Oil Production in the Arctic National

Wildlife 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 Arctic

National 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 Marine

and Fisheries and the Senate Committee on Energy and Natural Resources for an examination

of some technical issues concerning the potential future development of oil resources within the

coastal plain of the Arctic National Wildlife Refuge (ANWR) in northeastern Alaska. Because

geologists suspected that large quantities of oil might lie beneath the coastal plain, Congress had

earfier exempted the plain from a Federal Wilderness designation given to about 8 million acres

within ANWR. The U.S. Department of Interior has released a “legislative environmental impact

statement” recommending the immediate leasing of the entire coastal plain for oil exploration

and development. Upon release of that report, the plain’s future became the focus of a highstakes debate among a variety of environmental, business, Alaskan native, and government

groups 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 from

full-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 of

issues ranging from the environmental impacts of oilfield exploration, development, and production in an Arctic environment to the economic and national security benefits of potential additional oil production in Alaska. These issues have been explored in a wide-ranging series of congressional hearings sponsored by four House and Senate committees, reports issued by business

and environmental groups, executive branch reports, and a series of studies conducted by the

Congressional Research Service and the General Accounting Office.

This report presents the results of an assessment of a subset of these issues focusing in particular on: the oilfield technology being used to develop the Alaskan North Slope’s oil resources

and the likely configuration of that technology as it might be applied in the future to the coastal

plain; and the prospects for future North Slope oil production, especially the likelihood that the

flow of oil through the Trans Alaskan Pipeline System will suffer a serious decline during the next

decade.

A forthcoming OTA assessment, scheduled for release in the fall of 1989, will assist Congress

in addressing a third issue--ANWR’s potential role in future U.S. liquid fuel supplies. The assessment (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 potential 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 Staff

Oil Production in the Arctic National Wildlife Refuge

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Peter D. Blair

Energy and Materials Program Manager

Steven E. Plotkin, Project Director

Project Staff

Peter Johnson, Arctic Oilfield Technology

William Westermeyer, /Vorth Slope Production

Contributors

Lynn M. Powers, Editor

Administrative Staff

Lillian Chapman, Administrative Assistant

Linda Long, Administrative Secretary

Phyllis 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 Energy

Mr. Earl H. Beistline, Fairbanks, Alaska

Ms. Kristine Benson, Alaska Center for the

Environment

Mr. Jan Beyea, National Audobon Society

Mr. Rex Blazer, Northern Alaska Environmental

Center

Mr. Mike Bradshaw, CONOCO, Inc.

Ms. Lynne Corn, Congressional Research Service

Mr. William Dietzmannl Energy Information Administration, Dallas Texas

Mr. Roger Doughty, ARCO Oil and Gas Company

Dr. Daniel A. Dreyfus, Gas Research Institute,

Mr. Brock Evans, National Audobon Society

Mr. Chris Flavin, Worldwatch Institute

Mr. Don Forcier, General Accounting Office

Mr. Brad Fristoe, Alaska Dept of Environmental

Conservation

Dr. W. Tom Georold, Wilderness Society

Mr. Ozzie Girard, U.S. Geological Survey

Mr. W.A. Harms, Exxon Company U.S.A.

Ms. Leone Hatch, Trustees for Alaska

Dr. Robert Hirsch, ARCO Oil and Gas Company

Mr. Donald E, Hyer, Texaco U.S.A.

Mr. R. Ken Knight, UNOCAL Corporation

Dr. David Lee Kulp, Ford Motor Company

Ms. Judy Lakind, U.S. Environmental Protection

Agency

Mr. J. E. Little, Shell Oil Company

Dr. Jessica Mathews, World Resources Institute

Mr. Edward H. Mergens, Shell Oil Company

Ms. Sharon Newsome, National Wildlife Federation

Dr. Richard Rowberg, Congressional Research

Service

Ms. Lisa Speer, Natural Resources Defense

Council

Mr. Steven Taylor, Standard Alaska Production

Company

Mr. Bill Van Dyke, Alaska Department of Natural

Resources

Dr. John Wood, Energy Information Administration

Mr. Brooks Yeager, Sierra Club

Dr. Robert Williams, Princeton University

Many other individuals reviewed and made comments on sections of the report. In particular, OTA wishes

to thank Carl Behrens, Congressional Research Service, David Campbell, National Wildlife Federation,

Paul Deissler, Houston, Texas, E. Kaarlela, Bureau of Land Management, Lawrence Kumins, Congressional Research Service, Helmut Merklein, Energy Information Administration, James Mielke, Congressional Research Service, John Moore, Congressional Research Service, John Pearson, Energy Information

Administration, Joseph Riva, Congressional Research Service, Milton Russell, University of Tennessee, William 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 WORSKHOP

November 4,1987

Anchorage, Alaska

Mr. U.J. Baskurt

ARCO Alaska, Inc.

Ms. Lynn Billington

Standard Alaska Production Co.

Mr. Wes Black

Standard Alaska Production Co.

Mr. Mike Bradshaw

CONOCO, Inc.

Mr. Rod Branch

Standard Alaska Production Co.

Dr. Max Brewer

Staff Geologist/Geophysicist

US Geological Survey

Mr. Tom Cook

Chevron USA, Inc.

Mr. Fred Crory

Research Civil Engineer

U.S. Army Cold Regions Research

and Engineering Lab

Mr. Rob Dragnich

Exxon

Mr. Brad Fristoe

Alaska Department of Environmental Conservation

Mr. Paul Grimmer

CONOCO, Inc.

Mr. Stu Gustafson

EXXON Co. USA

Mr. Victor Manikian

ARCO Alaska Inc.

Dr. Maureen McCrea

Minerals Management Service

Alaska OCS Region

Mr. Robert Nagel

Amoco Production Co.

Mr. Richard Ogar

ARCO Alaska, Inc.

Mr. Lyle Perrigo

Arctic Environmental Information and Data Center

University of Alaska

Mr. Steven B. Porter

ARCO Alaska, Inc.

Mr. J.M. Posey

ARCO Alaska, Inc.

Mr. David Pritchard

Standard Oil Production Co.

Executive Offices

Mr. Blair Reber

Exxon Production Research Co.

Mr. Dick Roberts

Minerals Management Service

Alaska OCS Region

Dr. William Sackinger

University of Alaska

Geophysical Institute

Mr. Robin Senner

Senior Vice President

LGL Alaska Research Assn.

Mr Rupert (Bucky) G. Tart

Dames & Moore, Inc.

Mr. Bill Van Dyke

Petroleum Manager

Alaska Dept. of Natural Resources

vi
Workshop on North Slope Enhanced Oil Recovery Technologies

Houston, Texas

December 8, 1987

Mr. Roger Doughty

Arco Oil and Gas Company

Mr. Lyle Henderson

Manager

Enhanced Recovery Research

Shell Development Company

Mr. Arshad Khan

Reservoir Engineer

Chevron USA, Inc.

Mr. R. Ken Knight

Supervisor, Recovery Methods

UNOCAL Science and

Technology Division

Mr. J.M. Posey

Manager, Issues Advocacy

ARCO Alaska, Inc.

Mr. David Pritchard

Vice President, Technology

Standard Oil Production Co

Mr. W.D. Smith

Alaskan Interest

Production Coordinator

Exxon Company, USA

Dr. James Smith

Director

Center for Public Policy

University of Houston

Ms. Jill Hafner

Director of Operations

Center for Public Policy

University of Houston

Mr. Vello Kuuskraa

Vice President

Lewin/lCF

Fairfax, Virginia

Dr. Harry A. Deans

Professor of Chemical/Petroleum

Engineering

University of Houston

Dr. Elmond Claridge

Assoc. Professor of Chemical

Engineering/Director of

Petroleum Engineering

Graduate Program

University of Houston

Dr. Paul F. Deisler, Jr.

College of Business

Administration

University of Houston

Mr. R.J. Byrd

Manager, Reservoir Planning

Amoco Production Company

Mr. Thomas A. Harting

Senior Petroleum Engineer

Amoco Production Company

Mr. Ed Holstein

Reservoir Engineering

Coordinator

Exxon Company, USA

Mr. Mike Morrison

Director, Operations Planning

Exploration, Production

and Natural Gas-North America

Conoco, Inc.

Mr. Robert O. Hubbell

Vice President Reservoir

Engineering

Golden Engineering, Inc.

vii
Contents

Page

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 . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . 5

Projected TAPS Throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

North Slope Oil fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

The Arctic National Wildlife Refuge: Its Relationship to Alaska and Location of the Coastal

Plain . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Alaskan North Slope Producing Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

Prudhoe Bay Facilities Map . . . . . , , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Individual Facilities at Prudhoe Bay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Drilling Mud Flow Pattern in a Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Reserve Pit Operations During Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

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

Outline of a Prudhoe Bay Horizontal Well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Transportation Options Associated With Changing North Slope Physical Environment . . . . . . 49

A Comparison in Road Length Between Prudhoe Bay and Kuparuk . . . . . . . . . . . . . . . . 51

Development Scenario for Three Major Prospects on the ANWR Coastal Plain . . . . . . . . . . 65

OTA ANWR Development Scenario . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

North Slope Oil Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Projected TAPS Throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Alaska North Slope Production: Prudhoe Bay and Kuparuk . . . . . . . . . . . . . . . . . . . . 80

Alaska North Slope Production: Lisburne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82

Alaska North Slope Production: Endicott and Milne Point . . . . . . . . . . . . . . . . . . . . . 82

Alaska North Slope Production: West Sak and Seal Island . . . . . . . . . . . . . . . . . . . . . 85

Exploratory Wells in the Beaufort and Bering Seas . . . . . . . . . . . . . . . . . . . . . . . . . 97

Flow Chart of Simulation Method for Play Analysis . . . . . . . . . . . . . . . . . . . . . . . . .116

Flow 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 . . . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . 17

North Slope Petroleum Development Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Arctic Oil and Gas Technology: Composite List . . . . . . . . . . . . . . . , . . . . . . . . . . . 41

Typical Development Schedules , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

OTA ANWR Development Scenario . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . . . 66

Minimum Remaining In-Place Oil of Major North Slope Fields . . . . . . . . . . . . . . . . . . . 74

Estimated Recoverable Gas in Known North Slope Fields . . . . . . . . . . . . . . . . . . . . . 75

Estimated Remaining Recoverable Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Projected TAPS Throughput . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Some Enhanced Recovery Techniques Possibly Applicable to North Slope Fields . . . . . . . . 91

Problems Limiting North Slope Recovery and Technologies Which May Improve Recovery . . . 92

Proposed Alaska OCS and State of Alaska Sales . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Estimates of Undiscovered, Economically Recoverable Oil in Alaska . . . . . . . . . . . . . . . 97

Comparison of Estimates for Undiscovered In-place Oil in ANWR . . . . . . . . , . . . . . . . . 99
Summary and Conclusions
Contents

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

Arctic Oilfield Development and Technology .

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

Conclusions . . . . . . . . . . . . . . . .

North Slope Oil Production . . . . . . . . . . .

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

Conclusions . . . . . . . . . . . . . . . . . . . . . .

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Page ....... . 5. 99

“lo

14

14

14
Summary and Conclusions

INTRODUCTION

The coastal plain of the Arctic National Wildlife

Refuge (ANWR), in the extreme northeast corner

of Alaska (see Figure 1), has become the focal

point of a major debate among interest groups

seeking either to promote or to block the leasing,

exploration, and development of the area for its

suspected massive oil resources (see Box A).

Those groups opposing the development of

ANWR oil resources view the coastal plain as a

unique and invaluable Arctic ecosystem and

wilderness area. They fear that development will

destroy the plain’s wilderness character and

seriously damage its wildlife and other environmental values in return for a small potential to

capture an amount of oil that will make only a

temporary dent in the United States’ liquid fuels

dilemma. They believe that previous North Slope

development has damaged the Arctic environment and serves as a warning against expansion

of development into the coastal plain.

Pro-development interests view the coastal

plain as the most promising remaining area in the

United States for finding supergiant oilfields, and

they believe that the oil industry can explore and

develop the area without significantly compromising its environmental values. In contrast

to the views expressed by the environmental

groups opposing ANWR development, those

favoring ANWR development characterize existing North Slope oil development as a convincing

example of sound environmental management

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

ALASKA
BOX A

THE COASTAL PLAIN OF THE ARCTIC NATIONAL WILDLIFE REFUGE

●

●

●

●

●

●

●

●

●

●

●

Comprises 1.5 million acres of the19-million-acrw Arctic National Wdlife Refuge, established by the

Alaska National Interest Lands Conservation Act of 1980 (ANILCA). Known as the “1002 area,” a

reference 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, the

Nation’s largest oilfield; eastern edge 160 miles east of Prudhoe Bay and 30 miles west of the

Canadian border

Climate characterized by long, extremely cold winters and short, cool summers; persistent winds

throughout 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 Congress for additional study by the Department o the Interior of oil and gas potential and of wildlife f 

resources of the area

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

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

leasing of the area

Knowledge of subsurface geology very limited, but located between known petroleum provinces in

the 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 for

discovering supergiant oilfietds

The Department of the Interior estimates there is a 19 percent chance of finding economically

recoverable 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 important 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 caribou

herd, 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 the

ANWR coastal plain without unduly disturbing

its environmental values.

Through the terms of the legislation that established the Refuge, Congress has the final

decision over whether the coastal plain can be

leased for oil development. The ongoing congressional debate over the coastal plain’s future

has been informed by extensive hearing testimony as well as by a variety of analytical

reports from executive and congressional

branch agencies, industry, academia, and environmental organizations. Much of the testimony and reporting has focused on the

potential environmental impacts that development would cause and the nature of the environmental “record” of previous oil development on

the Alaskan North Slope.l

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

this information or to produce a complete assessment of all of the issues involved in Congress’

decision about ANWR’s future. In particular, we

have not produced an environmental assessment of ANWR oil development. Instead, at the

request of the Senate Committee on Energy and

Natural Resources, the House Committee on

Merchant Marine and Fisheries, and the OTA

Technology Assessment Board, we have focused

on two issues that will form a part of the congressional decision:

1.

2.

The nature of ANWR oilfield technology. To

what extent would ANWR development look

like existing development on the North

Slope? Would the basic technologies and

practices be the same or different?

ANWR’s potential role in Alaskan oil

production. How credible are recent projections of large declines in North Slope oil

production in the 1990s?

1. Opposing views of the environmental record are presented in: ‘(Oil in the Mctic: The Environmental Record of Oil Development

on Alaska’s North Slope,” Natural Resources Defense Council, Inc., January 1988; and “Current ANWR Environmental Issues, ” The

Standard Oil Co., August 1987.
Summary ● 9

ARCTIC OILFIELD DEVELOPMENT AND

TECHNOLOGY

Overview analytical techniques to design against well

damage from permafrost thawing, allowing

The technology and practices of Arctic oilfield

closer well spacing and thus smaller gravel pads

and less coverage of the tundra; and improveexploration and development have undergone ments in the use of enhanced oil recovery techimportant changes in the years since the Prud- nologies. These changes in technology and

hoe Bay oilfield was discovered and develop- practices stemmed from three sources:

ment began (see Box B for a brief description of

the process of extracting oil and gas resour- 1.

ces). Some important examples of technological changes include improved drilling rig design

and operation, improved use of directional drilling (drilling at an angle off the vertical) to allow 2.

multiple wells on single gravel “pads” to drain

oil from a greater area of the field; improved

the pressure of designing to solve unique

Arctic problems and adapting to the harsh

Arctic environment,

the industry-wide technological changes

stemming from the constant drive to improve

capabilities and performance and reduce

BOX B

THE 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 to

map the possible underground petroleum reservoirs as well as drilling exploratory wells to confirm

the existence and location of an actual oil pool (the pool, or reservoir, is actually a mass of porous

rock, with the oil stored in the rock pores)+ If oil is found,1 further drilling is also necessary to

delineate the size and extent of a reservoir and to determine whether it can be economically

produced. 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 pipelines

needed to produce whatever oil is discovered. On the North Slope, development begins with

building airfields, roads, drilling pads, and construction camps. This is followed by drilling production wells; building modules containing machinery and processing plants and installing them on

the site; building and installing pipelines and flow control equipment; and installing a myriad of

machinery to support a complex network through which oil flows from a pool deep beneath the

ground to the surface, is processed to yield crude oil and is pumped long distances to terminals

for loading on tankers, Production begins when all development is completed and the facilities

begin producing oil for the market. The production phase also jncludes maintenance of the

facilities and the wells, drilling more wells to keep oil flowing and to keep the underground reservoirs operating smoothly, and installing special equipment for “enhanced oil recovery” to extract

the 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 facilities

are 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 few

decades.

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 to

ship the gas to markets.
10 ● ANWR

costs, as well as from fortuitous scientific advances in other industries (such as

electronics), and

3. the special urgency to improve efficiency

and reduce costs associated with the

decline in oil prices beginning in 1981, especiallythe large price drop initiated in December 1985.2

OTA believes that the rate of change in

Arctic technology and practices likely to be

used for ANWR oil development may be more

gradual in the future, primarily because some

of the pressure for change has lessened. In

particular, industry knowledge of how to

operate efficiently in the onshore Arctic environment has matured considerably, and

further advancement in knowledge should

slow from its previous pace. In addition,

basic physical conditions on the ANWR coastal plain, while not identical to the current

North Slope development area, are quite

similar and do not represent a new challenge

to industry technology per se. Unless

economic or regulatory conditions change,

the industry is more likely to deploy systems

that have been tried and tested under similar

conditions than to take substantial risks in

the development of new technologies.

Therefore, we conclude that, in the absence

of new pressures, ANWR oilfield technology and practices will most likely

resemble the technology and practices

used at Kuparuk and Endicott, the latest

North Slope fields, modified to fit the particular field characteristics encountered.

Of course, the constant incentive to lower

costs will continue to drive innovation in the industry, and Arctic technology will continue to

evolve. Promising areas for technological

change include directional drilling, where advances continue to be made in offshore

developments such as the North Sea, and enhanced oil recovery, where innovation will be

driven by industry desire to boost the economic

potential of fields throughout the United States

and, on the North Slope, in fields such as West

Sak. Also, an additional motivation for technological change could come from mw regulatory

pressures. For ANWR oil exploration and

development, this pressure could arise from dissatisfaction with current environmental performance at Prudhoe Bay and the other developed

North Slope fields, or because the State and

Federal authorities seek a higher standard of environmental protection at ANWR because of its

status as a wildlife refuge. If this type of pressure

arises, the most likely focus for changes in technology and practices would be in the area of

waste management and habitat protection.

Conclusions

1. The major differences between North Slope

and Lower 48 conditions that affect the

choice and use of oilfield technologies are

the very cold weather, the presence of permafrost (ground which is permanently

frozen except at the surface, which thaws

during the Arctic summer), and the remoteness of the area. Designs for technologies

for operating at sub-zero temperatures draw

heavily on advanced concepts in metallurgy,

elastomers (elastic substances), lubricants,

and fuels. The harsh and extremely cold environment also has demanded development

of new survival systems and procedures to

assure personnel safety. All drilling rigs and

production facilities where people work are

enclosed, insulated, and heated. Exterior

steel structures are built from a special arcticgrade steel to prevent brittleness at very low

temperatures. Most pipelines and flowiines

are insulated, either to prevent water from

freezing, to avoid increased viscosity of the

crude oil, or to avoid permafrost melting.

Shut-in flowlines are freeze-protected or

evacuated 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” analysts

with extensive knowled e of Arctic oilfield technology and production, and analysts in the Alaskan State agencies and Federal

agencies such as the 8inerals Management Service are also dependent on industry as their primary information source. This

comment applies, as well, to our analysis of future North Slope oil production.

2.

3.

4

To prevent the permafrost from melting and

to provide a stable surface during the summer thaw, roads, buildings, pipelines, drilling pads, etc. are built atop thick gravel

pads and/or elevated on supports. And because the harshness and remoteness of the

North Slope make normal on-site construction methods difficult and expensive, major

facilities are built in huge modules in the

Lower 48 States, barged to the slope, and

installed on prepared foundations.

Although the technologies and practices

used on the North Slope today have

evolved considerably from those of the

early ’70s during the beginning of Prudhoe Bay development, the majority of

changes have involved the adaptation of

available practices and technologies to a

new environment rather than the develop

ment of new technologies and practices.

The adaptations address the unique Arctic

environment, as described above. Although

this conclusion does not negate the importance of what the oil industry has achieved

in Alaska – it has made tremendous

strides– it is important in projecting future

technological development, because it implies that future changes may come more

slowly.

Most of Prudhoe Bay and the Trans Alaska

Pipeline System (TAPS) have been in routine

operation for some time. The industry now

believes that it has ascended most of the

way up the “Arctic learning curve,” that its

technologies and practices for Arctic

development are mature, efficient, and effective. Therefore, they see little need to

change them for ANWR except to modify

them to fit specific conditions found on

the coastal plain (for example, the size,

shape, depth, and location of any oilbearing reservoirs discovered), and many

in the industry foresee little likelihood that

the technologies and practices will

change significantly for ANWR develop

ment.

Although the ANWR physical environment

is not precisely the same as that of Prudhoe Bay and the surrounding area, the differences do not appear to be large. ANWR

has more topographic relief than Prudhoe

Bay, producing less standing water but

5.

6.

more potential problems with channeling and

erosion; there are fewer deep lakes there to

serve as sources of fresh water; gravel conditions are about the same; and ANWR contains

a few more port sites with deeper water near

shore. None of the differences appear to

challenge industry capabilities per se.

At least a portion of the environmental effects associated with existing North Slope

oil development should not automatically

apply to ANWR. The capability now exists

for reducing or eliminating some of the impacts reported for early Prudhoe Bay

development. Newer North Slope fields

such as Kuparuk and Endicott incorporate

improvements in environmental management such as reduced requirements for

surface usage and gravel, improved handling of oilfield service operations, and

more attention to waste management.

These and other improvements are also likely to be used in any ANWR development and,

if necessary, regulatory agencies could stipulate use of desirable practices as a condition

of development. Critics, however, have expressed continued serious concerns about

several environmental issues because

they believe that even the newest operations are still causing significant environmental damage. Their principal concerns

include disposal of resewe pit waste and of

other solid and liquid wastes, air pollution,

fresh water supply, monitoring of industry activities by resource agencies, and wildlife

habitat alteration or destruction. Also, many

groups argue that the environment of the

ANWR coastal plain deserves greater protection than Prudhoe Bay because the coastal

plain is part of a wildlife refuge. These

groups either oppose development outright or conclude that oilfield technologies

and practices must change significantly

from those used for current North Slope

development if environmental values are

to be protected properly. OTA has not

evaluated these issues in this report.

If ANWR is leased and commercial quantities of oil are discovered, the period of

development and production is not likely

to be brief. Examination of the development

cycle of oil regions in the Lower 48 and

around 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 complex. Development of ANWR is likely to

begin with exploration and development of

large oilfields. With the development of an

extensive infrastructure, however, further

development will become economic, and

exploration will focus on smaller fields. AIso,

opportunities for enhanced oil recovery, for

the development of fringe areas of the large

reservoirs, and for development of smaller

reservoirs will extend high activity levels at

the larger fields. In the long term, gas

resources may be developed. This scenario

implies an extensive and elaborate infrastructure, and thus a significant visual impact, coverage of the surface, and

accompanying ecosystem impacts for at

least 25 to 30 years. Although the industry

argues--correctly--that actual coverage of

the surface is likely to be less than 1 percent

of the coastal plain, the physical coverage

would be spread out somewhat like a spiderweb, and some further physical effects, like

infiltration of road dust and changes in

drainage patterns, will spread out from the

land actually covered.

