoe Bay. ARCO committed todeveloping Lisburne in January 1984, and initialproduction began in December 1986. Of 51 totalwells, to date 45 are capable of production. Thecurrent production is from 37 of these wells. Whencompleted, about 100 permanent employees willwork in the Lisburne field, while about 1,000 will benecessary during portions of the constructionphase. Lisburne facilities include one centralproduction facility, five onshore gravel pads, 50miles of pipeline, and a pilot waterflood project.

The Endicott field, discovered in 1978, is lo-cated offshore about 20 miles east of PrudhoeBay. It is the first oil and gas field to bedeveloped in the Alaskan Beaufort Sea. Stan-dard Alaska Production Company is the operator.Production began in October 1987. The field isbeing developed from two artificial gravel islands,2 miles offshore. The Islands are connected by3.1 miles of solid fill causeway and joined to theSagavanirktok (Sag) River delta by 1.9 miles ofgravel causeway with two bridge-type breachestotaling 700 feet and 1.5 miles of onshorecauseway through the Sag delta wetlands. Agravel road, 8.7 miles long, connects thecauseways with the existing Prudhoe Bay roadsystem at Drill Site 9. An elevated oil pipelinefrom the field connects with TAPS at Pump Sta-tion #1. Other infrastructure includes an on-shore gravel pit, a base camp with living quartersfor 600 people, a warehouse, offices, fuel tanks,base operations center, seawater intake basin,utilities for the waterflood project, and a dock forsealift operations, Endicott operates with a per-mit for discharge of drilling effluents into theBeaufort Sea. The North Slope Borough landfillis used to dispose of oil-contaminated drill cut-tings, and deep well injection is used to disposeof oil-contaminated fluids.

The Milne Point field was discovered in 1969,and development started in 1979. It is operatedby Conoco. The 21 ,000-acre field is locatednortheast of the Kuparuk River field. Production,which began in November 1985, was suspendedin January 1987 pending an increase andstabilization of oil prices. Facilities include 2 4

wells on two pads, a 50-person permanent camp,and a 300-person construction camp. About 19miles of gravel roads connect Milne Point to theKuparuk spine road, and about 15 miles ofpipeline are available to carry oil from Milne Pointto the Kuparuk Pipeline. Waterflood infrastruc-ture includes a 45,000-barrels-per-day capacitywater injection system.

Camp Lonely, located 80 miles west of OliktokPoint and the Kuparuk field, once served as astaging area for western Beaufort Sea activitiesbut is now mothballed. Infrastructure includes a100-person camp, offices, carpentry shop, com-munications shop, sewage treatment plant,generating system, vehicle maintenance shop, alarge tank farm, and warm and cold storagewarehouses.

In addition to these areas, future developmentis possible from Niakuk, located offshore be-tween the Lisburne and Endicott fields, the WestSak Reservoir in the Kuparuk River and MilnePoint Units, Seal Island, Tern Island, SandpiperIsland, Colville Delta, Flaxman Island/PointThomson, the Hemi Springs Unit, ARCO Alaska’sK-10, and Bullen Point Staging Area.

Arctic Conditions AffectingTechnologies

Most experts agree that the major differencesbetween North Slope and Lower 48 conditionsthat affect the choice and use of oil and gas tech-nologies are the very cold weather, the presenceof permafrost, and the remoteness of the area.Designs for technologies for operating at sub-zero temperatures draw heavily on advancedconcepts in metallurgy, elastomers (elastic sub-stances), lubricants, and fuels. The harsh coldenvironment also has demanded development ofnew survival systems and procedures to assurepersonnel safety. All drilling rigs and productionfacilities where people work must be enclosed,insulated, and heated. Exterior steel structuresneed to be built from a special arctic-grade steelto prevent brittleness at very low temperatures.Most pipelines and flowlines are insulated, eitherto prevent water from freezing or to avoid in-creased viscosity of the crude oil. Shut-in

38 Ž ANWR

flowlines must be freeze-protected or evacuatedand then filled with inert gas.

Permafrost (see Box 2-A) has forced the develop-ment of a number of compatible technologies. Be-cause thawed permafrost lacks load-bearingcapacity, special construction techniques are usedto protect the permafrost layer so that it remainsfrozen. Where load-bearing is required, common

North Slope practice is to build up a thick gravel padto insulate the permafrost from warmer summertemperatures and from artificial heat sources. Thepads then become platforms for facilities, roads,etc. Ail roads and gravel pads are constructed witha thickness of about five feet of gravel or some alter-native, equally effective insulating technique.Flowlines, pipelines, and production handlingmodules are built above-ground on vertical support

Box 24PERMAFROST

The entire Nonth Slope of Alaska, including ANWR, is underlain by permafrost, permanently frozenground extending just below the land surface to as much as 2,000 feet below the surface. In theArctic winter, the permafrost surface is solid and stalble. In the summer, up to several feet of the sur-face permafrost layer thaw, becoming soft and water-soaked and unable to support even smallstructures, but the remainder stays frozen. Techniques to provide permanently soild foundationsfor heated buildings, facilities, roads, etc., on the surface (and to avoid melting the permafrost else-where where it is frozen) are therefore necessary for ail Arctic operations, With certain types ofthaw-stable soils, however, this is less of a problem.

<

Photo credit Standard Alaska

Arctic tundra, underlain with permafrost, does not provide a permanently stable foundation.

Chapter 2 ● 39

members (VSMs) to insulate the permafrost fromthe produced fluids. In special cases where linesmust be buried in the permafrost, refrigeration isused around the pipeline. To prevent the casing’s3

vertical movement and its collapse due to per-mafrost freeze-back after drilling or during well shut-down, casing materials are designed to withstandcollapse loads, special cold weather cements areused for the surface casing, and “Arctic Pack” (agelled freeze-proof diesel that has some insulatingproperties) is used between the surface casing andproduction casing. Most development drilling is

done from drilling pads, and wells are clustered atthe surface on these pads and drilled at an angle tothe producing formation. This practice minimizesthe amount of construction on and coverage of per-mafrost.

Because of permafrost there generally is a needfor elevated foundations for buildings andfacilities and for special containment of fluids andwaste discharges. As permafrost is imperviousto water, there is no downward percolation ofwater below mud pits, sewage lagoons, etc.

I

Photo credit Standard Alaska

The annual sealift from the Lower 48 to the North Slope brings in thousands of tons of modules,

3. Casing is the large steel pipe that lines an oil well. Some casing is installed during drilling operations and, if a well is used toproduce oil, additional casing is installed.

400 Ž ANWR

There are indications, however, that permafrost isnot impervious to other fluids including, perhaps,waste products, and that the migration of thesefluids from some reserve pits is an environmentalconcern.

The harshness and remoteness of the NorthSlope make the on-site construction of facilitiesdifficult and expensive. It is more cost-effectiveto start off-site-to prefabricate, to modularize,and to specially transport the needed structures,from 500 tons to 5,000 tons, to their final destina-tion. For the most part, oil facilities for the NorthSlope are built in modules in the Lower 48,barged to the Prudhoe Bay dock in late summer,off-loaded and moved by crawlers along a gravelroad network to a prepared site, and set on pre-installed large diameter piles. The transportationequipment itself has required the construction ofspecial docks and causeways into the BeaufortSea, especially where near-shore water depthsare very shallow. Typically, 8 feet of water at thedock is needed for barge traffic.

Status and Trends ofTechnologies

The status of technologies, new developmentsunderway, and needed improvements in explora-tion, development, production, and transporta-tion systems or practices are summarized below.Table 2-2 lists some of the technologies for theseapplications.

Reconnaissance Exploration

Exploration begins with reconnaissance.Geological and geophysical surveys are con-ducted both on the ground and from the air.Gravity measurements are usually taken atground stations, and magnetic measurementsare commonly made with airborne instruments.Seismic surveys, which probe the shape of un-derground rock formations by interpreting thereflections and refractions of sound waves travel-

ing through the rocks, are usually conducted withground-based transmitters and receivers.Detailed seismic reflection surveys commonlyuse either explosives or vibratory sound sourcesand, when feasible, are usually conducted on theice or snow to reduce tundra disturbance. In thepast, movement of seismic equipment in wheeledvehicles over the tundra when snow cover is thinhas left noticeable tracks. Survey technology ad-vancements that could affect future work areautomation of data collection and of transmis-sion, processing, and interpretation of data.While these technologies may contribute to moreaccuracy in future survey work, they do not havemuch effect on the environment. Exploratorydrilling is the activity of most environmental con-cern.

Drilling and Drilling Systems

Onshore exploratory or development drilling inthe Arctic is now routine, using fairly standardtechnology. A drilling rig with power supply,pipe, casing

, e q u i p m e n t , s u p p l i e s , b a s e c a m p f o rpersonnel, and ancillary equipment must bemoved to the drill site. The drilling site may be agravel pad, ice pad, or insulated timber pad,Depending on rock conditions, depth of targetzone, and other well conditions, drilling may bedone only in the winter. Winter drilling has ad-vantages for both movement of equipment (usingice roads and air strips) and for the use of icepads, because ice pads generally harm the en-vironment less than gravel pads. Depending onthe well, drilling may also require additional timeand cost. Gravel pads are needed for year-roundwork. Construction equipment is also needed atan exploratory drill site to build gravel pads, con-struct reserve pits, and install other supportfacilities.

Concerns about the impact of drilling technol-ogy on the environment mainly center on threeprincipal activities: 1) transportation of equip-ment to and from the site; 2) building of pads,foundations, and pits at the site; and 3) disposalof wastes or removal of equipment and materials

4. Mud is a viscaus fluid used to Iubrioate the drill bit and carry the cuttings to the surface.5. Cement is used to fix casing pipe in the well,6. Logging is the practioe of making measurements in the well with instruments lowered on a cable from the surface.

Chapter 2 ● 41

Table 2-2.—Arctic Oil and Gas Technology: Composite List From Workshop Participants Answering:“What are the best examples of Arctic ‘State-of-the-art’ technologies?”

—A. Exploration/Development

1. Drilling and Drilling Systemsa. Drilling Rig/Drilling-Lifting-Pipe Handling:

● Cant i lever rig design capable of driIIing on closespacing, easily transported.

● Top drive rotary system capable of driIling 90 feetat a time without making pipe connections.

• Automatic pipe-handling systems (off truck andinto hole),

● Iron-roughnecks, hydraulically driven make-up andbreak-out tongs.

b. Drill pipe/Bits/Downhole Drills:● Improved metallurgy, stronger pipe and casing.● Diamond bits capable of long run times,● Downhole mud turbines for directional work.

c. Casing/Cement:● Finite Element Analysis for casing connections.● Improved metallurgy,● Arctic Pak cements for cold hardening.

d. Circulation (Muds, etc.):● Extensive secondary and tertiary mud cleaning

equipment; cones, centrifuges. Dry systems.● Non-toxic mud systems,● AnnuIar injection of unwanted Iiquid Volume.● Polymer and mineral oil systems,

e. Coring and Logging:● Improvements in Iogging tool reliabiIity and capa-

bility.● High angle holes—drillpipe conveyed; coiled tub-

ing conveyed tools.● Measurement-while-driIIing (MWD) capabiIities—to

measure reservoir properties and to guide direc-tional work.

f. Directional Drilling:● MWD tools—continous monitoring of inclination

and azimuth. Mud pulse telemetry.● Down hole mud turbines, steerable mud motors.Ž Horizontal and near horizontal driIIing.

g. Blow-Out Prevention:● Training simuIators and i m proved detection

systems.h. Permafrost Protection:

● Arctic pak—freeze-back protection for casing.● Arctic cement—set-up prior to freezing; insuIates,● Thaw bulb computer modeling and monitoring,. Refrigerated conductor pipe systems,

2. Support Systemsa. Transport of Equipment”

● Rolligon.● Hercules Cl30 air-transportable rigs and equipment,Ž Hoverbarge.● Winter ice road.● Conventional barge i n summer (offshore island),. Ice airstrips for exploration.• Highiy modularized land rigs for fast moves be-

tween exploration wells and efficient moving onpads.

b. Personnel Support/Camps:● Self-contained rig camps (up to 100+- people).● Construction camps,• isolation/sociological studies.

c. Supply of Operations: “ –

● Major equipment and faciIities by annual sealift,● Motor freight via gravel and ice roads; roIIigons.● Air cargo (fixed wing plane via ice or gravel strip;

or helicopter).d. Construction of Drill Pads/Supply Bases”

●

●

●

●

●

●

Gravel (5 foot lift for thermal protection).Ice pads for single season exploratory wells.Foam and timber mats for multi-season explora-tory wells.“Thin” pads using other insulating materials andless gravel thicknesses,

Exploration reserve pits below-ground with per-mafrost for containment,Development reserve pits below grade containedin permafrost (proposed).

e. Waste Disposal:● Annular injection of Iiquid wastes.● Backhaul of solid or hazardous waste to approved

disposal sites,● Reduction in waste volumes (distiIlation),● ModuIar and air transported sewage plants,● Encapsulation and refreezing of driII cuttings and

mud solids,● Washing of cuttings.

B. Production1. Well Systems

a.

b.

c.

Casing/Tubing/Perforat ion/Cementing:● Special perforating guns.● “Clean” completion fluids.● Low-temperature metallurgy.● Non-freezing annuIar fluid for freeze back preven-

tion (Arctic pak).Wellhead/Flow Control:● Computerized gas-lift.● Ball valves,Permafrost Control:● Well spacing designed to minimize subsidence due

to thaw.● Permafrost cement.

2. Separation and Treatment● Compact module designs and overall facility

layout.● Duplex stainless steel separation vessels,Ž Control systems highIy computerized,

3. Fluid Injectiona.

b.

Gas- Prudhoe Bay Unit Central CompressionPlant and upgrades of existing equipment; cen-tralized field-wide gas lift system at Prudhoe Baywith interconnecting tieline between operatingareas.Water—Seawater Treatment Plants at PrudhoeBay and Kuparuk; incorporation of waterflood-sys-tem with treated seawater intake and relatedfieldwide processing facilities into initial produc-tion facilities at Endicott; source water Injectiondistribution system with tieline between operat-ing areas at Prudhoe Bay,

4. Auxiliariesa. Power:

● Generated on site using produced gas/or diesel

(cent/nued on next page)

42 ● ANWR

Table 2-2.—Arctic Oil and Gas Technology: Composite List From Workshop Participants Answering:“What are the best examples of Arctic *State-of- the-art’ technologies? ’’—Continued

5. Construction Operationsa. Gravel Pads/Foundations/Site Preparation:

● Small pad size (5 feet thick).● Winter season preferred for construction.● Optimum site location to minimize habitat loss,

pending or impoundment, other environmentalconcerns.

● Ground surface under some facilities insulatedaround piles in gravel pads to prevent settlement.

b. Transportation of Modules:● Sealift for large modules; smaller modules by truck

on haul road.Ž Large tractors, crawlers, or multi-tiered trailers to

move modules.c. Construction of Docks/Piers:

. Slope protection sheetpiIes and conerete armor/gravel bags.

d. Construction of Drainage Structures:● Arctic bridges for stream crossings.● Culverts and low water crossings for fish passage

and erosion control.C. Transportation

1. Oil through TAPSa. Construction of Pipelines/Pumping Stations:

● Winter construction above ground; summer con-struction for buried line.

● Earthquake-proof.● Insulated (primarily above ground).

b. Pipeline Operation:• Highly automated.● Drag reducing agent to increase throughput.

c. Permafrost Protection:● Heat pipes i n vertical support members in per-

mafrost.● Refrigerated facility pads.

d. Controls/Inspection:● Highly automated computer controlled.● Weekly inspection of line.● Automatic monitors and alarms throughout system

(leak detection, etc.).2. Oil Through Norman Wells Pipeline (Canada)

a. Construction of Pipeline:● Winter construction for buried Iine.● Uninsulated.

b. Pipeline Operation:● Operated at ambient temperature (25oF to 35oF)

due to high API gravity crude.c. Permafrost Protection:

. Increased pipe wall thickness.3. Gas

a. Overland Gas Pipeline:● Engineering studies and environmental impact

studies underway.● TAPS-operated buried fuel gas pipelinc.

b. LNG:. Plant under evaluation for Port Valdez to be built

in conjunction with gas pipeline from North Slope.provided by local topping plant.

● Gas-fired or diesel-fired electrical.● Large power generation via gas turbines; smaller

power needs by diesel fired generators.• Kuparuk industrial center for service company sup-

port facility.b. Hotel and Base Facilities:

● Production facilities self-contained and largely self-sufficient re: fuel and power generation, water,waste water, sewage treatment, etc.

● Interiors designed to avert psychological problemslinked to darkness and isolation.

c. Resupply and Transportation:● Sealift (short time for open water transport), mo-

tor freight, air freight.● Icebreaking ships for early supply in spring.

d. Waste Disposal:• Tertiary sewage treatment.• Annular injection of liquid wastes.● Back hauI of solid wastes and hazardous wastes

to approved disposal sites.e. Roads and Airfields:

• Gravel (about 5 feet thick), insulation, and geotex -tile fabric. ,

f. Oil Spill Control and Cleanup:● Prevention programs and awareness.● Specific plans for spiII prevention.● Environmental response team(s) and equipment

trailers.● Improved sorbent material and containment

booms.● Spill reporting procedures,● Cleanup and disposal.● Revegetation and monitoring.● Snow and ice used for containment and sorbent.

g. Water Supply:● Abandoned and flooded gravel pits.● Deep lakes.● Seawater treatment.● Produced water treatment.● Water supply wells from fresh water aquifers.● Snow control.

SOURCE Office of Technology Assessment, based on information from: CONOCO; Standard Oil Co.; ARCO Alaska, Inc.; CRREL; and EXXON

Chapter 2 ● 43

after the completion of drilling. Practices thatminimize such impacts are well-known but maylimit exploration flexibility or increase cost. Forexample, working only in winter months andtransporting by vehicles only on ice will minimizeimpacts but may require extra time and cost foran operator, especially when drilling deep or dif-ficult holes,

Circulation Mud

Most drilling operations use a circulation sys-tem with a water- or oil-based fluid, called mud.The mud is pumped down a hollow drill pipe andacross the face of the drill bit to lubricate it and

to remove cuttings. The mud and cuttings arethen pumped back up the annular space betweenthe drill pipe and the walls of the hole or casing.Mud is generally mixed with a weighting agent,such as barite, to: 1 ) stabilize the wellbore andprevent cave-ins; 2) counterbalance any highpressure oil, gas, or water zones in the forma-tions being drilled; and 3) provide lubrication toalleviate problems downhole (such as a stuckpipe).’

Drilling fluids are selected based on the types ofgeologic formations encountered, economics,availability, problems downhole, reservoirdamage potential, and well data-collection prac-

Photo credit Sfandard Alaska

Gravel production pad under development on the North Slope. Covered production wells are to the rear of the pad,reserve pits in the center.

7. U.S. Environmental Protection Agency, Office of Solid Waste and Emergency Response, Management of Wastes from theExploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal Energy, Report to Congress, December 1987.pp. 2-3 to 2-5

tices. Water-based mud with 70 to 80 percentwater is the most widely used fluid for all types ofdrilling in the United States. Colloidal materials,primarily bentonite clay, and weighting materials,such as barite, are common constituents ofwater-based mud, and small amounts of chemi-cal additives may make drilling easier. Oil-basedmud accounts for a small percentage of drillingfluids used nationwide,8 but is essential for cer-tain types of exploratory wells, directional wells,etc.

The composition of drilling mud and the prac-~tices of building reserve pits to contain the fluids

have improved over the past decade of Arctic oiloperations. The size of reserve pits has beenreduced in newer designs, and more recent prac-tices have aimed at better control of the wasteproducts. Smaller reserve pits are possible byrecycling muds and injecting unusable liquidsdown the well’s annulus. According to currentstated industry practice, when drilling is com-plete the reserve pit contains only drill cuttingsthat can be buried or used as fill. Smaller reservepits also mean smaller gravel drilling pads. Majoroil companies operating in Alaska usually followthese and other practices to minimize pad sizeand reduce wastes.

Figures 2-4, 2-5, and 2-6 show typical opera-tions involving drilling mud and reserve pits.Figure 2-4 shows the standard mud flow patternfrom mud pump to drill pipe, down the well andup the annulus, to a shale shaker on the surfacewhich screens out cuttings that are put in areserve pit. The remaining “cleaned” mud mayreceive some additives and then return to themud pump for another cycle. The leakage ofmud and other wastes out of reserve pits hasbeen a serious environmental concern in thepast. New systems have been developed to ad-dress this problem. These new systems wouldbe designed to separate the disposal of cuttingsfrom all fluids and from a pit used as a reservemud source. The rock cuttings are both com-paratively benign and simple to contain in a pit.Figures 2-5 and 2-6 show the location of areserve pit used just for drill cuttings, a practice

that some North Slope operators are reportedlybeginning. If this type of system proves feasible,the pit may be covered and permanently con-tained after drilling is completed. Environmentalgroups stress the-need forto confirm the permanence

Directional Drilling

long-term monitoringof this system.

Directional drilling is deliberately drilling at anangle from the vertical to reach a target that is off-set from the surface wellsite. Directional drillingwas developed specifically for offshore use toallow multiple wells to be drilled from a singleplatform. Directional drilling on land is usedwhen surface wellheads must be clustered in asmall area; one drill pad in the Arctic may containas many as 40 wells. As directional drilling im-proves, the number of pads can be decreasedand their locations can be more centralized. Cur-rently, North Slope wells are drilled at angles ofup to 60 degrees from the vertical with the pointof departure from vertical as shallow as 500 feet.Theoretically, a 5,000-acre field, if relatively deep,could be drilled from one site.

Directional drilling to a 60-degree offset is a ma-ture practice on the North Slope. Furtherdevelopments in directional drilling could allowdenser clustering of wells, but changes are ex-pected to be gradual. Continual advancementsin offshore extended-reach drilling are helping tocut the high costs of subsea wells; some of thesegains may be applied to the North Slope in the fu-ture. One North Sea proposal calls for up to a 75-degree angle and as much as 6 mile reach for aresearch and development well.

Horizontal Drilling

Horizontal drilling, perfected in South Texastests, is used to improve well flow-rates, especial-ly for thin formations. A conventional directionalhole is drilled to a predetermined depth and then,using another drilling method, the hole is drilledat a 90-degree angle from the vertical, as much

8. Ibid., pp. 2-5 to 2+.9. Reserve pits are open its near a well used to hold exoess or waste mud made during the drilling operation. The excess mud

Cfis sometimes needed to ad pressure to a well during drilling. The pits also serve a disposal function.

Charpter 2 ● 45

Figure 2-4.— Drilling Mud Flow Pattern in a Well

o

Chapter 2 ● 47

0

I

48 ● ANWR

as 2,000 feet sideways. In the Prudhoe Bay field,two horizontal wells have been drilled that havesubstantially increased flow rates and that haverecovered hard-to-get oil. Figure 2-7 illustratesone of the horizontal wells drilled at Prudhoe Bayto improve recovery in thin portions of the reser-voir near the edge of the field. Horizontal drillingcould enhance economic recovery rates in someother North Slope applications.

Both directional and horizontal dril l ing,however, could have some disadvantageous en-vironmental consequences since oil-based mudsare more likely to be used to better lubricate thedrilling bit. These oil-based muds are more dif-ficult to dispose of in an environmentally soundmanner.

Figure 2-7. -Outline of a Prudhoe Bay Horizontal Well

Directional profile of Sohio’s JX-2 well

o “

2,000 “

4,000 –

56,000 –

8,000 –

o 2,000 4,000 6,000Distance from vertical (ft)

SOURCE: 011 and Gas Journal, Feb 17, 1986

Permafrost Protection

The warmth of produced oil flowing through theupper portion of a well drilled through permafrostwill eventually melt the permafrost. Hence, thewell casing must be properly designed to preventthaw and subsidence. The area of the meltedpermafrost may limit close well spacing, as ex-tensive melting could cause subsidence of othernearby foundations. Nevertheless, work on thecauses, extent, predictability, and control of per-mafrost melting problems is continuing in in-dustry Arctic research and developmentprograms. Results of this work could affectdesigns of future well sites and drill pad arrange-ments. For example, some closely spaced sur-face wells (about 10 feet on center) with specialcasing have been recently instailed at Endicott.

T ranspor t o f Equ ipment

In the early stages of exploratory drilling,transporting equipment is a major activity. Tominimize damage to the tundra, winter seasonmovements of heavy equipment on ice roads arepreferred. Summer movements may be made byairplane, by barge, or by a specially designedground vehicle. Vehicles with large, soft tires,called rolligons, have been used, as have aircushioned vehicles. Soft-tired ground vehicletechnology is well-established; however, air-cushioned vehicles have not proven very reliableor efficient. Operators usually choose somecombination of transport methods to balancecost, environmental protection, and the need forflexibility. Figure 2-8 shows the typical uses ofvarious transportation systems during differentArctic seasons.

New transportation technologies are unlikelyanytime soon without more regulatory pressure.Operators may need specific guidelines on thetiming or location of movements and on maxi-mum weights, to keep environmental damagedown. However, some level of damage to thetundra is unavoidable. Future environmentalregulation must evaluate what level is acceptableand what operational controls will assure thatoperators stay within acceptable limits.

Once a field is discovered and developmentbegins, marine docks and gravel roads needed toreceive and transport heavy equipment and

Chapter 2 ● 49

.

SOURCE

Figure 2-8.—Transportation options Associated with changing North slope physical Environment

January February March April Mav June Julv Auaust Scot Oct Nov Dec

Dayllght

Temperature

Ice condi t ions

Open Ice breakingwate r by hoverbarge

I

BargingI 4

Smal l boats

Rolligons on ice roads

I

-leavy equipment on ice roads“ — -

Pontoon sleds or hoverbarae

Hel icopters

Fixed wing on ice runwaysiFixed wing on gravel runways

3 AM

6 AM

9 AM

12 Noon

3 PM

6 PM

9 PM

10

, 0

– 10

– 20

- 3 0

- 4 0

- 5 0

0

1

2

J. M. Gulick, “Transportation Requirements for Drilling Operations on the Arctic North Slope of Alaska, ” Journal of Petro/eum Technology, December 1983

500 • ANWR

Photo credit Standard Alaska

Specialized vehicles have been developed to protect the tundra during both summer and winter conditions.

modules to production sites bring more man-made change to the landscape.