The detailed form of any future ANWR oilfield

development cannot be predicted. Nevertheless, it is useful to postulate a hypothetical scenario for the ANWR coastal plain:

●

●

●

●

●

●

●

●

Two fields would be discovered and

developed:

— 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 Prudhoe Bay oilfield, and the small field roughly

the size of the Endicott oilfield.

Production from these two ANWR oilfields

would total 800,000 bbl/day -or 40 percent of

current North Slope oil production.

Facilities for two ANWR oilfields would include:

- 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 and

other disturbances – is 5,000 to 7,000 acres.

Total “sphere of infiuence” –denoting area

where some secondary effects occur on certain sensitive species – is 150,000 to 300,000

acres.

Hypothetical schedule:
14 ● ANWR

NORTH SLOPE OIL PRODUCTION

Overview

Today, the North Slope of Alaska provides

about 2 million barrels per day (mmbd) of oil to

the United States, nearly a quarter of total U.S.

domestic crude oil production. Most projections of future North Slope production show a

marked decline beginning around 1990 to 1991,

with production falling to half of current levels or

below by the year 2000 (see Figure 2). If

production is not to fall, then it must come either

from more intensive development of existing

fields, from discovered but undeveloped fields,

or from undiscovered resources. Based on the

available evidence, additional production

from more intensive development of existing

fields and development of discovered but

currently undeveloped fields is unlikely to

reverse the expected decline in North Slope

oil production. Production from undiscovered resources is highly uncertain and

would likely be more than a decade away

even if discoveries were made this year.

OTA notes, however, that the Prudhoe Bay

operators have been able to push back the expected date for the onset of field decline several

times, Although it is not clear how a strong

production decline can be delayed for much

Figure 2.-Projected TAPS Throughput

longer, history suggests caution in entirely writing off the possibility.

Conclusions

1.

2.

3.

The current low oil prices raise the possibility

that the oil companies on the North Slope

might be foregoing opportunities for adding

large increments of production and/or added

recovery, waiting for economic conditions to

improve. If this were true, then existing

forecasts of future North Slope production

might be missing the production boost that

an improvement in economic conditions

could bring about.

Although low oil prices have affected the

level of investment in new development on

the North Slope, in general the large producing fields continue to be developed intensively. Despite the low prices, we could not

identify any development opportunities

being foregone that would make a large difference in future North Slope production.

Thus, higher oil prices may slow but are

unlikely to stop the expected declines in

North Slope oil production.

Prospects for enhanced oil recovery (beyond

that already in place or scheduled) in the discovered fields are good, but the increments

of recovery and production from the available

enhanced oil recovery (EOR) technologies

will be small and will accrue over a long

period. In other words, there are no available or readily foreseeable technologies

that promise to “turn around” expectations

of declining production at Prudhoe Bay

and other North Slope fields. Table 1

describes the conditions affecting oil

recovery in the discovered North Slope fields;

Figure 3 shows the location of these fields,

Aside from additional recovery from the

producing fields, increments of production

must come from discovered but non-producing fields or from the undiscovered resource

base.
.

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 exdo not have large volumes of recoverable

resources and cannot be expected to

reverse the impending decline in oil flow

through the Trans Alaska Pipeline System

(TAPS).

Although the West Sak field contains large 4

in-place resources (at least 15 billion barrels), there are, as yet, no available technologies that can economically recover

more than a small fraction of these resources. ARCO, the majority owner of this field,

plans to begin a pilot drilling program soon,

and hopes eventually to produce a few

hundred thousand barrels per day from West

Sak. Given the substantial technical

problems remaining, however, large scale oil

production from West Sak must be viewed

as highly uncertain.

ploration on the North Slope and offshore has

been extremely disappointing. Afthough new

large discoveries cannot be ruled out, the

prospects for such discoveries seem to

have dimmed considerably.

The industry appears to have made significant

strides in controlling and reducing oilfield

costs over the past few years. Part of the

reduced costs are associated with reduced

prices for basic oilfield services, and these

lower prices are unlikely to be sustained for

more than a few years. Part, however, appears to be the result of improved practices

and design, and this should be sustained permanently. The industry now appears to be

able to bring new fields on line and develop

older fields more intensively at lower

breakeven oil prices than just a few years ago.

To the extent that production projections are

Table 1 .—Summary Field Data

Remaining Estimated

recoverable recoverable Recovery Daily 011

oil-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 permillion barrels feet original in-place per day gas injection infill former, production will

resources and horizontal ultimately be limited by

drilling 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 saturation

in-place resources waterflood

Lisburne 280-580 million 900 billion cubic 7-22% of original 50,000 barrels Small waterflood Difficulty of producing

barrels feet in-place resources per day pilot IS being tested fractured limestone reservoir, low porosity and

permeability

Endicott - - 270-445 million 800 billion cubic 35% of original Waterflood Faulting, gas handling

barrels feet In-place resources 100,000 barrels ability in future

per day

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

barrels 33% of original shut-in due to low

In-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, unconbarrels In-place resources waterflood solldated. fine-gralned

sand, VISCOUS , low temperature 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 7

rels condensate feet

(light grawty

hydrocarbons) —.

SOURCE Off Ice of Technology Assessment 1988 –
18 ● ANVVR

5

6.

based on older costs, they maybe pessimistic. Also, because reserve projections and

production rates are oil price dependent,

higher oil prices in the mid to late 1990s

could be expected to stimulate additional

production. Thus, the more optimistic of

the current projections for North Slope

production over the next 15 to 20 years

are more likely to be accurate, especially

if higher oil prices prevail. However, even

the optimistic projections still foresee a

large decline in the flow of oil through

TAPS during the next decade and a half.

The oil industry has over time tended to be

overly pessimistic about prospects for future

oil production, not only in Alaska but for the

United States as a whole. Projections for the

onset of decline in Prudhoe Bay production,

for example, have been pushed back a number of times. And U.S. production, although

down substantially since the oil price drop

of 1985-1986, has not fallen nearly as severely as the industry had predicted immediately following the price drop. Although OTA

could not identify a likely means to maintain

North Slope production at levels much

higher than the “high” curve in Figure 2, OTA

is reluctant to totally rule out this possibility.

Estimates of the resource potential of ANWR

are highly speculative, given that they are

not based on extensive drilling data. 001’s

“best guess” of AlNWR’s economically

recoverable resources is based on available

geologic and geophysical data and on a

number of economic assumptions. Several

7.

factors lead OTA to conclude that DOI’s estimate of the likelihood of finding economically recoverable quantities of oil in ANWR

may be conservative. These factors are: 1)

In its analysis, DOI assumed that the costs to

develop ANWR will be similar to costs as

detailed in the 1981 National Petroleum Council report on the Arctic. The oil companies

have reduced their costs substantially since

1981, and these reductions do not appear to

have been captured by the DOI assessment;4

2) DOI did not include the possibility that

ANWR oil could be developed with two or

three moderate-sized fields, even though no

single field exceeds the minimum economic

field size for a stand-alone field; and 3)

Smaller potential oil prospects were not included in DOI’s analysis. Even though these

smaller prospects are not large enough to

develop alone, some would likely be

developed in association with a large

prospect.

Many groups have either misinterpreted or

misused DOI’s estimate of ANWR’S economically recoverable resource potential. What

DOI has concluded is that there is an 81 percent chance that no economicall y

recoverable oil will be found in ANWR, but if

ANWR contains any recoverable oil, a mean

of 3.23 billion barrels is likely to exist. Estimates will change with acquisition of additional data, but geologic conditions for finding

oil in ANWR are favorable, and industry considers a 19 percent probability of finding

economically recoverable oil in any region to

be good odds.

4. Although some of the cost reduction may not be permanent, OTA believes that much of the savings will be retained even if

drilling activity levels pick up.
Chapter 1

Introduction
Contents

Page

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

The OTA Study . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Chapter 1

Introduction

OVERVIEW

The coastal plain of the Arctic National Wildlife

Refuge, in the extreme northeast corner of Alaska

(see Figure 1 -l), has become the focal point of a

major debate among interest groups seeking

either to promote or to block the leasing, exploration, and development of the area for its suspected massive oil resources. Because of the

perceived oil and gas potential of the area, the

1.5 million acre coastal plain, or so-called “1002

area” named after Section 1002 of the Alaska Native Interest Lands Conservation Act (Public Law

96-487), was left out of the Federal wilderness

designation that protected 8 million acres in the

Refuge. Instead, Congress asked the Department of the Interior (DOI) to study the area and to

recommend an appropriate development course

for it. Oil and gas development was forbidden

without explicit congressional approval. DOI has

now completed its study and has recommended

to Congress that the entire 1002 area be opened

to leasing and development. 1 This recommendation is fully supported by the oil industry and a

variety of other pro-development interests (including the entire Alaskan congressional delegation), is vigorously opposed by a number of

environmental groups and some Native groups,

and is supported with conditions by the Alaskan

State government and other interests. The

variety of proposed Federal legislation dealing

with the Refuge – summarized in Box 1 -A –

reflects these different positions.

The 1002 area is the focus of a variety of seemingly conflicting values. On one side, there is

unanimous agreement that the area represents a

high value as a wildlife refuge–the 1002 coastal

plain is, in most years, the primary calving

ground and summer home for the nearly 200,000

caribou of the Porcupine herd, as well as the

nesting habitat for millions of birds and the home

of polar and grizzly bears, an expanding herd of

musk oxen, and numerous other arctic species.

Also, there is widespread agreement – supported

even by the DOI report that recommended its

development –that it has a high value as a wilderness area. Further, the area provides wildlife

resources – particularly caribou – supporting the

subsistence lifestyle of a number of native lnuit.

On the other side, there is essentially unanimous

agreement that the 1002 area has a high potential – by industry standards – for containing massive oil and gas deposits, although various

interest groups differ on the value of these

deposits to the Nation (see Box 1 -B).

It seems unlikely that all of these values can be

supported simultaneously. For example, according to the DOI report, the successful exploration

for and development of the 1002 area’s potential

oil resources would damage and possibly

destroy the area’s wilderness character. Although some interests have argued that the

wilderness character can be restored over time,

at our current state of knowledge this outcome

should be viewed as extremely uncertain, and

probably unlikely. Thus, the true “value” of the

coastal plain as a wilderness area, though largely

a subjective measure, is an important part of the

development decision.

In addition, there is substantial disagreement

about the potential conflict between large-scale

oil development and the wildlife and other environmental and subsistence values of the area.

Generally, the oil companies vigorously defend

their environmental record in previous Alaskan

North Slope development and assert that ANWR

oil can be extracted with little damage to wildlife

and other values. Environmental groups are

taking the opposite view that previous develop1, N,K. Clough, R.C. Patton, and A..C. Christiansen (eds.), Arctic National Wldlife Refuge, Alaska, Coastal Plain Resource

Assessment-Report and Recommendation to the Congress of the United States and Final Legislative Environmental Im act

Statement, (Washington, DC: U.S. Fish and Wildlife Service, U.S. Geological Survey, and Bureau of Land Management, .S. E

Department of the Interior, 1987).

21
22• ANWR

ment has caused substantial damage and that These conflicting viewpoints have been the subany future oil development in ANWR also will sub- ject of a number of congressional hearings as

stantially damage wildlife and other environmen- well as studies by a number of groups. The istal 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-A

ARCTIC NATIONAL WILDLIFE REFUGE BILLS

More than a dozen bills have been introduced in the IOOth Congress that address issues related

to the Arctic National Wildlife Refuge. Two pro-leasing bills, S 2214 and HR 3928, have emerged as

the leading bills around which debate is currently centered.

S 2214, which Incorporates some of the provisions of a pro-leasing bill introduced by Senators

Murkowski and Stevens of Alaska, was reported by the Senate Energy and Natural Resources Committee on February 25, 1988. The bill provides for a phased-in leasing program governed by existing State Federal environmental law, and subject to further environmental regulations to be

developed by the Interior Department. S 2214 would permit Interior to exciude from leasing areas of

particular environmental sensitivity. Interior would be required to determine whether an activity

may result in “significant adverse effect” and to modify, suspend, or terminate the activity to prevent

that 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 development

proceed.

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, unlike

S 2214, it establishes a 260,000-acre protective management zone in the “we calving area” of the

Porcupine caribou herd and does hot require an energy study. The bill will also be considered by

the House Interior Committee, which is headed by Congressman Morris Udall, Chairman Udall

favors 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 more

than 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,” Special

Report, 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-B

WHAT 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 Statement

was released. The actual conclusion was:

1. There is a 19 percent chance that oil is present in the coastal plain under conditions that would

allow commercial recovery (Le., large quantity in one place, good quality oil, permeable reservoir

rock).

2. If oil is present in commercially recoverable form, its estimated mean volume is 3.23 billion barrels 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 that

case, the total impact of leasing will be restricted to the impacts of the exploratory program, No

permanent facilities will be built –no pipelines, no production facilities, and no permanent crew

quarters.

2. There is a 19 percent chance that commercially recoverable oil will be found. In that case, the expected vaIue of the magnitude of the oil Iikely to be recovered is 3.23 billion barrels. The value of

this oil must be weighed against the effects, negative and positive, of building and operating the

pipelines, production facilities, and other extensive infrastructure involved in producing this

volume of oil in an Arctic environment.

A number of misinterpretations of the DOI conclusions have been communicated to Congress and to the

media by both proponents and opponents of ANWR 011 development. The following two examples appear

to represent the extremes:

● ‘The Arctic Refuge coastal plain...is estimated to contain more than 9 billion barrels of

recoverable oil, an amount approximately equal to Prudhoe Bay. ” Secretary Hodel in the cover

letter accompanying the DOI ANWR assessment, April 21, 1987. According to the DOI assessment, the chance of recovering this amount or greater is about 1 percent... it represents the 5

percent probability mark for economically recoverable oil, and the latter occurs with only a 19

percent probability.

● “There is about a 7 percent chance of finding 3.2 billion recoverable barrels, a 200 day supply (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 distribution for resource magnitudes in the DOI report. The author notes that the 3.2 billion barrel

resource is situated at the 34th percentile on the probability curve, and interprets this to mean

that there is a 34 percent chance of obtaining 3.2 billion barrels of oil. Thus, he multiplies .34

by .19, the conditional probability of finding any recoverable oil, to obtain “the probability of

finding 3.2 billion barrels, However, the proper interpretation is that there is a 7 percent chance

of finding at least 3.2 billion barrels; this probability includes the potential of finding 8 billion,9

billion, or even more barrels of recoverable oil. In OTA’s view, the most useful interpretation

still is that there is a 19 percent chance of recovering oil at ANWR, and if oil is recovered, the

mean volume is 3.2 billion recoverable barreis.

Also, a number of leasing opponents have presented the leasing decision as a choice between 600 million barrels of oil –the “risked mean” volume of oil, obtained by multiplying 3.2 billion barrels by the 19 percent 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 unfair

comparison, because full development will occur only if recoverable amounts of 011 are found, and the expected volume of this oil is the full 3.2 billion barrels. As noted above, If no commercial oil is found, the impacts will be far less.

“Risked mean” volumes are useful when assessing the Iikely oil resources of an area that includes a number of unexplored regions. For example, in assessing the total oil resources remaining in all unexplored

regions 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-C

ISSUES AFFECTING THE MM/F? DEVELOPMENT DECISION

1. To what extent would development of ANWR oil resources improve U.S. national security and

offer significant economic benefits? Are the likely levels of ANWR oil production, if cotnmercial quantities are found, of real significance to U.S. liquid fuels supply? Are predictions of expected decfines in North Slope and U.S. oil production levels correct? Is it Iikelythat world oil

markets will be under the tight control of the Middle Eastern OPEC countries at the time when

ANWR oil could be flowing into the TAPS pipeline?

2. Are there alternatives to developing ANWR 011 that likely would prove more effective at lower

cost (including environmental cost)? Could improving the efficiency of the automobile fleet

save significantly more oil than ANWR could supply? Would pursuit of alternative liquid fuels

such as methanol be preferable to investing in marginal U.S. oil resources? What are the risks

of 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 determining

the extent of its oil resources? Is it likely that an accurate determination of its resources could

be made without promising that any commercial quantities of oil would be allowed to be

developed immediately after discovery? Are ANWR’s potential oil resources worth more to the

United 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 its

wilderness values duplicated elsewhere in Alaska? In other words, is developing the coastal

plain 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’s

wildlife and other natural resources?

● How have Prudhoe Bay and other North Slope development damaged the natural environment? 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 road

network? What solid and liquid waste problems exist, and what has been their effect? Does

the growth of the Central Arctic caribou herd reflect Its long-term health, or is the appropriate

interpretation less optimistic? What have been the effects of increased air emissions on the

North Slope? R

● Does current Arctic oilfieid technology and practices offer significant environmental improvements over those used earlier on the North Slope? Would probiems that existed at the &idY

Prudhoe Bay developments be significantly less of a problem at ANWR because of these

changes?

● What differences exist between ANWR and the North Slope/Prudhoe Bay area, and how will

these affect the environmental impacts that might accompany development at ANWR?

6. Could ANWR oil resources be developed without foreclosing the eventual return of the coastal plain to a wilderness state? How Iikely is it that drilling sites can be rehabilitated, roads dismantled, and other physical effects of development successfully removed? Would

development be likely to be temporary, or would the building of the needed infrastructure lead

to more permanent development and exploitation of other ANWR resources? Would oil

development be followed by natural gas development, extending the timeframe of petroleum

development well past 20 or 30 years?
Chapter 1 ● 27

THE OTA STUDY

At the request of the Senate Committee on

Energy and Natural Resources and the House

Committee on Merchant Marine and Fisheries,

the Office of Technology Assessment has undertaken a study of technologies for Arctic oil

production and their effect on future oil production in Alaska and, particularly, in the 1002 area.

The OTA study focuses on a subset of the issues

relevant to Congress’ decision on the fate of the

area (the full set of issues are listed in Box 1-C),

and does not provide guidance on a number of

issues critical to the decision. OTA hopes that

Congress, in making its decision, will draw on

this study in conjunction with an extensive hearing record, several analyses by the Congressional Research Service, the Department of the

Interior’s Legislative Environmental Impact Statement (LEIS) and its supporting documents, and

numerous reports and presentations from Alaskan State government, industry groups, Alaskan

Native associations, environmental organizations, and other interest groups and technical organizations.

In addition, a forthcoming OTA study (Technological Risks and Opportunities for Future U.S.

Energy Supply and Demand, scheduled for Fall,

1989) will examine topics associated with

ANWR’s role in future U.S. liquid fuels supply and

demand--including future domestic oil production; alternative liquid fuels; the potential for

reducing oil requirements by increasing energy

efficiency; and the security implications of growing oil imports.

In Chapter 2, this report examines the state-ofthe-art of Arctic oilfield technology and attempts

to project the nature of technology that might be

used in the future to explore, develop, and

produce oil in the 1002 area. As part of this

evaluation, the report attempts to show how such

technology may resemble or differ from the technology used to develop the Prudhoe Bay oilfield,

which is the oldest, largest, and most intensively

studied of the North Slope oilfields. During extensive congressional testimony on ANWR, advocates and opponents of oil development have

argued strenuously about the likelihood that

ANWR development would raise many of the

same environmental concerns associated with

Prudhoe Bay development, and about the importance and accuracy of such concerns. Because

the nature of the technology is an important

determinant of environmental impacts, this portion of the report should help Congress understand how the impacts of possible future

development at ANWR might resemble or differ

from the impacts of existing development at

Prudhoe. However, the report does not comment on the accuracy of the various claims made

about the absolute magnitude of environmental

impacts at Prudhoe Bay.

In Chapter 3, the report examines the available

estimates of total Alaskan North Slope oil resources and reserves and the projections of future oil

production, and evaluates the potential for shifts

in future production rates with technology

development and changing economic conditions. This evaluation includes an examination of

enhanced recovery technologies that might be

used to boost North Slope production in the future. The purpose of this portion of the report is

to place any future oil production from the 1002

area into a better overall Alaskan and U.S. oil

perspective. The report tries here to determine

whether or not ANWR oil production represents

the only feasible means of maintaining a high

throughput through the Trans Alaska Pipeline

System to the Lower 48 States for the year 2000

and beyond. Although projections of North

Slope production made available to OTA portray

sharply declining production in the 1990s, some

Members of Congress are skeptical of these

projections.
Chapter 2

Technologies for Oil and Gas

Development on the

North Slope of Alaska
Contents

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

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 Arctic

ANWR Special Conditions . . .

National Wildlife Refuge

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

Overview: ANWR Techndogiesand Practices . . . . . .

impacts: ANWR Technologies and Practices . . . . . . .

Technological Change . . . . . . . . . . . . . . . . . . .

schedule . . . . . . . . . . . . . . . . . . . . . . . . . . .

ANWR Development Scenarios . . . . . . . . . . . . . . . .●✎●✎✎●✎●✎✎✎✎✎✎ .●✎✎✎✎✎✎✎✎✎✎✎✎✎

● ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

✎ ✎

31

31

32

32

33

37

40

56

57

57

58

59

62

63

64
Chapter 2

Technologies for Oil and Gas Development

on the North Slope of Iaska A

INTRODUCTION

If oil and gas leasing is permitted in the Arctic

National Wildlife Refuge (ANWR), the exploration

for and development of any resources discovered there would likely follow the pattern established over the last two decades of

commercial petroleum activities on the North

Slope of Alaska. The basic oil exploration and

production systems for the Arctic have been

adapted from technologies used by the industry

in less severe environments. These adaptations

make it possible to work successfully in the unique Arctic environment of extreme cold temperatures and harsh weather, and to cope with

remoteness and the difficulty of transportation.

The need to work on permafrost, tundra, and ice

also forced some major technological changes.

Substantial engineering development was undertaken by the petroleum industry to produce efficient and effective systems for Arctic use. By the

early 1980s, after most of Prudhoe Bay and TAPS

had been in routine operation for some time, the

industry considered that the technology for onshore Arctic operations was proven and mature. 1

Four Environmental Questions

The debate about whether or not to allow leasing and petroleum development in ANWR includes four key questions about the impact of

technologies and practices on the environment:

1. To what extent will the physical presence

of infrastructure associated with oil

development disturb ANWR? How many

gravel pads, gravel roads, pipelines, facilities, etc., will cover the tundra? What will

be the effect of erosion, disruption of

drainage patterns, dust, etc, on local

ecosystems? How long will the facilities

operate? What is the potential for long2.

3.

4.

term growth? What regulations could limit

environmental disturbance?

To what extent will gravel mining and

other construction practices disrupt

ANWR? How much gravel will be needed?

What regulatory limits should there be?

How much waste discharge from drilling

and production operations will there be?

Will the practices of (and regulation for)

managing those wastes be acceptable in

ANWR? Is deep well injection a sound

practice? To what extent will environmentally benign muds be used? Will reserve pit

containment practices be adequate? Will

higher environmental standards than normal be necessary for a wildlife refuge?

Will the fresh water needs for ANWR

development and standard industry

practices for obtaining water be acceptable, feasible, and controllable by

regulation?

This report has focused attention on the first

two areas above because they relate most closely to our main objective of characterizing the

technological developments likely to occur

should ANWR leasing be permitted. The report

only briefly discusses the second two areas

above. In addition, air quality issues are not addressed. In commenting on the draft report, environmental groups have called attention to their

serious concerns about many environmental issues, but most importantly to questions about

waste disposal and fresh water supply. The

scope of this study has precluded significant environmental analysis. However, if ANWR leasing

goes forward, it is clear that all of these issues will

continue to be of concern and will need to be addressed 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 the

evolution of Arctic oil and gas technology and

practices on the North Slope yield important

clues to any likely development of the ANWR

coastal plain. The Prudhoe Bay oilfield was

developed during the 1970s. During that time,

the petroleum industry invested in major engineering projects to enable it to modify technologies developed in other areas for Arctic use.

Although the Prudhoe Bay field did not begin

production until 1977, pioneering efforts on what

was then called the Naval Petroleum Reseme in

Alaska (now the National Petroleum ReserveAlaska [NPRA]) at least 20 years before provided

much basic information about drilling in permafrost, use of ice roads and platforms, building

gravel pads, and other techniques for working in

the Arctic. Other fields were discovered in the

vicinity of Prudhoe Bay and put into production

using the experience at Prudhoe, to advance

technology even further.

All of the producing North Slope fields feed into

the Trans Alaska Pipeline System (TAPS). TAPS

delivers oil in an elevated pipeline along an 800-

mile route from Prudhoe to Valdez, an ice-free

terminal in southern Alaska. Research on permafrost along the TAPS route was done during

the 1950s and 1960s, and TAPS pipeline technology was developed during the 1970s.

.
Chapter 2 ● 33

Current North Slope

Development

Existing North Slope oil and gas development is

extensive and still growing.2 It is concentrated in

five fields: Prudhoe Bay, Kuparuk River, Lisburne, Endicott, and Milne Point (Figure 2-l).

Currently, all but Milne Point are producing. As a

group, the fields are supported by 1,123 miles of

pipeline (excluding TAPS) and 346 miles of

roads. Some 7,035 acres of land are covered by

gravel for facilities, drill sites, roads, and camps.

Nine river crossings and three airfields are used

for petroleum-related activities. A 370-mile

gravel haul road, the Dalton Highway, connects

Deadhorse (the operations base for most of the

contractors who support the major operations),

at the southern end of Prudhoe Bay, with Fairbanks. All the oil is transported via the Trans

Alaska Pipeline from Prudhoe Bay to Valdez. The

current rate of North Slope oil production is

about 2 million barrels per day (mmbd).

Table 2-1 summarizes development activities at

the five North Slope sites. Overall, the Deadhorse industrial complex serves as the prima~

support base for North Slope and Beaufort Sea

exploration and development. Deadhorse has

living quarters, warehouse facilities, and a paved,

State-operated airport. It is located in the

southern portion of the Prudhoe oilfield. By itself,

the Prudhoe Bay field, the Nation’s largest, has

two adjacent operating areas, one run by Standard Alaska Production Company (SAPC) and

the 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 oil

and gas unit boundary

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

Natural 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12/67

Size of oil pool (sq. ma.) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 400

Production start-update . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6/77

Production to date (million bbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,918

1986 average production rate (barrels/day) . . . . . . . . . . . . . . . . . . . 1,554,000

Remaining reserves:

million barrels (oil) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,672

billion cubic feet (gas) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,000

Existing wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 881

Drill sites/pads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Production centers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Base camps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Construction camps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Power plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Topping plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Gas compression plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Seawater treatment plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Enhanced oil recovery plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Docks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Causeways . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Water injection centers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Associated support and industrial sites . . . . . . . . . . . . . . . . . . . . . 1

Airports and company operated airstrips . . . . . . . . . . . . . . . . . . . . 2

Pipelines (miles) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63’

Roads (miles) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218e

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

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

e

12/67

125

12/86

5

40,000

395

625

51

5

1

1

0

1

0

1

0

0

0

0

0

0

0

e

e

e

e

4/69

400

12/81

292

257,000

1,308

565

557

34

3

1

1

1

1

1

1

1

1

0

d

1

1

418

94

1,409

5

10/69

45

11/85

5’

12,900

55

0

29

4

1

1

1

1

0

1

0

0

0

:

o

0

15

19

54

1

3178

40

10/87

b

100,000

375

730

30’

2

1

1

1

1

0

1

1

0

1

1

d

o

0

28

15

198

1

NOTE: The above does not include the considerable numberof support sites and acreage covered at Deadhorse

a Fleld shut in January 1987

b produ c tl o n commenced October 1987

C

80-100 wells planned

dwater injection system Included In production centers

eLlsburne 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 are

huge. They are located within a 200-square-mile

area of the 400-square-mile Prudhoe Bay Unit,

and include six oil/gas separation plants, gathering centers or flow stations, 38 drill pads with a

total of 828 wells, a central gas facility, a central

compression plant, a central powerplant, afield

fuel gasunit, a crude topping plant (refinery), a

waterflood seawater treatment facility, a gravel

airstrip, 200 miles of roads, permanent living

quarters, a dock, two construction camps, offices, and two water injection plants.

Figures 2-2 and 2-3 illustrate the large scale of

development at Prudhoe Bay. Figure 2-2 depicts

the major field production facilities only (drill

pads, airstrips, operations center gas plant,

docks, and connecting roads). Figure 2-3 shows

more detail of sizes and shapes of facility pads

and pipeline networks. while it is difficult to

portray the development on this scale, both the

extent of coverage and the diversity of the systems in place are evident. Whether (in total) this

is a major industrial complex defacing the natural

Landscape or whether it is only a small, incidental

disturbance in a vast wilderness depends mainly

on one’s values and perception.

The Kuparuk River field, located about 30 miles

west of Prudhoe Bay, is operated by ARCO Alaska. Production began in December 1981. About

500 people will be ultimately employed at the

field. Facilities currently include three central

production facilities, about 500 wells (800 are

planned), the Kuparuk Operations Center (offices

and housing for 384 people), the Kuparuk lndustrial Center a gasplant, a seawater treatment

plant, pipelines (a 26-mile-long, 24-inch-diameter

crude oil line, built in 1984, connects to TAPS at

Pump Station 1, and a 26-mile-long, 16-inchdiameter converted oil line carries natural gas to

Prudhoe 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 topping plant, two construction camps (one accommodates 650 people and the other 360), and one

gravel airstrip.

The Lisburne resewoir was discovered directly

beneath Prudhoe Bay. ARCO committed to

developing Lisburne in January 1984, and initial

production began in December 1986. Of 51 total

wells, to date 45 are capable of production. The

current production is from 37 of these wells. When

completed, about 100 permanent employees will

work in the Lisburne field, while about 1,000 will be

necessary during portions of the construction

phase. Lisburne facilities include one central

production facility, five onshore gravel pads, 50

miles of pipeline, and a pilot waterflood project.

The Endicott field, discovered in 1978, is located offshore about 20 miles east of Prudhoe

Bay. It is the first oil and gas field to be

developed in the Alaskan Beaufort Sea. Standard Alaska Production Company is the operator.

Production began in October 1987. The field is

being developed from two artificial gravel islands,

2 miles offshore. The Islands are connected by

3.1 miles of solid fill causeway and joined to the

Sagavanirktok (Sag) River delta by 1.9 miles of

gravel causeway with two bridge-type breaches

totaling 700 feet and 1.5 miles of onshore

causeway through the Sag delta wetlands. A

gravel road, 8.7 miles long, connects the

causeways with the existing Prudhoe Bay road

system at Drill Site 9. An elevated oil pipeline

from the field connects with TAPS at Pump Station #1. Other infrastructure includes an onshore gravel pit, a base camp with living quarters

for 600 people, a warehouse, offices, fuel tanks,

base operations center, seawater intake basin,

utilities for the waterflood project, and a dock for

sealift operations, Endicott operates with a permit for discharge of drilling effluents into the

Beaufort Sea. The North Slope Borough landfill

is used to dispose of oil-contaminated drill cuttings, and deep well injection is used to dispose

of oil-contaminated fluids.

The Milne Point field was discovered in 1969,

and development started in 1979. It is operated

by Conoco. The 21 ,000-acre field is located

northeast of the Kuparuk River field. Production,

which began in November 1985, was suspended

in January 1987 pending an increase and

stabilization of oil prices. Facilities include 2 4

wells on two pads, a 50-person permanent camp,

and a 300-person construction camp. About 19

miles of gravel roads connect Milne Point to the

Kuparuk spine road, and about 15 miles of

pipeline are available to carry oil from Milne Point

to the Kuparuk Pipeline. Waterflood infrastructure includes a 45,000-barrels-per-day capacity

water injection system.

Camp Lonely, located 80 miles west of Oliktok

Point and the Kuparuk field, once served as a

staging area for western Beaufort Sea activities

but is now mothballed. Infrastructure includes a

100-person camp, offices, carpentry shop, communications shop, sewage treatment plant,

generating system, vehicle maintenance shop, a

large tank farm, and warm and cold storage

warehouses.

In addition to these areas, future development

is possible from Niakuk, located offshore between the Lisburne and Endicott fields, the West

Sak Reservoir in the Kuparuk River and Milne

Point Units, Seal Island, Tern Island, Sandpiper

Island, Colville Delta, Flaxman Island/Point

Thomson, the Hemi Springs Unit, ARCO Alaska’s

K-10, and Bullen Point Staging Area.

Arctic Conditions Affecting

Technologies

Most experts agree that the major differences

between North Slope and Lower 48 conditions

that affect the choice and use of oil and gas technologies are the very cold weather, the presence

of permafrost, and the remoteness of the area.

Designs for technologies for operating at subzero temperatures draw heavily on advanced

concepts in metallurgy, elastomers (elastic substances), lubricants, and fuels. The harsh cold

environment also has demanded development of

new survival systems and procedures to assure

personnel safety. All drilling rigs and production

facilities where people work must be enclosed,

insulated, and heated. Exterior steel structures

need to be built from a special arctic-grade steel

to prevent brittleness at very low temperatures.

Most pipelines and flowlines are insulated, either

to prevent water from freezing or to avoid increased viscosity of the crude oil. Shut-in
38 Ž ANWR

flowlines must be freeze-protected or evacuated

and then filled with inert gas.

Permafrost (see Box 2-A) has forced the development of a number of compatible technologies. Because thawed permafrost lacks load-bearing

capacity, special construction techniques are used

to protect the permafrost layer so that it remains

frozen. Where load-bearing is required, common

North Slope practice is to build up a thick gravel pad

to insulate the permafrost from warmer summer

temperatures and from artificial heat sources. The

pads then become platforms for facilities, roads,

etc. Ail roads and gravel pads are constructed with

a thickness of about five feet of gravel or some alternative, equally effective insulating technique.

Flowlines, pipelines, and production handling

modules are built above-ground on vertical support

Box 24

PERMAFROST

The entire Nonth Slope of Alaska, including ANWR, is underlain by permafrost, permanently frozen

ground extending just below the land surface to as much as 2,000 feet below the surface. In the

Arctic winter, the permafrost surface is solid and stalble. In the summer, up to several feet of the surface permafrost layer thaw, becoming soft and water-soaked and unable to support even small

structures, but the remainder stays frozen. Techniques to provide permanently soild foundations

for heated buildings, facilities, roads, etc., on the surface (and to avoid melting the permafrost elsewhere where it is frozen) are therefore necessary for ail Arctic operations, With certain types of

thaw-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 from

the produced fluids. In special cases where lines

must be buried in the permafrost, refrigeration is

used around the pipeline. To prevent the casing’s3

vertical movement and its collapse due to permafrost freeze-back after drilling or during well shutdown, casing materials are designed to withstand

collapse loads, special cold weather cements are

used for the surface casing, and “Arctic Pack” (a

gelled freeze-proof diesel that has some insulating

properties) is used between the surface casing and

production casing. Most development drilling is

done from drilling pads, and wells are clustered at

the surface on these pads and drilled at an angle to

the producing formation. This practice minimizes

the amount of construction on and coverage of permafrost.

Because of permafrost there generally is a need

for elevated foundations for buildings and

facilities and for special containment of fluids and

waste discharges. As permafrost is impervious

to water, there is no downward percolation of

water 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 to

produce oil, additional casing is installed.
400 Ž ANWR

There are indications, however, that permafrost is

not impervious to other fluids including, perhaps,

waste products, and that the migration of these

fluids from some reserve pits is an environmental

concern.

The harshness and remoteness of the North

Slope make the on-site construction of facilities

difficult and expensive. It is more cost-effective

to start off-site-to prefabricate, to modularize,

and to specially transport the needed structures,

from 500 tons to 5,000 tons, to their final destination. For the most part, oil facilities for the North

Slope 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 gravel

road network to a prepared site, and set on preinstalled large diameter piles. The transportation

equipment itself has required the construction of

special docks and causeways into the Beaufort

Sea, especially where near-shore water depths

are very shallow. Typically, 8 feet of water at the

dock is needed for barge traffic.

Status and Trends of

Technologies

The status of technologies, new developments

underway, and needed improvements in exploration, development, production, and transportation systems or practices are summarized below.

Table 2-2 lists some of the technologies for these

applications.

Reconnaissance Exploration

Exploration begins with reconnaissance.

Geological and geophysical surveys are conducted both on the ground and from the air.

Gravity measurements are usually taken at

ground stations, and magnetic measurements

are commonly made with airborne instruments.

Seismic surveys, which probe the shape of underground rock formations by interpreting the

reflections and refractions of sound waves traveling through the rocks, are usually conducted with

ground-based transmitters and receivers.

Detailed seismic reflection surveys commonly

use either explosives or vibratory sound sources

and, when feasible, are usually conducted on the

ice or snow to reduce tundra disturbance. In the

past, movement of seismic equipment in wheeled

vehicles over the tundra when snow cover is thin

has left noticeable tracks. Survey technology advancements that could affect future work are

automation of data collection and of transmission, processing, and interpretation of data.

While these technologies may contribute to more

accuracy in future survey work, they do not have

much effect on the environment. Exploratory

drilling is the activity of most environmental concern.

Drilling and Drilling Systems

Onshore exploratory or development drilling in

the Arctic is now routine, using fairly standard

technology. A drilling rig with power supply,

pipe, casing

,

 equipment, supplies, base camp for

personnel, and ancillary equipment must be

moved to the drill site. The drilling site may be a

gravel pad, ice pad, or insulated timber pad,

Depending on rock conditions, depth of target

zone, and other well conditions, drilling may be

done only in the winter. Winter drilling has advantages for both movement of equipment (using

ice roads and air strips) and for the use of ice

pads, because ice pads generally harm the environment less than gravel pads. Depending on

the well, drilling may also require additional time

and cost. Gravel pads are needed for year-round

work. Construction equipment is also needed at

an exploratory drill site to build gravel pads, construct reserve pits, and install other support

facilities.

Concerns about the impact of drilling technology on the environment mainly center on three

principal activities: 1) transportation of equipment to and from the site; 2) building of pads,

foundations, and pits at the site; and 3) disposal

of 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 Systems

a. Drilling Rig/Drilling-Lifting-Pipe Handling:

● Cant i lever rig design capable of driIIing on close

spacing, easily transported.

● Top drive rotary system capable of driIling 90 feet

at a time without making pipe connections.

• Automatic pipe-handling systems (off truck and

into hole),

● Iron-roughnecks, hydraulically driven make-up and

break-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 capability.

● High angle holes—drillpipe conveyed; coiled tubing conveyed tools.

● Measurement-while-driIIing (MWD) capabiIities—to

measure reservoir properties and to guide directional 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 Systems

a. 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 between exploration wells and efficient moving on

pads.

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 exploratory wells.

“Thin” pads using other insulating materials and

less gravel thicknesses,

Exploration reserve pits below-ground with permafrost for containment,

Development reserve pits below grade contained

in 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. Production

1. 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 prevention (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 Injection

a.

b.

Gas- Prudhoe Bay Unit Central Compression

Plant and upgrades of existing equipment; centralized field-wide gas lift system at Prudhoe Bay

with interconnecting tieline between operating

areas.

Water—Seawater Treatment Plants at Prudhoe

Bay and Kuparuk; incorporation of waterflood-system with treated seawater intake and related

fieldwide processing facilities into initial production facilities at Endicott; source water Injection

distribution system with tieline between operating areas at Prudhoe Bay,

4. Auxiliaries

a. 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 Operations

a. 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 environmental

concerns.

● Ground surface under some facilities insulated

around 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 TAPS

a. Construction of Pipelines/Pumping Stations:

● Winter construction above ground; summer construction 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 permafrost.

● 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 support facility.

b. Hotel and Base Facilities:

● Production facilities self-contained and largely selfsufficient re: fuel and power generation, water,

waste water, sewage treatment, etc.

● Interiors designed to avert psychological problems

linked to darkness and isolation.

c. Resupply and Transportation:

● Sealift (short time for open water transport), motor 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 that

minimize such impacts are well-known but may

limit exploration flexibility or increase cost. For

example, working only in winter months and

transporting by vehicles only on ice will minimize

impacts but may require extra time and cost for

an operator, especially when drilling deep or difficult holes,

Circulation Mud

Most drilling operations use a circulation system with a water- or oil-based fluid, called mud.

The mud is pumped down a hollow drill pipe and

across the face of the drill bit to lubricate it and

to remove cuttings. The mud and cuttings are

then pumped back up the annular space between

the 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 and

prevent cave-ins; 2) counterbalance any high

pressure oil, gas, or water zones in the formations being drilled; and 3) provide lubrication to

alleviate problems downhole (such as a stuck

pipe).’

Drilling fluids are selected based on the types of

geologic formations encountered, economics,

availability, problems downhole, reservoir

damage potential, and well data-collection pracPhoto 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 the

Exploration, 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 percent

water is the most widely used fluid for all types of

drilling in the United States. Colloidal materials,

primarily bentonite clay, and weighting materials,

such as barite, are common constituents of

water-based mud, and small amounts of chemical additives may make drilling easier. Oil-based

mud accounts for a small percentage of drilling

fluids used nationwide,8 but is essential for certain 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 oil

operations. The size of reserve pits has been

reduced in newer designs, and more recent practices have aimed at better control of the waste

products. Smaller reserve pits are possible by

recycling muds and injecting unusable liquids

down the well’s annulus. According to current

stated industry practice, when drilling is complete the reserve pit contains only drill cuttings

that can be buried or used as fill. Smaller reserve

pits also mean smaller gravel drilling pads. Major

oil companies operating in Alaska usually follow

these and other practices to minimize pad size

and reduce wastes.

Figures 2-4, 2-5, and 2-6 show typical operations involving drilling mud and reserve pits.

Figure 2-4 shows the standard mud flow pattern

from mud pump to drill pipe, down the well and

up the annulus, to a shale shaker on the surface

which screens out cuttings that are put in a

reserve pit. The remaining “cleaned” mud may

receive some additives and then return to the

mud pump for another cycle. The leakage of

mud and other wastes out of reserve pits has

been a serious environmental concern in the

past. New systems have been developed to address this problem. These new systems would

be designed to separate the disposal of cuttings

from all fluids and from a pit used as a reserve

mud source. The rock cuttings are both comparatively benign and simple to contain in a pit.

Figures 2-5 and 2-6 show the location of a

reserve pit used just for drill cuttings, a practice

that some North Slope operators are reportedly

beginning. If this type of system proves feasible,

the pit may be covered and permanently contained after drilling is completed. Environmental

groups stress the-need for

to confirm the permanence

Directional Drilling

long-term monitoring

of this system.

Directional drilling is deliberately drilling at an

angle from the vertical to reach a target that is offset from the surface wellsite. Directional drilling

was developed specifically for offshore use to

allow multiple wells to be drilled from a single

platform. Directional drilling on land is used

when surface wellheads must be clustered in a

small area; one drill pad in the Arctic may contain

as many as 40 wells. As directional drilling improves, the number of pads can be decreased

and their locations can be more centralized. Currently, North Slope wells are drilled at angles of

up to 60 degrees from the vertical with the point

of 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 mature practice on the North Slope. Further

developments in directional drilling could allow

denser clustering of wells, but changes are expected to be gradual. Continual advancements

in offshore extended-reach drilling are helping to

cut the high costs of subsea wells; some of these

gains may be applied to the North Slope in the future. One North Sea proposal calls for up to a 75-

degree angle and as much as 6 mile reach for a

research and development well.

Horizontal Drilling

Horizontal drilling, perfected in South Texas

tests, is used to improve well flow-rates, especially for thin formations. A conventional directional

hole is drilled to a predetermined depth and then,

using another drilling method, the hole is drilled

at 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

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

substantially increased flow rates and that have

recovered hard-to-get oil. Figure 2-7 illustrates

one of the horizontal wells drilled at Prudhoe Bay

to improve recovery in thin portions of the reservoir near the edge of the field. Horizontal drilling

could enhance economic recovery rates in some

other North Slope applications.

Both directional and horizontal drilling,

however, could have some disadvantageous environmental consequences since oil-based muds

are more likely to be used to better lubricate the

drilling bit. These oil-based muds are more difficult to dispose of in an environmentally sound

manner.

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

Directional profile of Sohio’s JX-2 well

o “

2,000 “

4,000 –

5

6,000 –

8,000 –

o 2,000 4,000 6,000

Distance from vertical (ft)

SOURCE: 011 and Gas Journal, Feb 17, 1986

Permafrost Protection

The warmth of produced oil flowing through the

upper portion of a well drilled through permafrost

will eventually melt the permafrost. Hence, the

well casing must be properly designed to prevent

thaw and subsidence. The area of the melted

permafrost may limit close well spacing, as extensive melting could cause subsidence of other

nearby foundations. Nevertheless, work on the

causes, extent, predictability, and control of permafrost melting problems is continuing in industry Arctic research and development

programs. Results of this work could affect

designs of future well sites and drill pad arrangements. For example, some closely spaced surface wells (about 10 feet on center) with special

casing have been recently instailed at Endicott.

Transport of Equipment

In the early stages of exploratory drilling,

transporting equipment is a major activity. To

minimize damage to the tundra, winter season

movements of heavy equipment on ice roads are

preferred. Summer movements may be made by

airplane, by barge, or by a specially designed

ground vehicle. Vehicles with large, soft tires,

called rolligons, have been used, as have air

cushioned vehicles. Soft-tired ground vehicle

technology is well-established; however, aircushioned vehicles have not proven very reliable

or efficient. Operators usually choose some

combination of transport methods to balance

cost, environmental protection, and the need for

flexibility. Figure 2-8 shows the typical uses of

various transportation systems during different

Arctic seasons.

New transportation technologies are unlikely

anytime soon without more regulatory pressure.