C o n s t r u c t i o n

When a field is developed, onsite constructioncenters around building gravel pads, roads, cul-verts, docks, causeways, and foundations(pilings); installing modules; building pipelines,etc. Construction practices have changed overthe years since Prudhoe Bay developmentbegan–mainly through smaller, more compactdrilling pads. However, the typical 5-foot-thickgravel pad, road, or airstrip is reasonably stand-ard and is not likely to be much reduced in size inthe near future. Thus, lots of graveI still needs tobe mined and moved. Nevertheless, OTA iSaware of some insulated gravel pads built inKuparuk that reduce gravel thickness and, in ad-dition, of the consolidation of facilities to reducethe size of the pads. It is likely that industry’s in-

centive to reduce gravel use is mostly economic.If gravel is easily available and cheap, however,these gravel-reduction measures would not likelybe used without regulatory pressure.

Gravel is also used to build roads. Figure 2-9shows the growth in the length of the road net-work for both Prudhoe and Kuparuk since theywere first developed up through 1983. Thesedata indicate that even 15 years after Prudhoewas discovered, roads were still being con-structed at about the same rate as in early years.In 10 years Prudhoe’s road mileage tripled. TheKuparuk field is following the same pattern. Acorresponding growth in gravel coverage is as-sumed. While no more recent road coveragedata are available, industry claims that gravelcoverage leveled off in the last few years.

The continual, long-term growth in the extent ofareal coverage of the tundra by manmade facilitiesfollows the gradual and staged nature of the

Figure 2-9.–Growth of the Prudhoe and KuparukRoad Networks 1968-83

0 Prudhoe BayA Kuparuk

Eventually, less geologically attractive drillingtargets come into range by using the same in-frastructure. New opportunities may open for ex-panding production through: the development ofnew, smaller fields; infill drilling; seeking srrder,separate reservoirs within the same field; anddrilling on the margins of the field where the oil-bearing formation is relatively thin. As these ad-ditional drilling targets are pursued, the road andgravel coverage continues to grow.

Wherever construction operations requireheavy equipment and major facilities, accidents

development of large oilfields. The first stage ofdevelopment, when a pattern of primary recoverywells are drilled, can last several years simply be-cause of the large number of wells to be drilled andthe economic penalty involved in attempting tocomplete the drilling quickly by importing largenumbers of men and equipment. During thisperiod, the number of gravel pads and the length ofthe road network grows with the number of wellsbeing drilled. After the initial wells are drilled, after aportion of the field’s recoverable resources havebeen produced, and after the reservoir pressuredriving the oil to the wells is somewhat depleted, asecond stage of recovery seeks to maintain reser-voir pressure by injecting fluids – commonly water,in a “waterflood” operation – into the producing for-mation. This operation requires additional facilitiesand (usually) wells for injection, with additional re-quirements for gravel pads and roads. Further, in athird stage of recovery, heat, fluids, and chemicalsare injected into the rock to loosen its hold on the oilnot released in the first two stages; these operationsmay add still further to road and gravel coverage.

reduce these risks, but some environ mentalgroups claim that the regulations are not strongenough and that construction over large areascould cause extensive impacts.

Pipelines

Much of today’s Arctic pipeline technology wasfirst developed for the Trans Alaska Pipeline Sys-tem. All developed North Slope fields pump theirproduced oil by the same kind of elevatedpipeline to the TAPS Pump Station #1 at PrudhoeBay. Refinements have been made in insulationand construction techniques, which make con-struction more cost-effective. Arctic-grade steelis used for all pipeline vertical support members(VSMs) and other structural components. VSMsetting depths are now being adjusted to per-mafrost characteristics to prevent VSM move-ment.

Depending on the terrain and excavationnecessary, winter-only pipeline construction maybe preferred because it offers more tundraprotection and, generaily, lower cost. For ex-ample, winter work from a temporary ice pad orice road eliminates some of the need for a gravelconstruction pad or road parallel to the pipeline;road location becomes more flexible. A gravelaccess road, constructed later, may follow thepipeline but need not parallel it precisely.(Recent studies of caribou movement throughpipeline-road corridors indicate that pipeline androad separation of 600 to 800 feet may be neces-sary for caribou passage). In addition, VSMs canbe more firmly set during the winter anyway,when the tundra is frozen. Summer constructionis difficult because heavy equipment cannot

52 ● ANWR

w

*

.

Photo credit BP America Inc

Mile Zero, Start of the Trans Alaska Pipeline at Prudhoe Bay. The elevated pipeline rests on structures calledvertical support members (VSMs).

operate on the thawed tundra and surface water of sulfur dioxide, 17,000 tons of carbonfills up the VSM holes. monoxide, and 2,000 tons of suspended particu-

Iates enter the atmosphere each year from

Wastes and Waste Disposal production activities.11

The generation of wastes during oil productionis unavoidable. Waste products can be broadlycategorized into three types: air pollutants, liquidwastes, and solid wastes.

The principal air pollutants discharged –mainlyby natural-gas-fired turbines and heaters–aresulfur dioxide, carbon monoxide, suspended par-ticulate matter, and nitrogen oxides NOx. Emis-sions of NOx range from about 60,000 to 60,000tons per year.10 In comparison, about 600 tons

Liquid wastes include reserve pit fluids, domes-tic wastewater, brine discharges, hydrostatic testdischarges, vessel rinsates, excavation dis-charges, oily wastewater streams, workoverfluids, waste oil solvents, and others.

Major types of solid waste include drillingwastes, scrap metal, oily wastes, junked vehicles,construction debris, more than 10,000 useddrums per year, and other materials.

10. Larry Dietrick, Alaska Department of Environmental Conservation, Testimony before the Senate Committee on NaturalResources, &t. 13, 19S70

11. ARCO Alaska, Air Issues on the North Slope of Alaska, 1987.

Chapter 2 ● 53

Present Alaskan and U.S. Environmental Protec-tion Agency (EPA) regulations govern waste dis-posal practices. The industry considers itstechnology for handling waste to be adequate anddoes not expect major advances in the near future.Environmental groups, however, point to recentcharges of violations of the Clean Water Act andconsider waste disposal an important unresolvedregulatory issue. The Alaska Department of En-vironmental Conservation has noted that the NorthSlope has never been subjected to a detailedevaluation of waste management practices or en-vironmental protection measures. it appears thatthe industry could continue to improve waste han-dling practices if requirements become more strin-gent.

Waste disposal methods consist of well injec-tion, reserve pit use, confinement, recycling, in-cineration, and Iandfilling. Most waste generatedby oil production on the North Slope is eithernonhazardous or is currently exempt from haz-ardous waste regulation under the ResourceConservation and Recovery Act (RCRA). En-vironmental groups want to see more exemptwastes redesignated as hazardous, but EPArecently concluded that, pending further study,no significant changes are necessary.13 Existingpractice for wastes designated as hazardous iseither to recycle onsite or to ship them out of theState for incineration, recycling, or other dis-posal.

Deep injection of wastes is a source of con-troversy in arguments about the environmentalimpacts of current North Slope development andthe potential impacts of future development ofthe ANWR coastal plain. The controversy stemsfrom the contaminants found in the injectedmaterials, the relative lack of monitoring on theNorth Slope, the lack of detailed understandingof the geology of the coastal plain, and the his-tory of environmental problems associated withdeep well injection in the Lower 48. The types ofwastes subject to deep well injection in Alaska

are produced water and associated oilfield was-tes such as mud. The Alaska Oil and Gas Con-servation Commission has primary responsibilityfor regulating deep well injection. State regula-tions include requirements for casing andcementing wells to ensure initial structural in-tegrity and pressure monitoring to maintain it.

The basic environmental complaint about deepwell injection is the potential for migration of thewastes out of the injection zone and for con-tamination of shallower aquifers or surfacewaters. Contamination may occur because ofstructural failures in the injection wells, un-foreseen geological pathways for migration, orthe existence of undocumented or improperlyplugged wells intersecting the injection zones.

The industry claims that the thick permafrostlayers on the North Slope are ample protectionagainst “geological” failures, and that the per-mafrost layer at ANWR will serve this purpose.Despite these assurances, the Alaska Depart-ment of Environmental Conservation is con-cerned about the potential for unforeseenmigration of wastes, especially on the coastalplain where detailed geophysical studies and welldata are not available. Problems with wellfailures– either with the injection well, which isusually a converted production well, or with otherwells in the vicinity– have been a concern in theLower 48, where old wells are used for waste in-jection in many areas, and undocumented andimproperly sealed abandoned wells may sewe aspathways to other geologic strata or to the sur-face. On the North Slope, there are fewer wells,and none are more than 10 or 20 years old.Hence, well failures should not be as big a con-cern on the North Slope.

Resewe pit wastes, consisting of drilling mudand cuttings suspended in a water or oil base, areanother concern. There are over 250 reserve pitsin existing developments on the North Slope,with capacities ranging from 4.5 million to 13.5

12. Letter to OTAfrom Brad Fristoe, Alaska Department of Environmental Conservation, May 12, 1988. Fristoe also noted that DECis in the process of doing this evaluation, which will be used as the basis for developing appropriate stipulations for new areas likeANWR.

13. U.S. Environmental Protection Agency, op. cit., footnote 7, p. V21-2.

54 ● ANWR

million gallons of used drilling mud and cuttingsand associated wastes.14 Excess reserve pitfluids are either disposed directly onto the tundraor onto roads, or are injected into subsurface for-mations. The Alaska Department of Environmen-tal Conservation estimates that 100 milliongallons of supernatant (i.e., the liquids forming alayer above settled solids in the reserve pit) arepumped onto the tundra and roadways each yearto make room for new drilling waste and to avoidovertopping and/or breaching problems. Addi-tional resewe pit fluids may reach the tundra ifreserve pits are breached because of poor con-struction. Approximately 26 million barrels ofmuds and cuttings are currently impounded inPrudhoe Bay reseme pits. 15

Liquid reserve pit wastes contain small amountsof metals (e. g., aluminum, arsenic, barium, cad-mium, chromium, copper, lead, mercury, nickel,silver, and zinc); aromatic hydrocarbons; andchemical additives. In sufficient quantities andwith enough exposure, many of these com-ponents of liquid reserve pit wastes can be harm-ful to aquatic organisms and to waterfowl andother birds (for example, potentially causingbioaccumulation of heavy metals and other con-taminants in local wildlife, thus affecting the foodchain). EPA notes that the controlled dischargeof excess pit liquids has been a State-approvedpractice on the North Slope.

The Alaska Department of Environmental Con-servation, the State agency with primaryauthority to regulate the design, construction,and operation of resetve pits, now requires thatdischarges meet State water quality standards.Also, the reserve pit must have been stable (nodischarges into the pit) for one freeze-thaw cyclebefore any discharges can take place. Environ-

mental groups assert that these standards are in-adequate to protect aquatic species and that ef-fluents have exceeded acceptable levels in thepast. Since a National Pollutant DischargeElimination System’s (NPDES) permit does notcover these discharges, EPA is concerned aboutthe long-term effects of discharging large quan-tities of liquid reseme pit waste on the tundra.While concerned, EPA notes that the existingbody of scientific evidence is insufficient to con-clusively demonstrate whether or not there areproblems resulting from this practice. 16

A related concern is the potential unintendedbreaching of North Slope reserve pits, caused bythe intense freeze-thaw cycles that can breakdown the stability of the pit walls, enabling un-treated liquid and solid waste to spill onto thetundra. Some observers also question the ad-visability of underground injection or permafrostburial of reserve pit waste.

OTA has not addressed the environmental im-pacts of waste generated by North Slope oilproduction. Generally, neither the fact that thesewastes are generated nor the approximateamounts generated is in dispute. However, thereis considerable difference of opinion about theenvironmental impact of the various kinds of airpollutants and liquid and solid waste products.

The environmental community has issued adetailed report documenting what they believe issignificant environmental damage caused by

17 Environmentalists aredevelopment activities.concerned that air and water pollution and im-proper management of hazardous wastesthreatens aquatic and terrestrial ecosystems inthe Prudhoe Bay area and that similar pollutionwith similar results will occur in ANWR.

14. Trustees for Alaska, Natural Resources Defense Council, and the National Wildlife Federation, Oil in the Arctic, The EnvironmentalRecord of Oil Development on Alaska’s North Slope, Januay 1966. January 1966.

15. Standard Oil, Arctic Oil and Gas Exploration and Production Waste, 1967.16. U.S. Environmental Protection Agency, op. cit., footnote 7..17. Trustees for Alaska, Natural Resources Defense Council, National Wildlife Federation, Oil in the Arctic: The Environmental

Record of Oil Development on Alaska’s North Slope, January 1966.

Chapter 2 ● 55

The oil industry, for its part, has attempted todemonstrate that despite some unavoidable con-sequences of development, “there is no evidenceto support the allegation of widespread pollutionor to justify claims of significant adverse environ-mental impact. “18

The Environmental Protection Agency iscautious in its recent report to Congress19 but isgenerally less alarmed than the environmentalcommunity about pollution problems and is alsoless sanguine than the oil industry that there areno North Slope pollution issues of concern. EPAis concerned primarily about the discharge of su-pernatant onto the tundra and roads, suggestingthat further study of impacts is needed. 20 TheState of Alaska has recently adopted more strin-gent effluent limits and has suggested that zero-discharge of industrial wastewater streamsshould be carefully considered for ANWR.21

Water

Substantial amounts of fresh water are used indrilling and other oil production activities. Watersupplies in the Arctic are not easily tapped year-round, and some convenient supplies are en-vironmentally unacceptable to use. It is thereforeprudent to first reduce water consumption to themost reasonable practical level. Technologiesfor ensuring environmentally safe water suppliesare important. The methods used by industry in-clude trapping and melting snow; insulatingsmall, non-fish-bearing lakes; flooding gravelpits; and desalting seawater.

Among the most abundant sources of water arethe gravel extraction pits that have been con-verted to water reservoirs. Water for many of thePrudhoe Bay well operations is collected andhauled from the Put River pit, a former gravelsource that has been flooded and now sewes asa year-round water source. Similarly, Mine Site C

serves as a water source for the Kuparuk oilfield;this pit is replenished annually with overflow fromthe Ugnuravik River during break-up.

Desalination of seawater is sometimes a practi-cal option for operations near the coast. If theoperation is in the winter, an ice road is con-structed to a point where the seawater is notfrozen to bottom, the desalination operation isset up there, and fresh water is trucked to whereit is needed. This method was used for opera-tions on Challenge Island #1 in the winter of1980-81 and for Alaska Island #1 in the winter of1981-82. Desalination of seawater was also usedfor all the wells drilled from Endeavor Island andResolution Island and for most of the Niakukwells. A large desalination plant has been in-stalled at the Endicott field to support productionoperations. Conoco also used desalination fortheir Milne Point operations; however, itdesalinated water from a 3,000-foot-deep, brack-ish water, underground aquifer rather than fromseawater.

Many operations have had reasonable accessto deep lakes. For example, deep lakes in theSagavanirktok River delta were used for the firstthree “Sag Delta” wells in the 1970s. Two deeplakes were approved for water sources for opera-tions to the west of the Sag Delta in the winter of1981-82. No fish were found in either lake, butdraw-down restrictions were still applied toprotect the few that might have gone undetected.

Deep holes in a river or an oxbow lake are alsovaluable sources of water. The Alaska Depart-ment of Fish and Game applies withdrawal rate,filter size, and draw-down restrictions to ail riversources to protect fish. Water for the Niakuk #1well, for example, came from a deep hole in theSagavanirktok River. Big Lake, the water sourcefor Standard’s Base Operations Camp at Prud-hoe, is an example of a lake that has been insu-lated to minimize freeze-down. For several yearsit was insulated with styrofoam. Since 1983,

18. Standard Alaska Production Company, Assessing the Impact of Oil Development on Alaska’s North Slope: A Rebuttal of thehClaims of The Trustees for Alaska, The Natural Resources Defense Council, and t e National Wildlife Federation, February 1988., p.

2-6.19, U.S. Environmental Protection Agency, op. cit., footnote 7,20. Ibid., p. V21-3.21. Dietrick, op. cit. footnote 10.

56 ● ANWR

however, the lake has been insulated by erectingsnow fences that collect drifting snow for insula-t ion.22

Production Facilities

Production facilities designed to operate forlong periods of time with minimal attention mustbe installed onsite. Directional drilling minimizesthe area needed for drill pads and support forwellheads. Characteristics of the oil reservoir willdetermine the number and location of wellsneeded, but wellheads can be clusteredreasonably close together on individual pads.Wells are needed for both oil production and in-jection of fluids to stimulate flow. Soil types andpermafrost melting characteristics determine theminimum spacing and required support ofwellheads on the North Slope.

Production facilities for Arctic use are usuallybuilt offsite in large modules (from 500 to 5,000tons depending on service and distance fromdock), in locations such as Washington, Oregon,California, and the Gulf Coast and are moved bybarge to coastal docks and then onto pilings andpads at the site. Many kinds of modules areneeded to complete a production complex.These include oil/gas/water separation plants,gas injection plants, waterflooding plants, controlstations, power-plants, etc. In addition, manysupport modules are needed, including livingquarters, maintenance shops, storage and ad-ministrative areas, water and waste treatment,etc. The production field, in time, becomes a net-work of facility modules resembling a small fac-tory town built on pads and pilings and protectedfrom the harsh environment. Roads, airstrips,and marine docks complete the compiex. Allthese facilities require considerable acreage andthus need a large source of foundation materialto build the 5-foot-thick gravel pads commonlyused.

Production facilities are added and modifiedover time as an oilfield is further developed, withthe addition of enhanced recovery systems asneeded. Each change is usually accompaniedby some increase in size, space, and othermaterial needs.

Summary

Arctic oil and gas technology has evolved overthe past decade into today’s effective and matureindustrial system with its accepted commercialoperating practices. The recent development ofNorth Slope fields such as Kuparuk and Endicottare the result of this maturity, and any futureANWR development under similar economic andenvironmental constraints would probablyresemble closely these two fields. The industry isconfident that this likely extension of currentdesigns and practices is sound development andoffers adequate environmental protection. Someenvironmental groups, however, contend thattoday’s practices are not acceptable for develop-ment of ANWR.

While Arctic oil drilling and production technol-ogy has matured, the practices for using the tech-nology have improved even further. Theseimprovements have occurred because of botheconomic and environmental concerns. Prac-tices are likely to continue to improve in ANWR –if it is developed – if economic factors warrant orif environmental requirements are strong, OTAhas not evaluated the specific improvements thatmay reduce environmental impacts, but it ap-pears that extensive debates about environmen-tal protection versus economics will continue ifANWR is leased. Environmental groups havespecific concerns that will need to be resolvedduring the development of regulations for anydevelopment that may occur.

22. Standard Alaska Production Company, letter to OTA, Feb. 23, 1988.

Chapter 2 ● 57

TECHNOLOGY APPLICATIONS FOR THE ARCTICNATIONAL WILDLIFE REFUGE

If the Arctic National Wildlife Refuge’s (ANWR)coastal plain is leased, the oil industry will applyits broad technological and practical experiencein Arctic oil development to the specific condi-tions of ANWR. The industry generally claimsthat ANWR exploration and development will lookpretty much like the most recent operations else-where on the North Slope.

ANWR Special Conditions

OTA has attempted to identify any special orunique conditions of the ANWR coastal plain, ascompared to Prudhoe Bay and other North Slopeareas, that would affect the technology used orpractices followed for petroleum development.The primary data source was our Anchorageworkshop and subsequent submissions from in-dustry and other participants at the workshop, aswell as extensive comments from industry andenvironmental organizations that reviewed anearlier draft of this report.

Topographic Relief

The southern part of the ANWR coastal plainhas moderate topographic relief, with gently roll-ing foothills. In contrast, Prudhoe is a very flatthaw-lake plain. ANWR’s topography has ad-vantages in that there may be fewer problemswith standing water and that there may be betterelevated sites for facilities. But there are also dis-advantages to the greater relief, including thepotential for more problems with channeling anderosion (especially if and when east-to-westroads are built, crossing many streams and re-quiring attention to drainage patterns) andproblems with building roads or locatingfacilities.

For example, in ANWR, a pipeline can crossgullies and hills more or less in a straight line, buta pipeline access road will need to snake alongsome surface contours to avoid extensive ex-cavation and filling. A road may also create moreenvironmental problems than a pipeline, espe-cially problems related to drainage, mining

gravel, etc. Airstrips need to be reasonably flat;hence, suitable locations in the foothills of ANWRwould be more difficult to find than they are atPrudhoe, and, even then, some cutting and fillingwould have to be done. The same considera-tions are true for a camp or production facility inANWR. At Prudhoe, a camp or an airstrip can goalmost anywhere that is dry and, for a winter-onlyexploration well, an airstrip can be constructedeven on a convenient frozen lake.

Sea Ice and Port Sites

In generaI, potential ANWR port sites havedeeper water than do Prudhoe sites. Deeperwater eases the problem of building docks andmeans the length of causeways, needed to reachthe water depths of about 8 feet required for bar-ges and other shipping, could be reduced. Iceconditions in potential ANWR port sites aregenerally equivalent to those in the Prudhoeregion except in the extreme eastern part ofANWR, where more severe offshore ice condi-tions may cause problems for shipping.

Gravel Availability

Extensive gravel deposits are located within theANWR coastal plain, a situation that simplifiesfinding gravel for construction. Gravel availabilityin ANWR is similar to that at Prudhoe but betterthan at Kuparuk.

Permafrost Layer

Some experts believe the permafrost layer inANWR is thinner than at Prudhoe, but theevidence is sketchy. Permafrost thickness maysometimes affect aspects of well drilling (e.g., thestarting depth for directional drilling), but otherfactors could govern drilling decisions and maybe more important. This uncertainty will beresolved only with actual drilling. The permafrostsituation in ANWR, however, probably will behandled in much the same way as it is at PrudhoeBay.

5 8 * A N W R

Sites for Deep Injection of Wastes

Knowledge of subsurface geologic conditionsfor deep well injection is sketchy at this time butis important to locating acceptable sites for wasteinjection. Prudhoe is considered to have goodconditions for containing deep injected wastes.Conditions in ANWR are not defined, althoughexperts disagree about the interpretation of exist-ing evidence. Industry is reasonably confidentthat suitable sites can be found; however, dif-ferent experts have different opinions on the ex-tent of tests and study necessary to confirm a“suitable site. ” This ambiguity is one of the chiefconcerns of some environmental groups.

Potential Developed Area

The ANWR coastal plain covers about 1.5 mil-lion acres. This area is about twice the size of thegeneral region covering the Prudhoe, Kuparuk,Lisburne, and Endicott fields, the major produc-ing North Slope fields. The U.S. Department ofthe Interior has identified 26 faulted structuralprospects within the plain. The mapped andareal extent of these prospects is based on struc-tures defined by seismic data. Thus, theprospects contain potential petroleum traps, butthe extent of producible oil is unknown. If theseprospects contain oilfields, the largest prospect(227,000 acres) would be similar in acreage toKuparuk and the second largest (about 130,000acres) would be roughly the area of the PrudhoeBay field. All 26 prospects are of a size that couldcontain fields at least the areal size of the smallerknown North Slope fields. While these com-parisons are not predictive, they are indicative ofthe possible extent of surface development ifmajor ANWR discoveries are made. The extentof land coverage for development at ANWRwould then likely resemble Prudhoe and Kuparukand perhaps some smaller fields as well. Ifseveral of ANWR’s prospects contain economi-cally recoverable oil, the total developed areamay be equal to or greater than the developedarea of all existing North Slope development.

Water

Whereas industry has made extensive use ofexisting surface water supplies at Prudhoe,ANWR has few large, deep lakes. Substantialwater for ANWR development would probably

need to come from other sources. Industry couldresort to excavating pits, melting snow, and otherwater collection techniques, but these activitieswill likely prove to be more extensive in ANWRthan they were at Prudhoe Bay. Industry has alsoclaimed that 12 of the large rivers in the ANWRcoastal plain could be sources of water in sum-mer. Environmental groups believe that watersupply will require regulatory attention to mini-mize impacts.

Wildlife

Approximately 200,000 caribou of the Por-cupine Caribou herd inhabit the Arctic NationalWildlife Refuge from roughly mid-May to late July.The ANWR population vastly outnumbers 15,000 -or-so caribou of the Central Arctic Herd thatreside year-round in the Prudhoe Bay area; thiscontrast is probably the most dramatic for wildlifepopulations in the two areas. Both herds havebeen increasing in size in recent years. The de-gree to which the Porcupine herd will be able toacclimate to development compared to theCentral Arctic herd is still being debated. Thereintroduced musk oxen population in ANWRnow numbers about 500 animals; none live in thePrudhoe Bay area. The number of bears and wol-ves has declined in the Prudhoe Bay area, large-ly because they are not as tolerant of man as aresome other species. Total North Slope wildlifepopulations however, are not believed to havediminished.

Overview: ANWR Technologiesand Practices

The technologies used to explore for and pos-sibly produce any petroleum resources in theArctic National Wildlife Refuge will most likelyresemble those already in place on other NorthSlope fields. Technology now in use at the mostrecently developed sites, such as Endicott, hasbeen built to rigid industry design standards forthe Arctic environment and is efficient and effec-tive for producing oil from these fields. The in-dustry operators forcefully claim that thetechnology has been installed and operated withcare to avoid unnecessary environmental im-pacts. In opposition to this claim, the environ-mental community points to a number ofinstances where habitat has suffered damage.

Chapter 2 ● 59

OTA has not analyzed the history of accidents,spills, violations, etc., on the North Slope23 butnotes that future regulations will need to bebased on an objective analysis of these environ-mental concerns.

Only oil has been produced from Alaskan NorthSlope fields to date. While substantial gas reser-ves have been delineated, no system to transportgas to the major markets has been built. Severalmethods have been proposed to transport gasbut favorable economics and other concernshave prevented their adoption. The technologyfor Arctic gas production, however, has been inuse at Prudhoe where the world’s largest gascompression facility is operating and con-siderable gas handling capability is in place to in-ject the gas back into the formation.

Most industry experts believe that no majortechnological breakthroughs are needed to safe-ly and effectively explore for and produce oil atANWR. They say that the production systemshave advanced in practice during the past twodecades of Arctic work to an acceptable level,which they believe is demonstrated by smoothand reliable plant operations.

The level of environmental damage that has oc-curred, however, is vigorously debated. Many ofthe technological advances in the past 10 yearshave concentrated on improving operational ef-ficiency. Several of these advancements also ap-pear to reduce environmental impacts, butspecific measurements of reduced impact are notreadily available. Some advancements includeimproved waste handling, less toxic dischargesfrom drilling, and reduced needs for gravel padsand roads with possible reduced intrusion onwildlife. Other technological advances have ledto more cost-effective operations in the Arctic.These advances include substantial automationof oil field operations, more efficient sub-assemb-ly of modules, and systems for controlling per-mafrost melting. Modules for production plantsare built in complete units in the Lower 48 andmoved in large pieces on barges to the North

Slope, thus eliminating the need for large andcostly construction crews working onsite.