Operators may need specific guidelines on the

timing or location of movements and on maximum weights, to keep environmental damage

down. However, some level of damage to the

tundra is unavoidable. Future environmental

regulation must evaluate what level is acceptable

and what operational controls will assure that

operators stay within acceptable limits.

Once a field is discovered and development

begins, marine docks and gravel roads needed to

receive 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 conditions

Open Ice breaking

water by hoverbarge

I

Barging

I 4

Small boats

Rolligons on ice roads

I

-leavy equipment on ice roads

“— -

Pontoon sleds or hoverbarae

Helicopters

Fixed wing on ice runways

i

Fixed 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 manmade change to the landscape.

Construction

When a field is developed, onsite construction

centers around building gravel pads, roads, culverts, docks, causeways, and foundations

(pilings); installing modules; building pipelines,

etc. Construction practices have changed over

the years since Prudhoe Bay development

began–mainly through smaller, more compact

drilling pads. However, the typical 5-foot-thick

gravel pad, road, or airstrip is reasonably standard and is not likely to be much reduced in size in

the near future. Thus, lots of graveI still needs to

be mined and moved. Nevertheless, OTA iS

aware of some insulated gravel pads built in

Kuparuk that reduce gravel thickness and, in addition, of the consolidation of facilities to reduce

the size of the pads. It is likely that industry’s incentive to reduce gravel use is mostly economic.

If gravel is easily available and cheap, however,

these gravel-reduction measures would not likely

be used without regulatory pressure.

Gravel is also used to build roads. Figure 2-9

shows the growth in the length of the road network for both Prudhoe and Kuparuk since they

were first developed up through 1983. These

data indicate that even 15 years after Prudhoe

was discovered, roads were still being constructed at about the same rate as in early years.

In 10 years Prudhoe’s road mileage tripled. The

Kuparuk field is following the same pattern. A

corresponding growth in gravel coverage is assumed. While no more recent road coverage

data are available, industry claims that gravel

coverage leveled off in the last few years.

The continual, long-term growth in the extent of

areal coverage of the tundra by manmade facilities

follows the gradual and staged nature of the
Figure 2-9.–Growth of the Prudhoe and Kuparuk

Road Networks 1968-83

0 Prudhoe Bay

A Kuparuk

Eventually, less geologically attractive drilling

targets come into range by using the same infrastructure. New opportunities may open for expanding production through: the development of

new, smaller fields; infill drilling; seeking srrder,

separate reservoirs within the same field; and

drilling on the margins of the field where the oilbearing formation is relatively thin. As these additional drilling targets are pursued, the road and

gravel coverage continues to grow.

Wherever construction operations require

heavy equipment and major facilities, accidents

development of large oilfields. The first stage of

development, when a pattern of primary recovery

wells are drilled, can last several years simply because of the large number of wells to be drilled and

the economic penalty involved in attempting to

complete the drilling quickly by importing large

numbers of men and equipment. During this

period, the number of gravel pads and the length of

the road network grows with the number of wells

being drilled. After the initial wells are drilled, after a

portion of the field’s recoverable resources have

been produced, and after the reservoir pressure

driving the oil to the wells is somewhat depleted, a

second stage of recovery seeks to maintain reservoir pressure by injecting fluids – commonly water,

in a “waterflood” operation – into the producing formation. This operation requires additional facilities

and (usually) wells for injection, with additional requirements for gravel pads and roads. Further, in a

third stage of recovery, heat, fluids, and chemicals

are injected into the rock to loosen its hold on the oil

not released in the first two stages; these operations

may add still further to road and gravel coverage.

reduce these risks, but some environ mental

groups claim that the regulations are not strong

enough and that construction over large areas

could cause extensive impacts.

Pipelines

Much of today’s Arctic pipeline technology was

first developed for the Trans Alaska Pipeline System. All developed North Slope fields pump their

produced oil by the same kind of elevated

pipeline to the TAPS Pump Station #1 at Prudhoe

Bay. Refinements have been made in insulation

and construction techniques, which make construction more cost-effective. Arctic-grade steel

is used for all pipeline vertical support members

(VSMs) and other structural components. VSM

setting depths are now being adjusted to permafrost characteristics to prevent VSM movement.

Depending on the terrain and excavation

necessary, winter-only pipeline construction may

be preferred because it offers more tundra

protection and, generaily, lower cost. For example, winter work from a temporary ice pad or

ice road eliminates some of the need for a gravel

construction pad or road parallel to the pipeline;

road location becomes more flexible. A gravel

access road, constructed later, may follow the

pipeline but need not parallel it precisely.

(Recent studies of caribou movement through

pipeline-road corridors indicate that pipeline and

road separation of 600 to 800 feet may be necessary for caribou passage). In addition, VSMs can

be more firmly set during the winter anyway,

when the tundra is frozen. Summer construction

is 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 called

vertical support members (VSMs).

operate on the thawed tundra and surface water of sulfur dioxide, 17,000 tons of carbon

fills up the VSM holes. monoxide, and 2,000 tons of suspended particuIates enter the atmosphere each year from

Wastes and Waste Disposal production activities.11

The generation of wastes during oil production

is unavoidable. Waste products can be broadly

categorized into three types: air pollutants, liquid

wastes, and solid wastes.

The principal air pollutants discharged –mainly

by natural-gas-fired turbines and heaters–are

sulfur dioxide, carbon monoxide, suspended particulate matter, and nitrogen oxides NOx. Emissions of NOx range from about 60,000 to 60,000

tons per year.10 In comparison, about 600 tons

Liquid wastes include reserve pit fluids, domestic wastewater, brine discharges, hydrostatic test

discharges, vessel rinsates, excavation discharges, oily wastewater streams, workover

fluids, waste oil solvents, and others.

Major types of solid waste include drilling

wastes, scrap metal, oily wastes, junked vehicles,

construction debris, more than 10,000 used

drums per year, and other materials.

10. Larry Dietrick, Alaska Department of Environmental Conservation, Testimony before the Senate Committee on Natural

Resources, &t. 13, 19S70

11. ARCO Alaska, Air Issues on the North Slope of Alaska, 1987.
Chapter 2 ● 53

Present Alaskan and U.S. Environmental Protection Agency (EPA) regulations govern waste disposal practices. The industry considers its

technology for handling waste to be adequate and

does not expect major advances in the near future.

Environmental groups, however, point to recent

charges of violations of the Clean Water Act and

consider waste disposal an important unresolved

regulatory issue. The Alaska Department of Environmental Conservation has noted that the North

Slope has never been subjected to a detailed

evaluation of waste management practices or environmental protection measures. it appears that

the industry could continue to improve waste handling practices if requirements become more stringent.

Waste disposal methods consist of well injection, reserve pit use, confinement, recycling, incineration, and Iandfilling. Most waste generated

by oil production on the North Slope is either

nonhazardous or is currently exempt from hazardous waste regulation under the Resource

Conservation and Recovery Act (RCRA). Environmental groups want to see more exempt

wastes redesignated as hazardous, but EPA

recently concluded that, pending further study,

no significant changes are necessary.13 Existing

practice for wastes designated as hazardous is

either to recycle onsite or to ship them out of the

State for incineration, recycling, or other disposal.

Deep injection of wastes is a source of controversy in arguments about the environmental

impacts of current North Slope development and

the potential impacts of future development of

the ANWR coastal plain. The controversy stems

from the contaminants found in the injected

materials, the relative lack of monitoring on the

North Slope, the lack of detailed understanding

of the geology of the coastal plain, and the history of environmental problems associated with

deep well injection in the Lower 48. The types of

wastes subject to deep well injection in Alaska

are produced water and associated oilfield wastes such as mud. The Alaska Oil and Gas Conservation Commission has primary responsibility

for regulating deep well injection. State regulations include requirements for casing and

cementing wells to ensure initial structural integrity and pressure monitoring to maintain it.

The basic environmental complaint about deep

well injection is the potential for migration of the

wastes out of the injection zone and for contamination of shallower aquifers or surface

waters. Contamination may occur because of

structural failures in the injection wells, unforeseen geological pathways for migration, or

the existence of undocumented or improperly

plugged wells intersecting the injection zones.

The industry claims that the thick permafrost

layers on the North Slope are ample protection

against “geological” failures, and that the permafrost layer at ANWR will serve this purpose.

Despite these assurances, the Alaska Department of Environmental Conservation is concerned about the potential for unforeseen

migration of wastes, especially on the coastal

plain where detailed geophysical studies and well

data are not available. Problems with well

failures– either with the injection well, which is

usually a converted production well, or with other

wells in the vicinity– have been a concern in the

Lower 48, where old wells are used for waste injection in many areas, and undocumented and

improperly sealed abandoned wells may sewe as

pathways to other geologic strata or to the surface. 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 concern on the North Slope.

Resewe pit wastes, consisting of drilling mud

and cuttings suspended in a water or oil base, are

another concern. There are over 250 reserve pits

in 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 DEC

is in the process of doing this evaluation, which will be used as the basis for developing appropriate stipulations for new areas like

ANWR.

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

million gallons of used drilling mud and cuttings

and associated wastes.14 Excess reserve pit

fluids are either disposed directly onto the tundra

or onto roads, or are injected into subsurface formations. The Alaska Department of Environmental Conservation estimates that 100 million

gallons of supernatant (i.e., the liquids forming a

layer above settled solids in the reserve pit) are

pumped onto the tundra and roadways each year

to make room for new drilling waste and to avoid

overtopping and/or breaching problems. Additional resewe pit fluids may reach the tundra if

reserve pits are breached because of poor construction. Approximately 26 million barrels of

muds and cuttings are currently impounded in

Prudhoe Bay reseme pits. 15

Liquid reserve pit wastes contain small amounts

of metals (e. g., aluminum, arsenic, barium, cadmium, chromium, copper, lead, mercury, nickel,

silver, and zinc); aromatic hydrocarbons; and

chemical additives. In sufficient quantities and

with enough exposure, many of these components of liquid reserve pit wastes can be harmful to aquatic organisms and to waterfowl and

other birds (for example, potentially causing

bioaccumulation of heavy metals and other contaminants in local wildlife, thus affecting the food

chain). EPA notes that the controlled discharge

of excess pit liquids has been a State-approved

practice on the North Slope.

The Alaska Department of Environmental Conservation, the State agency with primary

authority to regulate the design, construction,

and operation of resetve pits, now requires that

discharges meet State water quality standards.

Also, the reserve pit must have been stable (no

discharges into the pit) for one freeze-thaw cycle

before any discharges can take place. Environmental groups assert that these standards are inadequate to protect aquatic species and that effluents have exceeded acceptable levels in the

past. Since a National Pollutant Discharge

Elimination System’s (NPDES) permit does not

cover these discharges, EPA is concerned about

the long-term effects of discharging large quantities of liquid reseme pit waste on the tundra.

While concerned, EPA notes that the existing

body of scientific evidence is insufficient to conclusively demonstrate whether or not there are

problems resulting from this practice. 16

A related concern is the potential unintended

breaching of North Slope reserve pits, caused by

the intense freeze-thaw cycles that can break

down the stability of the pit walls, enabling untreated liquid and solid waste to spill onto the

tundra. Some observers also question the advisability of underground injection or permafrost

burial of reserve pit waste.

OTA has not addressed the environmental impacts of waste generated by North Slope oil

production. Generally, neither the fact that these

wastes are generated nor the approximate

amounts generated is in dispute. However, there

is considerable difference of opinion about the

environmental impact of the various kinds of air

pollutants and liquid and solid waste products.

The environmental community has issued a

detailed report documenting what they believe is

significant environmental damage caused by 17 Environmentalists are development activities.

concerned that air and water pollution and improper management of hazardous wastes

threatens aquatic and terrestrial ecosystems in

the Prudhoe Bay area and that similar pollution

with similar results will occur in ANWR.

14. Trustees for Alaska, Natural Resources Defense Council, and the National Wildlife Federation, Oil in the Arctic, The Environmental

Record 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 to

demonstrate that despite some unavoidable consequences of development, “there is no evidence

to support the allegation of widespread pollution

or to justify claims of significant adverse environmental impact. “18

The Environmental Protection Agency is

cautious in its recent report to Congress19 but is

generally less alarmed than the environmental

community about pollution problems and is also

less sanguine than the oil industry that there are

no North Slope pollution issues of concern. EPA

is concerned primarily about the discharge of supernatant onto the tundra and roads, suggesting

that further study of impacts is needed. 20 The

State of Alaska has recently adopted more stringent effluent limits and has suggested that zerodischarge of industrial wastewater streams

should be carefully considered for ANWR.21

Water

Substantial amounts of fresh water are used in

drilling and other oil production activities. Water

supplies in the Arctic are not easily tapped yearround, and some convenient supplies are environmentally unacceptable to use. It is therefore

prudent to first reduce water consumption to the

most reasonable practical level. Technologies

for ensuring environmentally safe water supplies

are important. The methods used by industry include trapping and melting snow; insulating

small, non-fish-bearing lakes; flooding gravel

pits; and desalting seawater.

Among the most abundant sources of water are

the gravel extraction pits that have been converted to water reservoirs. Water for many of the

Prudhoe Bay well operations is collected and

hauled from the Put River pit, a former gravel

source that has been flooded and now sewes as

a year-round water source. Similarly, Mine Site C

serves as a water source for the Kuparuk oilfield;

this pit is replenished annually with overflow from

the Ugnuravik River during break-up.

Desalination of seawater is sometimes a practical option for operations near the coast. If the

operation is in the winter, an ice road is constructed to a point where the seawater is not

frozen to bottom, the desalination operation is

set up there, and fresh water is trucked to where

it is needed. This method was used for operations on Challenge Island #1 in the winter of

1980-81 and for Alaska Island #1 in the winter of

1981-82. Desalination of seawater was also used

for all the wells drilled from Endeavor Island and

Resolution Island and for most of the Niakuk

wells. A large desalination plant has been installed at the Endicott field to support production

operations. Conoco also used desalination for

their Milne Point operations; however, it

desalinated water from a 3,000-foot-deep, brackish water, underground aquifer rather than from

seawater.

Many operations have had reasonable access

to deep lakes. For example, deep lakes in the

Sagavanirktok River delta were used for the first

three “Sag Delta” wells in the 1970s. Two deep

lakes were approved for water sources for operations to the west of the Sag Delta in the winter of

1981-82. No fish were found in either lake, but

draw-down restrictions were still applied to

protect the few that might have gone undetected.

Deep holes in a river or an oxbow lake are also

valuable sources of water. The Alaska Department of Fish and Game applies withdrawal rate,

filter size, and draw-down restrictions to ail river

sources to protect fish. Water for the Niakuk #1

well, for example, came from a deep hole in the

Sagavanirktok River. Big Lake, the water source

for Standard’s Base Operations Camp at Prudhoe, is an example of a lake that has been insulated to minimize freeze-down. For several years

it 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 the

Claims of The Trustees for Alaska, The Natural Resources Defense Council, and t e National Wildlife Federation, February 1988., p. h

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 erecting

snow fences that collect drifting snow for insulation.

22

Production Facilities

Production facilities designed to operate for

long periods of time with minimal attention must

be installed onsite. Directional drilling minimizes

the area needed for drill pads and support for

wellheads. Characteristics of the oil reservoir will

determine the number and location of wells

needed, but wellheads can be clustered

reasonably close together on individual pads.

Wells are needed for both oil production and injection of fluids to stimulate flow. Soil types and

permafrost melting characteristics determine the

minimum spacing and required support of

wellheads on the North Slope.

Production facilities for Arctic use are usually

built offsite in large modules (from 500 to 5,000

tons depending on service and distance from

dock), in locations such as Washington, Oregon,

California, and the Gulf Coast and are moved by

barge to coastal docks and then onto pilings and

pads at the site. Many kinds of modules are

needed to complete a production complex.

These include oil/gas/water separation plants,

gas injection plants, waterflooding plants, control

stations, power-plants, etc. In addition, many

support modules are needed, including living

quarters, maintenance shops, storage and administrative areas, water and waste treatment,

etc. The production field, in time, becomes a network of facility modules resembling a small factory town built on pads and pilings and protected

from the harsh environment. Roads, airstrips,

and marine docks complete the compiex. All

these facilities require considerable acreage and

thus need a large source of foundation material

to build the 5-foot-thick gravel pads commonly

used.

Production facilities are added and modified

over time as an oilfield is further developed, with

the addition of enhanced recovery systems as

needed. Each change is usually accompanied

by some increase in size, space, and other

material needs.

Summary

Arctic oil and gas technology has evolved over

the past decade into today’s effective and mature

industrial system with its accepted commercial

operating practices. The recent development of

North Slope fields such as Kuparuk and Endicott

are the result of this maturity, and any future

ANWR development under similar economic and

environmental constraints would probably

resemble closely these two fields. The industry is

confident that this likely extension of current

designs and practices is sound development and

offers adequate environmental protection. Some

environmental groups, however, contend that

today’s practices are not acceptable for development of ANWR.

While Arctic oil drilling and production technology has matured, the practices for using the technology have improved even further. These

improvements have occurred because of both

economic and environmental concerns. Practices are likely to continue to improve in ANWR –

if it is developed – if economic factors warrant or

if environmental requirements are strong, OTA

has not evaluated the specific improvements that

may reduce environmental impacts, but it appears that extensive debates about environmental protection versus economics will continue if

ANWR is leased. Environmental groups have

specific concerns that will need to be resolved

during the development of regulations for any

development that may occur.

22. Standard Alaska Production Company, letter to OTA, Feb. 23, 1988.
Chapter 2 ● 57

TECHNOLOGY APPLICATIONS FOR THE ARCTIC

NATIONAL WILDLIFE REFUGE

If the Arctic National Wildlife Refuge’s (ANWR)

coastal plain is leased, the oil industry will apply

its broad technological and practical experience

in Arctic oil development to the specific conditions of ANWR. The industry generally claims

that ANWR exploration and development will look

pretty much like the most recent operations elsewhere on the North Slope.

ANWR Special Conditions

OTA has attempted to identify any special or

unique conditions of the ANWR coastal plain, as

compared to Prudhoe Bay and other North Slope

areas, that would affect the technology used or

practices followed for petroleum development.

The primary data source was our Anchorage

workshop and subsequent submissions from industry and other participants at the workshop, as

well as extensive comments from industry and

environmental organizations that reviewed an

earlier draft of this report.

Topographic Relief

The southern part of the ANWR coastal plain

has moderate topographic relief, with gently rolling foothills. In contrast, Prudhoe is a very flat

thaw-lake plain. ANWR’s topography has advantages in that there may be fewer problems

with standing water and that there may be better

elevated sites for facilities. But there are also disadvantages to the greater relief, including the

potential for more problems with channeling and

erosion (especially if and when east-to-west

roads are built, crossing many streams and requiring attention to drainage patterns) and

problems with building roads or locating

facilities.

For example, in ANWR, a pipeline can cross

gullies and hills more or less in a straight line, but

a pipeline access road will need to snake along

some surface contours to avoid extensive excavation and filling. A road may also create more

environmental problems than a pipeline, especially problems related to drainage, mining

gravel, etc. Airstrips need to be reasonably flat;

hence, suitable locations in the foothills of ANWR

would be more difficult to find than they are at

Prudhoe, and, even then, some cutting and filling

would have to be done. The same considerations are true for a camp or production facility in

ANWR. At Prudhoe, a camp or an airstrip can go

almost anywhere that is dry and, for a winter-only

exploration well, an airstrip can be constructed

even on a convenient frozen lake.

Sea Ice and Port Sites

In generaI, potential ANWR port sites have

deeper water than do Prudhoe sites. Deeper

water eases the problem of building docks and

means the length of causeways, needed to reach

the water depths of about 8 feet required for barges and other shipping, could be reduced. Ice

conditions in potential ANWR port sites are

generally equivalent to those in the Prudhoe

region except in the extreme eastern part of

ANWR, where more severe offshore ice conditions may cause problems for shipping.

Gravel Availability

Extensive gravel deposits are located within the

ANWR coastal plain, a situation that simplifies

finding gravel for construction. Gravel availability

in ANWR is similar to that at Prudhoe but better

than at Kuparuk.

Permafrost Layer

Some experts believe the permafrost layer in

ANWR is thinner than at Prudhoe, but the

evidence is sketchy. Permafrost thickness may

sometimes affect aspects of well drilling (e.g., the

starting depth for directional drilling), but other

factors could govern drilling decisions and may

be more important. This uncertainty will be

resolved only with actual drilling. The permafrost

situation in ANWR, however, probably will be

handled in much the same way as it is at Prudhoe

Bay.
58*ANWR

Sites for Deep Injection of Wastes

Knowledge of subsurface geologic conditions

for deep well injection is sketchy at this time but

is important to locating acceptable sites for waste

injection. Prudhoe is considered to have good

conditions for containing deep injected wastes.

Conditions in ANWR are not defined, although

experts disagree about the interpretation of existing evidence. Industry is reasonably confident

that suitable sites can be found; however, different experts have different opinions on the extent of tests and study necessary to confirm a

“suitable site. ” This ambiguity is one of the chief

concerns of some environmental groups.

Potential Developed Area

The ANWR coastal plain covers about 1.5 million acres. This area is about twice the size of the

general region covering the Prudhoe, Kuparuk,

Lisburne, and Endicott fields, the major producing North Slope fields. The U.S. Department of

the Interior has identified 26 faulted structural

prospects within the plain. The mapped and

areal extent of these prospects is based on structures defined by seismic data. Thus, the

prospects contain potential petroleum traps, but

the extent of producible oil is unknown. If these

prospects contain oilfields, the largest prospect

(227,000 acres) would be similar in acreage to

Kuparuk and the second largest (about 130,000

acres) would be roughly the area of the Prudhoe

Bay field. All 26 prospects are of a size that could

contain fields at least the areal size of the smaller

known North Slope fields. While these comparisons are not predictive, they are indicative of

the possible extent of surface development if

major ANWR discoveries are made. The extent

of land coverage for development at ANWR

would then likely resemble Prudhoe and Kuparuk

and perhaps some smaller fields as well. If

several of ANWR’s prospects contain economically recoverable oil, the total developed area

may be equal to or greater than the developed

area of all existing North Slope development.

Water

Whereas industry has made extensive use of

existing surface water supplies at Prudhoe,

ANWR has few large, deep lakes. Substantial

water for ANWR development would probably

need to come from other sources. Industry could

resort to excavating pits, melting snow, and other

water collection techniques, but these activities

will likely prove to be more extensive in ANWR

than they were at Prudhoe Bay. Industry has also

claimed that 12 of the large rivers in the ANWR

coastal plain could be sources of water in summer. Environmental groups believe that water

supply will require regulatory attention to minimize impacts.

Wildlife

Approximately 200,000 caribou of the Porcupine Caribou herd inhabit the Arctic National

Wildlife Refuge from roughly mid-May to late July.

The ANWR population vastly outnumbers 15,000 -

or-so caribou of the Central Arctic Herd that

reside year-round in the Prudhoe Bay area; this

contrast is probably the most dramatic for wildlife

populations in the two areas. Both herds have

been increasing in size in recent years. The degree to which the Porcupine herd will be able to

acclimate to development compared to the

Central Arctic herd is still being debated. The

reintroduced musk oxen population in ANWR

now numbers about 500 animals; none live in the

Prudhoe Bay area. The number of bears and wolves has declined in the Prudhoe Bay area, largely because they are not as tolerant of man as are

some other species. Total North Slope wildlife

populations however, are not believed to have

diminished.