More environmentally important than develop-ing new technologies for use in ANWR is control-ling the practices used to apply the existing ones.Operating practices include: transportation ofequipment; construction of dril l ing pads,pipelines, and facilities; selection of drilling tech-niques; controlling the effects of permafrost melt-ing; and containing and disposing of drillingfluids and other waste products.

Equipment transportation involves movingmany very large heavy pieces of equipment withlarge vehicles over long distances. The tundra isvery fragile, and it does not support much weightin the summer months. The construction ofpads, pipelines, and facilities are also major ac-tivities on fragile ground; a considerable amountof gravel must be mined which can alter thelandscape extensively. Drilling techniques canbe selected to minimize surface disturbance ifwells can be closely clustered on the surface andif rigs are easily moved or set up. Permafrostconsideration is critical because uncontrolledmelting may cause foundations or supports tofail, resulting in accidents, spills, etc. It is also im-portant to keep any waste products containedand/or to dispose of them properly.

Impacts: ANWR Technologiesand Practices

Key technologies and practices with potentialfor significant environmental stress wereanalyzed in an OTA workshop held in Anchorage,Alaska in November 1987. The following discus-sion expands on the workshop’s views.

Exploratory Drilling

Exploratory drilling practices in ANWR will likelyfollow those used in recent exploration wells onthe North Slope. Considerations that may affectthe environment include the ability of drillers to

23, A com rehensive discussion of environmental impacts on the North Slo e from the environmental community viewpointappears in “ &‘1 in the Arctic: The Environmental Record of Oil Development on R aska’s North Slope, ” Natural Resources DefenseCouncil, January 1988. Similar discussions from the industry view apOil Co., August 1987; “Assessing the Impact of Oil Development on r

ar in “Current ANWR Environmental Issues, ” The Standardaska’s North Slope, ” Standard Oil Company, February 1988;

and “Alaska Oil and Gas Association Response to Oil in the Arctic by Speer and Libenson, January 1988, ” February 1988.

60* ANWR

move rigs and camps to the site, to build tem-porary pads and other facilities, and then, whenwork is done, to remove all material with nodamage to the tundra. Practices and equipmenthave been developed over the years in the Arcticto protect the tundra, but economics and workconditions have sometimes ruled out the idealapproach. In any case, careful set-up and quickremoval are keys to environmentally acceptableexploratory drilling. Careful set-up probably canbe controlled by regulation, but quick removalwill depend on conditions– not always predict-able– encountered while drilling.

Techniques have been developed to build iceroads, ice pads, and ice air strips for winter-onlydrilling in the Arctic. Moreover, water can be ob-tained from melted snow, and reserve pits can beencapsulated. In these ways, the impacts of adrilling operation can be readily removed, andthere could be little need for gravel excavation orany other disturbance of the tundra except forreserve pits. However, winter-only drilling canhave economic and operational disadvantages.Given the added time and costs of winter-onlydrilling, industry argues for flexible regulations sothat they can judge when such practices are trulywarranted. Industry also notes that a small risk ofa blowout is always present and, if it occurs, theextra time needed to drill a relief well could ex-tend into the thaw season. Environmentalgroups argue, however, that, given the uniquenature of ANWR, very stringent regulationsshould be applied with minimal flexibility.

Drilling Systems

Most existing Arctic drilling technology likely tobe used in all ANWR exploration, production,workover, and service well drilling has beendeveloped to the point of acceptable efficiency.Use of the most advanced of these systems alsomay lessen some environmental impacts. Forexample, directional drilling and the close spac-ing of wells on the surface contribute to the abilityto design fewer and smaller drill pads and thus toreduce the quantity of gravel needed and thespatial impact of development. Directional drill-

ing technology is well developed and continuesto improve. In recent years, the development ofmeasurement-while-drilling (MWD) systems,24

computer analysis, and improved survey techni-ques have significantly improved directional drill-ing efficiency and directional limits (the angle offvertical that is possible). Improvements ex-pected in the next decade include more com-prehensive logging tools deployed during MWDoperations, better directional control from thesurface, and improved mud systems for reducedtorque or drag.

All of these advancements together may lead tocloser spacing of wells on drill pads, and toclustering of larger numbers of wells on each drillpad. However, there are many other factors toothat will determine the layout of pads andfacilities at ANWR. Well spacing will be deter-mined by a combination of economic, environ-mental, operational, and safety considerations.Specific conditions such as reservoir depth, welldrainage area, and permafrost thaw subsidencealso will be factors. Recently drilled wells atKuparuk and at Prudhoe are spaced as close as30 feet apart; on the Endicott gravel islands, wellsare now even more compact, spaced at 10-footintervals. Depending on actual conditions,ANWR wells would likely be spaced within thisrange.

Mud Systems

The most likely mud systems in ANWR arethose that have been successful in other NorthSlope fields. Weighted Iignosulfonate, polymer,and oil-based mud have applications in Arcticregions but are not unique to Alaskan oilfields.The majority of North Slope drilling operationsuse water-based polymer and Iignosulfonatemuds. However, some drilling operations suchas directional, high-angle, and horizontal drillingrequire the lubricating properties of oil-basedmud. Also, some coring 5 operations require oil-based mud to lubricate the bit cutting the coreand to minimize damage during drilling. General-ly, oil-based mud is used for drilling only the shortproductive intervals in non-conventional wells.

24. These systems feature remote sensors that measure angle, location, speed of penetration, and other factors at the bottom of1’a hole and transmit that information to a driller at the surfaoe without interrupting dring opwations,

25. The practioe of cutting and retrieving a cyiindrioal pieoe of the formation during the drilling operations.

Chapter 2 ● 61

Water-based mud usually would be used until theoil-based mud is required. The anticipated ad-vances from horizontal drilling will possibly in-crease the need for oil-based mud and, if thisoccurs, greater attention to suitable disposal ofoil-based systems may be needed in ANWR. En-vironmental groups consider the disposal of mudto be an issue worthy of closer attention.

It is not clear whether more stringent require-ments for disposal of used mud and cuttingswould be necessary in ANWR. Industry assertsthat present State of Alaska regulations are ade-quate and can be followed in ANWR withoutmuch trouble. Alaskan regulations–as theyapply in a permafrost region such as ANWR – re-quire that the drill solids be de-watered or frozenin place, covered with a membrane to prevent fu-ture fluid entry, and covered with gravel and or-ganic soils of sufficient depth to insure that thedrilled solids remain permanently frozen. The liq-uid drilling mud then would be injected into asubsurface zone. This process is commonlycalled annular injection because the drilling mudis displaced down the annulus between the sur-face casing and the production casing. Dedi-cated injection wells are also used. Someenvironmental groups have substantial concernsabout these practices; they advocate higherstandards for waste management in a wildliferefuge.

Fresh Water Supplies

Several techniques for supplying fresh water,developed and used at North Slope productionareas, are likely to be used in ANWR. These tech-niques include: creating deep pools that will notfreeze to the bottom in or adjacent torivers/streambeds, creating deep pools in lakes,desalinating seawater, erecting snow fences totrap snow (and then melting it using snow mel-ters), insulating lakes to keep them from freezingto the bottom, and converting gravel extractionpits to reservoirs. For exploratory sites, watercould be hauled from approved locations ifnecessary. OTA has not evaluated the extent towhich the effects of these practices have beenmonitored.

How much water would ANWR need? StandardOil Company submitted to OTA the following dataas typical of the water requirements that may beexpected in ANWR exploration.

● 414,000 gallons of water per mile for con-struction of an ice road; 4,200 gallons ofwater per mile for daily ice road main-tenance.

● 2,500,000 gallons of water for construc-tion of an ice airstrip;

● 2,100 gallons of water for daily main-tenance. (Volume would be less if airstripis built on a frozen lake.)

● 25,000 gallons of water daily for drilling rigand domestic use.

For a typical exploratory well with about 150days of operations and about 5 miles of roads,Standard Oil estimates that total water consump-tion would be about 10 million gallons. The U.S.Department of the Interior estimates 15 milliongallons for a similar exploratory well.

For development operations, water require-ments would depend on the size of the develop-ment, the number of wells, and the size of thesupport camp. Industry claims that ANWRoperations would most likely use developedwater reservoirs from former river channelsdeepened by gravel extraction or from thedesalination of seawater. Water withdrawn fromgravel extraction pits during the winter would bequickly replenished during the subsequent springsnowmelt. Currently, Prudhoe Bay developmentdrilling operations consume approximately630,000 gallons of water per well.

The potential for water supply techniques todamage the environment would need study ateach site. The environmental groups may wellurge regulatory attention here.

Gravel Pads/Roads, etc

The most likely number, size, and configurationof gravel pads for an ANWR development are dif-ficult to estimate until an actual discovery ismade and delineated. Industry believes,however, that less gravel will be required for anANWR development with today’s technology andexperience than was required for early PrudhoeBay development. Most others would agree, as-suming equivalent field characteristics andproduction systems. Improvements in direction-al drilling techniques and permafrost technology,along with the use of larger, more consolidatedand vertically-layered equipment modules and

620 ANWR

more space-efficient facility designs tend toreduce gravel pad requirements. Improvementsin the design of compact pads have already beenrealized in recent North Slope developmentssuch as Lisburne and Endicott.

Gravel pad design is also affected by the pad’slocation, insulation needs (to avoid permafrostthawing), stability requirements (to account forpermafrost subsidence and requirements forweight support), and site-specific soil conditions.

Characteristics of the actual oil reservoir,however, are the most important factors in deter-mining the most cost-effective design for the totalnumber of wells, the number of wells per pad,and the pattern of positioning well pads over thesurface. For example, while compact pad designimprovements are evident in Kuparuk, the actualarea covered by gravel pads, roads, etc., as aratio of total field production is much greater inKuparuk than Prudhoe because Prudhoe is amore productive field with much thicker payzones, producing higher per-well flows andhigher per-pad production. The total area oftundra that would be covered by gravel in ANWRdepends most upon whether an ANWR field hascharacteristics more similar to Prudhoe, withthick, productive reservoirs, or to Kuparuk withrelatively thinner and less productive reservoirs.

Pipelines

An elevated pipeline mounted on vertical sup-port members (VSMs) spaced about 60 feet apartwith expansion loops every 1,000 feet would bethe most likely pipeline design in ANWR.However, Arctic experience in the use of buriedambient temperature lines is growing and may beanother option for ANWR, depending on oilcharacteristics and production rates, environ-mental impacts, and economics. Depending onsoil conditions, it may be desirable to bury thepipeline in some areas and elevate it in others.

Winter pipeline construction practices are likelyto be used in ANWR unless a road parallel to thepipelines is needed for other reasons, in whichcase the road could support summer pipelineconstruction. The industry favors flexible regula-tions to allow it to use the best practices forspecific circumstances. On the other hand, en-vironmental groups are concerned about exces-

sive flexibility in regulations, especially in sensi-tive areas.

Construction of Culverts

Construction at ANWR, as with any majorpetroleum project, is likely to create extensive en-vironmental disturbance, and regulatory controlsmay be needed, The OTA workshop examinedthe construction of docks, piers, and culverts–all needed in any plausible ANWR developmentscenario.

Culvert design and construction, for example,carries several environmental concerns. In thePrudhoe Bay area of the North Slope, drainagepatterns are poorly defined and are controlledmore by the growth and melting of ground icethan by erosion and transport of sediment. Thus,consideration of thermal as well as hydraulicaspects of drainage design is necessary. ANWRtopography is such that drainage design will bevery important.

The predominant minor drainage structures areculverts. Culvetts must be designed to preventthaw settlement of the foundation and to supportside loads imposed on the culvert. When cul-verts are built, unstable material is usually ex-cavated and replaced with thaw-stable material.

Environmental groups point to various pastproblems with culverts. The most commonproblem is the restriction of fish passage, whichmay result from excessively high water velocitiesor from culvert outlets perched above thestreambed. Another problem is pending whenculverts are improperly located or placed toohigh in an embankment and large ponds areformed. Pending has adverse effects on vegeta-tion and, depending on depth, may either in-crease or decrease the seasonal thaw. Theseproblems can be minimized by careful planningand location of drainage works and by the use ofgood maintenance programs.

Technological Change

OTA concludes that technologies likely to be usedin the ANWR coastal plain will closely resemble themost recent North Slope developments such asKuparuk or Endicott. Major changes in tech-nologies are likely to be too slow and gradual to

alter the big picture for ANWR development, but anumber of factors are involved in this judgment: thedefinition of technologies considered, assumptionsabout the development process, and observationsabout past technological change and the underlyingcauses.

Definition of Technologies Considered

OTA defines technologies to cover all of theequipment and facilities that are used for explora-tion, development, and production. Tech-nologies are of course dominated by largestructures, pipelines, pumps, machinery, etc., tothe extent that change in one small part wouldnot have much effect on the whole.

Development Assumptions

OTA assumes that if ANWR is developed, the in-dustry will be just as able to select technologiesthat best suit its economic needs as it has in thepast. OTA also assumes that economic andother constraints will not change drastically.Since ANWR is similar to Prudhoe and Kuparuk,there is little incentive for industry to make majorchanges in technologies that have worked well inthese two other fields. With few new problems tosolve, industry will tend to model the next genera-tion of technology after the best of the past. Ofcourse, new regulatory demands could forceconsequent technological change at any time.

Past Technological Changes

In two decades of Alaskan North Slope oildevelopment, technological advancement hasbeen fast and many systems have reached whatthe industry considers a mature state. Standardgeotechnical design practices for Arctic per-mafrost conditions have been developed andtested for well casing, roads, facility foundationsand pipeline supports. Low-temperature needsare now fil led in metallurgy, elastomers,lubricants, and fuels. Modularization of facilitiesand their transportation can be also consideredmature technology. Maturity also applies tothose systems adapted from other regions tomeet severe Arctic conditions as well as manysystems specifically designed to solve uniqueArctic problems.

OTA concludes that these technologies willcontinue to advance, but at a much slower pacebecause the need for improvement is less urgent.Just a few years ago when oil prices plummeted,cost reduction pressure was heavy as industryre-evaluated the amount of investment that couldbe justified for future production. Some drillingtechnology advancements probably can be at-tributed to the need to reduce drilling costs. Thispressure from low oil prices has begun to level offin the past year and will probably continue at alow level. However, there is evidence that in-dustry-wide technological change will continueto occur; and when developments elsewhere canbe applied to the North Slope, they will be. Thispressure for technological change will probablybe the same in the future as in the past but, whencombined with the other elements of change, thelikely rate of change is likely to be lower in the fu-ture.

In OTA’s view the challenge of ANWR develop-ment, if it occurs, will be met by the petroleum in-dustry with proven technologies rather than withinnovative ones. A big unknown, however, is out-side forces – such as major regulatory pressures–that could require changes in technologies. Suchchanges might come first in methods of waste han-dling or management or in methods to reduce in-trusion on wildlife habitat.

Schedule

Projecting a likely schedule for ANWR develop-ment is hard. Much depends on the timing andsequence of events. Table 2-3 shows some ac-tual development histories for North Slope oilfields and two current ANWR estimates.

Judging from Table 2-3, the ANWR schedule islikely to be at least as long as the ARCO andDepartment of Energy estimates of 10 to 12 yearsfrom lease sale to production start-up, and pos-sibly even longer. Considering that it will probab-ly take a few years before a lease sale iscompleted, a reasonable schedule would be 15years from today for the start of any substantialproduction. If a major field is discovered inANWR (equivalent to Prudhoe or even Kuparuk),one could expect production to span at least 25to 30 years from start-up. If ANWR developmentfollows common experience in other oil produc-ing regions, and if regulations, technology, and

Table 2-3.—Typical Development Schedules

Years from Years fromlease to discovery Total years

Development discovery to start-up lease to start

P r u d h o e B a y 3 9 12Lisburne 3 18 21K u p a r u k 4 12 16Endicott 9 9 18ARCO Estimate for ANWRa 3 9 12EIA Reportb (assuming existing

p r o c e d u r e s ) 3 7 10

price-cost relationships allow, more explorationand discoveries will follow, spanning many years.At Prudhoe, new fields are continuing to bebrought into production some 20 years after thefirst strike.

Experience indicates that, should ANWR ex-ploration proceed and lead to discovery of amajor oilfield, commercial petroleum activities onthe ANWR coastal plain are likely to continue intothe middle of the 21 st century. It is also likely thatdevelopment will use enhanced recovery techni-ques after production has started.

ANWR Development Scenarios

OTA investigated two plausible scenarios forANWR development, one done by the Depart-ment of the Interior in its LEIS (see Figure 2-10)and one done by ARCO in a presentation to theHouse Subcommittee on Water and PowerResources in October 1987.

Neither of these two scenarios presents com-plete details on all major exploration anddevelopment steps or activities. For example,neither provides the number of exploratory wellsthat may be drilled on lease tracts. The ARCOscenario gives only sizes and gravel pad es-timates for the drill pads but not for the gravelpads for facilities, pipelines, roads, docks, etc.

The ARCO scenario does give an estimate of totalaffected area. The LEIS details a series of padareas and gravel requirements but does not re-late these to specific facility descriptions, func-tions, and locations. The LEIS assumes thedevelopment of three commercial fields with atotal of 3.2 billion barrels of recoverable oil reser-ves but does not give a reserve figure for each ofthe three fields. It also does not estimate theproduction rate. It appears that two of the LEISprospective areas are the same as the onesARCO uses as hypothetical examples (prospect19 and prospect 6 in the LEIS). The ARCOscenario with two fields developed assumes atotal of 3.75 billion barrels of recoverable oilreserves and a peak production rate of 935,000barrels per day.

Despite the discrepancies and gaps in thesetwo scenarios, they are generally similar, and theestimates and assumptions are close. For thisreason, OTA was able to use the combined datato prepare its own generaI but more simplifiedscenario, adding a few assumptions that weremissing. The OTA scenario and its assumptionsare shown in Table 2-4, and a correspondingdevelopment schedule is shown in Figure 2-11.

Exploration

The LEIS states that three of the four blocks inthe ANWR coastal plain are assumed to beleased and one discovery will be on each, but thesize of each discovery is not given. OTA as-sumes that two discoveries will be commercialand that the total reserves will be roughly theaverage of the reserves assumed by the LEIS andARCO. As in the LEIS, an additional 1,500 milesof seismic data are acquired on the coastal plain.

Neither ARCO nor the LEIS estimates the num-ber of exploratory wells to be drilled after leasing;OTA assumes that 10 to 20 wells will be requiredto identify the two fields. (It has been reported inthe past that Prudhoe was discovered on the 19thexploratory well and that over 250 exploratoryand delineation wells have been drilled overall onthe North Slope over the past two decades.Therefore, this assumption appears consewa-tive.) The size and location of the two OTA as-sumed discoveries correspond to the LEIS andARCO data.

—

Chapter 2 ● 65

Figure 2-10.— Development Scenario for Three Major Prospects on the ANWR Coastal Plain, Department ofthe Interior, Legislative Environmental Impact Statement for the ANWR Coastal Plain

Estimated Linear or Areal Coverage by Selected Facilities

Main oil pipeline within the 1002 area2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Main road paralleling main pipeline and from marine facilities2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Spur roads with collecting lines within production fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Marine and salt-water-treatment facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Large central production facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Small central production facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Large permanent airfields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Small permanent airfields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Permanent drilling pads. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Borrow sites . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gravel for construction, operation, and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Major river or stream crossings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2The distance from the 1002 western boundary to TAPS Pump Station 1 [s approximately 50 miles, across State of Alaska land. This 50 miles is not included inthe mileage estimates

Location of Selected Facilities in 1002 Area

SOURCE U.S. Department of the Interior, Legislative Environmental Impact Statement for the ANWR Coastal Plain

66 ● ANWR

Table 2-4.—OTA ANWR Development Scenario

Exploration: 3 of 4 blocks leasedAdditional seismic survey s-1 ,500 line miles10-20 exploration wells drilledTwo commercial discoveries—one large/one small field (equivalent to prospect19 and 6 in EIS)Air transport exploration drill rigs—ice pads#1 Large field—eastern end of coastal plain#2 Small field—western end of coastal plain

Development: #l #2

Field size (billion barrels recoverable)Peak production rate (barrels/day)Number of well sites (Pads)Total number of wellsCentral industrial facilityProduction facilities

AirfieldsPort facilities

Seawater treatment plantOil transport

Gravel pads/roads/etc.

3.0 0.5700,000 100,00012 2700 100(One similar to Kuparuk for two fields)2 large complexes 1 large complex4 satellite —One large One smallPort complex near Port complex atBeaufort Lagoon Camden Bay1 130” elevated Spur Pipeline tomain trunk Main Trunkpipeline, 150 mi.to TAPS PumpStation #l2,500-3,000 acres 500-1,000 acres

Total “Footprint” incl. main pipeline & road, burrow 5,000-7,000 acres depending on finalsites, other disturbances designsTotal “Sphere of Influence” 150,000—300,000 acresNOTE” The assumptions in this table are OTA’s but have been reviewed by several industry and government participants in

our workshops. While small changes have been suggested, the reviewers generally agree that the numbers are reasonable

SOURCE Off Ice of Technology Assessment

Development

The OTA assumption of peak production ratefor the two fields and the total number of wellsand well pads roughly corresponds to the ARCOdata except that the assumed production rates(as a ratio of recoverable reserves) are somewhatlower. Production rates can be highly variabledepending on the actual characteristics of thefields. However, even the OTA numbers cor-respond to some of the highest production ratesfrom other North Slope fields. For example, dis-covery #1 is about one-third the size of the Prud-hoe Bay field with about half the production rate.It is also about twice the size of the Kuparuk fieldwith about 2.5 times the production rate.Hypothetical discovery #2, on the other hand, isroughly equivalent to the Endicott field whichcame on-line in 1987.

OTA’s assumptions about production facilitiesare based on both the ARCO scenario and the ex-isting developments at Kuparuk and Endicott. A

central industrial facility for the entire ANWRcoastal plain would follow the Kuparuk modeleven though ANWR is somewhat more remotefrom the other components of the Prudhoe sup-port network. This comparative isolation wouldprobably mean that ANWR would need a largerindustrial facility than Kuparuk. Productionfacilities, airfields, ports, and seawater treatmentplants would be similar to those at Kuparuk fordiscovery #1 and at Endicott for discovery #2.The assumed oil transport pipeline is similar toboth the LEIS and ARCO scenarios.

OTA assumptions about gravel pads and roadacreage are derived from the LEIS estimates foreach field but include neither the main pipeline orroad to TAPS nor the other areas of disturbanceto the land surface, such as gravel pits. Theseassumptions, in turn, are all included in the es-timate of total “footprint” to be expected from thefirst development of both hypothetical fields. Theprojected total “footprint” –area of direct physi-cal coverage –was derived from individual area

Figure 2.1 1.—OTA MNWR Development Scenario

o

estimates, but the high end also corresponds tothe ARCO estimate of 11 square miles as the totalarea affected by development.

Finally, OTA made a rough estimate of the total“sphere of influence” to be expected from fulldevelopment activities. The notion of a sphere ofinfluence appears in the LEIS as that area sur-rounding a facility or activity where certainwildlife species potentially would be affected.The actual extent of this sphere of influencewould vary depending on the species, andspecific impacts are not always quantified. Thisestimated sphere of influence corresponds, onthe high side, to an estimate in the LEIS based onan influence zone of about 3 kilometers aroundall facilities, pads, pipelines, roads, etc. Theupper estimate probably would be relevant onlyfor the more sensitive species. The lower es-timate corresponds to the total acreage enclosedby the two hypothetical fields in the scenario. Inany case, the total area of 150,000 to 300,000acres assumed in the OTA scenario could be aconsiderable portion of available habitat for anumber of species.

OTA’s estimates are only for initial developmentof the two hypothetical ANWR fields. Based onexperience in all of the other developed NorthSlope oilfields, it is likely that, after the ANWRfields are producing, a series of modifications willbe made. Such activities would include routine

maintenance, upgrading, and improvement inrecovery and production to extend the life of thefield, plus well workovers, infill drilling, addition ofsecondary and tertiary recovery techniques, andmany others. Experience at Prudhoe Bay hasshown about a 50-percent increase in thecoverage of tundra by gravel roads, pipelines,and facility pads from the time of initial produc-tion start-up in 1977 through 1988. Experience atKuparuk is following the same pattern.

The above scenario for ANWR development canbe used to project possible changes to the coastalplain environment that may result. It is clear that thechanges could be substantial, to some extent, af-fecting hundreds of thousands of acres and sup-porting considerable human and mechanicalactivity for several decades, and that environmentalprotection issues would continue to be contentiousshould such development proceed. The four keyprincipal environmental concerns–physical landdisturbance, gravel mining and construction, wastemanagement, and fresh water supply–that arelisted at the beginning of this chapter, appear to beof continual future concern. OTA has notedindustry’s approach to addressing these issues andthe fact that many environmental critics believe theindustry’s approach to be inadequate. Further en-vironmental assessment is probably needed, mostimportantly in the above four areas, to evaluate theeffectiveness and adequacy of these approaches.

Chapter 3

Oil and Gas Production onthe North Slope of Alaska

ContentsIntroduction . . . .

Oil Production FromResource Terms . . . . . . . . .In-place Resources of Known FieldsProduction Constraints . . . . . . .Reserves and Production . . . . . .Significant North Slope Oilfields . .

Technologies for Improved Recovery . .Summary . . . . . . . . . . . . . .

Oil Production From Undiscovered Resources .Estimates for the North Slope . . . . . . .Estimates for ANWR . . .

Oil Industry Cost-Cutting and the

. . . . . * * * .

Effect on Oilfield Development

71

737374757 779

91

949597

. * 100

Chapter 3Oil and Gas Production onthe North Slope of Alaska

INTRODUCTION

The U.S. oil industry and the U.S. Departmentof the Interior (DOI) contend that unless oil leas-ing is allowed in the Arctic National WildlifeRefuge (ANWR) and significant quantities of oilare found there, North Slope oil production willsoon begin to decline, and that with a decline theUnited States will become ever more dependenton oil imports.

To examine this contention, OTA investigatedthe status of current production on the NorthSlope and the potential for additional oilfielddevelopment there. In particular, OTA assessedreserves and/or in-place resources in all provenand developed North Slope fields and in knownbut undeveloped fields where public informationis available; assessed what additional productionmight be expected from these fields in the futureas technology improves and/or if additional en-hanced oil recovery (EOR) technology is in-stalled; and examined what the contribution toNorth Slope production from as yet undiscoveredonshore and offshore oilfields might be.