Overview: ANWR Technologies

and Practices

The technologies used to explore for and possibly produce any petroleum resources in the

Arctic National Wildlife Refuge will most likely

resemble those already in place on other North

Slope fields. Technology now in use at the most

recently developed sites, such as Endicott, has

been built to rigid industry design standards for

the Arctic environment and is efficient and effective for producing oil from these fields. The industry operators forcefully claim that the

technology has been installed and operated with

care to avoid unnecessary environmental impacts. In opposition to this claim, the environmental community points to a number of

instances where habitat has suffered damage.
Chapter 2 ● 59

OTA has not analyzed the history of accidents,

spills, violations, etc., on the North Slope23 but

notes that future regulations will need to be

based on an objective analysis of these environmental concerns.

Only oil has been produced from Alaskan North

Slope fields to date. While substantial gas reserves have been delineated, no system to transport

gas to the major markets has been built. Several

methods have been proposed to transport gas

but favorable economics and other concerns

have prevented their adoption. The technology

for Arctic gas production, however, has been in

use at Prudhoe where the world’s largest gas

compression facility is operating and considerable gas handling capability is in place to inject the gas back into the formation.

Most industry experts believe that no major

technological breakthroughs are needed to safely and effectively explore for and produce oil at

ANWR. They say that the production systems

have advanced in practice during the past two

decades of Arctic work to an acceptable level,

which they believe is demonstrated by smooth

and reliable plant operations.

The level of environmental damage that has occurred, however, is vigorously debated. Many of

the technological advances in the past 10 years

have concentrated on improving operational efficiency. Several of these advancements also appear to reduce environmental impacts, but

specific measurements of reduced impact are not

readily available. Some advancements include

improved waste handling, less toxic discharges

from drilling, and reduced needs for gravel pads

and roads with possible reduced intrusion on

wildlife. Other technological advances have led

to more cost-effective operations in the Arctic.

These advances include substantial automation

of oil field operations, more efficient sub-assembly of modules, and systems for controlling permafrost melting. Modules for production plants

are built in complete units in the Lower 48 and

moved in large pieces on barges to the North

Slope, thus eliminating the need for large and

costly construction crews working onsite.

More environmentally important than developing new technologies for use in ANWR is controlling the practices used to apply the existing ones.

Operating practices include: transportation of

equipment; construction of drilling pads,

pipelines, and facilities; selection of drilling techniques; controlling the effects of permafrost melting; and containing and disposing of drilling

fluids and other waste products.

Equipment transportation involves moving

many very large heavy pieces of equipment with

large vehicles over long distances. The tundra is

very fragile, and it does not support much weight

in the summer months. The construction of

pads, pipelines, and facilities are also major activities on fragile ground; a considerable amount

of gravel must be mined which can alter the

landscape extensively. Drilling techniques can

be selected to minimize surface disturbance if

wells can be closely clustered on the surface and

if rigs are easily moved or set up. Permafrost

consideration is critical because uncontrolled

melting may cause foundations or supports to

fail, resulting in accidents, spills, etc. It is also important to keep any waste products contained

and/or to dispose of them properly.

Impacts: ANWR Technologies

and Practices

Key technologies and practices with potential

for significant environmental stress were

analyzed in an OTA workshop held in Anchorage,

Alaska in November 1987. The following discussion expands on the workshop’s views.

Exploratory Drilling

Exploratory drilling practices in ANWR will likely

follow those used in recent exploration wells on

the North Slope. Considerations that may affect

the environment include the ability of drillers to

23, A com rehensive discussion of environmental impacts on the North Slo e from the environmental community viewpoint

appears in “&‘1 in the Arctic: The Environmental Record of Oil Development on Raska’s North Slope, ” Natural Resources Defense

Council, January 1988. Similar discussions from the industry view ap

Oil Co., August 1987; “Assessing the Impact of Oil Development on r

ar in “Current ANWR Environmental Issues, ” The Standard

aska’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 temporary pads and other facilities, and then, when

work is done, to remove all material with no

damage to the tundra. Practices and equipment

have been developed over the years in the Arctic

to protect the tundra, but economics and work

conditions have sometimes ruled out the ideal

approach. In any case, careful set-up and quick

removal are keys to environmentally acceptable

exploratory drilling. Careful set-up probably can

be controlled by regulation, but quick removal

will depend on conditions– not always predictable– encountered while drilling.

Techniques have been developed to build ice

roads, ice pads, and ice air strips for winter-only

drilling in the Arctic. Moreover, water can be obtained from melted snow, and reserve pits can be

encapsulated. In these ways, the impacts of a

drilling operation can be readily removed, and

there could be little need for gravel excavation or

any other disturbance of the tundra except for

reserve pits. However, winter-only drilling can

have economic and operational disadvantages.

Given the added time and costs of winter-only

drilling, industry argues for flexible regulations so

that they can judge when such practices are truly

warranted. Industry also notes that a small risk of

a blowout is always present and, if it occurs, the

extra time needed to drill a relief well could extend into the thaw season. Environmental

groups argue, however, that, given the unique

nature of ANWR, very stringent regulations

should be applied with minimal flexibility.

Drilling Systems

Most existing Arctic drilling technology likely to

be used in all ANWR exploration, production,

workover, and service well drilling has been

developed to the point of acceptable efficiency.

Use of the most advanced of these systems also

may lessen some environmental impacts. For

example, directional drilling and the close spacing of wells on the surface contribute to the ability

to design fewer and smaller drill pads and thus to

reduce the quantity of gravel needed and the

spatial impact of development. Directional drilling technology is well developed and continues

to improve. In recent years, the development of

measurement-while-drilling (MWD) systems,24

computer analysis, and improved survey techniques have significantly improved directional drilling efficiency and directional limits (the angle off

vertical that is possible). Improvements expected in the next decade include more comprehensive logging tools deployed during MWD

operations, better directional control from the

surface, and improved mud systems for reduced

torque or drag.

All of these advancements together may lead to

closer spacing of wells on drill pads, and to

clustering of larger numbers of wells on each drill

pad. However, there are many other factors too

that will determine the layout of pads and

facilities at ANWR. Well spacing will be determined by a combination of economic, environmental, operational, and safety considerations.

Specific conditions such as reservoir depth, well

drainage area, and permafrost thaw subsidence

also will be factors. Recently drilled wells at

Kuparuk and at Prudhoe are spaced as close as

30 feet apart; on the Endicott gravel islands, wells

are now even more compact, spaced at 10-foot

intervals. Depending on actual conditions,

ANWR wells would likely be spaced within this

range.

Mud Systems

The most likely mud systems in ANWR are

those that have been successful in other North

Slope fields. Weighted Iignosulfonate, polymer,

and oil-based mud have applications in Arctic

regions but are not unique to Alaskan oilfields.

The majority of North Slope drilling operations

use water-based polymer and Iignosulfonate

muds. However, some drilling operations such

as directional, high-angle, and horizontal drilling

require the lubricating properties of oil-based

mud. Also, some coring 5 operations require oilbased mud to lubricate the bit cutting the core

and to minimize damage during drilling. Generally, oil-based mud is used for drilling only the short

productive intervals in non-conventional wells.

24. These systems feature remote sensors that measure angle, location, speed of penetration, and other factors at the bottom of

a hole and transmit that information to a driller at the surfaoe without interrupting dring 1’ 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 the

oil-based mud is required. The anticipated advances from horizontal drilling will possibly increase the need for oil-based mud and, if this

occurs, greater attention to suitable disposal of

oil-based systems may be needed in ANWR. Environmental groups consider the disposal of mud

to be an issue worthy of closer attention.

It is not clear whether more stringent requirements for disposal of used mud and cuttings

would be necessary in ANWR. Industry asserts

that present State of Alaska regulations are adequate and can be followed in ANWR without

much trouble. Alaskan regulations–as they

apply in a permafrost region such as ANWR – require that the drill solids be de-watered or frozen

in place, covered with a membrane to prevent future fluid entry, and covered with gravel and organic soils of sufficient depth to insure that the

drilled solids remain permanently frozen. The liquid drilling mud then would be injected into a

subsurface zone. This process is commonly

called annular injection because the drilling mud

is displaced down the annulus between the surface casing and the production casing. Dedicated injection wells are also used. Some

environmental groups have substantial concerns

about these practices; they advocate higher

standards for waste management in a wildlife

refuge.

Fresh Water Supplies

Several techniques for supplying fresh water,

developed and used at North Slope production

areas, are likely to be used in ANWR. These techniques include: creating deep pools that will not

freeze to the bottom in or adjacent to

rivers/streambeds, creating deep pools in lakes,

desalinating seawater, erecting snow fences to

trap snow (and then melting it using snow melters), insulating lakes to keep them from freezing

to the bottom, and converting gravel extraction

pits to reservoirs. For exploratory sites, water

could be hauled from approved locations if

necessary. OTA has not evaluated the extent to

which the effects of these practices have been

monitored.

How much water would ANWR need? Standard

Oil Company submitted to OTA the following data

as typical of the water requirements that may be

expected in ANWR exploration.

● 414,000 gallons of water per mile for construction of an ice road; 4,200 gallons of

water per mile for daily ice road maintenance.

● 2,500,000 gallons of water for construction of an ice airstrip;

● 2,100 gallons of water for daily maintenance. (Volume would be less if airstrip

is built on a frozen lake.)

● 25,000 gallons of water daily for drilling rig

and domestic use.

For a typical exploratory well with about 150

days of operations and about 5 miles of roads,

Standard Oil estimates that total water consumption would be about 10 million gallons. The U.S.

Department of the Interior estimates 15 million

gallons for a similar exploratory well.

For development operations, water requirements would depend on the size of the development, the number of wells, and the size of the

support camp. Industry claims that ANWR

operations would most likely use developed

water reservoirs from former river channels

deepened by gravel extraction or from the

desalination of seawater. Water withdrawn from

gravel extraction pits during the winter would be

quickly replenished during the subsequent spring

snowmelt. Currently, Prudhoe Bay development

drilling operations consume approximately

630,000 gallons of water per well.

The potential for water supply techniques to

damage the environment would need study at

each site. The environmental groups may well

urge regulatory attention here.

Gravel Pads/Roads, etc

The most likely number, size, and configuration

of gravel pads for an ANWR development are difficult to estimate until an actual discovery is

made and delineated. Industry believes,

however, that less gravel will be required for an

ANWR development with today’s technology and

experience than was required for early Prudhoe

Bay development. Most others would agree, assuming equivalent field characteristics and

production systems. Improvements in directional drilling techniques and permafrost technology,

along with the use of larger, more consolidated

and vertically-layered equipment modules and
620 ANWR

more space-efficient facility designs tend to

reduce gravel pad requirements. Improvements

in the design of compact pads have already been

realized in recent North Slope developments

such as Lisburne and Endicott.

Gravel pad design is also affected by the pad’s

location, insulation needs (to avoid permafrost

thawing), stability requirements (to account for

permafrost subsidence and requirements for

weight support), and site-specific soil conditions.

Characteristics of the actual oil reservoir,

however, are the most important factors in determining the most cost-effective design for the total

number of wells, the number of wells per pad,

and the pattern of positioning well pads over the

surface. For example, while compact pad design

improvements are evident in Kuparuk, the actual

area covered by gravel pads, roads, etc., as a

ratio of total field production is much greater in

Kuparuk than Prudhoe because Prudhoe is a

more productive field with much thicker pay

zones, producing higher per-well flows and

higher per-pad production. The total area of

tundra that would be covered by gravel in ANWR

depends most upon whether an ANWR field has

characteristics more similar to Prudhoe, with

thick, productive reservoirs, or to Kuparuk with

relatively thinner and less productive reservoirs.

Pipelines

An elevated pipeline mounted on vertical support members (VSMs) spaced about 60 feet apart

with expansion loops every 1,000 feet would be

the most likely pipeline design in ANWR.

However, Arctic experience in the use of buried

ambient temperature lines is growing and may be

another option for ANWR, depending on oil

characteristics and production rates, environmental impacts, and economics. Depending on

soil conditions, it may be desirable to bury the

pipeline in some areas and elevate it in others.

Winter pipeline construction practices are likely

to be used in ANWR unless a road parallel to the

pipelines is needed for other reasons, in which

case the road could support summer pipeline

construction. The industry favors flexible regulations to allow it to use the best practices for

specific circumstances. On the other hand, environmental groups are concerned about excessive flexibility in regulations, especially in sensitive areas.

Construction of Culverts

Construction at ANWR, as with any major

petroleum project, is likely to create extensive environmental disturbance, and regulatory controls

may be needed, The OTA workshop examined

the construction of docks, piers, and culverts–

all needed in any plausible ANWR development

scenario.

Culvert design and construction, for example,

carries several environmental concerns. In the

Prudhoe Bay area of the North Slope, drainage

patterns are poorly defined and are controlled

more by the growth and melting of ground ice

than by erosion and transport of sediment. Thus,

consideration of thermal as well as hydraulic

aspects of drainage design is necessary. ANWR

topography is such that drainage design will be

very important.

The predominant minor drainage structures are

culverts. Culvetts must be designed to prevent

thaw settlement of the foundation and to support

side loads imposed on the culvert. When culverts are built, unstable material is usually excavated and replaced with thaw-stable material.

Environmental groups point to various past

problems with culverts. The most common

problem is the restriction of fish passage, which

may result from excessively high water velocities

or from culvert outlets perched above the

streambed. Another problem is pending when

culverts are improperly located or placed too

high in an embankment and large ponds are

formed. Pending has adverse effects on vegetation and, depending on depth, may either increase or decrease the seasonal thaw. These

problems can be minimized by careful planning

and location of drainage works and by the use of

good maintenance programs.

Technological Change

OTA concludes that technologies likely to be used

in the ANWR coastal plain will closely resemble the

most recent North Slope developments such as

Kuparuk or Endicott. Major changes in technologies are likely to be too slow and gradual to
alter the big picture for ANWR development, but a

number of factors are involved in this judgment: the

definition of technologies considered, assumptions

about the development process, and observations

about past technological change and the underlying

causes.

Definition of Technologies Considered

OTA defines technologies to cover all of the

equipment and facilities that are used for exploration, development, and production. Technologies are of course dominated by large

structures, pipelines, pumps, machinery, etc., to

the extent that change in one small part would

not have much effect on the whole.

Development Assumptions

OTA assumes that if ANWR is developed, the industry will be just as able to select technologies

that best suit its economic needs as it has in the

past. OTA also assumes that economic and

other constraints will not change drastically.

Since ANWR is similar to Prudhoe and Kuparuk,

there is little incentive for industry to make major

changes in technologies that have worked well in

these two other fields. With few new problems to

solve, industry will tend to model the next generation of technology after the best of the past. Of

course, new regulatory demands could force

consequent technological change at any time.

Past Technological Changes

In two decades of Alaskan North Slope oil

development, technological advancement has

been fast and many systems have reached what

the industry considers a mature state. Standard

geotechnical design practices for Arctic permafrost conditions have been developed and

tested for well casing, roads, facility foundations

and pipeline supports. Low-temperature needs

are now filled in metallurgy, elastomers,

lubricants, and fuels. Modularization of facilities

and their transportation can be also considered

mature technology. Maturity also applies to

those systems adapted from other regions to

meet severe Arctic conditions as well as many

systems specifically designed to solve unique

Arctic problems.

OTA concludes that these technologies will

continue to advance, but at a much slower pace

because the need for improvement is less urgent.

Just a few years ago when oil prices plummeted,

cost reduction pressure was heavy as industry

re-evaluated the amount of investment that could

be justified for future production. Some drilling

technology advancements probably can be attributed to the need to reduce drilling costs. This

pressure from low oil prices has begun to level off

in the past year and will probably continue at a

low level. However, there is evidence that industry-wide technological change will continue

to occur; and when developments elsewhere can

be applied to the North Slope, they will be. This

pressure for technological change will probably

be the same in the future as in the past but, when

combined with the other elements of change, the

likely rate of change is likely to be lower in the future.

In OTA’s view the challenge of ANWR development, if it occurs, will be met by the petroleum industry with proven technologies rather than with

innovative ones. A big unknown, however, is outside forces – such as major regulatory pressures–

that could require changes in technologies. Such

changes might come first in methods of waste handling or management or in methods to reduce intrusion on wildlife habitat.

Schedule

Projecting a likely schedule for ANWR development is hard. Much depends on the timing and

sequence of events. Table 2-3 shows some actual development histories for North Slope oil

fields and two current ANWR estimates.

Judging from Table 2-3, the ANWR schedule is

likely to be at least as long as the ARCO and

Department of Energy estimates of 10 to 12 years

from lease sale to production start-up, and possibly even longer. Considering that it will probably take a few years before a lease sale is

completed, a reasonable schedule would be 15

years from today for the start of any substantial

production. If a major field is discovered in

ANWR (equivalent to Prudhoe or even Kuparuk),

one could expect production to span at least 25

to 30 years from start-up. If ANWR development

follows common experience in other oil producing regions, and if regulations, technology, and
Table 2-3.—Typical Development Schedules

Years from Years from

lease to discovery Total years

Development discovery to start-up lease to start

Prudhoe Ba y 3 9 12

Lisburne 3 18 21

Kuparu k 4 12 16

Endicott 9 9 18

ARCO Estimate for ANWRa

3 9 12

EIA Reportb (assuming existing

procedures ) 3 7 10

price-cost relationships allow, more exploration

and discoveries will follow, spanning many years.

At Prudhoe, new fields are continuing to be

brought into production some 20 years after the

first strike.

Experience indicates that, should ANWR exploration proceed and lead to discovery of a

major oilfield, commercial petroleum activities on

the ANWR coastal plain are likely to continue into

the middle of the 21 st century. It is also likely that

development will use enhanced recovery techniques after production has started.

ANWR Development Scenarios

OTA investigated two plausible scenarios for

ANWR development, one done by the Department of the Interior in its LEIS (see Figure 2-10)

and one done by ARCO in a presentation to the

House Subcommittee on Water and Power

Resources in October 1987.

Neither of these two scenarios presents complete details on all major exploration and

development steps or activities. For example,

neither provides the number of exploratory wells

that may be drilled on lease tracts. The ARCO

scenario gives only sizes and gravel pad estimates for the drill pads but not for the gravel

pads for facilities, pipelines, roads, docks, etc.

The ARCO scenario does give an estimate of total

affected area. The LEIS details a series of pad

areas and gravel requirements but does not relate these to specific facility descriptions, functions, and locations. The LEIS assumes the

development of three commercial fields with a

total of 3.2 billion barrels of recoverable oil reserves but does not give a reserve figure for each of

the three fields. It also does not estimate the

production rate. It appears that two of the LEIS

prospective areas are the same as the ones

ARCO uses as hypothetical examples (prospect

19 and prospect 6 in the LEIS). The ARCO

scenario with two fields developed assumes a

total of 3.75 billion barrels of recoverable oil

reserves and a peak production rate of 935,000

barrels per day.

Despite the discrepancies and gaps in these

two scenarios, they are generally similar, and the

estimates and assumptions are close. For this

reason, OTA was able to use the combined data

to prepare its own generaI but more simplified

scenario, adding a few assumptions that were

missing. The OTA scenario and its assumptions

are shown in Table 2-4, and a corresponding

development schedule is shown in Figure 2-11.

Exploration

The LEIS states that three of the four blocks in

the ANWR coastal plain are assumed to be

leased and one discovery will be on each, but the

size of each discovery is not given. OTA assumes that two discoveries will be commercial

and that the total reserves will be roughly the

average of the reserves assumed by the LEIS and

ARCO. As in the LEIS, an additional 1,500 miles

of seismic data are acquired on the coastal plain.

Neither ARCO nor the LEIS estimates the number of exploratory wells to be drilled after leasing;

OTA assumes that 10 to 20 wells will be required

to identify the two fields. (It has been reported in

the past that Prudhoe was discovered on the 19th

exploratory well and that over 250 exploratory

and delineation wells have been drilled overall on

the North Slope over the past two decades.

Therefore, this assumption appears consewative.) The size and location of the two OTA assumed discoveries correspond to the LEIS and

ARCO data.
Chapter 2 ● 65

Figure 2-10.— Development Scenario for Three Major Prospects on the ANWR Coastal Plain, Department of

the 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2

The 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 in

the 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 leased

Additional seismic survey s-1 ,500 line miles

10-20 exploration wells drilled

Two commercial discoveries—one large/one small field (equivalent to prospect

19 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 wells

Central industrial facility

Production facilities

Airfields

Port facilities

Seawater treatment plant

Oil transport

Gravel pads/roads/etc.

3.0 0.5

700,000 100,000

12 2

700 100

(One similar to Kuparuk for two fields)

2 large complexes 1 large complex

4 satellite —

One large One small

Port complex near Port complex at

Beaufort Lagoon Camden Bay

1 1

30” elevated Spur Pipeline to

main trunk Main Trunk

pipeline, 150 mi.

to TAPS Pump

Station #l

2,500-3,000 acres 500-1,000 acres

Total “Footprint” incl. main pipeline & road, burrow 5,000-7,000 acres depending on final

sites, other disturbances designs

Total “Sphere of Influence” 150,000—300,000 acres

NOTE” 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 rate

for the two fields and the total number of wells

and well pads roughly corresponds to the ARCO

data except that the assumed production rates

(as a ratio of recoverable reserves) are somewhat

lower. Production rates can be highly variable

depending on the actual characteristics of the

fields. However, even the OTA numbers correspond to some of the highest production rates

from other North Slope fields. For example, discovery #1 is about one-third the size of the Prudhoe Bay field with about half the production rate.

It is also about twice the size of the Kuparuk field

with about 2.5 times the production rate.

Hypothetical discovery #2, on the other hand, is

roughly equivalent to the Endicott field which

came on-line in 1987.

OTA’s assumptions about production facilities

are based on both the ARCO scenario and the existing developments at Kuparuk and Endicott. A

central industrial facility for the entire ANWR

coastal plain would follow the Kuparuk model

even though ANWR is somewhat more remote

from the other components of the Prudhoe support network. This comparative isolation would

probably mean that ANWR would need a larger

industrial facility than Kuparuk. Production

facilities, airfields, ports, and seawater treatment

plants would be similar to those at Kuparuk for

discovery #1 and at Endicott for discovery #2.

The assumed oil transport pipeline is similar to

both the LEIS and ARCO scenarios.

OTA assumptions about gravel pads and road

acreage are derived from the LEIS estimates for

each field but include neither the main pipeline or

road to TAPS nor the other areas of disturbance

to the land surface, such as gravel pits. These

assumptions, in turn, are all included in the estimate of total “footprint” to be expected from the

first development of both hypothetical fields. The

projected total “footprint” –area of direct physical coverage –was derived from individual area
Figure 2.1 1.—OTA MNWR Development Scenario

o
estimates, but the high end also corresponds to

the ARCO estimate of 11 square miles as the total

area affected by development.

Finally, OTA made a rough estimate of the total

“sphere of influence” to be expected from full

development activities. The notion of a sphere of

influence appears in the LEIS as that area surrounding a facility or activity where certain

wildlife species potentially would be affected.

The actual extent of this sphere of influence

would vary depending on the species, and

specific impacts are not always quantified. This

estimated sphere of influence corresponds, on

the high side, to an estimate in the LEIS based on

an influence zone of about 3 kilometers around

all facilities, pads, pipelines, roads, etc. The

upper estimate probably would be relevant only

for the more sensitive species. The lower estimate corresponds to the total acreage enclosed

by the two hypothetical fields in the scenario. In

any case, the total area of 150,000 to 300,000

acres assumed in the OTA scenario could be a

considerable portion of available habitat for a

number of species.

OTA’s estimates are only for initial development

of the two hypothetical ANWR fields. Based on

experience in all of the other developed North

Slope oilfields, it is likely that, after the ANWR

fields are producing, a series of modifications will

be made. Such activities would include routine

maintenance, upgrading, and improvement in

recovery and production to extend the life of the

field, plus well workovers, infill drilling, addition of

secondary and tertiary recovery techniques, and

many others. Experience at Prudhoe Bay has

shown about a 50-percent increase in the

coverage of tundra by gravel roads, pipelines,

and facility pads from the time of initial production start-up in 1977 through 1988. Experience at

Kuparuk is following the same pattern.

The above scenario for ANWR development can

be used to project possible changes to the coastal

plain environment that may result. It is clear that the

changes could be substantial, to some extent, affecting hundreds of thousands of acres and supporting considerable human and mechanical

activity for several decades, and that environmental

protection issues would continue to be contentious

should such development proceed. The four key

principal environmental concerns–physical land

disturbance, gravel mining and construction, waste

management, and fresh water supply–that are

listed at the beginning of this chapter, appear to be

of continual future concern. OTA has noted

industry’s approach to addressing these issues and

the fact that many environmental critics believe the

industry’s approach to be inadequate. Further environmental assessment is probably needed, most

importantly in the above four areas, to evaluate the

effectiveness and adequacy of these approaches.
Chapter 3

Oil and Gas Production on

the North Slope of Alaska
Contents

Introduction . . . .

Oil Production From

Resource Terms . . . . . . . . .

In-place Resources of Known Fields

Production 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

73

73

74

75

77

79

91

94

95

97

. * 100
Chapter 3

Oil and Gas Production on

the North Slope of Alaska

INTRODUCTION

The U.S. oil industry and the U.S. Department

of the Interior (DOI) contend that unless oil leasing is allowed in the Arctic National Wildlife

Refuge (ANWR) and significant quantities of oil

are found there, North Slope oil production will

soon begin to decline, and that with a decline the

United States will become ever more dependent

on oil imports.

To examine this contention, OTA investigated

the status of current production on the North

Slope and the potential for additional oilfield

development there. In particular, OTA assessed

reserves and/or in-place resources in all proven

and developed North Slope fields and in known

but undeveloped fields where public information

is available; assessed what additional production

might be expected from these fields in the future

as technology improves and/or if additional enhanced oil recovery (EOR) technology is installed; and examined what the contribution to

North Slope production from as yet undiscovered

onshore and offshore oilfields might be.

Long-term oil production forecasts for the

Nonth Slope or, for that matter, for any large area

of the United States, are at best gross approximations. Oil forecasts make assumptions about future oil prices, technological developments,

environmental requirements, tax and royalty

rates, and other variables. Also, forecasts

project the success of drilling and other field

development activities in areas in which geologic

data are often sparse. Finally, forecasts make assumptions about future business strategies, yet

company strategies are almost always confidential and, at the same time, subject to change.

Consequently, OTA focused its efforts on determining the general production potential of the

known fields on the Slope, and on asking the

question, “if oil production from the North Slope

is not going to decline drastically, where will

added production come from?”

We concluded that, although small quantities of

additional reserves can be expected from

developed, undeveloped, and as yet undiscovered fields on the North Slope, there is no

likely source of additional reserves that is large

enough to stem a production decline. Thus,

North Slope production is likely to begin declining around 1990 – the expected onset of Prudhoe

Bay decline–or shortly thereafter. Although the

discovery of another Prudhoe Bay-size field in

ANWR or elsewhere on the North Slope will help

reverse this trend, a field discovered in 1988

would not likely be brought into production

before 1998.

As of early 1988, four major oilfields were

producing oil in the North Slope of Alaska: Prudhoe Bay, Kuparuk, Lisburne, and Endicott (see

Figure 3-l). A fifth field, Milne Point, is developed

but not currently producing. In addition to these

five oilfields, a number of fields have been discovered but are not yet developed. There are important reasons these other North Slope fields

are not yet producing: some may not yet have

been sufficiently delineated to determine whether

they would be economic to produce; many are

too small and/or too far from the Trans Alaska

Pipeline System (TAPS) to be economically

producible at current market prices; some may

have reservoir characteristics that make production difficult and/or prohibitively expensive; and

offshore discoveries in more than a few feet of

water are currently too expensive to develop and

produce. Finally, although many of the best

prospects have been tested, only a relatively

small portion of the North Slope of Alaska – onshore or offshore – has been explored for

hydrocarbons. How much remains to be found is

subject 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 the

North Slope is called “in-place” resources. The

amount of in-place oil in known fields that has not

yet been extracted is considerable, but only a

portion of it is currently economically and technically producible. The amount of in-place resources that geological and engineering studies

have shown to be recoverable under current

economic conditions using existing technology

are known as “proved” or “existing” reserves.

“Inferred” or “potential” reserves are those

resources that should eventually be added to

proved reserves through extensions of known

fields, through revisions of earlier reserve estimates based on new subsurface and production

information, and through production from new

producing zones in known fields. 2 The application of new recovery technology (e. g., enhanced

oil recovery [EOR] methods) may also result in

additional proved reserves . The term

“recoverable” resources is less precise but frequently used. The amount specified by the term

is sensitive to changing economic conditions and

in this study refers to the sum of proved and

potential reserves.

Estimates of in-place and recoverable resources can be made using very little data; of course,

the more data available, the more accurate the

estimates can be (See Box 3-A). Reserves, on the

other hand, are based on drilling results and engineering measurements. Estimates of in-place

resources in known fields are ideally based on

knowledge of the size of the reservoir; porosity of

the reservoir rock; reservoir pressure, temperature, and as/oil ratio; and amount of water

3

saturation. Recoverable resource estimates use

the same type of information, but in addition they

generally require information or assumptions

about permeability and oil viscosity, which help

reservoir engineers determine the degree to

which in-place oil is capable of flowing to a

wellhead. Recoverable resource estimates also

incorporate assumptions about the expected

selling price of oil and the technology used to

produce it. Reserve estimates require more extensive resetvoir and producibility information

and assume production at current market prices

and the use of existing technology.

BOX 3-A

A CAVEAT

Resource estimation is as much art as science, and numerous pitfalls make accurate estimates

difficult. Two typical shortcomings of most estimation techniques are limited availability of data

and the need to use simplifying assumptions to make estimates. This situation is why most estimates risk input parameters and report probability distributions. Some of the problems encountered in efforts to estimate North Slope resources are considered in more detail in Appendix

A. Often, the assumptions –e.g., oil price or state-of-the-art of technology–on which North Slope

resource estimates have been based are not specified or are vague. Although OTA considers the

data in this report to be the best data currently available to the public, often there was no compelling reason to select one source of information over another. All resource data in this report should

be 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 ● ANW R

In-Place Resources of

Known Fields

Despite the pitfalls of resource estimation (see

Appendix A), the quantity of in-place oil in the

developed North Slope fields is reasonably well

known from extensive drilling (Table 3-1 ).

Remaining in-place resources in the five

developed North Slope fields as of September

1987 are estimated to be about 25 billion barrels.

In-place resources of all known North Slope

fields may total more than 50 billion barrels.

More important is the amount of these in-place

resources that is expected to be ultimately

recoverable. For the North Slope overall, the

recovery efficiency of in-place oil in developed

and undeveloped fields is approximately 26 percent.

4 However, recovery efficiencies of individual North Slope fields may vary from O

percent to perhaps as high as 50 percent,

depending on reservoir and fluid characteristics.

Resources in some major undeveloped North

Slope fields will not be economic to produce unTable 3-1 .—Minimum Remaining In”Place Oil of Major

North Slope Fields As of September 1987

Billion barrels

(rounded)

Proven and developed

Endicott . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Kuparuk River . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Lisburne . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Milne Point . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Prudhoe Bay . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

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

Discovered but undeveloped

Point Thomson (gas condensate) . . . . . . . . . 1

Seal Island . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Ugnu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

West Sak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Other North Slope . . . . . . . . . . . . . . . . . . . . 2

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

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

SOURCES Bureau of Land Management, Anchorage, Alaska, Alaska Department

of Natural Resources, Division of 011 and Gas, Institute for Social and

Economic Research, University of Alaska

less oil prices rise substantially and/or unless

new, less expensive or more efficient production

technologies are developed.

Estimates of in-place resources of known but as

yet undeveloped oilfields on the North Slope are

more provisional than those for the five

developed fields, and estimates for some discoveries may not yet have been released. Undeveloped oil and gas discoveries on the North

Slope include the West Sak and Ugnu fields; the

Seal Island and Tern Island discoveries; and the

Colville Delta, Gwydyr Bay, Niakuk, Umiat, Kavik,

Kemik, and Point Thomson fields (Figure 3-l).

Only two of these fields are believed to contain

significant in-place resources, and even these

two are unlikely to contribute significantly to the

North Slope production total in the foreseeable

future. Many discoveries are either too small or

too far from TAPS or both to be economically

producible at this time.

The West Sak and Ugnu reservoirs, both of

which generally overlie the Kuparuk River reservoir, deserve special attention due to their huge

estimated in-place resources. West Sak contains

between 15 billion and 25 billion barrels of oil inplace. ARCO has proved the technical feasibility

of producing West Sak oil with existing technology, but the reservoir and oil characteristics

(e.g., high oil viscosity, low temperature, shallow

depth, complex structure) indicate that recovery

will be less than 5 percent of the in-place oil if the

field is fully developed using current technology.

It appears that some production of West Sak may

take place if and when oil prices rise (and stabilize) above $20 per barrel. The Ugnu field contains between 6 billion and 11 billion barrels of

in-place resources, 5 but the cost and difficulty of

recovery of Ugnu oil will be much greater than for

West Sak oil. Thermal stimulation through the

permafrost probably would be required to

produce the very heavy Ugnu oil, but this technique is likely to be impractical and prohibitively

expensive on the North Slope for the foreseeable

future.

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

B

“Potential Oil Production From the ~astal Piain of the &ctic

National 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 Alaska

Department of Natural Resouroes, Division of Geological and Geophysical Surveys, 1984), p. 9.
Chapter 3 ● 75

Significant gas resources are also found in

North Slope fields (Table 3-2). Prudhoe Bay

alone contains at least 23 trillion cubic feet of gas

considered ultimately recoverable. The distance

from U.S. markets and the consequent high cost

of building a transportation system for North

Slope gas, however, makes it uncompetitive at

current gas prices (and at prices corresponding

to DOI’s oil price scenarios for ANWR development). Neither the proposed Alaska Natural Gas

Transportation System nor the competing TransAlaska Gas System has secured construction

financing or a guaranteed market for the gas it

would carry. The Reagan Administration recently

determined, however, that North Slope gas could

be exported, a finding that may ultimately give a

boost to development of North Slope gas, perhaps in the form of Liquefied Natural Gas to

Japan. Most of the gas produced at Prudhoe

Bay and other North Slope fields is currently reinfected to help maintain reservoir pressure or is

used in miscible fluid recovery operations. Some

gas is used to operate North Slope facilities.

More of this gas may eventually be used on the

North Slope to provide the energy required to

produce such heavy oilfields as West Sak.

Table 3-2.—Estimated Recoverable Gas in Known

North Slope Fields

Billion cubic feet

Endicott . . . . . . . . . . 800

Kuparuk River ., . . . . . . . . . . . . . . 600

Lisburne . . . . . . . . . . . . . . . . . . . . 900

Point Thomson . . . . . . . . . . . 5,000a

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

Total . . . . . . . . . . . . 30,300

aNo 011 or gas IS currently being produced from the Point Thomson field The

cost to develop Point Thomson’s gas resources would be greater than the cost

to develop gas resources in fields already producing 011 Hence, higher gas prices

would be needed to develop Point Thomson unless the gas resources were de

veloped 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 the

North Slope of Alaska is more difficult than

production in the Lower 48 States. Factors affecting production include the harsh Arctic

climate, lack of infrastructure, and great distance

from supply sources and markets. The harsh

climate of the Arctic is characterized by very low

average and absolute temperatures, frequent

high winds, and periods of dense fog. Precipitation is low, but snow cover lasts for 8 months or

more each year, and blowing snow is common.

Low temperatures give rise to permafrost, which

may extend 2,000 or more feet below the land

surface or seabed, and to sea ice, which can attain average thicknesses of 7 feet or more and

persist for as much as 10 months per year in the

Beaufort Sea.

Ice affects all aspects of oil activity. On land,

the presence of permafrost requires use of special design and construction practices. For instance, well casing must be designed to

withstand thaw subsidence stresses that may

occur when warm oil flows through the well

tubing. Also, all pads and roads must be constructed of gravel about 5 feet thick. Offshore,

landfast and moving sea ice, pressure ridges,

and other ice phenomena cause problems and

added expense for transportation, exploration,

and production. All offshore structures must be

designed to be able to withstand ice forces.6

Lack of infrastructure in the Arctic is another important factor affecting the cost and difficulty of

North Slope production. Before Prudhoe Bay

was developed, there were no roads, pipelines,

or ports on the North Slope and no housing for

oilfield workers. Beyond the immediate vicinity of

Prudhoe Bay and Kuparuk, this is still the case–

for instance, in both the National Petroleum

Reserve in Alaska and the Arctic National Wildlife

Refuge. Except insofar as development of new

fields can take advantage of the infrastructure

now in place in the Prudhoe Bay area – more difficult to do as the distance from Prudhoe Bay

grows–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 no

major fabrication facilities on the North Slope, so

oil production facilities must be prefabricated in

the Lower 48 or overseas and barged north

during the summer months or trucked overland.

Moreover, except for the few Native North Slope

Inuit who work for the oil companies, oilfield

workers do not live permanently in the Arctic but

are shuttled back and forth on a weekiy or biweekly basis between the North Slope and locations either in southern Alaska or– less common

now–the Lower 48.

Oilfields close to Prudhoe Bay will be able to

connect directly to the Trans Alaska Pipeline System; however, as a field’s distance from the

pipeline terminus at Pump Station #1 increases,

the cost of constructing a connecting pipeline increases. Beyond a certain distance, it may not

be economically feasible to construct a smalldiameter pipeline connecting with TAPS, and

other transportation alternatives will need to be

considered. The use of ice-strengthened

tankers, for instance, has been considered for

transporting any oil found beneath the Chukchi

Sea, off Alaska’s northwestern coast. For

producing oil from offshore fields, pipelines must

either be buried below the depth of sea ice scour

or mounted on expensive and environmentally

controversial causeways.

These production constraints – isolation, lack of

infrastructure, and harsh climate–are all important reasons why the minimum economic field

size (MEFS) required for development increases

greatly with increasing distance from Prudhoe

Bay. The other significant determinant of the

MEFS is the price of oil. The Seal Island discovery is only 12 miles from Prudhoe Bay, but,

given its offshore location in 39 feet of water, it is

not economic at current market prices– even

though its recoverable reserves are estimated to

be at least 300 million barrels. The areawide

MEFS for onshore ANWR development is estimated by the Department of the Interior to be

440 million barrels, given a market price of $33

per barrel of North Slope oil (1984 dollars) in the

year 2000. If oil prices are significantly lower

than this in 2000 (e.g., at $20 per barrel in 1984

dollars) and costs remain the same, the MEFS for

ANWR could easily surpass 1.5 billion barrels, assuming that the calculation of the MEFS for

ANWR is correct (OTA has some doubts about

this calculation; see Box 3-B on page 104). 7 A t

distances even further from Prudhoe Bay, in the

Chukchi Sea for instance, the MEFS could conceivably be 2 billion barrels or more.

The cost to transport oil from remote North

Slope fields to Pump Station #1 and from this

point to market is an important factor in determining the MEFS. Total transportation costs

averaged about $6 per barrel to transport oil from

Pump Station #1 to southern markets in 1987.

This oil must travel 800 miles south through the

Trans Alaska Pipeline, where it is loaded onto

tankers at Valdez and shipped either to the West

Coast of the United States or to the U.S. Gulf

Coast (after being off-loaded on the Pacific side

of the Isthmus of Panama, piped across the

Isthmus, and reloaded onto other tankers). If the

market price of this delivered North Slope oil is

near $17, as it was in January 1988, suppliers

would be able to charge $11 at Pump Station #1.

The price at the wellhead – given that there is a

charge for transporting oil from the wellhead to

Pump Station #1 –would be even less. For instance, 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 Lisburne price $11.10. For the 6-month period of

September 1987 through Februaty 1988, composite wellhead prices for the North Slope

decreased from $13.00 to $9.40 per barrel for 27o

API crude oil.a From per-barrel prices must be

subtracted per-barrel capital and operating expenses, taxes, royalties, and the like. Clearly,

some of the North Slope producers are operating

on a thin profit margin at current market prices.

Evidence of this is that the Milne Point field has

been shut down since January 1987.

7. U.S. De artment of the Interior, Arctic National Wildlife Refuge, Alaska, Coastal Plain Resouroe Assessment, final Legislative

Environment Impact Statement, r 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 from

proven and developed fields on the North Slope

of Alaska are estimated by the Alaska Department of Natural Resources (DNR), Division of Oil

and Gas, to be between 5.25 and 8.22 billion barrels with a mid-range estimate of oil reserves of

about 6.5 billion barrels (Table 3-3).9 This range

brackets most other estimates that have been

made. Total reserves are sensitive to the price of

oil. With low prices, it may not be economical to

continue infill drilling beyond a certain point, and

the use of EOR techniques may not be economically justified. As prices rise, oil companies are

able and willing to expend more money to extract

additional oil by implementing EOR techniques

and by increasing infill drilling.

Table 3-3. —Estimated Remaining Recoverable Oil

As of January 1, 1988 (millions of barrels)

.

Mid

Low $18-$202 High

<$15’ (1987 $) <$243

Proven and developed

Endicott . . . . . . . . . 2704

370 445

Kuparuk River . . . . 600 900 1,100

Lisburne . . . . . . . . 280 380 580

Milne Point. . . . . . . . . . . . . . . . . . 0 60 955

Prudhoe Bay . . . . . . . . . . . . . . . 4,100 4,800 6,000

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

Discovered but undeveloped

Gwydyr Bay . . . . . . . . . . . . . . . . . 0 0 10

Niakuk. . . . . . . . . . . . . . . . . . . . . O 55 75

Point Thomson ... . . . . . . 0 0 3506

Seal Island . . . . . . . . . . . . 0 0 300

West Sak7 . . . . . . . . . . . . . . . . . 0 500 1,500

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

Total . ..................5,25 0 7,065 10,455

‘All low estimates assume infill drilling will be less than the number of wells

forecast for the midrange estimate

‘All mid. range estimates assume that existing technology IS used, that no new

enhanced 011 recovery operations are implemented, and that reservoirs perform

as expected

‘Al I estimates assume more In fill than for the mid. range forecast and that additional 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 feet

of 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 based

On discussion with Standard Alaska Production Co officials

The difference between the high and low estimates in Table 3-3 is accounted for largely by

different assumptions about price, success of

EOR operations, and amount of infill drilling likely

to be done. The low estimate assumes that oil

prices are less than or equal to $15 per barrel (in

1987 dollars) and that infill drilling is less than expected by DNR for the mid-range estimate. The

mid-range estimate assumes that oil prices are

$18 to $20 per barrel, that existing technology is

used, that no new enhanced oil recovery operations are implemented, and that reservoirs perform as expected. The high-range estimate

might be reached if oil prices rise above $24 per

barrel and if additional EOR operations are implemented and successful.

If the high-range price assumption is realized,

the Division of Oil and Gas also expects additional oil recovery from discovered but as yet undeveloped North Slope fields, principally the

West Sak, Point Thomson, Seal Island, Niakuk,

Colville Delta, and Gwydyr Bay fields (Table 3-3).

The West Sak field has the potential to contribute

the most additional oil from known but undeveloped fields, but there is a wide range of

opinion about the amount of oil ultimately

recoverable from West Sak. The current ARCO

estimate of West Sak’s recoverable reserves is

much lower than the Division of Oil and Gas estimate.

While there are large amounts of oil in the

ground on the North Slope, most of the reserves

in producing fields are located in the Prudhoe

Bay and Kuparuk River fields. Currently, TAPS is

running at just about full capacity with oil from

the Prudhoe Bay, Kuparuk River, Lisburne, and

Endicott fields. As of spring 1988, the pipeline

can carry a maximum of 2.2 million barrels of oil

per day, although this capacity could be increased somewhat by installing additional pumps

and/or by adding more friction-reducing additives. About 1.55 million barrels per day are

produced from Prudhoe Bay, 300,000 from

Kuparuk River, 100,000 from Endicott, and about

50,000 from Lisburne, a total of about 2.0 million

barrels, comprising roughly 24 percent of the

daily 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 Slope

production may begin declining sometime

around 1990 (Table 3-4). Some believe this

forecast of decline in 1990 is unduly pessimistic,

given that estimates of the onset of decline have

been revised several times in the past and that

the impact of technological improvements cannot be entirely foreseen. Whatever the exact date

of the onset of decline, Prudhoe Bay, whose

production dominates that of other fields (in 1986

it accounted for 82.8 percent of Alaska’s production), is now considered a mature field, and

production there must soon begin to slow. Some

of the smaller North Slope fields will also begin to

decline in the next few years. By 2000, TAPS

throughput is expected to be at best 50 percent

of current throughput, even with incremental additions from currently planned EOR operations in

existing fields and from possible production in

several new fields (Figure 3-2). Production could

be as low as 25 percent of current throughput by

2000 if low-range reserve estimates prove more

accurate.

Table 3-4.—Projected TAPS Throughput

(thousand barrels per day)

Year Maximum Minimum

1987 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,908 1,908

1988 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,024 2,024

1989 . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,040 2,030

1990 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,033 1,968

1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,891 1,776

1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,735 1,565

1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,591 1,371

1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,430 1,182

1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,317 991

1996 ... , . . . . . . . . . . . . . . . . . . . . . . . 1,233 863

1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,176 736

1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,110 625

1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,013 533

2000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 931 453

2001 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 857 385

2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 789 327

2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 726 278

Total . . . . . . . . . . . . . . . . . . . . . . . . . . 23,804 19,015

SOURCE Alaska Department of Natural Resources, Division of Oil and Gas

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

Production forecasts have been made by the

Energy Information Administration, the Alaska

Department of Natural Resources, the Alaska

Department of Revenue, and others. The data

presented in Table 3-4 and Figure 3-2 w a s

recently compiled by the Alaska Department of

Natural Resources, but it is representative of

other forecasts as well. Most of the difference

between the maximum and minimum North Slope

production profiles depends on whether or not

Milne Point is restarted and Niakuk, West Sak,

Gwydyr Bay, Seal Island, and Colville Delta are

developed in the early 1990s. Starting production at these fields depends on the price of oil,

but it is impossible to specify the exact price at

which each field would be developed. Milne

Point–currently shut-in due to low oil prices–

may be producing again shortly, and Niakuk is

said to be commercial at current oil prices, but

the other fields probably will not be developed

until the price of oil rises and stabilizes in the area

of $24 per barrel. Recent strides incest control

could conceivably lower the breakeven price for

production from these fields, and recent remarks

by ARCO Alaska, Inc. suggest that breakeven

prices have indeed come down.10

Figure 3-2.-Projected TAPS Throughput

Million 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 the

exploration 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 location, size, structure, and other reservoir characteristics, but also in their response to EOR

stimulation, their production profiles, and the

recovery expected from each.