Long-term oil production forecasts for theNonth Slope or, for that matter, for any large areaof the United States, are at best gross approxima-tions. Oil forecasts make assumptions about fu-ture oil prices, technological developments,environmental requirements, tax and royaltyrates, and other variables. Also, forecastsproject the success of drilling and other fielddevelopment activities in areas in which geologicdata are often sparse. Finally, forecasts make as-sumptions about future business strategies, yetcompany strategies are almost always confiden-tial and, at the same time, subject to change.Consequently, OTA focused its efforts on deter-mining the general production potential of theknown fields on the Slope, and on asking thequestion, “if oil production from the North Slope

is not going to decline drastically, where willadded production come from?”

We concluded that, although small quantities ofadditional reserves can be expected fromdeveloped, undeveloped, and as yet undis-covered fields on the North Slope, there is nolikely source of additional reserves that is largeenough to stem a production decline. Thus,North Slope production is likely to begin declin-ing around 1990 – the expected onset of PrudhoeBay decline–or shortly thereafter. Although thediscovery of another Prudhoe Bay-size field inANWR or elsewhere on the North Slope will helpreverse this trend, a field discovered in 1988would not likely be brought into productionbefore 1998.

As of early 1988, four major oilfields wereproducing oil in the North Slope of Alaska: Prud-hoe Bay, Kuparuk, Lisburne, and Endicott (seeFigure 3-l). A fifth field, Milne Point, is developedbut not currently producing. In addition to thesefive oilfields, a number of fields have been dis-covered but are not yet developed. There are im-portant reasons these other North Slope fieldsare not yet producing: some may not yet havebeen sufficiently delineated to determine whetherthey would be economic to produce; many aretoo small and/or too far from the Trans AlaskaPipeline System (TAPS) to be economicallyproducible at current market prices; some mayhave reservoir characteristics that make produc-tion difficult and/or prohibitively expensive; andoffshore discoveries in more than a few feet ofwater are currently too expensive to develop andproduce. Finally, although many of the bestprospects have been tested, only a relativelysmall portion of the North Slope of Alaska – on-shore or offshore – has been explored forhydrocarbons. How much remains to be found issubject to much speculation.

71

72 ● ANWR

Chapter 3 ● 73

OIL PRODUCTION FROM KNOWN FIELDS

Resource Terms

The total amount of oil in known fields on theNorth Slope is called “in-place” resources. Theamount of in-place oil in known fields that has notyet been extracted is considerable, but only aportion of it is currently economically and techni-cally producible. The amount of in-place re-sources that geological and engineering studieshave shown to be recoverable under currenteconomic conditions using existing technologyare known as “proved” or “existing” reserves.“Inferred” or “potential” reserves are thoseresources that should eventually be added toproved reserves through extensions of knownfields, through revisions of earlier reserve es-timates based on new subsurface and productioninformation, and through production from newproducing zones in known fields. 2 The applica-tion of new recovery technology (e. g., enhancedoil recovery [EOR] methods) may also result inadd i t i ona l p roved reserves . The term“recoverable” resources is less precise but fre-quently used. The amount specified by the termis sensitive to changing economic conditions and

in this study refers to the sum of proved andpotential reserves.

Estimates of in-place and recoverable resour-ces can be made using very little data; of course,the more data available, the more accurate theestimates can be (See Box 3-A). Reserves, on theother hand, are based on drilling results and en-gineering measurements. Estimates of in-placeresources in known fields are ideally based onknowledge of the size of the reservoir; porosity ofthe reservoir rock; reservoir pressure, tempera-ture, and as/oil ratio; and amount of water

3saturation. Recoverable resource estimates usethe same type of information, but in addition theygenerally require information or assumptionsabout permeability and oil viscosity, which helpreservoir engineers determine the degree towhich in-place oil is capable of flowing to awellhead. Recoverable resource estimates alsoincorporate assumptions about the expectedselling price of oil and the technology used toproduce it. Reserve estimates require more ex-tensive resetvoir and producibility informationand assume production at current market pricesand the use of existing technology.

BOX 3-AA CAVEAT

Resource estimation is as much art as science, and numerous pitfalls make accurate estimatesdifficult. Two typical shortcomings of most estimation techniques are limited availability of dataand the need to use simplifying assumptions to make estimates. This situation is why most es-timates risk input parameters and report probability distributions. Some of the problems en-countered in efforts to estimate North Slope resources are considered in more detail in AppendixA. Often, the assumptions –e.g., oil price or state-of-the-art of technology–on which North Sloperesource estimates have been based are not specified or are vague. Although OTA considers thedata in this report to be the best data currently available to the public, often there was no compell-ing reason to select one source of information over another. All resource data in this report shouldbe viewed skeptically and with knowledge of the limitations of resource estimation techniques.

1. Joseph P. Riva, Jr., World Petroleum Resources and Reserves (Boulder, Colorado: Westview Press, 1983), Chapter 5, “Resewes,Resources, and Resewes/Production Ratios,” p. 124.

2. Ibid,, p. 126.3. Ibid.

74 ● A N W R

In-Place Resources ofKnown Fields

Despite the pitfalls of resource estimation (seeAppendix A), the quantity of in-place oil in thedeveloped North Slope fields is reasonably wellknown from extensive drilling (Table 3-1 ).Remaining in-place resources in the fivedeveloped North Slope fields as of September1987 are estimated to be about 25 billion barrels.In-place resources of all known North Slopefields may total more than 50 billion barrels.More important is the amount of these in-placeresources that is expected to be ultimatelyrecoverable. For the North Slope overall, therecovery efficiency of in-place oil in developedand undeveloped fields is approximately 26 per-cent.4 However, recovery efficiencies of in-dividual North Slope fields may vary from Opercent to perhaps as high as 50 percent,depending on reservoir and fluid characteristics.Resources in some major undeveloped NorthSlope fields will not be economic to produce un-

Table 3-1 .—Minimum Remaining In”Place Oil of MajorNorth Slope Fields As of September 1987

Billion barrels(rounded)

Proven and developedEndicott . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Kuparuk River . . . . . . . . . . . . . . . . . . . . . . . . . . 4Lisburne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Milne Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Prudhoe Bay . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Discovered but undevelopedPoint Thomson (gas condensate) . . . . . . . . . 1Seal Island . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Ugnu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6West Sak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Other North Slope . . . . . . . . . . . . . . . . . . . . 2

Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50SOURCES Bureau of Land Management, Anchorage, Alaska, Alaska Department

of Natural Resources, Division of 011 and Gas, Institute for Social andEconomic Research, University of Alaska

less oil prices rise substantially and/or unlessnew, less expensive or more efficient productiontechnologies are developed.

Estimates of in-place resources of known but asyet undeveloped oilfields on the North Slope aremore provisional than those for the fivedeveloped fields, and estimates for some dis-coveries may not yet have been released. Un-developed oil and gas discoveries on the NorthSlope include the West Sak and Ugnu fields; theSeal Island and Tern Island discoveries; and theColville Delta, Gwydyr Bay, Niakuk, Umiat, Kavik,Kemik, and Point Thomson fields (Figure 3-l).Only two of these fields are believed to containsignificant in-place resources, and even thesetwo are unlikely to contribute significantly to theNorth Slope production total in the foreseeablefuture. Many discoveries are either too small ortoo far from TAPS or both to be economicallyproducible at this time.

The West Sak and Ugnu reservoirs, both ofwhich generally overlie the Kuparuk River reser-voir, deserve special attention due to their hugeestimated in-place resources. West Sak containsbetween 15 billion and 25 billion barrels of oil in-place. ARCO has proved the technical feasibilityof producing West Sak oil with existing technol-ogy, but the reservoir and oil characteristics(e.g., high oil viscosity, low temperature, shallowdepth, complex structure) indicate that recoverywill be less than 5 percent of the in-place oil if thefield is fully developed using current technology.It appears that some production of West Sak maytake place if and when oil prices rise (and stabi-lize) above $20 per barrel. The Ugnu field con-tains between 6 billion and 11 billion barrels ofin-place resources, 5 but the cost and difficulty ofrecovery of Ugnu oil will be much greater than forWest Sak oil. Thermal stimulation through thepermafrost probably would be required toproduce the very heavy Ugnu oil, but this tech-nique is likely to be impractical and prohibitivelyexpensive on the North Slope for the foreseeablefuture.

4. U.S. Department of Enery, Energy Information Administration,B

“Potential Oil Production From the ~astal Piain of the &cticNational VVlldhfe Refuge,” OctO er 1987, p. 18.

5. W.W. Barnwell and K.S. Pearson, AJaska’s Resourm Inventory 1984, Special Report 36 (Fairbanks, AK: State of AlaskaDepartment of Natural Resouroes, Division of Geological and Geophysical Surveys, 1984), p. 9.

Chapter 3 ● 75

Significant gas resources are also found inNorth Slope fields (Table 3-2). Prudhoe Bayalone contains at least 23 trillion cubic feet of gasconsidered ultimately recoverable. The distancefrom U.S. markets and the consequent high costof building a transportation system for NorthSlope gas, however, makes it uncompetitive atcurrent gas prices (and at prices correspondingto DOI’s oil price scenarios for ANWR develop-ment). Neither the proposed Alaska Natural GasTransportation System nor the competing Trans-Alaska Gas System has secured constructionfinancing or a guaranteed market for the gas itwould carry. The Reagan Administration recentlydetermined, however, that North Slope gas couldbe exported, a finding that may ultimately give aboost to development of North Slope gas, per-haps in the form of Liquefied Natural Gas toJapan. Most of the gas produced at PrudhoeBay and other North Slope fields is currently rein-fected to help maintain reservoir pressure or isused in miscible fluid recovery operations. Somegas is used to operate North Slope facilities.More of this gas may eventually be used on theNorth Slope to provide the energy required toproduce such heavy oilfields as West Sak.

Table 3-2 .—Estimated Recoverable Gas in KnownNorth Slope Fields

Billion cubic feet

Endicott . . . . . . . . . . 800Kuparuk River ., . . . . . . . . . . . . . . 600Lisburne . . . . . . . . . . . . . . . . . . . . 900Point Thomson . . . . . . . . . . . 5,000a

Prudhoe Bay . . . . . . . . . . . . . . . . . . 23,000

Total . . . . . . . . . . . . 30,300aNo 011 or gas IS currently being produced from the Point Thomson field Thecost to develop Point Thomson’s gas resources would be greater than the costto develop gas resources in fields already producing 011 Hence, higher gas priceswould be needed to develop Point Thomson unless the gas resources were developed in conjunction with the gas condensate and NGLs in the reservoir

SOURCES Alaska Department of Natural Resources, Division of 011 and Gas,Standard Alaska Product Ion Co

Production Constraints

For a number of reasons, oil production on theNorth Slope of Alaska is more difficult thanproduction in the Lower 48 States. Factors af-fecting production include the harsh Arcticclimate, lack of infrastructure, and great distancefrom supply sources and markets. The harshclimate of the Arctic is characterized by very lowaverage and absolute temperatures, frequenthigh winds, and periods of dense fog. Precipita-tion is low, but snow cover lasts for 8 months ormore each year, and blowing snow is common.Low temperatures give rise to permafrost, whichmay extend 2,000 or more feet below the landsurface or seabed, and to sea ice, which can at-tain average thicknesses of 7 feet or more andpersist for as much as 10 months per year in theBeaufort Sea.

Ice affects all aspects of oil activity. On land,the presence of permafrost requires use of spe-cial design and construction practices. For in-stance, well casing must be designed towithstand thaw subsidence stresses that mayoccur when warm oil flows through the welltubing. Also, all pads and roads must be con-structed of gravel about 5 feet thick. Offshore,landfast and moving sea ice, pressure ridges,and other ice phenomena cause problems andadded expense for transportation, exploration,and production. All offshore structures must bedesigned to be able to withstand ice forces.6

Lack of infrastructure in the Arctic is another im-portant factor affecting the cost and difficulty ofNorth Slope production. Before Prudhoe Baywas developed, there were no roads, pipelines,or ports on the North Slope and no housing foroilfield workers. Beyond the immediate vicinity ofPrudhoe Bay and Kuparuk, this is still the case–for instance, in both the National PetroleumReserve in Alaska and the Arctic National WildlifeRefuge. Except insofar as development of newfields can take advantage of the infrastructurenow in place in the Prudhoe Bay area – more dif-ficult to do as the distance from Prudhoe Baygrows–each new development on the North

6. See the Office of Technology Assessment’s study, Oil and Gas Technologies for the Arctic and Deepwater, Chapter 3,“Technologies for Arctic and Deepwater Areas” (Washington, DC: Government Printing Office, May 1985).

76 ● ANWR

Slope must be built from scratch. There are nomajor fabrication facilities on the North Slope, sooil production facilities must be prefabricated inthe Lower 48 or overseas and barged northduring the summer months or trucked overland.Moreover, except for the few Native North SlopeInuit who work for the oil companies, oilfieldworkers do not live permanently in the Arctic butare shuttled back and forth on a weekiy or bi-weekly basis between the North Slope and loca-tions either in southern Alaska or– less commonnow–the Lower 48.

Oilfields close to Prudhoe Bay will be able toconnect directly to the Trans Alaska Pipeline Sys-tem; however, as a field’s distance from thepipeline terminus at Pump Station #1 increases,the cost of constructing a connecting pipeline in-creases. Beyond a certain distance, it may notbe economically feasible to construct a small-diameter pipeline connecting with TAPS, andother transportation alternatives will need to beconsidered. The use of ice-strengthenedtankers, for instance, has been considered fortransporting any oil found beneath the ChukchiSea, off Alaska’s northwestern coast. Forproducing oil from offshore fields, pipelines musteither be buried below the depth of sea ice scouror mounted on expensive and environmentallycontroversial causeways.

These production constraints – isolation, lack ofinfrastructure, and harsh climate–are all impor-tant reasons why the minimum economic fieldsize (MEFS) required for development increasesgreatly with increasing distance from PrudhoeBay. The other significant determinant of theMEFS is the price of oil. The Seal Island dis-covery is only 12 miles from Prudhoe Bay, but,given its offshore location in 39 feet of water, it isnot economic at current market prices– eventhough its recoverable reserves are estimated tobe at least 300 million barrels. The areawideMEFS for onshore ANWR development is es-timated by the Department of the Interior to be

440 million barrels, given a market price of $33per barrel of North Slope oil (1984 dollars) in theyear 2000. If oil prices are significantly lowerthan this in 2000 (e.g., at $20 per barrel in 1984dollars) and costs remain the same, the MEFS forANWR could easily surpass 1.5 billion barrels, as-suming that the calculation of the MEFS forANWR is correct (OTA has some doubts aboutthis calculation; see Box 3-B on page 104). 7 A tdistances even further from Prudhoe Bay, in theChukchi Sea for instance, the MEFS could con-ceivably be 2 billion barrels or more.

The cost to transport oil from remote NorthSlope fields to Pump Station #1 and from thispoint to market is an important factor in determin-ing the MEFS. Total transportation costsaveraged about $6 per barrel to transport oil fromPump Station #1 to southern markets in 1987.This oil must travel 800 miles south through theTrans Alaska Pipeline, where it is loaded ontotankers at Valdez and shipped either to the WestCoast of the United States or to the U.S. GulfCoast (after being off-loaded on the Pacific sideof the Isthmus of Panama, piped across theIsthmus, and reloaded onto other tankers). If themarket price of this delivered North Slope oil isnear $17, as it was in January 1988, supplierswould be able to charge $11 at Pump Station #1.The price at the wellhead – given that there is acharge for transporting oil from the wellhead toPump Station #1 –would be even less. For in-stance, the Milne Point wellhead price would be$7.70, the Endicott price $9.25, the Kuparuk price$9.61, the prudhoe Bay price $11.00, and the Lis-burne price $11.10. For the 6-month period ofSeptember 1987 through Februaty 1988, com-posite wellhead prices for the North Slopedecreased from $13.00 to $9.40 per barrel for 27o

API crude oil.a From per-barrel prices must besubtracted per-barrel capital and operating ex-penses, taxes, royalties, and the like. Clearly,some of the North Slope producers are operatingon a thin profit margin at current market prices.Evidence of this is that the Milne Point field hasbeen shut down since January 1987.

7. U.S. De artment of the Interior, Arctic National Wildlife Refuge, Alaska, Coastal Plain Resouroe Assessment, final LegislativerEnvironment Impact Statement, April 1987, p. 79.

8. Alaska Department of Natural Resources data reported by the Oil and Gas Journal.

Reserves and Production

Total oil reserves as of January 1988 fromproven and developed fields on the North Slopeof Alaska are estimated by the Alaska Depart-ment of Natural Resources (DNR), Division of Oiland Gas, to be between 5.25 and 8.22 billion bar-rels with a mid-range estimate of oil reserves ofabout 6.5 billion barrels (Table 3-3).9 This rangebrackets most other estimates that have beenmade. Total reserves are sensitive to the price ofoil. With low prices, it may not be economical tocontinue infill drilling beyond a certain point, andthe use of EOR techniques may not be economi-cally justified. As prices rise, oil companies areable and willing to expend more money to extractadditional oil by implementing EOR techniquesand by increasing infill drilling.

Table 3-3. —Estimated Remaining Recoverable OilAs of January 1, 1988 (millions of barrels)

.Mid

Low $18-$202 High<$15’ (1987 $) <$24 3

Proven and developedEndicott . . . . . . . . . 2704 370 445Kuparuk River . . . . 600 900 1,100Lisburne . . . . . . . . 280 380 580Milne Point. . . . . . . . . . . . . . . . . . 0 60 955Prudhoe Bay . . . . . . . . . . . . . . . 4,100 4,800 6,000

Subtotal . . . . . . . . . . . . . 5,250 6,510 8,220

Discovered but undevelopedGwydyr Bay . . . . . . . . . . . . . . . . . 0 0 10Niakuk. . . . . . . . . . . . . . . . . . . . . O 55 75Point Thomson ... . . . . . . 0 0 3506

Seal Island . . . . . . . . . . . . 0 0 300West Sak7 . . . . . . . . . . . . . . . . . 0 500 1,500

Subtotal . . . . . . . . . . . . . . . . . . 0 555 2,235

T o t a l . . . . . . . . . . . . . . . . . . . 5 , 2 5 0 7,065 10,455‘All low estimates assume infill drilling will be less than the number of wellsforecast for the midrange estimate

‘All mid. range estimates assume that existing technology IS used, that no newenhanced 011 recovery operations are implemented, and that reservoirs performas expected

‘Al I estimates assume more In fill than for the mid. range forecast and that addi-tional secondary recovery and/or EOR IS implemented and successful

‘Also assumes waterflood is not successful‘Al so assumes Cretaceus sands are developed‘Prlmarlly gas condensate This Is a natural gas reservoir with 5-trillion cubic feetof recoverable gas and a thin “rim” of underlying crude 011

‘Also assumes operating agreement signed

SOURCES Alaska Department of Natural Resources, Division of Oil and Gas;West Sak estimate from ARCO Alaska, Inc.. Niakuk estimate basedOn discussion with Standard Alaska Production Co officials

The difference between the high and low es-timates in Table 3-3 is accounted for largely bydifferent assumptions about price, success ofEOR operations, and amount of infill drilling likelyto be done. The low estimate assumes that oilprices are less than or equal to $15 per barrel (in1987 dollars) and that infill drilling is less than ex-pected by DNR for the mid-range estimate. Themid-range estimate assumes that oil prices are$18 to $20 per barrel, that existing technology isused, that no new enhanced oil recovery opera-tions are implemented, and that reservoirs per-form as expected. The high-range estimatemight be reached if oil prices rise above $24 perbarrel and if additional EOR operations are imple-mented and successful.

If the high-range price assumption is realized,the Division of Oil and Gas also expects addition-al oil recovery from discovered but as yet un-developed North Slope fields, principally theWest Sak, Point Thomson, Seal Island, Niakuk,Colville Delta, and Gwydyr Bay fields (Table 3-3).The West Sak field has the potential to contributethe most additional oil from known but un-developed fields, but there is a wide range ofopinion about the amount of oil ultimatelyrecoverable from West Sak. The current ARCOestimate of West Sak’s recoverable reserves ismuch lower than the Division of Oil and Gas es-timate.

While there are large amounts of oil in theground on the North Slope, most of the reservesin producing fields are located in the PrudhoeBay and Kuparuk River fields. Currently, TAPS isrunning at just about full capacity with oil fromthe Prudhoe Bay, Kuparuk River, Lisburne, andEndicott fields. As of spring 1988, the pipelinecan carry a maximum of 2.2 million barrels of oilper day, although this capacity could be in-creased somewhat by installing additional pumpsand/or by adding more friction-reducing addi-tives. About 1.55 million barrels per day areproduced from Prudhoe Bay, 300,000 fromKuparuk River, 100,000 from Endicott, and about50,000 from Lisburne, a total of about 2.0 millionbarrels, comprising roughly 24 percent of thedaily U.S. domestic oil supply.

9. William Van Dyke, Alaska Department of Natural Resources, Division of Oil and Gas, personal communication, January 1988.

78 ● ANWR

According to current estimates, North Slopeproduction may begin declining sometimearound 1990 (Table 3-4). Some believe thisforecast of decline in 1990 is unduly pessimistic,given that estimates of the onset of decline havebeen revised several times in the past and thatthe impact of technological improvements can-not be entirely foreseen. Whatever the exact dateof the onset of decline, Prudhoe Bay, whoseproduction dominates that of other fields (in 1986it accounted for 82.8 percent of Alaska’s produc-tion), is now considered a mature field, andproduction there must soon begin to slow. Someof the smaller North Slope fields will also begin todecline in the next few years. By 2000, TAPSthroughput is expected to be at best 50 percentof current throughput, even with incremental ad-ditions from currently planned EOR operations inexisting fields and from possible production inseveral new fields (Figure 3-2). Production couldbe as low as 25 percent of current throughput by2000 if low-range reserve estimates prove moreaccurate.

Table 3-4.—Projected TAPS Throughput(thousand barrels per day)

Year Maximum Minimum1987 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,908 1,9081988 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,024 2,0241989 . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,040 2,0301990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,033 1,9681991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,891 1,7761992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,735 1,5651993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,591 1,3711994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,430 1,1821995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,317 9911996 ... , . . . . . . . . . . . . . . . . . . . . . . . 1,233 8631997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,176 7361998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,110 6251999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,013 5332000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 931 4532001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 857 3852002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 789 3272003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 726 278

Total . . . . . . . . . . . . . . . . . . . . . . . . . . 23,804 19,015SOURCE Alaska Department of Natural Resources, Division of Oil and Gas

(19871999), consensus from OTA workshop (2000.2003).

Production forecasts have been made by theEnergy Information Administration, the AlaskaDepartment of Natural Resources, the AlaskaDepartment of Revenue, and others. The datapresented in Table 3-4 and Figure 3-2 w a srecently compiled by the Alaska Department ofNatural Resources, but it is representative ofother forecasts as well. Most of the differencebetween the maximum and minimum North Slopeproduction profiles depends on whether or notMilne Point is restarted and Niakuk, West Sak,Gwydyr Bay, Seal Island, and Colville Delta aredeveloped in the early 1990s. Starting produc-tion at these fields depends on the price of oil,but it is impossible to specify the exact price atwhich each field would be developed. MilnePoint–currently shut-in due to low oil prices–may be producing again shortly, and Niakuk issaid to be commercial at current oil prices, butthe other fields probably will not be developeduntil the price of oil rises and stabilizes in the areaof $24 per barrel. Recent strides incest controlcould conceivably lower the breakeven price forproduction from these fields, and recent remarksby ARCO Alaska, Inc. suggest that breakevenprices have indeed come down.10

Figure 3-2.-Projected TAPS ThroughputMillion Barrels Per Day

Mill Ion barrels per day

2.5

2

1 5

1

0 5

0

10. ARCO Alaska, Inc., “Security Analyst Meeting,” Mar. 30, 1988. ARCO notes that “the majority of capital associated with theexploration program and development of exploration successes is viable in the $15 to $25 a barrel range, ” p. 29.

Chapter 3 ● 79

Significant North Slope Oilfields

All oilfields are different, not only in their loca-tion, size, structure, and other reservoir charac-teristics, but also in their response to EORstimulation, their production profiles, and therecovery expected from each.

Prudhoe Bay

Prudhoe Bay is the largest oilfield in the UnitedStates and the 18th largest in the world. It is es-timated to have had original recoverable oil of 10billion to 12 billion barrels. Of this amount, 4 bil-lion to 6 billion barrels remain. The lower figurefor Prudhoe Bay’s remaining recoverable oil in-cludes oil recovered using primary and currentlyin-place waterflood and miscible fluid recoverytechnologies. The higher, more optimistic figureassumes the success of enhanced oil recoveryprojects that could begin in the future, more infilldrilling, and a gradual rise in the price of oil.

Prudhoe Bay oil has a large gas cap and is con-tained in a high-quality, well managed reservoir,as is reflected by its relatively high estimatedrecovery factor. Approximately 45 percent oforiginal in-place resources are expected to berecovered. The principal producing formation ofthe Prudhoe Bay field is the Ivashak Sandstone ofthe Sadlerochit Group. This sandstone consistsprimarily of two fine- to medium-grained pebblysandstone sequences separated by an intervaldominated by massive conglomerates. Thedepth of producing zones is between 8,000 and9,000 feet.