Prudhoe Bay

Prudhoe Bay is the largest oilfield in the United

States and the 18th largest in the world. It is estimated to have had original recoverable oil of 10

billion to 12 billion barrels. Of this amount, 4 billion to 6 billion barrels remain. The lower figure

for Prudhoe Bay’s remaining recoverable oil includes oil recovered using primary and currently

in-place waterflood and miscible fluid recovery

technologies. The higher, more optimistic figure

assumes the success of enhanced oil recovery

projects that could begin in the future, more infill

drilling, and a gradual rise in the price of oil.

Prudhoe Bay oil has a large gas cap and is contained in a high-quality, well managed reservoir,

as is reflected by its relatively high estimated

recovery factor. Approximately 45 percent of

original in-place resources are expected to be

recovered. The principal producing formation of

the Prudhoe Bay field is the Ivashak Sandstone of

the Sadlerochit Group. This sandstone consists

primarily of two fine- to medium-grained pebbly

sandstone sequences separated by an interval

dominated by massive conglomerates. The

depth of producing zones is between 8,000 and

9,000 feet.

To stimulate additional recovery at the Prudhoe

Bay field, waterflooding (injection of water into

the reservoir to drive additional oil to producing

wells) began in 1984. With this technique, field

operators expect to recover 1 billion more barrels

of oil than would otherwise have been possible

(included In the above estimate of recoverable

oil). In addition, Prudhoe’s miscible fluid operation began in December 1986 with the installation

of the world’s largest natural gas plant. The

facility produces miscible injectant (Ml–a mixture of natural gas and natural gas liquids; see

Technologies for Improved Recovery later in this

chapter) from raw plant feed gas stripped from

well fluids. The Ml is injected into the reservoir

with alternate injections of water to stimulate additional oil recovery. The operation also currently produces 50,000 barrels per day of natural gas

liquids which are blended into the crude oil 11 Remaining residue gas is -

stream in TAPS.

jected into the reservoir to maintain gas cap pressure. The operators estimate that the project will

allow 5 percent additional oil recovery beyond

the waterflood operation for that part of the reservoir affected by the EOR project, or an additional 12 plus recovery ‘

f a t

115 million barrels of oil,

least 500 million barrels of natural gas liquids

(both additions have been included in the above

estimate). Also, the facility establishes a large

part of the infrastructure that will be needed to

proceed with any future large-scale gas sales or

expanded gas cycling projects.13

Infill drilling in some portions of the field is continuing at an 80-acre spacing intetval; 40-acre

spacing is likely to begin soon14, which may

enable recovery of up to 100 million barrels of additional oil. However, infill drilling is probably

more important for maintaining or increasing the

production rate of fields than for adding reserves.

The total number of wells in the Prudhoe Bay

field, when fully developed, is expected to be

about 1200. Incremental reserves also might be

added by expanding the waterflooding operation

and/or by expanding the miscible flooding

project. Installation of additional gas handling

capability would allow greater short-term production 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 with

the oil– but would not significantly change reserves.

The West End/Eileen area of Prudhoe Bay is expected to begin producing in 1988 and will include gas injection facilities for pressure

maintenance. There are believed to be about 500

million barrels of oil in place in this area, of which

about 150 million barrels are considered

recoverable. Production from this portion of the

Prudhoe Bay field is expected to peak at 60,000

to 70,000 barrels per day.15

Eventually, more resources also might be

recovered in the peripheral area of the Prudhoe

Bay field. In the past, operators assumed that

production of the Prudhoe oil column was limited

to areas where “pay” thicknesses are greater

than 100 feet. However, production of the

“wedge” zone at the edges of the field using

horizontal drilling techniques may yield more oil.

This relatively thin zone would not be economic

to produce with vertical wells, but horizontal wells

allow much more of the formation to be open to

the borehole. 16 ARCO notes that development ‘f

potential reserves (e.g., Prudhoe Bay’s Hurl State

and Kuparuk Sand areas, as well as wedge areas)

is partially dependent on State severence tax

considerations. Under current Alaskan law, oil

from marginal fields is taxed at a lower rate than

production from more productive fields, thus

enabling development of some marginal fields to

be economically justified. 17

Industry and government sources now predict

that Prudhoe Bay production will begin to decline

in late 1989 or sometime in 1990 (initially the

decline was expected sometime in 1987) (Figure

3-3). The actual date will depend on the level of

infill development drilling, scheduling of well

workovers, water and rich gas injection rates,

and the capabilities of the installed and to-be-in18 pruhoe's gas-oil stalled gas handling facilities.

and water-oil ratios will continue to increase as its

oil is produced. When limits on handling gas and

water are reached and additional gas and water

injection can no longer be done economically,

decline will set in. When the Prudhoe Bay field

begins to decline, the rate is expected to be

about 10 to 12 percent per year.19 Such a decline

rate is typical of most large oilfields that are subjected to pressure maintenance operations.

Kuparuk River

Production of the Kuparuk River field, located

about 40 miles west of Prudhoe Bay, commenced in December 1981. Remaining reserves

recoverable with primary and existing waterflood

technology were estimated to be slightly over 1

billion barrels as of September 1987. Production,

which is now between 290,000 and 300,000 barrels of oil per day, second in the United States

only to Prodhoe Bay’s, is expected to begin a

gradual decline to 65,000 barrels per day in 2000

Figure 3-3.-Alaska North Slope

Production: Prudhoe Bay and Kuparuk

1 5

1

0 5

0

Million barrels per day

1987 1990 1993 1996 1999 200 2

SOURCES: Alaska Department of Natural Resources, Division of Oil and Gas and

Alaska Department of Revenue, November 1987

15. 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 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 of

Oil 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 expected to fall off less rapidly than production at

Prudhoe Bay, it is only about one-fifth of Prudhoe

Bay’s production and contributes only about 15

percent of TAPS throughput. Remaining

recoverable gas is estimated to be about 525 billion cubic feet.

The Kuparuk River reservoir is not as thick or of

as high quality as the Prudhoe Bay reservoir. It

has no natural gas cap, and is characterized by

faulting and discontinuities. The field covers 400

square miles, of which 200 are currently considered commercially productive. By the end of

1986, 300 wells had been drilled, but at least 700

wells will be required for full field development.

Constant infill drilling will be necessary to retard

decline as long as possible and to tap areas

separated by faults.

ARCO Alaska, the operator, is expanding the

waterflood program and has recently begun a

pilot miscible gas injection project to boost ultimate recovery from the reservoir. A third

central production facility was added in 1986,

with a reserve addition of 170 million barrels of oil. 20 A small gas plant in the field currently

produces about 3,700 barrels per day of natural

gas liquids that are blended with the oil and sold.

Lisburne

The Lisburne reservoir lies within the Prudhoe

Bay Unit but is about 1,000 feet deeper than

Prudhoe Bay’s main reservoir in the Ivishak formation. Lisburne and Prudhoe Bay were discovered by the same well. Production from this

third largest North Slope field (in terms of estimated reserves) began in December 1986.

Thus far, production at the Lisburne reservoir has

not been as good as hoped. Lisburne is a

naturally fractured carbonate reservoir, less

porous than the Sadlerochit main producing formation at Prudhoe Bay. Lisburne’s fractured nature has presented some technical production

problems. Moreover, at least parts of the formation contain hydrogen sulfide gas which is both

21 Although the Lis -

corrosive and poisonous.

burne field originally had about 3 billion barrels of

oil in place, only between 7 percent and 22 percent of in-place resources are expected to be

recovered from primary production and with EOR

operations planned or in place. The small size of

the Lisburne field compared to Prudhoe Bay, as

well as lower per well production rates, faster

decline in individual well production rates,

greater costs associated with greater drilling

depths, more difficult rock to drill, presence of

hydrogen sulfide gas, etc., make Lisburne somewhat of a marginal North Slope field at current

market prices.

Recoverable resources as of January 1988

were estimated by DNR to be between 280 million

and 580 million barrels, but operators have noted

that, due to the fracturing, it is very difficult to estimate reserves accurately in the Lisburne field

without substantial additional drilling. Reserves

of this size would be considered substantial in the

Lower 48; however, on the North Slope, Lisburne

is only marginally economic. Lisburne’s early

development was helped by its proximity to TAPS

and to the infrastructure already in place at Prudhoe Bay. If current lower oil prices had been anticipated, Lisburne might not have been

developed when it was. A similar size and type of

field 100 miles from the pipeline probably would

not be economic to develop at the present time.

Lisburne production was initially expected to

peak in the mid-1990s at between 80,000 and

100,000 barrels per day. A revised estimate,

which takes into account the difficulties in

producing Lisburne, calls for peak production of

onl 50,000 to 60,000 barrels per day (Figure 3-

4).22 Production of between 45,000 and 60,000

barrels per day is expected to continue through

the mid-1990s.

The Lisburne field includes both onshore and

offshore areas. Proposed offshore site construction, however, has been canceled. Most of the

offshore oil in the Lisburne field can be reached

by 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 Slope

Production: Lisburne

Thousand barrels per dav

100

80

60

40

20

0

1987 1990 1993 1996 1999 200 2

 Llsburn 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–the

optimum location for reinfecting gas– by drilling

wells with large horizontal offsets from shore.

Directional drilling is not expected to reduce oil

recovery. A separate geologic structure offshore

(the Kuparuk River sand play, productive in the

Kuparuk River oilfield and at Niakuk) with an estimated 20 million barrels of reserves is accessible only from an offshore site.23 Alternatives to

exploit this reservoir will have to be developed

now that the offshore Lisburne drill site has been

canceled. Ultimate recovery at Lisburne is expected to increase if a pilot waterflood project

now underway proves to be successful. A small

gas plant in the field currently produces about

2,600 barrels per day of natural gas liquids

(NGLs), which are blended with the oil and sold.

Endicott

The Endicott field, which began oil production

in October 1987, is the North Slope’s newest

developed field. It is distinctive in that it is the

North Slope’s first offshore producing field. Located about 15 miles from Prudhoe Bay and

about 2 miles offshore in State waters 8 to 10 feet

deep, the Endicott field is believed to have about

375 million barrels of oil resewes and 800 billion

cubic feet of recoverable gas. Approximately 35

percent of its in-place oil resources are expected

to be recovered. Production is from the Kekiktuk

conglomerate formation of Mississippian age and

takes place from an artificial 45-acre main

production island and a 10-acre satellite island.

A gravel causeway connects both islands with

the shore and provides pipeline and road access.

The Endicott reservoir is similar to Prudhoe

Bay’s in that it consists of good quality

sandstone-conglomerate and contains a large

gas cap. The main producing zone has better

quality rock than does Prudhoe Bay. The continuity and quality of a second producing zone

are still being studied. A significant amount of

gas will be produced with Endicott’s oil; hence,

lack of sufficient gas handling capability could

constrain oil production. Production peaked at

115,000 barrels per day in early 1988– equivalent

to 5 percent of maximum daily TAPS throughput–and is expected to remain at this level until

the field begins to decline, estimated to be someFigure 3-5.-Alaska North Slope

Production: Endicott and Milne Point

Thousand barrels per day

A 1 1

1987 1990 1993 1996 1999 200 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 per

day of NGLs are produced at Endicott.

Endicott is also of interest because its development is economic only as a result of intensive efforts 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 Prudhoe Bay-size fields, and close attention will have

to be paid to keeping development costs down.

Endicott developers were able to build upon experience gained at Prudhoe Bay for example,

operators found that retrofitting is very expensive. Thus, primary and secondary recovery

capabilities have been part of the production

facilities at Endicott from the outset. Hence,

waterflood, low pressure separation, gas reinjectionj and gas lift can begin at Endicott without

substantial additional capital expenditures.

Milne Point

With approximately 60 million barrels of reserves, Milne Point is the smallest of the

developed North Slope fields. Production is from

the Kuparuk River formation, an extensively

faulted sandstone. Milne Point is about 35 miles

northwest of Prudhoe Bay. Like Lisburne and Endicott, the proximity of the Trans Alaska Pipeline

has spurred development; however, the amount

of oil that Milne Point can contribute to TAPS is

relatively 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 target is reached, Milne Point will account for 1.5

percent of TAPS throughput during its peak

production period. Currently, the peak production capacity is 15,000 barrels per day, or only

half the production target (Figure 3-5).

Waterflooding has been used since inception, but

additional waterflooding and other conventional

engineering will be required to produce all of the

field’s estimated reserves.

Milne Point is the only North Slope field to date

that has been shut down due to low oil prices.

The field was shut down in January 1987 after a

little more than one year in operation. However,

it is being maintained in a “warm shutdown”

mode so operations can resume quickly if oil

prices rise. Conoco, the operator, believes that

Milne Point can be economically viable at an oil

price of $22 to $25 per barrel .25

Milne Point has both onshore and submerged

tracts. In addition to the 60 million barrel reserve

within the Kuparuk River formation, additional oil

may be recoverable using tertiary recovery techniques from the field’s shallower Cretaceus

sands (identical to the West Sak sands in

Kuparuk). However, these shallow sands are

loosely cemented and contain viscous oil. Techniques have not yet been worked out to allow the

operator to maintain economic flow rates. Closer

well spacing will be needed, so the cost of

developing these sands will be higher than the

cost to develop the main portion of the field.26

Proven But Undeveloped Fields

The Alaska Department of Natural Resources

has estimated potential reserves for five proven

but undeveloped North Slope fields: West Sak,

Point Thomson/Flaxman Island, Seal lsland/Northstar, Niakuk, and Gwydyr Bay. DNR

estimates that production of some West Sak oil

might begin at oil prices somewhat below $24 per

barrel, but DNR estimates that oil prices will have

to rise to at least $24 per barrel before the other

three fields will be profitable to develop. Technical innovation may be required in some fields as

well.

West Sak, with estimated in-place resources of

roughly 15 to 25 billion barrels, is potentially the

most important of these fields. Between 2 and 5

percent of these resources are considered

recoverable. Approximately 0.5 billion barrels

are likely to be recoverable using technology

developed from the West Sak pilot project, and

1.5 billion barrels may be recoverable with higher

oil prices and using advanced EOR techniques.27

However, both the amount of oil in place and the

ultimate production potential of this marginal field

are highly uncertain .28 Ultimate production

potential may be higher than currently estimated.

The West Sak field is at a shallow depth, close to

an overlying 1,800-foot-thick layer of permafrost,

and has a reservoir temperature of about 70°F

compared to 195°F for the deeper pay zones in

the Prudhoe Bay field. Temperature affects viscosity and the lower temperature West Sak oil is

a thick, molasses-like, low-grade crude, which

makes it much more difficult to produce than the

higher quality, higher temperature oil in the Prudhoe Bay and Endicott reservoirs. The West Sak

reservoir is composed of unconsolidated finegrained sand that tends to flow into the well bore

when higher flow rates are attempted. 29 Structurally, West Sak is fairiy complex, consisting of

multiple faults and “finger” sands. There is large

variability in pay zones and fluid properties

across the fieid.

The only long-term production tests to date in

West Sak have been in conjunction with a 2-year

pilot project. In all, 14 pilot production and injection wells were drilled to a depth of 4,000 feet.

Water for the injection wells was heated and injected under high pressure into the formation to

increase the temperature of the oil. The flow rate

for 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 200

barrels per day versus up to 20,000 barrels per

day at Prudhoe (Prudhoe Bay production

averages about 6,000 bpd per well). Because of

the reservoir rock and fluid properties, many

more wells are likely to be needed than is the

case for Prudhoe Bay. Also, the shallow depth of

the West Sak reservoir implies that more well

pads will be needed than at Prudhoe or Kuparuk

since the same horizontal drilling offsets will be

difficult to achieve. West Sak acreage drained

per well pad will be substantially less (assuming

the same number of wells per pad and similar

drilling angles and “kickoff” points, a Prudhoe

Bay pad would be able to drain 12 times the area

as one in West Sak). Thus, a West Sak field

would take a long time to develop, and without a

breakthrough in recovery technology, is not expected to contribute much to keeping TAPS full.

One development scenario envisions five

production centers with a total of 5,100 wells

(about five times the number of development

wells in the Prudhoe Bay field).

In 1984, ARCO estimated that the West Sak field

could be in full production by the late 1980s;

however, the company suspended work on the

West Sak pilot project in December 1986. ARCO

is still evaluating the pilot project results and conducting research on how to develop the field

economically. If economic conditions are right,

the field could produce about 100,000 barrels of

oil per day by 2000 and account for approximately 5 percent of current TAPS capacity.

ARCO has shown that the field can be producti

using existing technology. However, sophisticated enhanced recovery systems would be required, and these are justifiable only with high oil

prices and stable economic conditions.30 One

advantage for West Sak development is that it

should be able to capitalize on the extensive

facilities already in place for the Kuparuk field;

however, full development of West Sak will require the same enclosed production and personnel facilities as Prudhoe Bay but with far less

revenue-production potential per dollar invested .3’

ARCO remains hopeful that it can achieve

breakthrough in recovery technology. It plans on

beginning a new experimental drilling program in

1989, with up to 25 wells in the pilot program if

32 If the program i s

early wells are successful.

fully successful, ARCO hopes eventually to

produce 200,000 to 300,000 bbl/day from the

field. 33 Given the substantial technical problems

remaining, however, the prospects for West Sak

are highly uncertain. Figure II I-6 presents a

projection of future West Sak production assuming use of available technology.

The Seal lsland/Northstar field, being explored

by Shell, Amerada Hess, and partners, may be

the second offshore field developed. Located

approximately 12 miles northwest of Prudhoe

Bay, the Seal lsland/Northstar field is partially in

Alaskan State waters and partially in waters disputed between Alaska and the Federal Government. The disputed leases are managed by the

Federal Government. The field is estimated to

have in-place resources of approximately 900

million barrels and potential reserves of about

Figure 3-6.-Alaska North Slope

Production: 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, 21

32. 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 to

have about the minimum volume of recoverable

oil necessary for economic production in the

Beaufort Sea given $24 per barrel oil.34 Seal lsIand will be considerably more expensive to

develop than the Endicott field because it is located 6 miles offshore (4 miles further offshore

than Endicott), in 39 feet of water (3o feet deeper

than Endicott), and in a floating fast ice zone

where moving ice can be a hazard during storms

and “breakup.” Given the long lead times required for development in the Arctic offshore,

production is not expected to begin before the

mid-1990s even if prices bounce back up. Higher

oil prices and the expectation of continued higher

prices will be required to start development and

production from the Seal Island and Northstar

discoveries. If developed, production could

reach 45,000 barrels per day (Figure 3-6) or

more. To date, four exploration wells have been

drilled on Seal Island and another two on

Northstar Island, which is 5 miles west of Seal.

Furthur offshore, Shell and partners announced

discovery of oil in early 1986 in the Harvard

prospect. The discovery was made from the

manmade Sandpiper Island in 49 feet of water.

The Haward prospect is geographically close to

Seal and Northstar, and, if enough recoverable

oil is present, could be developed concurrently.

The Minerals Management Service has termed

the find “producible,” by which it means there is

at least enough oil present to cover daily operating costs of production. The most difficult

problem in developing the Seal/Northstar/-

Sandpiper area will be constructing the pipeline

to shore. Either a buried pipeline or a 5-mile

piling-mounted pipeline will be needed, both of

which will be very expensive.

The Point Thomson/Flaxman Island field, located on the coast of the Beaufort Sea east of

Prudhoe Bay, is estimated to contain about 350

million barrels of recoverable condensate (light

gravity hydrocarbons) and approximately 6 trillion cubic feet of recoverable gas. However,

development not only awaits higher oil prices but

is based on the assumption that a gas cycling

project will work that will enable recovery of gas

liquids without having to transport and sell the

field’s gas resources, which is not now economi- 35 The development potential ‘f ‘he cally feasible.

Point Thomson field also suffers from its location

about 60 miles from the Trans Alaska Pipeline.

The outlook for development of this field could

improve if a significant oil discovery is made in

the Arctic National Wildlife Refuge immediately to

the east and a pipeline is built that could also

sewe Point Thomson.

In December 1987, the Standard Alaska

Production Company declared the Niakuk field,

located in 4 feet of water 1 mile offshore in State

waters immediately northeast of Prudhoe Bay, to

be commercial. Standard has estimated reserves to be about 55 million barrels of oil,

recoverable using primary and waterflood techniques, and thus the field appears to be in a class

with Milne Point and other marginal North Slope

fields 36 The reservoir is the Sag River sandstone!

productive at Prudhoe Bay, and separated from

Prudhoe by the Niakuk fault system. The field is

heavily faulted and divided into at least three discrete pieces, two of which are considered by

Standard to be commercial at current oil prices.

Standard would like to start producing Niakuk in

1991, contending that this field will be economic

to produce, despite its small size, because the

field is quite close to Prudhoe Bay, will not require a long offshore causeway or onshore connecting road, will likely be able to use spare

production capacity at the Prudhoe Bay and Lisburne fields by the time production begins, and,

given its small size, will not require special engineering but will be able to use off-the-shelf

facilities. Standard hopes that the field can contribute 20,000 barrels of oil per day to TAPS by

the end of 1991.37

DNR has estimated potential reserves in the

Gwydyr Bay field northeast of Prudhoe Bay–assuming 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.
Chapter 3 ● 87

barrels. Potential resewes of other small oil dis- ANWR and the East Umiat and Gubik fields in the

coveries – including Tern Island 35 miles east of NPRA have either not yet been determined or not

Prudhoe Bay, Colville Delta west of the Kuparuk released. There is little to suggest that any of

field, Umiat in the National Petroleum Reserve in these fields will ever contribute more than small

Alaska (N PRA), and the Hammerhead and incremental amounts to total North Slope

Phoenix 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 producing

North Slope fields– Prudhoe, Kuparuk, Lisburne,

and Endicott– make up all of the present TAPS

production and will continue to dominate with at

Ieast 80 to 90 percent of ail North Slope production well into the 1990s, even with the most optimistic assumption of development for other

known fieids. With this background, OTA investigated the potentiai of new advanced recovery

technologies either to improve production

forecasts for these four fieids or to improve

production opportunities for other known, but not

yet producing, North Slope fields.

To begin this investigation, OTA evaluated future Alaskan North Slope oil production projections and the technological assumptions that

affect them. Next, OTA held a workshopm to

identify current technologies and to project the

development of new technologies that could improve production from known Alaskan oilfields.