To stimulate additional recovery at the PrudhoeBay field, waterflooding (injection of water intothe reservoir to drive additional oil to producingwells) began in 1984. With this technique, fieldoperators expect to recover 1 billion more barrels

of oil than would otherwise have been possible(included In the above estimate of recoverableoil). In addition, Prudhoe’s miscible fluid opera-tion began in December 1986 with the installationof the world’s largest natural gas plant. Thefacility produces miscible injectant (Ml–a mix-ture of natural gas and natural gas liquids; seeTechnologies for Improved Recovery later in thischapter) from raw plant feed gas stripped fromwell fluids. The Ml is injected into the reservoirwith alternate injections of water to stimulate ad-ditional oil recovery. The operation also current-ly produces 50,000 barrels per day of natural gasliquids which are blended into the crude oil

11 Remaining residue gas is -

stream in TAPS.jected into the reservoir to maintain gas cap pres-sure. The operators estimate that the project willallow 5 percent additional oil recovery beyondthe waterflood operation for that part of the reser-voir affected by the EOR project, or an additional

1 2 p l u s r e c o v e r y ‘f a t115 million barrels of oil,least 500 million barrels of natural gas liquids(both additions have been included in the aboveestimate). Also, the facility establishes a largepart of the infrastructure that will be needed toproceed with any future large-scale gas sales orexpanded gas cycling projects.13

Infill drilling in some portions of the field is con-tinuing at an 80-acre spacing intetval; 40-acrespacing is likely to begin soon14, which mayenable recovery of up to 100 million barrels of ad-ditional oil. However, infill drilling is probablymore important for maintaining or increasing theproduction rate of fields than for adding reserves.The total number of wells in the Prudhoe Bayfield, when fully developed, is expected to beabout 1200. Incremental reserves also might beadded by expanding the waterflooding operationand/or by expanding the miscible floodingproject. Installation of additional gas handlingcapability would allow greater short-term produc-tion levels–since production is constrained by

11. “World’s Biggest Gas Plant Operating on North Slope,” Oil and Gas Journal, Jan. 26, 1967, p. 26.12. Matthew Berman, Susan Fison, Arlon Tussing, and Samuel Van Vactor, Report on Alaska Benefits and Costs of Exporting Alaska

North Slope Crude Oil, for the Alaska State Senate Finance Committee, May 1987, p. A-23.13. Alaska Department of Oil and Gas, Division of Oil and Gas, Historical and Projected Oil and Gas Consumption, January 1966,

p. 6.14, Optimal spacing of wells is determined by balancing expected recovery with the costs to drill additional wells. on the North

Slope, Wacre spacing is typical. In the Lower 46, 40-acre spacing is standard, but even $acre spacing is not uncommon.

the operator’s ability to handle gas produced withthe oil– but would not significantly change re-serves.

The West End/Eileen area of Prudhoe Bay is ex-pected to begin producing in 1988 and will in-clude gas injection facilit ies for pressuremaintenance. There are believed to be about 500million barrels of oil in place in this area, of whichabout 150 mill ion barrels are consideredrecoverable. Production from this portion of thePrudhoe Bay field is expected to peak at 60,000to 70,000 barrels per day.15

Eventually, more resources also might berecovered in the peripheral area of the PrudhoeBay field. In the past, operators assumed thatproduction of the Prudhoe oil column was limitedto areas where “pay” thicknesses are greaterthan 100 feet. However, production of the“wedge” zone at the edges of the field usinghorizontal drilling techniques may yield more oil.This relatively thin zone would not be economicto produce with vertical wells, but horizontal wellsallow much more of the formation to be open tothe borehole. 16 ARCO notes that development ‘f

potential reserves (e.g., Prudhoe Bay’s Hurl Stateand Kuparuk Sand areas, as well as wedge areas)is partially dependent on State severence taxconsiderations. Under current Alaskan law, oilfrom marginal fields is taxed at a lower rate thanproduction from more productive fields, thusenabling development of some marginal fields tobe economically justified. 17

Industry and government sources now predictthat Prudhoe Bay production will begin to declinein late 1989 or sometime in 1990 (initially thedecline was expected sometime in 1987) (Figure3-3). The actual date will depend on the level ofinfill development drilling, scheduling of wellworkovers, water and rich gas injection rates,and the capabilities of the installed and to-be-in-

18 pruhoe's gas-oilstalled gas handling facilities.and water-oil ratios will continue to increase as itsoil is produced. When limits on handling gas andwater are reached and additional gas and waterinjection can no longer be done economically,decline will set in. When the Prudhoe Bay fieldbegins to decline, the rate is expected to beabout 10 to 12 percent per year.19 Such a declinerate is typical of most large oilfields that are sub-jected to pressure maintenance operations.

Kuparuk River

Production of the Kuparuk River field, locatedabout 40 miles west of Prudhoe Bay, com-menced in December 1981. Remaining reservesrecoverable with primary and existing waterfloodtechnology were estimated to be slightly over 1billion barrels as of September 1987. Production,which is now between 290,000 and 300,000 bar-rels of oil per day, second in the United Statesonly to Prodhoe Bay’s, is expected to begin agradual decline to 65,000 barrels per day in 2000

Figure 3-3.-Alaska North SlopeProduction: Prudhoe Bay and Kuparuk

1 5

1

0 5

0

Mill ion barrels per day

1987 1990 1993 1996 1999 2 0 0 2

SOURCES: Alaska Department of Natural Resources, Division of Oil and Gas andAlaska Department of Revenue, November 1987

15. Matthew Berman, Susan Fison, Arlon Tussing, and Samuel Van Vactor, Report on Alaska Benefits and Costs of Exporting AlaskaNorth Slope Crude Oil, for the Alaska State Senate Finanoe Committee, May 1987, p. A-24.

16. J.H, Littleton, “Sohio Studies Extended-Reach Drilling For Prudhoe Bay,” Petroleum Engineer International, Ootober 1985, p.34.

17. H.P. Foster, Senior Vice President, ARCO Alaska, letter to James Eason, Alaska Department of Natural Resources, Division ofOil and Gas, June 25, 1987.

18. Alaska Department of Oil and Gas, Division of Oil and Gas, Historical and Projected Oil and Gas Consumption, January 1988,p. 6-7

19. “Big Prudhoe Bay Field Passes Halfway Mark at 5 Billion BBL,” Oil and Gas Journal, Mar, 30, 1987, p. 40.

Chapter 3 ● 81

(Figure 3-3). Although Kuparuk production is ex-pected to fall off less rapidly than production atPrudhoe Bay, it is only about one-fifth of PrudhoeBay’s production and contributes only about 15percent of TAPS throughput. Remainingrecoverable gas is estimated to be about 525 bil-lion cubic feet.

The Kuparuk River reservoir is not as thick or ofas high quality as the Prudhoe Bay reservoir. Ithas no natural gas cap, and is characterized byfaulting and discontinuities. The field covers 400square miles, of which 200 are currently con-sidered commercially productive. By the end of1986, 300 wells had been drilled, but at least 700wells will be required for full field development.Constant infill drilling will be necessary to retarddecline as long as possible and to tap areasseparated by faults.

ARCO Alaska, the operator, is expanding thewaterflood program and has recently begun apilot miscible gas injection project to boost ul-timate recovery from the reservoir. A thirdcentral production facility was added in 1986,with a reserve addition of 170 million barrels ofoil. 20 A small gas plant in the field currently

produces about 3,700 barrels per day of naturalgas liquids that are blended with the oil and sold.

Lisburne

The Lisburne reservoir lies within the PrudhoeBay Unit but is about 1,000 feet deeper thanPrudhoe Bay’s main reservoir in the Ivishak for-mation. Lisburne and Prudhoe Bay were dis-covered by the same well. Production from thisthird largest North Slope field (in terms of es-timated reserves) began in December 1986.Thus far, production at the Lisburne reservoir hasnot been as good as hoped. Lisburne is anaturally fractured carbonate reservoir, lessporous than the Sadlerochit main producing for-mation at Prudhoe Bay. Lisburne’s fractured na-ture has presented some technical productionproblems. Moreover, at least parts of the forma-tion contain hydrogen sulfide gas which is both

2 1 A l t h o u g h t h e L i s -corrosive and poisonous.burne field originally had about 3 billion barrels ofoil in place, only between 7 percent and 22 per-cent of in-place resources are expected to berecovered from primary production and with EORoperations planned or in place. The small size ofthe Lisburne field compared to Prudhoe Bay, aswell as lower per well production rates, fasterdecline in individual well production rates,greater costs associated with greater drillingdepths, more difficult rock to drill, presence ofhydrogen sulfide gas, etc., make Lisburne some-what of a marginal North Slope field at currentmarket prices.

Recoverable resources as of January 1988were estimated by DNR to be between 280 millionand 580 million barrels, but operators have notedthat, due to the fracturing, it is very difficult to es-timate reserves accurately in the Lisburne fieldwithout substantial additional drilling. Reservesof this size would be considered substantial in theLower 48; however, on the North Slope, Lisburneis only marginally economic. Lisburne’s earlydevelopment was helped by its proximity to TAPSand to the infrastructure already in place at Prud-hoe Bay. If current lower oil prices had been an-ticipated, Lisburne might not have beendeveloped when it was. A similar size and type offield 100 miles from the pipeline probably wouldnot be economic to develop at the present time.

Lisburne production was initially expected topeak in the mid-1990s at between 80,000 and100,000 barrels per day. A revised estimate,which takes into account the difficulties inproducing Lisburne, calls for peak production ofonl 50,000 to 60,000 barrels per day (Figure 3-4). 22 Production of between 45,000 and 60,000barrels per day is expected to continue throughthe mid-1990s.

The Lisburne field includes both onshore andoffshore areas. Proposed offshore site construc-tion, however, has been canceled. Most of theoffshore oil in the Lisburne field can be reachedby directional drilling from shore, and ARCO

20. ARCO, Oil lndust~ Analysts Meeting, New York City, March 31, 1987, p. 13.21. M. Harris, “Marginal Fields: Minimizing the Risk, ” Alaska Construction and Oil, July 1985, p. 15.22. Alaska Oil and Gas Conservation Commission, personal communication, December 1987.

Figure 3-4.-Alaska North SlopeProduction: Lisburne

Thousand barrels per dav

100

80

60

40

20

01987 1990 1993 1996 1999 2 0 0 2

L l s b u r n e

SOURCES: Alaska Department of Natural Resources, Dwision of Oil and Gas,November 1987; ARCO Alaska, May 1988

believes it can get to the top of the gas cap–theoptimum location for reinfecting gas– by drillingwells with large horizontal offsets from shore.Directional drilling is not expected to reduce oilrecovery. A separate geologic structure offshore(the Kuparuk River sand play, productive in theKuparuk River oilfield and at Niakuk) with an es-timated 20 million barrels of reserves is acces-sible only from an offshore site.23 Alternatives toexploit this reservoir will have to be developednow that the offshore Lisburne drill site has beencanceled. Ultimate recovery at Lisburne is ex-pected to increase if a pilot waterflood projectnow underway proves to be successful. A smallgas plant in the field currently produces about2,600 barrels per day of natural gas liquids(NGLs), which are blended with the oil and sold.

Endicott

The Endicott field, which began oil productionin October 1987, is the North Slope’s newestdeveloped field. It is distinctive in that it is theNorth Slope’s first offshore producing field. Lo-cated about 15 miles from Prudhoe Bay andabout 2 miles offshore in State waters 8 to 10 feetdeep, the Endicott field is believed to have about

375 million barrels of oil resewes and 800 billioncubic feet of recoverable gas. Approximately 35percent of its in-place oil resources are expectedto be recovered. Production is from the Kekiktukconglomerate formation of Mississippian age andtakes place from an artificial 45-acre mainproduction island and a 10-acre satellite island.A gravel causeway connects both islands withthe shore and provides pipeline and road access.

The Endicott reservoir is similar to PrudhoeBay’s in that it consists of good qualitysandstone-conglomerate and contains a largegas cap. The main producing zone has betterquality rock than does Prudhoe Bay. The con-tinuity and quality of a second producing zoneare still being studied. A significant amount ofgas will be produced with Endicott’s oil; hence,lack of sufficient gas handling capability couldconstrain oil production. Production peaked at115,000 barrels per day in early 1988– equivalentto 5 percent of maximum daily TAPS through-put–and is expected to remain at this level untilthe field begins to decline, estimated to be some-

Figure 3-5.-Alaska North SlopeProduction: Endicott and Milne Point

Thousand barrels per dayA 1 1

1987 1990 1993 1996 1999 2 0 0 2

Mllne Point Endlcott

SOURCE: Alaska Department of Natural Resources, Division of Oil and Gas,November 1987

23. “Arco Eyes Production Start at Lisburne During Me 1986,” Oil and Gas Journal, August 5, 1985, p. 85.

time in 1992 (Figure 3-5). About 2,500 barrels perday of NGLs are produced at Endicott.

Endicott is also of interest because its develop-ment is economic only as a result of intensive ef-forts to trim the high costs of Arctic construction

24 Fields like Endicofl are likely b

and drilling.far more common on the North Slope than Prud-hoe Bay-size fields, and close attention will haveto be paid to keeping development costs down.Endicott developers were able to build upon ex-perience gained at Prudhoe Bay for example,operators found that retrofitting is very expen-sive. Thus, primary and secondary recoverycapabilities have been part of the productionfacilities at Endicott from the outset. Hence,

waterflood, low pressure separation, gas reinjec-tion j and gas lift can begin at Endicott withoutsubstantial additional capital expenditures.

Milne Point

With approximately 60 million barrels of re-serves, Milne Point is the smallest of thedeveloped North Slope fields. Production is fromthe Kuparuk River formation, an extensivelyfaulted sandstone. Milne Point is about 35 milesnorthwest of Prudhoe Bay. Like Lisburne and En-dicott, the proximity of the Trans Alaska Pipelinehas spurred development; however, the amountof oil that Milne Point can contribute to TAPS isrelatively insignificant. The production target for

— . ..

Photo credit American Petroleum Institute

Production facilities at Milne Point. The field is now shut in.

24. Ml. Curtis and D.B. Huxley, “first Arctic Offshore field, Endicott, On Decade-Long Way to Production,” Oil and Gas Journal,June 24, 1985, p. 64.

84 • ANWR

the resewoir is 30,000 barrels per day. If this tar-get is reached, Milne Point will account for 1.5percent of TAPS throughput during its peakproduction period. Currently, the peak produc-tion capacity is 15,000 barrels per day, or onlyhal f the product ion target (Figure 3-5).Waterflooding has been used since inception, butadditional waterflooding and other conventionalengineering will be required to produce all of thefield’s estimated reserves.

Milne Point is the only North Slope field to datethat has been shut down due to low oil prices.The field was shut down in January 1987 after alittle more than one year in operation. However,it is being maintained in a “warm shutdown”mode so operations can resume quickly if oilprices rise. Conoco, the operator, believes thatMilne Point can be economically viable at an oilprice of $22 to $25 per barrel .25

Milne Point has both onshore and submergedtracts. In addition to the 60 million barrel reservewithin the Kuparuk River formation, additional oilmay be recoverable using tertiary recovery tech-niques from the field’s shallower Cretaceussands (identical to the West Sak sands inKuparuk). However, these shallow sands areloosely cemented and contain viscous oil. Tech-niques have not yet been worked out to allow theoperator to maintain economic flow rates. Closerwell spacing will be needed, so the cost ofdeveloping these sands will be higher than thecost to develop the main portion of the field.26

Proven But Undeveloped Fields

The Alaska Department of Natural Resourceshas estimated potential reserves for five provenbut undeveloped North Slope fields: West Sak,Point Thomson/Flaxman Island, Seal ls-land/Northstar, Niakuk, and Gwydyr Bay. DNRestimates that production of some West Sak oilmight begin at oil prices somewhat below $24 per

barrel, but DNR estimates that oil prices will haveto rise to at least $24 per barrel before the otherthree fields will be profitable to develop. Techni-cal innovation may be required in some fields aswell.

West Sak, with estimated in-place resources ofroughly 15 to 25 billion barrels, is potentially themost important of these fields. Between 2 and 5percent of these resources are consideredrecoverable. Approximately 0.5 billion barrelsare likely to be recoverable using technologydeveloped from the West Sak pilot project, and1.5 billion barrels may be recoverable with higheroil prices and using advanced EOR techniques.27

However, both the amount of oil in place and theultimate production potential of this marginal fieldare highly uncertain .28 Ultimate productionpotential may be higher than currently estimated.The West Sak field is at a shallow depth, close toan overlying 1,800-foot-thick layer of permafrost,and has a reservoir temperature of about 70°Fcompared to 195°F for the deeper pay zones inthe Prudhoe Bay field. Temperature affects vis-cosity and the lower temperature West Sak oil isa thick, molasses-like, low-grade crude, whichmakes it much more difficult to produce than thehigher quality, higher temperature oil in the Prud-hoe Bay and Endicott reservoirs. The West Sakreservoir is composed of unconsolidated fine-grained sand that tends to flow into the well borewhen higher flow rates are attempted. 29 St ruc -turally, West Sak is fairiy complex, consisting ofmultiple faults and “finger” sands. There is largevariability in pay zones and fluid propertiesacross the fieid.

The only long-term production tests to date inWest Sak have been in conjunction with a 2-yearpilot project. In all, 14 pilot production and injec-tion wells were drilled to a depth of 4,000 feet.Water for the injection wells was heated and in-jected under high pressure into the formation toincrease the temperature of the oil. The flow ratefor the test wells was only about 1 percent of the

25, M. Harris, “Oil Industry in Transition,” Alaska Construction and Oil, p. 12.28. Matthew Berman, Susan Fkon, Adon Tussing, and Samuel Van Vactor, Report on Alaska Benefits and Costs of Exporting Alaska

North Slope Crude Oil, for the Alaska State Senate Finance Committee, May 1987, p. A-24.27, R.K. Doughty, ARCO Oil and Gas Company, letter to OTA, Jan. 14, 1988.28. 6erman et al., op. cit., footnote 26.29. M. Harris, “Marginal Fields: Minimizing the Risk,” Alaska Censtruotion and Oil, July 1985, p. 21.

Chapter 3 ● 85

rate for Prudhoe Bay’s initial wells–about 200barrels per day versus up to 20,000 barrels perday at Prudhoe (Prudhoe Bay productionaverages about 6,000 bpd per well). Because ofthe reservoir rock and fluid properties, manymore wells are likely to be needed than is thecase for Prudhoe Bay. Also, the shallow depth ofthe West Sak reservoir implies that more wellpads will be needed than at Prudhoe or Kuparuksince the same horizontal drilling offsets will bedifficult to achieve. West Sak acreage drainedper well pad will be substantially less (assumingthe same number of wells per pad and similardrilling angles and “kickoff” points, a PrudhoeBay pad would be able to drain 12 times the areaas one in West Sak). Thus, a West Sak fieldwould take a long time to develop, and without abreakthrough in recovery technology, is not ex-pected to contribute much to keeping TAPS full.One development scenario envisions fiveproduction centers with a total of 5,100 wells(about five times the number of developmentwells in the Prudhoe Bay field).

In 1984, ARCO estimated that the West Sak fieldcould be in full production by the late 1980s;however, the company suspended work on theWest Sak pilot project in December 1986. ARCOis still evaluating the pilot project results and con-ducting research on how to develop the fieldeconomically. If economic conditions are right,the field could produce about 100,000 barrels ofoil per day by 2000 and account for approxi-mately 5 percent of current TAPS capacity.ARCO has shown that the field can be productiusing existing technology. However, sophisti-cated enhanced recovery systems would be re-quired, and these are justifiable only with high oilprices and stable economic conditions.30 Oneadvantage for West Sak development is that itshould be able to capitalize on the extensivefacilities already in place for the Kuparuk field;however, full development of West Sak will re-quire the same enclosed production and person-nel facilities as Prudhoe Bay but with far less

revenue-production potential per dollar in-vested .3’

ARCO remains hopeful that it can achievebreakthrough in recovery technology. It plans onbeginning a new experimental drilling program in1989, with up to 25 wells in the pilot program if

32 If the p r o g r a m i searly wells are successful.fully successful, ARCO hopes eventually toproduce 200,000 to 300,000 bbl/day from thefield.33 Given the substantial technical problemsremaining, however, the prospects for West Sakare highly uncertain. Figure II I-6 presents aprojection of future West Sak production assum-ing use of available technology.

The Seal lsland/Northstar field, being exploredby Shell, Amerada Hess, and partners, may bethe second offshore field developed. Locatedapproximately 12 miles northwest of PrudhoeBay, the Seal lsland/Northstar field is partially inAlaskan State waters and partially in waters dis-puted between Alaska and the Federal Govern-ment. The disputed leases are managed by theFederal Government. The field is estimated tohave in-place resources of approximately 900million barrels and potential reserves of about

Figure 3-6.-Alaska North SlopeProduction: West Sak and Seal Island

30. M. Harris, “Oil Industry in Transition: Alaska Activity on the Rebound,” Alaska Construction and oil, October 1987, p. 11.31. M. Harris, “Marginal Fields: Minimizing the Risk,” Alaska Construction and Oil, July 1985, p, 2132. T. Bradner, “ARCO Plans West Sak Development,” The Energy Daily, December 7, 1988; and personal communication, James

Posey, ARCO Alaska, December 12, 1988.33. Ibid. This rate of production would be sustained only for a short eriod, unlike the longer production plateau at Prudhoe,

?Personal communication, James Mitchell, ARCO Oil and Gas Co,, Piano, exas, December 12, 1988,

86 ● ANWR

300 million barrels. Thus, the field appears tohave about the minimum volume of recoverableoil necessary for economic production in theBeaufort Sea given $24 per barrel oil. 34 Seal ls-Iand will be considerably more expensive todevelop than the Endicott field because it is lo-cated 6 miles offshore (4 miles further offshorethan Endicott), in 39 feet of water (3o feet deeperthan Endicott), and in a floating fast ice zonewhere moving ice can be a hazard during stormsand “breakup.” Given the long lead times re-quired for development in the Arctic offshore,production is not expected to begin before themid-1990s even if prices bounce back up. Higheroil prices and the expectation of continued higherprices will be required to start development andproduction from the Seal Island and Northstardiscoveries. If developed, production couldreach 45,000 barrels per day (Figure 3-6) ormore. To date, four exploration wells have beendrilled on Seal Island and another two onNorthstar Island, which is 5 miles west of Seal.

Furthur offshore, Shell and partners announceddiscovery of oil in early 1986 in the Harvardprospect. The discovery was made from themanmade Sandpiper Island in 49 feet of water.The Haward prospect is geographically close toSeal and Northstar, and, if enough recoverableoil is present, could be developed concurrently.The Minerals Management Service has termedthe find “producible,” by which it means there isat least enough oil present to cover daily operat-ing costs of production. The most difficultproblem in developing the Seal/Northstar/-Sandpiper area will be constructing the pipelineto shore. Either a buried pipeline or a 5-milepiling-mounted pipeline will be needed, both ofwhich will be very expensive.

The Point Thomson/Flaxman Island field, lo-cated on the coast of the Beaufort Sea east ofPrudhoe Bay, is estimated to contain about 350million barrels of recoverable condensate (lightgravity hydrocarbons) and approximately 6 tril-

lion cubic feet of recoverable gas. However,development not only awaits higher oil prices butis based on the assumption that a gas cyclingproject will work that will enable recovery of gasliquids without having to transport and sell thefield’s gas resources, which is not now economi-

35 The development potential ‘f ‘hecally feasible.Point Thomson field also suffers from its locationabout 60 miles from the Trans Alaska Pipeline.The outlook for development of this field couldimprove if a significant oil discovery is made inthe Arctic National Wildlife Refuge immediately tothe east and a pipeline is built that could alsosewe Point Thomson.

In December 1987, the Standard AlaskaProduction Company declared the Niakuk field,located in 4 feet of water 1 mile offshore in Statewaters immediately northeast of Prudhoe Bay, tobe commercial. Standard has estimated re-serves to be about 55 million barrels of oil,recoverable using primary and waterflood tech-niques, and thus the field appears to be in a classwith Milne Point and other marginal North Slopefields 36 The reservoir is the Sag River sandstone!

productive at Prudhoe Bay, and separated fromPrudhoe by the Niakuk fault system. The field isheavily faulted and divided into at least three dis-crete pieces, two of which are considered byStandard to be commercial at current oil prices.Standard would like to start producing Niakuk in1991, contending that this field will be economicto produce, despite its small size, because thefield is quite close to Prudhoe Bay, will not re-quire a long offshore causeway or onshore con-necting road, will likely be able to use spareproduction capacity at the Prudhoe Bay and Lis-burne fields by the time production begins, and,given its small size, will not require special en-gineering but will be able to use off-the-shelffacilities. Standard hopes that the field can con-tribute 20,000 barrels of oil per day to TAPS bythe end of 1991.37

DNR has estimated potential reserves in theGwydyr Bay field northeast of Prudhoe Bay–as-suming a minimum oil price of $24– of 10 million

34. Alaska Department of Natural Resources, Division of Oil and Gas, 1987,35. Berman et al., op. cit., footnote 26.36. “Alaska Work Hikes Standard Reserves; Niakuk Commercial,” Oil and Gas Journal, Dec. 21, 1987. p, 17.37. T. Obeney, Niakuk Field Manager, Standard Alaska Production Company, telephone conversation, Jan. 28, 1988.

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Chapter 3 ● 87

barrels. Potential resewes of other small oil dis- ANWR and the East Umiat and Gubik fields in thecoveries – including Tern Island 35 miles east of NPRA have either not yet been determined or notPrudhoe Bay, Colville Delta west of the Kuparuk released. There is little to suggest that any offield, Umiat in the National Petroleum Reserve in these fields will ever contribute more than smallAlaska (N PRA), and the Hammerhead and incremental amounts to total North SlopePhoenix prospects–and of gas discoveries such production. Many may never be developed.as the Kavik and Kemik fields immediately west of

88 ● ANWR

TECHNOLOGIES FOR IMPROVED RECOVERY

As discussed above, the four largest producingNorth Slope fields– Prudhoe, Kuparuk, Lisburne,and Endicott– make up all of the present TAPSproduction and will continue to dominate with atIeast 80 to 90 percent of ail North Slope produc-tion well into the 1990s, even with the most op-timistic assumption of development for otherknown fieids. With this background, OTA inves-tigated the potentiai of new advanced recoverytechnologies either to improve productionforecasts for these four fieids or to improveproduction opportunities for other known, but notyet producing, North Slope fields.

To begin this investigation, OTA evaluated fu-ture Alaskan North Slope oil production projec-tions and the technological assumptions thataffect them. Next, OTA held a workshopm t oidentify current technologies and to project thedevelopment of new technologies that could im-prove production from known Alaskan oilfields.In preparation for the workshop, OTA extractedfrom pubiished data oil production projectionswith their accompanying assumptions and as-sembled brief descriptions of field characteris-tics. The workshop was focused on theidentification of technologies (and their stages ofdevelopment) that may be used in these fieids.OTA asked the workshop participants to reviewand critique the data assembled and to suggestand discuss technologies from their ownknowledge and experience. Participants in theworkshop included industry experts in enhancedoil recovery and in North Slope reservoir en-gineering, as well as researchers from the Univer-sity of Houston and private independent firms.

The findings of the workshop covered threeprincipal topics: field characteristics that limitrecovery; technologies to improve recovery; andprojections of future North Siope oil production.

Prudhoe Bay is now and has aiways been thepremier oiifield on the Alaskan North Siope. Notonly is it the largest field in the United States, butit is seven to eight times as large (in reserves) as

Kuparuk, which ranks number two. Prudhoe is afield with high recovery potential, now estimatedat 42 to 45 percent of original oil in place. Prud-hoe is the fieid whose potential fired all NorthSlope development over a decade ago, and itsproduction is still more than 80 percent of ailNorth Slope oil. Prudhoe is a mature field and isnear its peak production.

The other three producing North Slope fields–Kuparuk, Lisburne, and Endicott– now contri-bute about 15, 2, and 5 percent, respectively, tototal North Slope production. The other knownNorth Slope fields– both onshore and offshore–are considered to be of minor importance eitherbecause of size (e.g., insignificant portion ofTAPS throughput) or because present econom-ics prohibit their development. OTA workshopparticipants reviewed the information on theseother fields and selected one (West Sak) out ofthe group for discussion. West Sak is a very largefield that is not presently economical and thatwould require significant implementation of en-hanced recovery techniques to produce oil. Itrepresents a field with potential but with a rangeof significant barriers (technical problems) toovercome to reach its potential. The workshopparticipants therefore focused on technologiesthat would be applicable to five known NorthSlope fields –four now producing and one poten-tial.

The oil well recovery systems that are usedtoday are typically described as either primary,secondary, or tertiary. Primary recoveryproduces the fraction of in-place oil that will flowunaided or can be pumped from the reservoirrock matrix to the surface. Depending on thereservoir characteristics, from 5 to 80 percent ofin-place oil may be recovered using primaryrecovery techniques. In the United States as awhole, average primary recovery has been about

39 In 1979, the American28 percent of in-place oil.Petroleum institute reported that the average ul-timate recovery of U.S. oil is about 32 percent,with a low of about 14 percent in Ohio and a high

38. “North Slope Enhanced Oil Recovery Technologies”, Dec. 8, 1987, University of Houston, Houston, Texas.39. Todd M. Doscher, “Enhanoed Recovery of Crude Oil,” American Scientist, April 1981, p. 195.

— —

Chapter 3 ● 89

of about 65 percent in east Texas. The large,highly permeable reservoirs of east Texas andsouthern Louisiana have a history of high primaryproduction. Prudhoe Bay is this type of reservoir.

Secondary recovey techniques are in commonuse in many reservoirs to increase the percent-age of oil recovered. These methods attempt tomaintain or restore reservoir pressure by the in-jection of gas or water (waterflooding). Depend-ing on reservoir conditions and oil properties,secondary recovery techniques can improve in-place oil recovery to between 30 and 50 percent.The injection of water into a reservoir to displacethe in-place oil, to reproduce a natural waterdrive, is the basic secondary recovery operation.In the United States as a whole, waterfloodingraises oil recovery efficiency by a factor of 1.5 to2.0. Waterflooding is dominant among fluid in-jection methods, and its widespread use is due tothe easy availability of water, the relative ease ofinjection, and the efficiency with which waterspreads through a reservoir and displaces oil.

Prudhoe Bay and Kuparuk fields have sec-ondary recovery waterflood operations in place;Endicott is scheduled to start waterflood in 1989and Lisburne has a waterflood pilot operating. Allproducing North Slope fields now have appli-cable secondary recovery techniques in place orplanned.

After secondary recovery methods are ex-hausted, the extraction of additional oil fromfields requires the application of more sophisti-cated and expensive techniques. Enhanced oilrecovery processes (or tertiary techniques) canfurther increase recovery to 40 to 80 percent ofthe original in-place oil, depending upon theprocess employed and upon the physical proper-ties of the reservoir and the oil. These techniquesusually attempt to reduce oil viscosity and/or toaffect other characteristics that impede oil flow.The techniques work by introducing to theproducing formation either heat (steam) or sub-stances such as rich miscible gas, carbondioxide, polymers, solvents, surfactants, micellarfluids, or even microorganisms in various com-binations, depending upon reservoir conditionsand crude oil properties.

One of these techniques (rich miscible gas in-jection) is now in place with a major project atPrudhoe Bay and another at Kuparuk. The OTA

workshop focused attention on whether a rangeof enhanced recovery techniques might be ap-plied to the four producing fields and West Sakand, under the most optimistic economic condi-tions, what improvements in ultimate recove~might be expected.

The OTA workshop reviewed each of the fivefields under consideration and noted key featuresas well as constraints to further production as fol-lows:

Prudhoe Bay (42 to 45 percent recovery)

● Largest light oilfield (27oAPI, 190°F)

● Dominant and most mature field

● Nearest to decline (1989 or 1990)

● Projects now in place to enhance recoveyinclude:

- Waterflood– Miscible gas injection– Infill wells*– Horizontal drilling*- Other studies by the operators to en-

hance future recovery include:– Adding more natural gas liquids to

TAPS— Expanding gas handling to increase

miscible gas injection

● Reservoir is a thick, high-quality sand witha big gas cap

- Barriers to increased recovery arelimited waterflood contact with oil inthe reservoir and gas handlingcapacity

*These techniques are used primarily to ac-celerate production rather than to increase ul-timate recovery, although some increases arepossible, for example, when horizontal drilling isused to reach areas of thin pay not easily drainedby regular wells or when infill wells drain portionsof oil reservoirs that are not in close connectionto the primary network of wells.

Kuparuk (25 to 30 percent recovery)

● Second largest field (27 oAPI, 150°F)

● Compared to Prudhoe, formation is thin-ner and more spread out with more faultsand no gas cap

90 ● ANWR

● The field is constantly on decline withoutcontinual infill drilling

● Of 400 square miles, only the inner 200square miles is commercial

● Waterflood and miscible gas injectionprojects are now in place

● Barriers to improved recovery include oilsaturation, faulting, and relatively thin pay

Lisburne (7 to 22 percent recovery)

● About one-half of this reservoir underliesthe main reservoir of the Prudhoe Bay field(27oAPI, 190°F)

● Very difficult field to produce

● Carbonate reservoir, not well described

● How well oil can be recovered from com-plex matrix is not yet known; more drillingis needed to better define the reservoir.

● Small waterflood pilot is being tested

● Barriers to improved recovery include lowporosity and permeability; fracturing

Endicott (35 percent recovery)

●

●

●

●

●

West

Similar to Prudhoe reservoir with big gascap (23oAPI, 210°F)

Waterflood designed into the beginning ofproject for 1989 start-up

Gas handling may be future problem

Small field compared to Prudhoe produc-tion

Constrained by faults; reservoir volumewell-defined

Sak (15 to 25 billion barrels estimated oilin place)

●

●

●

●

●

Largest medium-heavy oilfield on NorthSlope (14 to 22oAPI, 70°F average)

Recovery rates are now estimated be-tween O and 5 percent by industry,depending on section of the field

Very difficult field to produce because ofpoor reservoir conditions, i.e., uncon-solidated fine sand and viscous, low-temperature oil

Early tests indicate well production rateswill be very low (hundreds of barrels perday), requiring thousands of wells for anysubstantial production

Industry concludes the field is notproducible at today’s prices

Enhanced recovery techniques possibly ap-plicable to North Slope fields are in threecategories: miscible flooding, chemical flooding,and thermal techniques.

Miscible flooding is a technique based uponusing some gas– such as enriched reservoir gas(as at Prudhoe) or carbon dioxide (COQ) oranother gas–to miscibly displace some oils,thereby permitting the recovery of most of the in-place oil contacted. The miscible gas is injectedinto the formation at an injection well and forcedtoward a production well. A technique for forcingand directing the miscible gas is to alternatewater slugs through the same injection well. Thisis known as Water-Alternating Gas (WAG). A fur-ther improvement can be achieved by adding adetergent to the water in WAG which then formsa foam and reduces the apparent viscosity of thefluid. COQ gas is more commonly used in theLower 48 because reservoir gas is a more valu-able product. At Prudhoe Bay, gas is not current-ly marketable and therefore is a more attractiveflooding agent.

Chemical flooding is a technique based on ad-ding various chemicals to the water used inwaterflooding in order to increase waterflood ef-ficiencies. Chemicals may be polymers, whichincrease the viscosity of water, surfactants tohelp release immobilized oil, strong alkalineswhich themselves form surfactants, or othermore complex substances. Foaming agents alsohave been added to chemical flooding to create amore efficient solution.

Thermal methods involve the injection of steamor hot gas or in-situ combustion – all for produc-tion of heavy crude oils whose recovery is im-peded by viscous resistance to flow at reservoirtemperatures. Foaming agents also can beadded to steam to increase steam injection ef-ficiency.

Pressure cycling is the technique of injectingnatural gas or COQ into the producing formationand alternating high and low injection pressuresto induce mixing with the crude and thusstimulating the flow. Lab testing and simulationsof “pressure cycling” have been done, and it is

believed to be a promising technique for highlyfractured rese~oirs (such as Lisburne).

Some of these techniques have already beenapplied (rich miscible gas injection at Prudhoeand Kuparuk) and others have been studied. Thelist in Table 3-5 covers most of those consideredpossibly viable by the industry and other re-searchers at this time. The technique that hasprovided major improvements for North Slopefields (beyond secondary waterflood) is misciblegas injection. Most others are considered ex-perimental at this stage and almost all must befield tested. A common feature of EOR develop-ment is that it is difficult or sometimes impossibleto accurately scale up the results of laboratorytests to the field level. Also, some technologiesappear impractical for certain North Slope condi-tions. For example, many thermal processes aredifficult to apply because of wide well spacing,depth of the reservoirs, and the substantial per-mafrost layer.

None of the techniques appear to offer a majorincrease in recovery rates for the existing NorthSlope fields. Rather, the dominant industry viewis that continued enhanced recovery efforts overa long period of time would likely be able to adda series of small increments to the ultimaterecovery percentage for any given field. Ingeneral, the industry appears to have greaterfaith in the gradual accretion of experience fromapplication of existing recovery methods than inthe potential of exotic new methods. For Prud-

Table 3-5.—Some Enhanced Recovery TechniquesPossibly

M/se/b/e - flooding

Chemical flooding

Themal methods:

Pressure cyclingNOTES 1 In use II other-Lower 48-fields

2 In use— North Slope3 Some pilot tests4 Lab tests and experiments

SOURCE Off Ice of Technology Assessment, based on Dec. 8, 1987 workshop

hoe Bay this may mean that about 10 percentmore oil ultimately will be recovered. For otherfields, application of EOR techniques might pushrecovery rates to the high end of ranges now es-timated. In any case, it is not likely that the onsetof decline in North Slope production can bedelayed more than a few years. The most likelyoutcome of using more enhanced recovery tech-nology would be to extend field life. This out-come would increase total recovery from certainfields but not necessarily have any immediate ef-fect upon short-term production rates.

Application of EOR technology is a/ways adecision based on economics. Those tech-niques which the industry considers to beeconomic under current conditions are being ap-plied in North Slope reservoirs. Higher crude oilprices could result in wider application of currenttechniques and also increase the chances foreconomic application of other more speculativetechnologies.

Table 3-6 shows, for four North Slope fields ofinterest, the factors for each which may limitproduction and some applicable enhancedrecovery techniques. “Present EOR” denoteswork already in place; category A covers tech-niques that may be applied depending oneconomic conditions and individual companyplans. Category B includes speculative tech-niques which require development and/or testingand higher oil prices.

Summary

Most of the enhanced recovery techniques thatseem practical for North Slope fields today areeither in place or already planned for installationin the future. OTA’s review did not uncover anytechnologies that offered major improvements inrecovery rates from the fields where we had avail-able information. A careful examination of ad-vanced technologies at the University of Houstonworkshop led to the summary of possible futureenhancements discussed above. The conven-tional approaches cover most of those in use orplanned. More speculative technologies havepromise for the future but would certainly requirefurther field testing. OTA was not able toevaluate the economics of EOR but notes that in-dustry claims oil prices must increase before any

Table 3-6.—Problems Limiting North Slope Recoveryand Technologies Which May Improve Recovery

Prudhoe BayLimits: Residual Oil Saturation to Waterflood

Actual High Recovery at 42-45%(A good performer as Is)

Present EOR: Waterflood; Miscible Gas Injection;Infill and Horizontal Drilling

A) Conventional Technologies: Expansion of WaterfloodMore Miscible GasExpand Gas Handling Capability (GasCycling)More Infill Drilling

B) Speculate Technologies: Foam to Improve Miscible Gas (Mlsci-ble Flood)Surfactant/Polymer (Chemical Flood)

West SakLimits: Unconsolidated Fine Grained/Sand Production

Viscous OilPoor Rock Quality (shaly)

A) Conventional Technologies: Waterflood(not econom!c today) Fracturing

B) Speculative Technologies: Thermal MethodsMiscible Gas or CO, (Miscible Flood)

KuparukLlmds Basic Residual 011 Saturation Problem

FaultedThin Pay–Especially Outer Edges (half of field area)Absence of a gas cap not a problem since much gas nearby

A) Conventional Technologies: WaterfloodMiscible GasInfill Drilling

B) Speculative Technologies: Foam to Improve Miscible Gas (Misci-ble Flood)Polymer (Chemical Flood)Micellar Polymer (Chemtcal Flood)

LisburneLimits Fractured Limestone

Low Porosity/PermeabilityA) Conventional Technologies: Waterflood (may be difficult)

Infill DrillingB) Speculative Technologies: Strategic Infill Drilling

Pressure Cycling/Natural GasSOURCE Office of Technology Assessment based on Oec. 8 1987 workshop

techniques beyond ones currently in use arelikely to be implemented.

OTA reviewed available current estimates of in-dividual field production rates and ultimaterecovery and concluded that the projections inFigures 3-3 through 3-6 are reasonable. In somecases, the data may be either too optimistic ortoo pessimistic, but, on average, the estimatesare as accurate as available information will per-mit. The total TAPS production estimates in

Figure 3-2 seem to adequately bracket the highand low range of future production possibilities.

Future “surprises” at Prudhoe Bay, thedominant field, are unlikely; Prudhoe appears tobe the most monitored and computer-modeledfield in the world. Futihermore, the operatorshave foreseen Prudhoe Bay’s decline and havebeen working over a long period of time to keepproduction high and maximize recovery. Theremay be, however, a conflict between keepingproduction high and maximizing ultimaterecovery. Some researchers have noted, for ex-ample, that increasing the production of naturalgas liquids through TAPS, as industry plans todo, may beat the expense of increasing the mis-cible gas injection project. This could thereforelead to higher production now and lower ultimaterecovery. OTA has not investigated the impactsof these details of reservoir management in orderto reach an independent conclusion but onlynotes that choices are not always clear andsitnple.

The other three fields also do not appear tohave many surprises in the offing, and, even ifthey did, the impact would be minor in relation toTAPS throughput. Kuparuk requires substantialconventional work, such as infill drilling, to keepproduction up. With waterflood and miscible gasprojects in place, the future EOR opportunitiesthat are available are a few of the more exoticchemical flooding techniques. These techniquesrequire further study and testing. Endicott todate is as good a performing field as Prudhoe,and lessons from Prudhoe can best be appliedthere.

Lisburne is a very difficult field to produce, anddisappointing results to date have downgradedits future potential. Some researchers have ad-vocated more experimental technologies to betried at Lisburne, but this would probably requireindustry development and testing beyond thatjustified by today’s economics.

The optimistic view of new EOR technologiesimproving ultimate North Slope recovery appearsto be that improvement, if any, will be slow andincremental. Over the next decade the total im-provement may be expected to be about 10 per-cent. Improvements would need to come fromadvanced techniques that will require testing and

Chapter 3 ● 93

capital expenditures beyond what indust~ claims to decline in several years, and application of en-are presently economically justifiable. hanced oil recovery technologies to known North

Slope fields will result in additional reserves.The discovered but still undeveloped fields on However, neither development of currently un-

the North Slope of Alaska do have the potential to developed fields nor the success of EOR projectstake up some of the slack that will be created nor both together is likely to stem the inevitablewhen the Prudhoe Bay and Kuparuk fields begin decline of TAPS thoughput.

OIL PRODUCTION FROM UNDISCOVEREDRESOURCES

Alaska’s North Slope still contains areas ofpotential hydrocarbons that the oil industry hasnever explored or that have received only mini-mal attention. In prospective offshore areas, forinstance, no exploration has yet taken place inthe Chukchi Sea, and very little has taken place inthe Beaufort Sea adjacent to and north of ANWR.Even the more explored central and western por-tions of the Beaufort Sea have been barelyscratched. Onshore, only one well has beendrilled in ANWR, and although a number of un-successful wells have been drilled in the NationalPetroleum Reserve in Alaska, some experts stillsee the possibility of a commercial discovery inthis vast area.

Both the State of Alaska and the FederalGovernment have scheduled a number of leasesales in the next 5 years. The State plans to holdfour offshore and five onshore lease sales onState lands in northern Alaska, while the FederalGovernment has scheduled two offshore sales inboth the Beaufort and Chukchi seas in its mostrecent 5-year plan (Table 3-7). Discovery of newoil resources on the North Slope could, if largeenough and in favorable locations, help keep oilflowing through TAPS. However, a sizable fielddiscovered in 1988 probably would not beproducing before 1998, given the long lead timesneeded to bring a new North Slope field on line.

Photo credff Arctm S/ope Consu/t/r?g Engineers

Chevron’s KIC well near Kaktovik is the only onshore exploratory well to probe the oil resourcesof the ANWR coastal plain. The results are a closely guarded secret.

Chapter 3 ● 95

Table 3~7.—Alaska Lease Sales

N u m b e r S a l e Sale dateA. Proposed Alaska OCS Region Sales97 Beaufort Sea March 1988109 Chukchi Sea May 1988107 Navarin Basin December 1989101 ● St. George Basin February 19901 14* Gulf of Ak./Cook Inlet September 1990117 N. Aleutian Basin October 1990124 Beaufort Sea February 1991126 Chukchi Sea May 1991120’ Norton Basin September 1989129’ Shumagin January 1992133’ Hope Basin May 1992130’ Navarin Basin January 1992“To be held only [f Industry Interest warrantsSOURCE U S Department of the lnterlor, April 1988

B. Proposed State of Alaska Sales54 Kuparuk Uplands55 Demarcation Point66A North Slope Exempt52 Beaufort Sea56 Alaska Peninsula67A Cook Inlet Exempt59 Cook Inlet57 North Slope Foothills64 Kavik65 Beaufort Sea61 White Hills68 Beaufort SeaNOTE North Slope sales bold

January 1988June 1988June 1988January 1989June 1989June 1989January 1990June 1990January 1991June 1991January 1992June 1992

SOURCE Alaska Department of Natural Resources Division of 011 and Gas

Estimates of undiscovered oil may be useful fora number of reasons. These estimates may beused for 1) making long-term energy policy, 2)forecasting rates of domestic discovery andsupply, 3) anticipating environmental impacts ofexploration and production, 4) making invest-ment decisions, 5) anticipating future technologyand capital requirements, 6) realistically evaluat-ing regulatory options, 7) scheduling lease sales,8) conducting cost-benefit studies of leasing al-ternatives, and/or 9) analyzing the economics of

38 Estimates ‘ f

Industry’s bids on leasable tracts.

the undiscovered resources on the North Slopeof Alaska are needed for all of these reasons.Several techniques are available for estimating

the amount of undiscovered resources a regionmay contain (see Appendix B). Even with thebest techniques available, estimates of undis-covered resources are inherently much more ten-tative than estimates of resources in knownfields.

Estimates for the North Slope

The expectation of the early 1980s that moremajor oil resources would be found on the NorthSlope and in other parts of Alaska has not yetbeen realized. All of the currently producing on-shore fields were discovered in the late 1960s,and no significant new discoveries have beenmade. Offshore areas have been judged bymany 3g to be particularly promising, but the onlyoffshore development to date is Standard AlaskaProduction Company’s Endicott field, discoveredin 1978. After considerable exploratory drilling,the only noteworthy offshore discovery in the1980s has been Shell’s Seal Island, a field that isnot economic to develop at current low oil prices.

While much oil probably remains to be discoveredboth onshore and in still relatively unexplored off-shore areas, it is unlikely that undiscovered resour-ces will be found and developed in time to keep theTrans Alaska Pipeline running at full capacity after1990. Lead times for development of 15 years ormore may be required in some of the more remoteplaces. in any case, new oil discovered in Alaskawill not necessarily be found in proximity to TAPSand, hence, may require installation of an alternativetransportation infrastructure. Also there has been aslowdown in exploration spending since 1985 be-cause the current price of oil is low.

Several estimates of the undiscovered, economi-cally recoverable resource potential of Alaska havebeen made. In 1981, the U.S. Geological Survey(USGS) estimated the risked mean of undiscovered,economically recoverable oil offshore Alaska to be12.2 billion barrels and of natural gas to be 64.6 tril-lion cubic feet;w onshore Alaskan oil and gasresources were estimated to be 6.9 billion barrels of

38. National Research Council, Offshore Hydrocarbon Resource Estimation: The Minerals Management Service’s Methodology(Washington, D. C.: The National Academy Press, 1986), p. 5.

39. See, for instance, National Petroleum Council, U.S. Arctic Oil and Gas, December 1981.40. US, Geological Survey, Circular 860, Estimates of Undiscovered Recoverable Conventional Resources of Oil and Gas in the

United States, 1981.

96 • ANWF

oil and 36.6 trillion cubic feet of natural gas. In 1985,the Minerals Management Servicce (MMS), which as-sumed the offshore leasing responsibilities of theConsevation Division of the U.S. Geological Surveyin 1982, again estimated offshore undiscoveredresources. The newer assessment concluded thatAlaskan Outer Continental Shelf (OCS) areas con-tained 3.3 billion barrels of undiscovered, economi-cally recoverable oil and 13.9 trillion cubic feet ofgas. This volume is much lower than the 1981 es-timates. MMS assessed only OCS resources (i.e.,resources beyond the 3-mile-wide band of State-controlled waters) while the previous USGS es-timate considered all offshore resources together,MMS also used a different estimation methodologyand revised some of the assumptions used in theearlier USGS estimate. Still, most of the reduction inthe estimate of offshore undiscovered, economical-ly recoverable resources probably can be ac-counted for by the disappointing offshoreexploration record between 1981 and 1985 (Table 3-8).

In May 1988, the Minerals Management Serviceand the U.S. Geological Survey released prelimi-nary data from a new study of the Nation’s undis-covered oil and gas.42 The new study incorporatesa great deal of new data and uses improved estima-tion methodologies.43 The USGS estimated on-shore resources and resources in State waters;MMS estimated resources in Federal OCS waters.The new USGS estimate of undiscovered, economi-cally recoverable resources for the total of onshoreand State offshore areas of the United States is con-siderably smaller than the 1981 estimate. The pic-ture for Alaska is less dear. The preliminary 1988estimate indicates a risked mean of approximately 8billion barrels of oil in onshore areas and in AlaskanState waters. The corresponding 1981 figure, 6.9billion barrels, does not differentiate between Stateand OCS waters, thus making comparisons be-tween the two estimates difficult; however, given the

Table 3-8.—Estimates of Undiscovered, EconomicallyRecoverable Oil in Alaska (risked mean billion barrels)

magnitude of USGS’s 1981 combined estimate ofonshore and shelf offshore oil, a reduced estimatecan be inferred.a

Alaskan OCS data also have been revised.Preliminary offshore estimates of undiscovered,economically recoverable oil indicate substantial-ly less oil than was estimated in MMS’s 1985 es-timate. Since 1975, over 90 exploration wellshave been drilled in the State and Federal watersof the Beaufort Sea and in the Navarin, Norton,and St. George Basins in the Bering Sea.45 Fewof these exploration wells struck “producible”quantities of oil.46 Only one offshore discovery,

41, U.S. Congress Office of Technology Assessment, Oil and Gas Technologies for the Arctic and Deepwater (Washington, DC:U.S. Government Printing Office, 1965), p. 30.

42. U.S. Department of the Interior, National Asessment of Undiscovered Conventional Oil and Gas Resources, USGS-MMSWorking Paper (Preliminary), Open File Report 68-373, 1986.

43. The pla analysis methodology used by USGS and MMS and underlying geologic assumptions will be reviewed before final7publication o the report,

44. The mean total for onshore oil and shelf offshore oil was estimated in 1981 by USGS to be 17.7 billion barrels. Some of theshelf offshore oil would be expected to be found in State waters.

45. W.W, Wade, “Exploration and Production in Alaska: A Review and Forecast,” World Oil, February 1986, p. 101.46. That is, few were determined to be “producible” in accordance with OCS Order No, 4.

Chapter 3 ● 97

the Endicott reservoir, located in shallow Statewaters, has been developed to date; only twoother likely commercial discoveries have beenmade, Niakuk and Seal Island. Niakuk is in veryshallow State waters adjacent to the existingPrudhoe Bay infrastructure and, hence, may pos-sibly be producing by the early 1990s. Seal ls-Iand has been the only OCS discovery to date(although, as noted previously, its OCS status isbeing disputed by the State of Alaska).

The most notable disappointment in OCS ex-ploration was Sohio’s Mukluk prospect in theBeaufort Sea. The Mukiuk structure was con-sidered the most promising prospect in theBeaufort during 1983, but the failure to discoveroil there transformed it into the most costly dryhole in history ($140 million in drilling and islandconstruction costs and over $1 billion in totalcosts). The Mukluk dry hole figured prominentlyin the substantial lowering of Beaufort Searesource estimates in MMS’S 1985 reassessmentof undiscovered, economically recoverableresources.

Figure 3-7.-Exploratory Wells in theBeaufort and Bering Seas, 1976-88

SOURCE U S Department of the Interior, Minerals Management Service, Alaska/Summary Index, January 1966-December 1966, pp. 26, 27, 39

Offshore areas remain relatively unexplored,but the lack of drilling success since 1985 is amajor reason for the lower 1988 estimates. Fur-thermore, low and volatile oil prices have dam-pened enthusiasm. Exploratory drilling activityhas dropped off sharply since the peak year of1985 (Figure 3-7). Only one well has been drilledthus far in 1988, Tenneco’s Aurora well about 4miles off the coast of the Arctic National WildlifeRefuge, and no others are expected. However,higher and more stable oil prices would likelystimulate higher levels of offshore exploration inthe future.

Estimates for ANWR

Although much is said and written about theresource potential of ANWR, it is still a virtuallyunknown area, and a wide range of resources ispossible in ANWR’S coastal plain. Muchdepends, for instance, on the existence andthickness of Ellesmerian sequence rocks in theANWR area, and State and Federal geologists dif-fer in their assessment of these rocks. Both theState of Alaska and the U.S. Department of theInterior (DOI) have used play analysis to estimatethe in-place resource potential of ANWR. TheState used a model known as the Resource Ap-praisal Simulation for Petroleum (RASP) to es-timate undiscovered resources there. DOI useda modified version of the play analysis techniquedeveloped by the Geological Survey of Canadato estimate ANWR’S potential in its mandatedreport to Congress. The DOI assessment isdriven by an efficient computer program knownas the Fast Appraisal System for Petroleum(FASP) (see Appendix B for a discussion of thesemodels). Both models use information gainedthrough seismic work and through studies ofANWR’S surface geology; both models dependfor much of their input on the opinions ofgeologists familiar with the area; and bothmodels report their results as probability distribu-tions rather than as single point estimates.

The State reports that there is a mean of 7.22billion barrels of in-place oil in ANWR while DOl

98 ● ANWR

reports a mean of 13.8 billion barrels. Given thelack of information about ANWR’S subsurfacegeology, it is not surprising that DOI and State ofAlaska estimates differ at all probability levels(Table 3-9). 47 Although the results dif fer , both

studies conclude: a) that the key elements forpetroleum accumulations are present beneaththe coastal plain of ANWR, b) that there is only asmail possibility that unusuaily large petroleumresources are present, and c) that there is agreater likelihood that resources more moderatein size are present.48

One thing is important – much of the differencebetween the two estimates is due mainly to sub-jective factors. For instance, DOI and Aiaskageologists identified different geological plays foranaiysis (not unusual given the limited geoiogicdata available), had quite different opinions aboutthe quantity of potentially oil-bearing Ellesmeriansequence rocks in the area, and disagreed aboutthe contribution of pre-Mississippian rocks for oil

49 Had the same subjective infor-

accumulation.mation been used in each study, the DOI andState estimates using FASP and RASP wouidhave been about the same, but the estimateswould not necessarily have been more accurate,Subjective factors necessarily introduce a con-

Table 3-9.—Comparison of Estimates forUndiscovered In-place Oil in ANWR

Probability y State of Alaska Department of Interiorgreater than RASP FASP

SOURCE Alaska Department of Natural Resources, “Overview of the Hydrocar.bon Potential of the Arctic National Wildlife Refuge Coastal Plaln,Alaska, ” report of investigations 87-7

siderabie amount of uncertainty in estimates ofundiscovered resources. Drilling data is notavailable for ANWR’s coastal plain.

The Department of the Interior estimatedeconomically recoverable resources using thePRESTO (Probabilistic Resource Estimates-Off-shore) model. With PRESTO, DOI estimated thatif at least one field with commercially recoverablequantities of oil is present in ANWR, then there isIikely to be a mean of at least 3.23 billion barrelsof recoverable oil, a 5 percent probability of atleast 9.24 billion barreis, and a 95 percent prob-ability of at least 590 million barrels. Note thatthese estimates are very sensitive to DOI’s mini-mum areawide economic field size, which in turnis dependent on the assumed price of oil (in thiscase, world oil prices at $35 in the year 2000 in1984 doilars, with North Slope oil $33 because ofmarket conditions).

The Energy Information Administration (EiA)also estimated the undiscovered, economicallyrecoverable resources of ANWR. EIA assumedthat 25 percent of the in-place resources esti-mated in the DOI study would be recoverable,basing its assumed recovery factor on the ap-proximately 26 percent area-wide recovery factor

50 This assumptionfor known North Slope fields.resuits in a base case estimate of 3.45 billion bar-reis of recoverable oil. If EIA had applied thesame recovery factor to the State’s in-place es-timate, the comparable undiscovered, economi-cally recoverable estimate would be 1.8 billionbarrels. OTA has no basis for concluding thatone estimate is more accurate than the other, i.e.,for using DOI’s mean oil in-place figure versususing Alaska’s figure.

Note that the EIA and DOI estimates are not assimilar as they appear. The DOI estimate dependson the existence of at least one commercial field,and, according to DOI, there is a 19 percent chancethat such a field exists in ANWR. The EIA estimateassumes the probability of finding economicallyrecoverable oil is nearly 100 percent (uncondition-

47. J,J. Hanson and R.W. Kornbrath, “AComparison of State and Federal Appraisals of the ktic National Wildlife Refuge CoastalPlain,” Staff paper, Alaska Department of Natural Resources, Division of Mining and Geology, 1987,

48. Ibid., p. 4.49. Ibid,, p. 3.50. Energy Information Administration, Potential Oil Production From the Coastal Plain of the Arctic National Wildlife Refuge,

Ootober 1987,

—

Chapter 3 ● 99

al); EIA reasons that the geologic ingredients arepresent, that traps exist other than those used byDOI in its PRESTO analysis, and that oil accumula-tions smaller than 440 million barrels can beeconomically recovered.

Various groups support DOI’s risked mean es-timate of approximately 600 million barrels–thatis, 3.23 billion barrels multiplied by the probabilityof finding economically recoverable oil (19 per-cent), –as the appropriate measure of ANWR’sresource potential. In OTA’s view, the more ap-propriate interpretation of the DOI analysis is thatthere is an 81 percent chance that no economi-

cally recoverable resources will be discovered inANWR, but if there are any economicallyrecoverable resources at all, there will be a meanof at least 3.23 billion barrels.

On the other hand, if approximately 3.5 billionbarrels of recoverable oil are found in ANWR,OTA considers peak production of about 800,000barrels per day from two producing fields to bereasonable (see OTA scenario – Table 2-4– inChapter 2). Production that started in 2002 mightpeak by 2008 and then decline at a rate of about12 percent per year.

100 ● ANWR

OIL INDUSTRY COST-CUTTING AND THEEFFECT ON OILFIELD DEVELOPMENT

Oilfield costs during the past 15 years havebeen linked to oil prices. When prices wererising, costs also tended to rise after a short timelag. One reason was that the sellers of equip-ment and services were able to raise their pricesand increase their profit margins when risingprices spurred oilfield activity levels and when thedemand for services and equipment outran thesupply. Another reason was that rising oil pricestended to dull the incentive for innovative, cost-cutting design and operation. When oil pricesbegan to fall, beginning in 1981, oilfield activitylevels dropped, and prices for drilling and otherservices fell substantially. When oil pricesnosedived in late 1985, prices for equipment andsewices fell along with them. In many areas, forexample, day rates for rigs fell more than 50 per-cent. At the same time, extensive cost-cutting inthe industry streamlined oilfield activities so thatthe actual number of mandays and equipment-days required to complete projects was dramati-cally down.

For example, the industry drilled about 92,000wells in 1981 with nearly 4,000 rotafy rigs active;84,000 wells in 1982 with 3,100 ri s active; and85,000 wells in 1984 with 2,400 rigs. 15 This improve-ment in “rig efficiency” is a complex function of ac-tual efficiency improvements and other factors,such as changing geographical drilling patterns,shifts in the balance of oil and gas targets, and lowerlevels of exploration. Unfortunately, it is difficult, ifnot impossible, to separate out the roles of thevarious causal factors in the chan es in this andother measures of oitfield efficiency. Thus, it is notpossible to predict reliably what portion of this in-creased efficiency would remain if oil pricesrebound or other oilfield conditions improve.Nevertheless, OTA believes that there is sufficientevidence to conclude that a significant portion of the

measured increases in efficiency represent real in-creases and are not merely statistical artifacts.

Anecdotal evidence implies that the NorthSlope has seen considerable cost-cutting suc-cess. For example, Standard Alaska ProductionCompany claims to be drilling development wellsat Endicott for 40 percent of the originallyprojected cost–with no reduction in time ratesfor rigs–and the overall cost for developing thefield was about one-third of original projections($1.3 billion final cost, $3.8 billion conceptual es-timate =). The majority of the savings came froma combination of additional knowledge of theresource that dictated less expensive require-ments and lower material and labor costs be-cause of the general slowdown in oilfieldactivity– cost reductions that are not likely to berepeatable. A substantial part of the savings,however, resulted from Standard’s consciousdecision to scale-back and redesign the project.Cost-saving measures included:

using fewer but larger productionmodules;

using self-propelled, cantilevered drillingrigs to allow smaller spacing for wells andto reduce time for well-to-well moves;

changing the design from one island totwo, reducing drilling costs;

building a gravel causeway rather than un-dersea pipelines; and

using a single, rathe~~han a redundant, oil-processing system---

None of these changes are dramatic tech-nological breakthroughs, and all could well havebeen implemented without the decline in oilprices that began in 1981. However, it seemslikely that the price drops were the proximatecause of the process that led to these savings.

51. U.S. Congress Office of Technology Assessment, U.S. Oil Production: The Effect of Low Oil Prices- Special Report, OTA-E-348(Washington, DC: U.S. Government Printing Office, September 1987).

52. Ibid.53. Ml. Curtis and D.B. Huxley, “Endicott Development-Making the Arctic Offshore Economical,” Twelfth World Petroleum

Congress, Houston, Texas, 1987.54. Ibid.

Photo credit Standard Alaska

Endicot t F ie ld , August 1987. Carefu l redes ign a l lowed substant ia l cost sav ings a t th is f ie ld ,

The result of these and other cost-cutting suc-cesses is that, as oil prices have declined, the“breakeven” oil prices for project developmenthave declined as well. Consequently, projectionsof reduced activity levels (because of low oilprices) that relied strictly on previous estimatesof project costs should be viewed as overly pes-simistic. Also, if oil prices rise back to previouslevels, much of the “benefit” associated with theperiod of low prices would remain. For example,the rates for services probably would rise also,but not to previous levels. Higher efficiencyreached during the period of low oil prices wouldprobably remain, except for temporary lossesthat might occur if the demand for oilfield ser-vices and equipment outstripped the capacity ofthe providers. The net result would be that a

return to previous oil price levels might find theindustry capable of doing more project develop-ment than was economic at the time of the pre-vious price peaks,

The oil industry’s ability to cut costs in the faceof low oil prices implies that projections based onprevious cost estimates should be viewed some-what skeptically. This view applies to productionprojections for the entire North Slope as well asto estimates of the oil price necessary to developa 500-million-barrel oilfield in the Arctic NationalWildlife Refuge. For the North Slope, the abilityof the industry to complete projects at lowercosts makes it likely that the more optimistic ofthe available production projections–forecast-ing a 25 percent decline in production by 2000–

is the more realistic of the two presented pre- Mlnimum Economic Field Size (MEFS) isSs–that a $35/bbl oil Price

viousl y. However, basic resource constraints probably too largeand the unavailability of any “breakthrough” en- (1984 dollars) would allow the development of ahanced oil recovery technologies implies that still field smaller than DOI’s MEFS of 440 million bar-higher production levels are unlikely. For ANWR, rels of economically recoverable oil, or else that aOTA tends to agree with the Energy Information 440-million-barrel field could be developed at aAdministration’s argument that DOI’S estimated price lower than $35/bbl (see Box 3-B).

55. Energ Information Administration, Potential Oil Production from the Coastal Plain of the Arctic National Wildlife Refuge, revisediedition, WV NGD/87+1, ootober 19S7.

—--—-—

BOX 3-BHOW MUCH OIL IS IN THE ANWR COASTAL PLAIN?

The decision to allow or block leasing of the ANWR coastal plain depends on balancing the poten-tial damage that expiration and development may cause the wilderness, wildlife, subsistence, andother values with the value of the potential oil resources, Resource estimates for undrilied regionsare notoriously subjective and inaccurate, however, and Congress should view the Department ofInterior’s estimates of ANWR resources as “best guesses” rather than as accurate measurements,Nevertheless, the methods and assumptions used by DOI can be reviewed objectively, and anevaluation can be made of the degree to which the estimates may be conservative or optimistic.OTA has examined DOI’S documentation of its economic assessment and reviewed critiques of theassessment. In our view, the assessment is more likely to have produced results that are conserv-ative, that is, resuits that are more pessimistic about the likely recoverable oil than the evidencesuggests. OTA did not review DOI’s geologic assessment that produced estimates of total in-placeoil, but we note that this assessment is substantially more optimistic than the assessment producedby the State of Alaska. Because the estimate of total recoverable resources reflects both thegeologic assessment of in-place resources and the economic assessment of recoverability, OTA isreluctant to conclude that DOI’s estimate of total recoverable oil resources in the ANWR coastalplain is either conservative or optimistic. On the other hand, we conclude that DOI’s estimate of thelikelihood that economically recoverable quantities of oil will be found in ANWR –19 percent atworld oil prices of $35/bbl (1984 doilars) – probably is overly pessimistic.

Opponents of development have argued that the DOI estimates of ANWR resources are overly op-timistic because DOI assumed unrealistically high world oil prices –$35/bbi (1984 dollars) refineryacquisition costs by the year 2000 with a continued growth in “real’ prices beyond 2000 of 1 per-cent per year. ’f Because the size of the “minimum economic field” –the smallest oilfield that couldsupport the pipeline and other facilities needed to produce and transport ANWR oil – is inversely de-pendent on oil prices, lowering the assumed prices would tend to increase the minimum field sizeand thus reduce the estimated probability of finding commercial quantities of oil in ANWR. Lower-ing the assumed oil price would also affect the estimated volume of recoverable oil. However, theeffect appears somewhat pewerse because the estimated “mean” voiume of oil, assuming thateconomic amounts are found, actuaily increases if assumed oil prices are lowered. This counterin-tuitive effect occurs because reducing the minimum field size adds a number of lower-resourcepossibilities to the universe of resource possibilities sampled by DOJ’s probabilistic model, Inreality, of course, if economic quantities of oil exist In ANWR, a lower oil price would tend todecrease the volume of oil recovered.

The assumed oil price is only one of several factors that may affect the reliability of the economicassessment. These factors include:

1. Including or excluding ‘Sunk Costs. "2 /n determinating the mi’nimum economic fieid size(MEFS), the costs of exploration and delineation weils are included in the total costs thatmust be balancecf by the economic value of the oil found. Assuming that a company pur-chases a iease and begins exploration, if it then discovers a field it will treat ail prior costs–inciuding the costs of exploration –as sunk in determining whether or not to proceed withcommercialization. Hence, an oii company may choose to proceed with development even

1, J.S, Young and W,S, Hauser, Economice of Oil and Gas Production From ANWR for the Determination of MinimumEconomic Field Size, 8ureau of Land Management Report PT-87415-3120-9S5.

2. Sunk costs are costs that have already been inourred and cannot be reoove red if the project fails.

104 ● ANWR

If the total costs exceed the economic value of the oil. The DOI assumption Ignores this pos-sibility.

2. Including or excluding the possibility of 6ciu$ters* of small fields. The AKFS is calculatedon the bw% of its stand-alone prospects. {n other words, each prospect is evetuated on thebask of its ability to pay for afi of the infrastructure necessary to develop the field, includingthe main p]pethe to TAPS Pump Statian #l in the Prudhoe Bay area. tn reality, two or morefields can share the costs of production faciilties, the main pipeline, and other infrastructurecosts. Aiso, offshore development In the Beaufort Sea could share infrastructure costs withonshore fieids.3 Consequently, there Isa realistic possibility-Ignored by the DOI quantitativeanaiysis–that ANWR 011 couid be developed even though no single field exceeds the MEFS.

3. Selection of the assumed tax and royaitysystem. Theincorne M.xespa/dbya fielddeveloperwe calculated using the terms of the taxsystempriorto the 1986 changes in the taxkw. Theseterms inciude aliowance of investment tax credits, 80 percent expensing of intangible drillingcosts, ACRS depreciation for 5~year property for tangibie drilling costs, and a 46 percentFederal income tax rate. The indust~ has ciaimed that the resuit of the 1986 changes, onbalance, has been to reduce the incentive to find and develop rwwfie[ds. Thus, using currenttax rules might tend to lower the estimated oii potential M ANWR.

4. Assumed Oilfieid costs. The estimated cost$of driliing, buiiding the pipeiine, and dher neces-sary construction and operations are based on the 1981 National Petroieum Cotincii report onArctic oil and gas,4 supplemented with other data. According to industry reports, experienceof the past few years–especially foilowing the severe oil price drop of 1985/86-hasdemonstrated that the costs of Arctic operations can be reduced significantly, For example,both ARCO and the Standard Alaska Production Company ciaim to have reduced developmentdriliing costs sharply by Increasing drilling efficiency. Thus, there is a strong possibility thatthe DOI cost data overstates the likely costs for ANWR fieid development and depresses theestimated oii potentiai.

5. Assumed oil ptice$. in its base case, DOi assumed that worid oii prices would rise to $35/bbiin 1984 doliars by 2000 and wouid then rise in real terms by 1 percent per year thereafter. i301’sanaiysis clearly demonstrates that the estimates of MEFS– and thus the iikeiy resource vaiue -are highly sensitive to the assumed oii price+ For example, for a field in the western portion ofANWR, MEFS is 425 rniilion bbi at a $35/bbi oil price and 1.39 biilion bbl for a $22/bbl oii pricesAlthough DOI’S price assumptions have been severely criticized, OTA beiieves that oii pricescouid attain this ievei if current forecasts of future world oli demand and supply trends proveto be correct. There are, however, piausibie circumstances that wouid maintain prices sig-nificantly beiow this ievei. in C)TA’S view, the range of piausible year 2000 oii prices is wide–probabiy at least from $22 to $40 per barrel in 198? doliars–and there is no way to select a“most iikeiy” price that could achieve any kind of consensus.

& Inclusion or exclusion of geologic targets. The DOI recoverable resource analysis isrestricted to the 26 largest structural prospects identified by the im?ial geophysical suiveys ofthe area. As noted in DOi’s ANWR Resource Assessment,6 additional amounts of economical-ly recoverable oii may be present in smaiier structural traps and in so-called stratigraphic traps

3. Thesefactmsared isoussed in the Departmentcifthe lnteriot, Arctic IUationalwlldlife Refuge, Maska, Coastal Plain Resource*sessment, l@ril 19S7.

4. National Petroleum Council, U.S, Arotb 01 and Gas, Oecember 19S1.5, Young and Hauser, op.dt., Box 3-B, footnote 1,6. U.$. Deptient of the Interior, Arotic National wildlife Refuge, Alaska, bastal Plain Resource Nwessment, April 1967.

Chapter 3 ● 105

that were not identified by the available geophysical? information. Including these additionalprospects should increase the estimated values of both the probability of finding economical-ly recoverable oil in ANWR and the mean recoverable resource.

The first, second, fourth, and sixth factors tend to understate the likely oil potential in ANWR; thethird tends to overstate it; and the fifth gives no clear direction. Overall, OTA believes that i)O1’seconomic evaluation of ANWR oil potential is likely to be too pessimistic, especiaMy withregard to the probability of finding a field of commercial size.

The DOI assessment of ANWR’S oil potential is dependent on both the economic and geologic as-sessments, however. The geologic assessment prepared by the State of Alaska is more pessimis-tic than DOI’s geoiogic assessment. For example, the State estimated the “50th percentile”in-place resource to be 3,77 billion barrels (that is, there is a 50 percent chance that there are atleast 3.77 billion barreis of in-place resources) versus DOI’s estimate of 11.9 billion. The primaryfactors causing the disagreement are sharply differing views of the likelihood of finding largevolumes of oil-bearing Ellesmerian rocks in the coastal plain (the State largely discounts the role ofthe Ellesmerian) and differing estimates of success rates for indhddual wells (the State expectstower success rates than does DOI). Given the judgmental character of the estimates and the lackof drilling data, this level of disagreement is not at all unusual. However, the State’s estimateswould imply a much lower resource value for the ANWR coastal plain than the value assigned byDOI.

The Energy Information Administration (EIA) also has examined the DOI assessment of economi-cally recoverable oil in the coastal plain. EIA concfuded that 1)01’s assessment of in-place re-sources was reasonable, but it disagreed strongly with 001’s evaluation of the risk of findingeconomically recoverable oil and also disagreed with DOI’S assessment of the likely magnitude ofany recoverable resources. In particular, EIA rejected DOI’s estimate that there is only a iS per-cent probability of finding oil in economically recoverable quantities; instead, EIA concludedthat the probability of finding economically recoverable oil in ANWR is very high. EIA projectsthe likely economically recoverable oil in ANWR (at DOI’s assumed oil prices) to be 3.4 billionbarrels, with little likelihood (compared to DOI's 81 percent likelihood) that nothing will berecovered. OTA generally agrees with ElA’s qualitative assessment of 001’s economic evaluation,We note, however, that ElA’s alternative methodology for estimating ANWR recoverable resourcesis unsophisticated, relying on a simple extrapolation of the recovery rates of known North Slopefields. On the other hand, given the limited data on ANWR, ElA’s slmple approach may prove justas accurate as the more detailed approach of DOI.

7. Energy Mformation Administration, Potential Oil Production from the Coastal Plain of the Arctic National Wildlife ~fi9etrevised edition, SwRNGD/87-01, In its re rt, EIA arrived at essentially the same qualitative conclusions about the details of

rDO1’s eoonomic analylis as OTAdid and as discussed them in more detail.

Appendixes

Appendix AMethods of Estimating Discovered In-Place

Resources and Reserves

An estimate is only as good as the quality andquantity of the data available at the time it ismade. Estimating either in-place resources,recoverable resources, or reserves is inherentlydifficult because petroleum engineers cannot seethe reservoir. Typically they must rely on indirectmeasurements (e. g., from well logs and cores,seismic work, regional geology, etc. ) that supplythem with only a partial picture about the shapeand characteristics of the reservoir. As moredata become available through exploratory drill-ing, development drilling, and production, earlyestimates can be refined, Reserve estimatesoften grow with time. For instance, accumulatedinitial domestic reserve estimates have averagedabout 50 percent of final estimates. Also, there isa tendency to overestimate small discoveries andto underestimate large ones’ (estimates of Prud-hoe Bay’s reserves have indeed grown over time,but estimates of original reserves (i.e., of ultimaterecovery) appear to be converging on 12 billionbarrels).

Several methods are available for estimating in-place resources. The volumetric method, for in-stance, is one of the simplest ways of calculatingin-place resources and is useful when not muchdata are available. In the volumetric method,seismic and drilling information are used to deter-mine the structure, areal extent, and thickness ofpotential reservoir rocks. A rough estimate of thebulk rock volume of the resewoir can then bemade. In addition, estimates are made of theaverage porosity and water saturation of thereservoir and of oil and gas volume factors re-lated to the reservoir’s pressure and temperature.Knowledge of the porosity–a measure of theamount of void or pore space in a rock– enablesthe reservoir engineer to estimate the amount offluids the reservoir is capable of holding.Knowledge of average water saturation within thepore spaces allows engineers to determine how

much of the pore space is not occupied by waterand could contain oil and/or gas. Once es-timates of bulk volume, average porosity, watersaturation, and oil/gas volume factors have beenobtained, a calculation of the in-place resourcecan be made.

Estimates made using the volumetric methodmay vary widely depending on the amount of in-formation available. If data are derived from onlya few wells or from the results of pre-driiling sur-veys, the best one can do is assume uniformthickness, porosity, and water saturation forvarious segments of a reservoir. In reality, reser-voirs are usually complex: for example, thick-ness, porosity, and water saturation may all varyconsiderably; faulting introduces barriers to flow,as do low permeability zones; and oil and gaswithin the gross reservoir may be in unconnectedcompartments. Hence, if the geological inter-pretation is not correct or not sufficiently precise,the result of gross volumetric calculations will bewrong.

A second technique sometimes used to obtainestimates of in-place resources (and reserves aswell) is the material balance method. A materialbalance calculation relies on the assumption thata petroleum reservoir can function as a largeclosed tank containing oil, gas, and water. Bymeasuring the change in pressure after variousknown increments of production, it is possible tocalculate the original in-place amounts of oil, gas,and water.2 A principal weakness of this methodis that reservoirs are treated as a single unitunder constant pressure. Typically, however,pressure will vary considerably throughout areservoir. Treating the reservoir as an undifferen-tiated unit, therefore, may not adequately modelthe reservoir.

1, Rival op. cit., p, 126.2. Riva, op. cit., p. 125,

109

110 ● ANWR

Several techniques are also used for estimatingrecoverable oil and gas. A rough estimate ofrecovery can be made using the analogy method.For this technique, one can simply apply arecovery factor to in-place resources. A recoveryfactor is the percentage of in-place resourcesthat are expected to be recoverable in a reser-voir, and the factor used to estimate recoverablevolumes from a given reservoir is one associatedwith another reservoir having a recovery factorknown from production history and characteris-tics similar to the one being investigated.

A second recoverable resource estimationtechnique is decline curve analysis. Peakproduction must already have taken place toproperly use this technique. From a study of theproduction trend over time, a mathematicalrelationship can be established. Using thisrelationship, one can then project production intothe future to the point where further productionwould no longer be economically feasible. Thetotal production over time constitutes the ul-timately recoverable oil and gas. A weakness inthe decline curve method is that it is only indica-tive if wells are allowed to produce at their maxi-mum (unrestricted) rate. If the flow rate isrestricted, either by company policy or State orFederal regulations, the decline curve will show adownward trend in time that will not truly reflectrecoverable oil and gas.3

The most sophisticated technique used to esti-mate recoverable oil and gas is reservoir si-mulation. In setting up a simulator, all availableinformation on reservoir and fluid characteristicsis used. Unlike the material balance method inwhich the reservoir is considered to function as asingle tank, reservoir simulation more systemati-cally considers the reservoir as an aggregate ofmany cells, each with its own parametric values,such as fluid saturations, permeabilities, pres-sures, etc. Using all the data, flow equations aredeveloped for a reservoir which match thereservoir’s history. These equations are thensolved, using computer processing, to estimaterecoverable resources. Typically, reservoirsimulators are quite expensive to develop andare developed only for the largest fields. The

Prudhoe Bay field, the country’s largest, hasbeen simulated using the best available methods.

All estimation techniques have their shortcom-ings. Specifically, one must always keep in mindthat 1 ) although estimates may make use of thebest available data, the availability and quality ofdata for oil and gas estimates are often limited,and 2) the estimate is usually based on a numberof simplifying assumptions about the reservoircharacteristics and/or future trends in price andtechnology development.

In addition to the inherent difficulty of makingaccurate resource and reserve estimates, dataaccess problems hamper the accuracy, or atleast the credibility, of published estimates.Published reserve estimates made by such agen-cies as the Alaska Oil and Gas ConservationCommission; the Alaska Department of NaturalResources, Division of Oil and Gas; and the U.S.Department of Energy’s Energy Information Ad-ministration all ultimately rely on data supplied bythe oil and gas industry. Although some oil com-pany data must by law be released to these andother State and Federal agencies which make es-timates and regulate the oil industry, much in-dustry data is proprietary. Estimates that the oilcompanies themselves make are generally notpublicly available. Moreover, oil companiesusually are not willing to be too precise about es-timates they do release. Typically, a companywill confirm that recoverable resources, for ex-ample, are likely within a specified range, butthey are reluctant to go further. Hence, publicestimates, even if in the same range as theindustry’s estimates, are usually not based on allthe information to which the oil companies haveaccess.

The oil and gas business is competitive, andproprietary knowledge represents an advantage.Among the reasons for industry’s desire to keepinformation proprietary are that: 1 ) a competitorwith precise knowledge of a company’s reservesestimate could gain an advantage in future leasesales in the area; 2) estimates, even by the com-panies themselves, are at best only approximate;hence, publication of a resewe estimate that laterturned out to represent falsely company assets

3. Robert Hubbell, reservoir engineer, Golden Engineering, personal communication, Dec. 23, 1987.

Amendix A ● 111

could significantly affect investors or potential in-vestors; and 3) a company’s oil and gas resetvescan be the object of hostile takeover attempts.

An additional caveat in comparing estimatesmade by different groups (particularly of reservesor recoverable resources) is that the assump-tions on which each estimate is based may notbe–in fact, usually are not– made explicit. Suchassumptions usually include the projected priceof oil, the amount of capital investment plannedfor the field, and the type of secondary or en-

hanced oil recovery techniques expected to beused. Also, it is sometimes difficult to determinewhich portion of a reported resewes estimate isproved and which is only inferred or potential(some North Slope estimates include bothproved and potential reserves). This greatlycomplicates attempts to compare alternative es-timates of reserves. Also, unless all reserve es-timates are accounted to the same time for aspecific field or group of fields, estimate com-parisons will not be valid.

-—

Appendix BEstimation Methods for

Undiscovered Resources

The purpose of any resource estimate is toproduce the best possible guess about the extentof resources in the absence of data which wouldallow one to calculate a more precise figure.Reasonably accurate data about oil and gasresources can only be generated through exten-sive drilling; however, geological and geophysi-cal information prior to extensive drilling andpreliminary exploratory drilling at a later stagedoes provide information which can be used forgaining some insight into the amount of resour-ces in an area. This information can be used toestimate resources. Methods have been devel-oped to estimate both undiscovered, in-placeresources and economically recoverable re-sources. Geological factors are the main con-sideration in estimating in-place resources;estimates of economically recoverable oil andgas must take into account various economicand technological factors and regulatory policyas well.

Although methods for estimating resourceshave become sophisticated, estimates are onlyas good as the data used to produce them. Anestimate may represent the best appraisal thatcan be made at the time, but only by the greatestof luck will the amount of resources eventuallyfound in an area be similar to the amount original-ly estimated. As relevant today as in 1934 is J.T.Hayward’s remark, “... we must not fall into theerror of believing that because we have attacheda number to a chance that we have thereby madea successful issue more sure, or have in any wayaltered its probability. Further, we must be everon the watch for that most insidious andwidespread superstition that assumes that math-ematical manipulation, if sufficiently accurate, in-volved, and prolonged can transmute doubtfuldata into positive scientific fact.”l

In a recent study of hydrocarbon estimationtechniques the National Research Councilpointed out that the quality of an estimate of un-discovered resources is highly dependent upon:1 ) the quantity and quality of the geologic infor-mation available; 2) the knowledge, experience,and awareness of the group making the estimate;3) the appropriateness of the estimationmethodology; and 4) (for estimates of economi-cally recoverable resources), the economic as-sumptions used. Moreover, they noted thatusers of any resource estimate must recognizeits probabilistic nature and resulting inherent un-centainty. 2

The variability between estimates made by dif-ferent people using the same method (as well asbetween estimates made using different techni-ques) can also be wide. This is so because eachmodel calls for a number of subjective inputs.For example, many models depend in one way oranother on the use of geologic analogy. Differ-ences of opinion easily can exist over whatgeologic analogy is most appropriate. When lit-tle information is available, structural geologyand stratigraphy can and are interpreted dif-ferently. For example, in evaluating the resourcepotential of the Arctic National Wildlife Refuge,geologists from the State of Alaska and from theDepartment of the Interior used similar playanalysis methods; however, they identified theplays differently.

A number of methodologies have been devisedto help estimate, with limited data, the expectedamount of resources in an area. Some of themethods are fairly crude; others are quite sophis-ticated, although again it must be stressed thateven the most sophisticated methods produceonly estimates, and many of these estimates re-quire numerous assumptions and much subjec-

1. J.T. Hayward, “Probabilities and Wildcats Tested Through Mathematical Manipulation,” Oil and Gas Journal, vol. 33, No. 26,Nov. 15, 1934, pp. 129-131.

2. National Research Council, Offshore Hydrocarbon Resource Estimation, p. 7.

113

114 ● ANWR

tive input. Five basic types of assessmentmethods are currently in use. These include:

1.

2,

3.

4.

5.

The

Areal and volumetric yield methods in com-bination with geologic analogy. Thesetechniques range from worldwide averageyields applied uniformly over a sedimenta~basin to more sophisticated analyses inwhich the yields from a geologicallyanalogous basin are used to provide a basisof comparison.

Delphi or subjective consensus methods.In this approach, the estimation ofpetroleum resources is the consensus of ateam of experts who review all the geologicinformation available in an area or basin.

Historical performance or behavioristicmethods. These methods are based on ex-trapolating historical data, such as dis-covery rates, drilling rates, productivityrates, and known field size distributions.

Geochemical material balance methods.These methods are used to estimate howmuch oil or gas was generated in sourcerocks of a given area, how much was in-volved in migration, probable losses duringmigration, and the quantity that accumu-lated in deposits.

Integrated methods. These methods use acombination of some or all of the above andincorporate geological and statisticalmodels. 3

integrated methods, such as play andprospect analyses, are the most sophisticated.Play analysis methods have become popular inrecent years for assessing conventionalpetroleum resources in identified or conceptual

exploration plays in a basin or province.4 Thesemethods produce a range of estimates related tothe probability of occurrence of certain amountsof oil rather than a single estimate of resourcesexpected in one or more plays. Since much ef-fort has been expended by State and Federalresource agencies applying these methods to es-timating the resources of both the NationalPetroleum Reserve in Alaska and the Arctic Na-tional Wildlife Refuge, these methods and the as-sumptions that go into them will be described ingreater detail.

In-Place Resource Models:RASP and FASP

In-place oil and gas resources include all cate-gories of resources still in the ground, that is,those that are considered to be economicallyrecoverable, those that are technically but noteconomically recoverable, and those that cannotyet be technically or economically recovered. ln-place resources, usually expressed in terms oforiginal in-place volumes, constitute the resourcebase. Roughly 10 percent to at most 50 percentof in-place oil resources in any given resourcearea can typically be economically recoveredusing currently available technology and techni-ques. Estimates of in-place resources dependupon the interpretation of the geology, economicfactors being irrevelant.

Play and prospect analysis models for assess-ing in-place resources include the Resource Ap-praisal Simulation for Petroleum (RASP) and theFast Appraisal System for Petroleum (FASP).RASP has been used by the U.S. Geological Sur-vey to assess resources in both the NationalPetroleum Reserve in Alaska (1979) and in the

3. Betty M. Miller, “Resouroe Appraisal Methods: Choioe and Outmme,” in Oil and Gas Assessment-Methods and Applications,MPG Studies in Geology #21, Dudley D. Rice (cd.) (Tulsa, OK: American Association of Petroleum Geologists, 19S6), pp. 2-5.

4, Ibid,, pp. 4-5.

—.

pendix B ● 115

Arctic National Wildlife Refuge (1980 ).5 Morerecently (1986) the State of Alaska used theRASP methodology to estimate resources inANWR. 6 And the newer FASP method, which ismore efficient but produces similar estimates,was used by the Department of the Interior in1986 to estimate in-place resources in ANWR.7

Both methods are based upon the samegeologic model and employ the same probabilityassumptions. 8 However, RASP employs a MonteCarlo simulation technique which typically re-quires 3000 to 5000 repetitions while FASP is ananalytic method which uses statistical techniquesand probability theory rather than simulation andthereby greatly speeds up and reduces the costof the estimation process.

Both methods make extensive use of the judg-ment of geologists familiar with the geology ofthe area. In undrilled areas, geologists mustdepend on surface geology and geophysicaldata and consider possible geologic analogieswith other areas when they make their appraisals.For each identified play (group of geologically re-lated prospects with similar hydrocarbon sour-ces, reservoirs, and traps) within an assessmentarea, RASP and FASP require that geologistsjudge the probability that a hydrocarbon sourceexists, that the timing of oil formation has beenfavorable, that oil migration from source to trapshas been successful, and that the trap containsreservoir grade rock. The product of these fourregional geological characteristics (assuming theprobability of each occurring is independent ofthe others’ occurrence) jointly determines themarginal probability– the probability that the playcontains hydrocarbon accumulations.

Expert judgment is likewise called for at thelevel of individual prospects, the untestedgeologic features having the potential for trap-ping and accumulating hydrocarbons. Theprospect attributes are the geologic characteris-tics common to the individual prospects within aplay. Geologists must assess the probability ofthe existence of a trapping mechanism for theprospects, the likelihood that effective porosityexceeds a certain amount, and the probabilitythat oil and gas exist in at least 1 percent of atrap, The product of these probabilities (againassuming independence) is the probability that aprospect is a deposit, but it is conditional uponthe favorability of the play. Together the marginalplay probability and the conditional deposit prob-ability are the risk factors. If all attributes com-prising these risk factors are favorable, it is likelythat there will be hydrocarbons in at least someof the prospects within the play.

A third set of judgments is needed to determinehow much oil may be contained in eachprospect. Geologists are asked to estimate therange of possible values for each of five volumeattributes (area of closure, reservoir thickness, ef-fective porosity, trap fill, and reservoir depth) andto assign the probability of a given value to one ofseven categories. For example, a geologist mayestimate that there is a 100 percent probabilitythat the reservoir thickness of a deposit is greaterthan or equal to 50 feet, a 75 percent probabilitythat the thickness is greater than 80 feet, and a 25percent probability that the thickness is greaterthan 100 feet. From these estimates, a prob-ability distribution for each of the volume at-tributes can be made. A range of values is alsoestimated for the number of drillable prospects ineach play, And finally, geologists are asked to as-

5. Kenneth J. Bird, “A Comparison of the Play Analysis Technique as Applied in Hydrocarbon Resource Assessments of theNational Petroleum Rtserve in Alaska and the Arctic National Wild like Refuge, ” in Oil and Gas Assessment – Methods and Applications,Dudley D. Rice (Tulsa, OK: American Association of Petroleum Geologists, 1986), pp. 133-142.

6. J.J. Hansen and R.W. Kornbrath, “Resource Appraisal Simulation for Petroleum in the Arctic National Wildlife Refuge, Alaska,”Professional Report 90 (State of Alaska: Department of Natural Resources, 1986), pp. 1-13.

7, U.S. Department of the Interior, Arctic National V41dlife Refuge, Alaska, Coastal Plain Resource Assessment (Washington, DC:U.S. Fish and Wildlife Service, U.S. Geological Survey, and Bureau of Land Management, 1987). See chapter Ill, “Assessment of Oiland Gas Potential and Petroleum Geology of the 1002 Area, ” pp. 55-81.

8. Robert A. Crovelli, “An Analytic Probabilistic Methodology for Resource Appraisal of Undiscovered Oil and Gas Resources inPlay Analysis, ” U.S. Geological Survey Open File Report 85-657, 1985.

116 ● ANWR

Figure B.l.— Flow Chart of Simulation Method for Play Analysis

I Select dav b

Sample marginalplay probability

*1 I

1

Zero resources Yes +

for play * Dry play?

1 No

+I Select prospect

I

Zero resources Yes +

for prospect Dry prospect?I

SOURCE:

Sample hydrocarbonvolume attributes

iI Calculate resources I

+ +

iLast prospect?

No1

i Yes

I 1

Ii

Last pass?No

I

i Yesr ,

Form playdistributions

tLast play? No

1 Yes

Robert A CrovellI, “A Comparison of Analyhc and Simulation Methods for Petroleum Play Analysls and Aggregation “ U SGaologlcal Survey Open-File Reporf 86-97 1985

* Pendix B ● 117

sess the likely reservoir characteristics andhydrocarbon mix.

If RASP is used, a simulation is run using theprobabilities estimated in the geologic model(figure B-l). First, the marginal play probability issampled. If the sampled play is “dry,” zeroresources are assigned to that play on that pass.If the play is not dry, the number of prospects inthe play are sampled. Then each of theprospects in the play are examined in turn. Sam-pling the conditional deposit probability for eachprospect determines whether the prospect is dryor contains oil and/or gas. If hydrocarbons aresimulated as present, each of the hydrocarbonvolume attributes are sampled, and the resourceswithin the prospect are calculated using standardreservoir engineering equations. After the lastprospect within the play is sampled, the resour-ces are totaled for that play, and the simulationproceeds to the next play. The process isrepeated until all the plays have been examined.The resource estimates for all the plays aresummed to obtain the total amount of simulatedoil in the assessment area. The simulation is thenrerun as many as 5,000 times. Probability dis-tributions can then be derived by ranking resultsfor each ass and dividing the rank ordering intofractiles. 8

The simulation method is easier to understandthan the analytic method, but the outcomes aremuch the same. In the FASP analytic method,the simulation is replaced by a statistical proce-dure which calculates means and variances ofthe same geologic variables to derive an estimatefor one play (figure B-2). Results for individualplays are then aggregated using the aggregationmodel FASPA. Comparisons of RASP and FASPhave been made, and results show excellent

10 The analytic method, however, ‘asagreement.some advantages. A principle one is that it isthousands of times faster. The cost to run theprogram is therefore negligible and FASP can be

rerun frequently, incorporating new data as avail-able. The analytic method is also potentiallymore useful because it produces mathematicalequations of probabilistic relationships involvingpetroleum resources.

Estimating EconomicallyRecoverable Undiscovered

Resources: PRESTO

Models have also been developed to estimatethe amount of undiscovered but economically re-coverable resources in a given area. In par-ticular, the Minerals Management Service’sPRESTO (Probabilistic Resource Estimates-Of-fshore) model (now in its third version) has beenused to estimate undiscovered, economicallyrecoverable resources in arctic offshore areasand, recently, in the Arctic National WildlifeRefuge. Conceptually, the model has much incommon with RASP, in that it incorporates MonteCarlo simulation, ranges of values for volumetricinput parameters, and risk analysis.l 1 The mostimportant unit of analysis used to derive PRESTOestimates is the prospect, or individual potentialoil or gas field. As in RASP, marginal and condi-tional risks are determined. The marginal basinrisk is the probability that no prospect within agiven basin contains hydrocarbons; the condi-tional prospect risk is the probability that an in-dividual prospect modelled is “dry,” conditionalupon the basin containing at least someeconomically recoverable hydrocarbons. Theserisks are determined by geologists using all avail-able geological and geophysical data. Needlessto say, in undrilled and largely unexplored areas,the data are usually scanty. Moreover, PRESTO,like other resource estimation models, uses thejudgment of experts when “hard” data are un-available. Identification and characterization ofprospects, for instance, calls for significant sub-jective input in the absence of substantial drilling.

9. For additional information about RASP and FASP see Bird, “A Comparison of the Play Anal sis Technique...”; Hansen andKornbrath, “Resource Appraisal Simulation for Petroleum...”; 2and L,P. White, “A Play Approach to Hy rocarbon Resource Assessmentand Evaluation, ” in Oil and Gas Assessment– Methods and Applications, AAPG Studies in Geology #21, Dudley D. Rice ed, (Tulsa,OK: American Association of Petroleum Geologists, 1986), pp. 125-132.

10. R.A. Crovelli, “A Comparison ofltnalytic and Simulation Methods for Petroleum Play Analysis and Aggregation,” U.S. GeologicalSurvey Open-File Report 8&97, 1986.

11. L.W. Cooke, “Estimates of Undiscovered, Economically Recoverable Oil and Gas Resources for the Outer Continental Shelf AsOf July 1984.” U.S. Department of the Interior, Minerals Management Service, 198S, p, 9.

118 ● ANWR

Figure B-2. —Flow Chart of Analytic Method of Play Analysis

+Fractiles of

hydrocarbon volumeattributes

L J 1

Ib

+

I I 1 1I I

4

.—

Using risk factors and Monte Carlo simulation,PRESTO simulates an exploratory drillingprogram. For each PRESTO trial, every prospectin the basin is “drilled, ” and discovered resourcesare summed to determine an area total. Thesimulation is repeated as many as 5000 times,and results are sorted, ranked, and divided intopercentiles. Output includes the conditional 95percent, 5 percent, and mean resource estimatesfor oil and gas and the corresponding probabilityof economically recoverable hydrocarbons afteraccounting for the possibility that there may beno hydrocarbons in the area (the ‘(risked” es-timates).

The major difference between RASP and PRES-TO is that PRESTO incorporates economic fac-tors into the model. Thus, not only does PRESTOdetermine the amount of resources in eachprospect, it determines whether the resourceswithin each prospect are large enough to warrantdevelopment. To accomplish this, PRESTO usesa single point estimate of the minimum economicfield size (MEFS) required for development in thearea. The MEFS is derived from MONTCAR, adiscounted cash flow analysis program. An im-portant consideration in determining MEFS is theassumed price of oil – as the price of oildecreases, the MEFS increases. Other importantconsiderations include development and operat-ing costs, and distance from markets,

Significantly, the prospect’s resources areadded to the total for the area only if the MEFS is

exceeded for the prospect being “drilled. ” But ifthe MEFS is not exceeded, the prospect’s resour-ces are set to zero. Hence, PRESTO estimates ofundiscovered, economically recoverable resour-ces may be conservative. For example, aprospect that, in isolation, is not estimated tocontain enough resources to be developed maynevertheless be developed if there are otherprospects in the area that are large enough todevelop, or even if a number of fields, all belowthe MEFS, are found in close proximity and canshare infrastructure costs. The Lisburne, En-dicott, and Milne Point fields, for instance, wouldnever have been developed were it not for theirproximity to Prudhoe Bay and the TAPS pipeline.PRESTO would have modeled these fields ashaving zero resources, but they are currentlycontributing to TAPS throughput, if only about 5to 10 percent. Likewise, some geologists believethat PRESTO est imates of economical lyrecoverable resources in ANWR are conserva-tive. 12 The MEFS for ANWR as a whole has beendetermined to be about 440 million barrels (for a$33 per barrel price of North Slope oil in 2000(1984 dollars)) . 13 However, given the Possibility

of shared infrastructure costs, recent decliningdevelopment costs, the high probability thatmore prospects than were evaluated in DOI’sANWR analysis will subsequently be identified,and other factors, the estimate of economicallyrecoverable resources do appear too conserva-tive. 14

12. For example, Joe Riva of the Congressional Research Service.13. U.S. Department of the Interior, Arctic National VVlldlife Refuge, Alaska, Coastal Plain Resouroe Assessment, April 1987, p. 79.14. Energy Information Administration, Potential Oil Production from the Coastal Plain of the Arctic National Wtldlife Refuge (Revised

Edition), EIA Service Report, October 1987, pp. 1s17.

Appendix CGlossary

API gravity: The standard American Petroleum in-stitute method for specifying the density ofcrude petroleum. The density in degrees ofAPI equals (141.5 ”P)-131 .5, where P is thespecific gravity of the oil measured at 60° F.

barrel: A common unit of measurement of liquidsin the petroleum industry; it equals 42 U.S.standard gallons.

chemical flooding: An enhanced oil recoverytechnique based upon adding various chemi-cals to the water used in waterflooding inorder to increase waterflood efficiencies.

conditional mean resources: The averageamount of oil and/or gas expected to exist ifat least one of the prospects in an area con-tained economically recoverable accumula-tions of hydrocarbons and if all of theprospects modelled were drilled.

directional dril l ing: Drill ing that has beendeliberately angled away from the vertical.

drilling mud: A special mixture of clay, water, oroil and chemical additives pumped throughthe drill pipe and drill bit. The mud cools therapidly rotating bit; lubricates the drill pipe asit turns in the well bore; carries rock cuttingsto the surface; serves as a plaster to preventthe wall of the bore hole from crumbling or col-lapsing; and provides the weight or hydros-tatic head to prevent formation fluids fromentering the well bore and to controldownhole pressures,

economically recoverable resource estimate:An assessment of the hydrocarbon potentialof a field that takes into account physical andtechnological constraints on production andthe relation of costs and market price.

enhanced oil recovery: See tertiary recovery.

fault: A fracture along which the rocks on one sideare displaced relatively to those on the other.

field: Composed of a single pool or multiple pools

that are grouped on or related to a singlestructural and/or stratigraphic feature. “Pool”is a term meaning a body of reservoir rockcontaining recoverable oil and/or gas.

formation: A rock mass composed of individualbeds or units with similar physical characteris-tics or origin.

gas lift: The effect of either naturally or artificiallyinduced gas pressure in an oil well t hat causesthe oil to flow from the well.

gas/oil ratio: The proportion of gas producedrelative to oil produced from a reservoir(s) orfield(s), usually expressed as cubic feet perbarrel of oil.

gas injection: The process of injecting (or rein-fecting) gas into a reservoir to maintain theproducing pressure.

infill drilling: Drilling at a smaller spacing thancalled for in the original development plan,designed to speed up production and/or in-crease ultimate recovery.

in-place resources: The total amount of oil in afield, only a portion of which will ultimately berecoverable.

inferred, potential reserves: Those resourcesthat should eventually be added to provedreserves through extensions of known fields,revisions of earlier reserves estimates result-ing from new subsurface and production in-formation, and product ion from newproducing zones in known fields.

log, well log: Measurements of the physicalproperties of the drilled section, generallytaken while raising measurement devices upthe wellbore on an electrical cable.

marginal probability: The probability thateconomically recoverable oil and gas resour-ces exist in an area under study.

121

migration: The movement of oil, gas, or waterthrough porous and permeable rock.

miscible flooding: A technique based upon usingsome gas – such as enriched reservoir gas orC02–to miscibly displace some oils, therebypermitting the recovery of most of the in-placeoil contacted.

outer continental shelf: The part of the continen-tal shelf beyond the line that marks Stateownership; that part of the offshore areaunder Federal jurisdiction.

pay: A rock stratum or zone that yields oil or gas.

permafrost: Any soil, subsoil, or other surficialdeposit occurring in arctic, subarctic, and al-pine regions at a variable depth beneath theEarth’s surface in which a temperature belowfreezing has existed continuously for a longtime.

permeability: The degree to which a rock willallow liquid or gas to pass through it.

play: A rock formation or group of formationswithin a sedimentary basin with geologicalcharacteristics similar to those that have beenproven productive. A play serves as a plan-ning unit around which an explorationprogram can be constructed.

pool: A subsurface accumulation of oil and/or gasin porous and permeable rock, having its ownisolated pressure system, Theoretically, asingle well could drain a pool. Also known asa resemoir.

porosity: The proportion of a rock’s total volumeoccupied by the voids between the mineralgrains.

pressure cycling: A technique of injecting naturalgas or CO2 into a producing formation and al-ternating high and low pressures to inducemixing with the crude and thus stimulating theflow.

primary recovery: The fraction of original oiland/or gas in-place that will flow unaided orcan be pumped from the reservoir rock matrixto the surface.

production: Activities that take place after thesuccessful establishment of means for theremoval of oil and/or gas, including suchremoval, field operations, operation monitor-ing, maintenance, and workover driiiing.

proprietary information: Scientific, engineering,and financial data, information, and deriva-tives thereof that are not released to the publicfor a specified term. Federal laws, regula-tions, statutes, or contractual requirementsaffect the terms,

prospect: An area that is a potential site ofeconomically recoverable petroleum ac-cumulation based on preliminary exploration.A play is composed of one or more prospects.

recoverable oil: The sum of proved and potentialreserves. May also inciude estimated undis-covered recoverable oil.

reserves, proved reserves (oil): The portion ofan oil field’s resource base that has been iden-tified by drilling and estimated directly by en-gineering measurements, and that isrecoverable at current prices and technology.

reservoir pressure: The pressure existing at thelevel of the oil and/or gas productive zone ina well.

reservoir rock: A porous and permeable rock,e.g., sandstone or limestone, which containsoil and/or gas that can be produced.

resources: The total amount of oil or gas thatremains to be produced in the future.Generally does not include oil or gas in suchsmall deposits or under such difficult condi-tions that it is not expected to be produced atany foreseeable price/technology combina-tion.

risked mean resources: The product obtained bymultiplying the conditional mean value by themarginal probability that economicallyrecoverable hydrocarbon resources exist inthe area under study.

secondary recovery: Oil and gas obtained by theaugmentation of resetvoir energy, often bythe injection of gas or water into a producingreservoir.

pendix C – Glossary ● 123

show: An indication of the presence of oil or gasin the formations penetrated during drilling.

shut-in: Shutoff, so there is no flow; refers to awell, plant, pump, etc., when valves areclosed. A shut-in well can be returned toproduction, often with some downholecleanup work.

source rock: Sedimentary rock in which organicmaterial under pressure, heat, and time wastransformed to liquid or gaseous hydrocar-bons. Source rock is usually shale or lime-stone.

stratigraphic trap: A trap for oil and/or gas, result-ing from changes in rock type, porosity, orpermeability, that occurs as a result ofsedimentation and diagenetic processesrather than from structural deformation.

structural trap: A trap for oil or gas resulting fromfolding, faulting, or other rock deformation.

tertiary recovery: Oil recovered using advancedtechniques beyond secondary recovery tech-niques. Techniques include injection of steamor of other injected substances, such as richmiscible gas, carbon dioxide, polymers, sol-vents, surfactants, micellar fluids, or evenmicroorganisms.

thermal recovery/stimulation: A petroleum re-covery process that utilizes heat (in the formof steam or hot gas) to thin viscous oil in anunderground reservoir and allow it to flow

more readily toward wells through which itcan be brought to the surface.

trap: Any barrier to the upward movement of oilor gas that allows either or both to accumu-late. A trap includes reservoir rock and over-lying impermeable cap rock.

viscosity: That prope~y of a fluid which deter-mines its rate of flow. As the temperature ofa fluid is increased, its viscosity decreases,and it therefore flows more readily.

waterflood: A secondary-recovery operation foroilfields in which water is injected into apetroleum reservoir to force more oil to theproducing wells.

work-over: A term applied to any remedial opera-tion performed on a well after completion.

undiscovered, economica Ily recoverableresources: Quantities of economicallyrecoverable oil and gas estimated to exist out-

side known fields.

undiscovered, in-place resources: Quantities ofoil and gas estimated to exist outside knownfields, without reference to technological or

economic factors.

wellhead: The equipment used to maintain sur-face control of a well. It is formed of thecasing head, tubing head, and Christmas tree(assemblage of valves, gages, fittings, etc.).Also refers to various parameters as they existat the wellhead: wellhead pressure, wellheadprice of oil, etc.