In preparation for the workshop, OTA extracted

from pubiished data oil production projections

with their accompanying assumptions and assembled brief descriptions of field characteristics. The workshop was focused on the

identification of technologies (and their stages of

development) that may be used in these fieids.

OTA asked the workshop participants to review

and critique the data assembled and to suggest

and discuss technologies from their own

knowledge and experience. Participants in the

workshop included industry experts in enhanced

oil recovery and in North Slope reservoir engineering, as well as researchers from the University of Houston and private independent firms.

The findings of the workshop covered three

principal topics: field characteristics that limit

recovery; technologies to improve recovery; and

projections of future North Siope oil production.

Prudhoe Bay is now and has aiways been the

premier oiifield on the Alaskan North Siope. Not

only is it the largest field in the United States, but

it is seven to eight times as large (in reserves) as

Kuparuk, which ranks number two. Prudhoe is a

field with high recovery potential, now estimated

at 42 to 45 percent of original oil in place. Prudhoe is the fieid whose potential fired all North

Slope development over a decade ago, and its

production is still more than 80 percent of ail

North Slope oil. Prudhoe is a mature field and is

near its peak production.

The other three producing North Slope fields–

Kuparuk, Lisburne, and Endicott– now contribute about 15, 2, and 5 percent, respectively, to

total North Slope production. The other known

North Slope fields– both onshore and offshore–

are considered to be of minor importance either

because of size (e.g., insignificant portion of

TAPS throughput) or because present economics prohibit their development. OTA workshop

participants reviewed the information on these

other fields and selected one (West Sak) out of

the group for discussion. West Sak is a very large

field that is not presently economical and that

would require significant implementation of enhanced recovery techniques to produce oil. It

represents a field with potential but with a range

of significant barriers (technical problems) to

overcome to reach its potential. The workshop

participants therefore focused on technologies

that would be applicable to five known North

Slope fields –four now producing and one potential.

The oil well recovery systems that are used

today are typically described as either primary,

secondary, or tertiary. Primary recovery

produces the fraction of in-place oil that will flow

unaided or can be pumped from the reservoir

rock matrix to the surface. Depending on the

reservoir characteristics, from 5 to 80 percent of

in-place oil may be recovered using primary

recovery techniques. In the United States as a

whole, average primary recovery has been about 39 In 1979, the American 28 percent of in-place oil.

Petroleum institute reported that the average ultimate 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 and

southern Louisiana have a history of high primary

production. Prudhoe Bay is this type of reservoir.

Secondary recovey techniques are in common

use in many reservoirs to increase the percentage of oil recovered. These methods attempt to

maintain or restore reservoir pressure by the injection of gas or water (waterflooding). Depending on reservoir conditions and oil properties,

secondary recovery techniques can improve inplace oil recovery to between 30 and 50 percent.

The injection of water into a reservoir to displace

the in-place oil, to reproduce a natural water

drive, is the basic secondary recovery operation.

In the United States as a whole, waterflooding

raises oil recovery efficiency by a factor of 1.5 to

2.0. Waterflooding is dominant among fluid injection methods, and its widespread use is due to

the easy availability of water, the relative ease of

injection, and the efficiency with which water

spreads through a reservoir and displaces oil.

Prudhoe Bay and Kuparuk fields have secondary recovery waterflood operations in place;

Endicott is scheduled to start waterflood in 1989

and Lisburne has a waterflood pilot operating. All

producing North Slope fields now have applicable secondary recovery techniques in place or

planned.

After secondary recovery methods are exhausted, the extraction of additional oil from

fields requires the application of more sophisticated and expensive techniques. Enhanced oil

recovery processes (or tertiary techniques) can

further increase recovery to 40 to 80 percent of

the original in-place oil, depending upon the

process employed and upon the physical properties of the reservoir and the oil. These techniques

usually attempt to reduce oil viscosity and/or to

affect other characteristics that impede oil flow.

The techniques work by introducing to the

producing formation either heat (steam) or substances such as rich miscible gas, carbon

dioxide, polymers, solvents, surfactants, micellar

fluids, or even microorganisms in various combinations, depending upon reservoir conditions

and crude oil properties.

One of these techniques (rich miscible gas injection) is now in place with a major project at

Prudhoe Bay and another at Kuparuk. The OTA

workshop focused attention on whether a range

of enhanced recovery techniques might be applied to the four producing fields and West Sak

and, under the most optimistic economic conditions, what improvements in ultimate recove~

might be expected.

The OTA workshop reviewed each of the five

fields under consideration and noted key features

as well as constraints to further production as follows:

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 recovey

include:

- Waterflood

– Miscible gas injection

– Infill wells*

– Horizontal drilling*

- Other studies by the operators to enhance 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 with

a big gas cap

- Barriers to increased recovery are

limited waterflood contact with oil in

the reservoir and gas handling

capacity

*These techniques are used primarily to accelerate production rather than to increase ultimate recovery, although some increases are

possible, for example, when horizontal drilling is

used to reach areas of thin pay not easily drained

by regular wells or when infill wells drain portions

of oil reservoirs that are not in close connection

to the primary network of wells.

Kuparuk (25 to 30 percent recovery)

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

● Compared to Prudhoe, formation is thinner and more spread out with more faults

and no gas cap
90 ● ANWR

● The field is constantly on decline without

continual infill drilling

● Of 400 square miles, only the inner 200

square miles is commercial

● Waterflood and miscible gas injection

projects are now in place

● Barriers to improved recovery include oil

saturation, faulting, and relatively thin pay

Lisburne (7 to 22 percent recovery)

● About one-half of this reservoir underlies

the 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 complex matrix is not yet known; more drilling

is needed to better define the reservoir.

● Small waterflood pilot is being tested

● Barriers to improved recovery include low

porosity and permeability; fracturing

Endicott (35 percent recovery)

●

●

●

●

●

West

Similar to Prudhoe reservoir with big gas

cap (23oAPI, 210°F)

Waterflood designed into the beginning of

project for 1989 start-up

Gas handling may be future problem

Small field compared to Prudhoe production

Constrained by faults; reservoir volume

well-defined

Sak (15 to 25 billion barrels estimated oil

in place)

●

●

●

●

●

Largest medium-heavy oilfield on North

Slope (14 to 22oAPI, 70°F average)

Recovery rates are now estimated between O and 5 percent by industry,

depending on section of the field

Very difficult field to produce because of

poor reservoir conditions, i.e., unconsolidated fine sand and viscous, lowtemperature oil

Early tests indicate well production rates

will be very low (hundreds of barrels per

day), requiring thousands of wells for any

substantial production

Industry concludes the field is not

producible at today’s prices

Enhanced recovery techniques possibly applicable to North Slope fields are in three

categories: miscible flooding, chemical flooding,

and thermal techniques.

Miscible flooding is a technique based upon

using some gas– such as enriched reservoir gas

(as at Prudhoe) or carbon dioxide (COQ) or

another gas–to miscibly displace some oils,

thereby permitting the recovery of most of the inplace oil contacted. The miscible gas is injected

into the formation at an injection well and forced

toward a production well. A technique for forcing

and directing the miscible gas is to alternate

water slugs through the same injection well. This

is known as Water-Alternating Gas (WAG). A further improvement can be achieved by adding a

detergent to the water in WAG which then forms

a foam and reduces the apparent viscosity of the

fluid. COQ gas is more commonly used in the

Lower 48 because reservoir gas is a more valuable product. At Prudhoe Bay, gas is not currently marketable and therefore is a more attractive

flooding agent.

Chemical flooding is a technique based on adding various chemicals to the water used in

waterflooding in order to increase waterflood efficiencies. Chemicals may be polymers, which

increase the viscosity of water, surfactants to

help release immobilized oil, strong alkalines

which themselves form surfactants, or other

more complex substances. Foaming agents also

have been added to chemical flooding to create a

more efficient solution.

Thermal methods involve the injection of steam

or hot gas or in-situ combustion – all for production of heavy crude oils whose recovery is impeded by viscous resistance to flow at reservoir

temperatures. Foaming agents also can be

added to steam to increase steam injection efficiency.

Pressure cycling is the technique of injecting

natural gas or COQ into the producing formation

and alternating high and low injection pressures

to induce mixing with the crude and thus

stimulating the flow. Lab testing and simulations

of “pressure cycling” have been done, and it is
believed to be a promising technique for highly

fractured rese~oirs (such as Lisburne).

Some of these techniques have already been

applied (rich miscible gas injection at Prudhoe

and Kuparuk) and others have been studied. The

list in Table 3-5 covers most of those considered

possibly viable by the industry and other researchers at this time. The technique that has

provided major improvements for North Slope

fields (beyond secondary waterflood) is miscible

gas injection. Most others are considered experimental at this stage and almost all must be

field tested. A common feature of EOR development is that it is difficult or sometimes impossible

to accurately scale up the results of laboratory

tests to the field level. Also, some technologies

appear impractical for certain North Slope conditions. For example, many thermal processes are

difficult to apply because of wide well spacing,

depth of the reservoirs, and the substantial permafrost layer.

None of the techniques appear to offer a major

increase in recovery rates for the existing North

Slope fields. Rather, the dominant industry view

is that continued enhanced recovery efforts over

a long period of time would likely be able to add

a series of small increments to the ultimate

recovery percentage for any given field. In

general, the industry appears to have greater

faith in the gradual accretion of experience from

application of existing recovery methods than in

the potential of exotic new methods. For PrudTable 3-5.—Some Enhanced Recovery Techniques

Possibly

M/se/b/e - flooding

Chemical flooding

Themal methods:

Pressure cycling

NOTES 1 In use II other-Lower 48-fields

2 In use— North Slope

3 Some pilot tests

4 Lab tests and experiments

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

hoe Bay this may mean that about 10 percent

more oil ultimately will be recovered. For other

fields, application of EOR techniques might push

recovery rates to the high end of ranges now estimated. In any case, it is not likely that the onset

of decline in North Slope production can be

delayed more than a few years. The most likely

outcome of using more enhanced recovery technology would be to extend field life. This outcome would increase total recovery from certain

fields but not necessarily have any immediate effect upon short-term production rates.

Application of EOR technology is a/ways a

decision based on economics. Those techniques which the industry considers to be

economic under current conditions are being applied in North Slope reservoirs. Higher crude oil

prices could result in wider application of current

techniques and also increase the chances for

economic application of other more speculative

technologies.

Table 3-6 shows, for four North Slope fields of

interest, the factors for each which may limit

production and some applicable enhanced

recovery techniques. “Present EOR” denotes

work already in place; category A covers techniques that may be applied depending on

economic conditions and individual company

plans. Category B includes speculative techniques which require development and/or testing

and higher oil prices.

Summary

Most of the enhanced recovery techniques that

seem practical for North Slope fields today are

either in place or already planned for installation

in the future. OTA’s review did not uncover any

technologies that offered major improvements in

recovery rates from the fields where we had available information. A careful examination of advanced technologies at the University of Houston

workshop led to the summary of possible future

enhancements discussed above. The conventional approaches cover most of those in use or

planned. More speculative technologies have

promise for the future but would certainly require

further field testing. OTA was not able to

evaluate the economics of EOR but notes that industry claims oil prices must increase before any
Table 3-6.—Problems Limiting North Slope Recovery

and Technologies Which May Improve Recovery

Prudhoe Bay

Limits: 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 Waterflood

More Miscible Gas

Expand Gas Handling Capability (Gas

Cycling)

More Infill Drilling

B) Speculate Technologies: Foam to Improve Miscible Gas (Mlscible Flood)

Surfactant/Polymer (Chemical Flood)

West Sak

Limits: Unconsolidated Fine Grained/Sand Production

Viscous Oil

Poor Rock Quality (shaly)

A) Conventional Technologies: Waterflood

(not econom!c today) Fracturing

B) Speculative Technologies: Thermal Methods

Miscible Gas or CO, (Miscible Flood)

Kuparuk

Llmds Basic Residual 011 Saturation Problem

Faulted

Thin Pay–Especially Outer Edges (half of field area)

Absence of a gas cap not a problem since much gas nearby

A) Conventional Technologies: Waterflood

Miscible Gas

Infill Drilling

B) Speculative Technologies: Foam to Improve Miscible Gas (Miscible Flood)

Polymer (Chemical Flood)

Micellar Polymer (Chemtcal Flood)

Lisburne

Limits Fractured Limestone

Low Porosity/Permeability

A) Conventional Technologies: Waterflood (may be difficult)

Infill Drilling

B) Speculative Technologies: Strategic Infill Drilling

Pressure Cycling/Natural Gas

SOURCE Office of Technology Assessment based on Oec. 8 1987 workshop

techniques beyond ones currently in use are

likely to be implemented.

OTA reviewed available current estimates of individual field production rates and ultimate

recovery and concluded that the projections in

Figures 3-3 through 3-6 are reasonable. In some

cases, the data may be either too optimistic or

too pessimistic, but, on average, the estimates

are as accurate as available information will permit. The total TAPS production estimates in

Figure 3-2 seem to adequately bracket the high

and low range of future production possibilities.

Future “surprises” at Prudhoe Bay, the

dominant field, are unlikely; Prudhoe appears to

be the most monitored and computer-modeled

field in the world. Futihermore, the operators

have foreseen Prudhoe Bay’s decline and have

been working over a long period of time to keep

production high and maximize recovery. There

may be, however, a conflict between keeping

production high and maximizing ultimate

recovery. Some researchers have noted, for example, that increasing the production of natural

gas liquids through TAPS, as industry plans to

do, may beat the expense of increasing the miscible gas injection project. This could therefore

lead to higher production now and lower ultimate

recovery. OTA has not investigated the impacts

of these details of reservoir management in order

to reach an independent conclusion but only

notes that choices are not always clear and

sitnple.

The other three fields also do not appear to

have many surprises in the offing, and, even if

they did, the impact would be minor in relation to

TAPS throughput. Kuparuk requires substantial

conventional work, such as infill drilling, to keep

production up. With waterflood and miscible gas

projects in place, the future EOR opportunities

that are available are a few of the more exotic

chemical flooding techniques. These techniques

require further study and testing. Endicott to

date is as good a performing field as Prudhoe,

and lessons from Prudhoe can best be applied

there.

Lisburne is a very difficult field to produce, and

disappointing results to date have downgraded

its future potential. Some researchers have advocated more experimental technologies to be

tried at Lisburne, but this would probably require

industry development and testing beyond that

justified by today’s economics.

The optimistic view of new EOR technologies

improving ultimate North Slope recovery appears

to be that improvement, if any, will be slow and

incremental. Over the next decade the total improvement may be expected to be about 10 percent. Improvements would need to come from

advanced techniques that will require testing and
Chapter 3 ● 93

capital expenditures beyond what indust~ claims to decline in several years, and application of enare 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 unthe North Slope of Alaska do have the potential to developed fields nor the success of EOR projects

take up some of the slack that will be created nor both together is likely to stem the inevitable

when the Prudhoe Bay and Kuparuk fields begin decline of TAPS thoughput.
OIL PRODUCTION FROM UNDISCOVERED

RESOURCES

Alaska’s North Slope still contains areas of

potential hydrocarbons that the oil industry has

never explored or that have received only minimal attention. In prospective offshore areas, for

instance, no exploration has yet taken place in

the Chukchi Sea, and very little has taken place in

the Beaufort Sea adjacent to and north of ANWR.

Even the more explored central and western portions of the Beaufort Sea have been barely

scratched. Onshore, only one well has been

drilled in ANWR, and although a number of unsuccessful wells have been drilled in the National

Petroleum Reserve in Alaska, some experts still

see the possibility of a commercial discovery in

this vast area.

Both the State of Alaska and the Federal

Government have scheduled a number of lease

sales in the next 5 years. The State plans to hold

four offshore and five onshore lease sales on

State lands in northern Alaska, while the Federal

Government has scheduled two offshore sales in

both the Beaufort and Chukchi seas in its most

recent 5-year plan (Table 3-7). Discovery of new

oil resources on the North Slope could, if large

enough and in favorable locations, help keep oil

flowing through TAPS. However, a sizable field

discovered in 1988 probably would not be

producing before 1998, given the long lead times

needed 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 resources

of the ANWR coastal plain. The results are a closely guarded secret.
Chapter 3 ● 95

Table 3~7.—Alaska Lease Sales

Numbe r Sal e Sale date

A. Proposed Alaska OCS Region Sales

97 Beaufort Sea March 1988

109 Chukchi Sea May 1988

107 Navarin Basin December 1989

101 ● St. George Basin February 1990

1 14* Gulf of Ak./Cook Inlet September 1990

117 N. Aleutian Basin October 1990

124 Beaufort Sea February 1991

126 Chukchi Sea May 1991

120’ Norton Basin September 1989

129’ Shumagin January 1992

133’ Hope Basin May 1992

130’ Navarin Basin January 1992

“To be held only [f Industry Interest warrants

SOURCE U S Department of the lnterlor, April 1988

B. Proposed State of Alaska Sales

54 Kuparuk Uplands

55 Demarcation Point

66A North Slope Exempt

52 Beaufort Sea

56 Alaska Peninsula

67A Cook Inlet Exempt

59 Cook Inlet

57 North Slope Foothills

64 Kavik

65 Beaufort Sea

61 White Hills

68 Beaufort Sea

NOTE North Slope sales bold

January 1988

June 1988

June 1988

January 1989

June 1989

June 1989

January 1990

June 1990

January 1991

June 1991

January 1992

June 1992

SOURCE Alaska Department of Natural Resources Division of 011 and Gas

Estimates of undiscovered oil may be useful for

a number of reasons. These estimates may be

used for 1) making long-term energy policy, 2)

forecasting rates of domestic discovery and

supply, 3) anticipating environmental impacts of

exploration and production, 4) making investment decisions, 5) anticipating future technology

and capital requirements, 6) realistically evaluating regulatory options, 7) scheduling lease sales,

8) conducting cost-benefit studies of leasing alternatives, and/or 9) analyzing the economics of

38 Estimates ‘ f

Industry’s bids on leasable tracts.

the undiscovered resources on the North Slope

of Alaska are needed for all of these reasons.

Several techniques are available for estimating

the amount of undiscovered resources a region

may contain (see Appendix B). Even with the

best techniques available, estimates of undiscovered resources are inherently much more tentative than estimates of resources in known

fields.

Estimates for the North Slope

The expectation of the early 1980s that more

major oil resources would be found on the North

Slope and in other parts of Alaska has not yet

been realized. All of the currently producing onshore fields were discovered in the late 1960s,

and no significant new discoveries have been

made. Offshore areas have been judged by

many 3g to be particularly promising, but the only

offshore development to date is Standard Alaska

Production Company’s Endicott field, discovered

in 1978. After considerable exploratory drilling,

the only noteworthy offshore discovery in the

1980s has been Shell’s Seal Island, a field that is

not economic to develop at current low oil prices.

While much oil probably remains to be discovered

both onshore and in still relatively unexplored offshore areas, it is unlikely that undiscovered resources will be found and developed in time to keep the

Trans Alaska Pipeline running at full capacity after

1990. Lead times for development of 15 years or

more may be required in some of the more remote

places. in any case, new oil discovered in Alaska

will not necessarily be found in proximity to TAPS

and, hence, may require installation of an alternative

transportation infrastructure. Also there has been a

slowdown in exploration spending since 1985 because the current price of oil is low.

Several estimates of the undiscovered, economically recoverable resource potential of Alaska have

been made. In 1981, the U.S. Geological Survey

(USGS) estimated the risked mean of undiscovered,

economically recoverable oil offshore Alaska to be

12.2 billion barrels and of natural gas to be 64.6 trillion cubic feet;w

onshore Alaskan oil and gas

resources 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 assumed the offshore leasing responsibilities of the

Consevation Division of the U.S. Geological Survey

in 1982, again estimated offshore undiscovered

resources. The newer assessment concluded that

Alaskan Outer Continental Shelf (OCS) areas contained 3.3 billion barrels of undiscovered, economically recoverable oil and 13.9 trillion cubic feet of

gas. This volume is much lower than the 1981 estimates. MMS assessed only OCS resources (i.e.,

resources beyond the 3-mile-wide band of Statecontrolled waters) while the previous USGS estimate considered all offshore resources together,

MMS also used a different estimation methodology

and revised some of the assumptions used in the

earlier USGS estimate. Still, most of the reduction in

the estimate of offshore undiscovered, economically recoverable resources probably can be accounted for by the disappointing offshore

exploration record between 1981 and 1985 (Table 3-

8).

In May 1988, the Minerals Management Service

and the U.S. Geological Survey released preliminary data from a new study of the Nation’s undiscovered oil and gas.42 The new study incorporates

a great deal of new data and uses improved estimation methodologies.43 The USGS estimated onshore resources and resources in State waters;

MMS estimated resources in Federal OCS waters.

The new USGS estimate of undiscovered, economically recoverable resources for the total of onshore

and State offshore areas of the United States is considerably smaller than the 1981 estimate. The picture for Alaska is less dear. The preliminary 1988

estimate indicates a risked mean of approximately 8

billion barrels of oil in onshore areas and in Alaskan

State waters. The corresponding 1981 figure, 6.9

billion barrels, does not differentiate between State

and OCS waters, thus making comparisons between the two estimates difficult; however, given the

Table 3-8.—Estimates of Undiscovered, Economically

Recoverable Oil in Alaska (risked mean billion barrels)

magnitude of USGS’s 1981 combined estimate of

onshore and shelf offshore oil, a reduced estimate

can be inferred.a

Alaskan OCS data also have been revised.

Preliminary offshore estimates of undiscovered,

economically recoverable oil indicate substantially less oil than was estimated in MMS’s 1985 estimate. Since 1975, over 90 exploration wells

have been drilled in the State and Federal waters

of the Beaufort Sea and in the Navarin, Norton,

and St. George Basins in the Bering Sea.45 Few

of 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-MMS

Working 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 final

publication o the report, 7

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 the

shelf 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 State

waters, has been developed to date; only two

other likely commercial discoveries have been

made, Niakuk and Seal Island. Niakuk is in very

shallow State waters adjacent to the existing

Prudhoe Bay infrastructure and, hence, may possibly be producing by the early 1990s. Seal lsIand has been the only OCS discovery to date

(although, as noted previously, its OCS status is

being disputed by the State of Alaska).

The most notable disappointment in OCS exploration was Sohio’s Mukluk prospect in the

Beaufort Sea. The Mukiuk structure was considered the most promising prospect in the

Beaufort during 1983, but the failure to discover

oil there transformed it into the most costly dry

hole in history ($140 million in drilling and island

construction costs and over $1 billion in total

costs). The Mukluk dry hole figured prominently

in the substantial lowering of Beaufort Sea

resource estimates in MMS’S 1985 reassessment

of undiscovered, economically recoverable

resources.

Figure 3-7.-Exploratory Wells in the

Beaufort 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 a

major reason for the lower 1988 estimates. Furthermore, low and volatile oil prices have dampened enthusiasm. Exploratory drilling activity

has dropped off sharply since the peak year of

1985 (Figure 3-7). Only one well has been drilled

thus far in 1988, Tenneco’s Aurora well about 4

miles off the coast of the Arctic National Wildlife

Refuge, and no others are expected. However,

higher and more stable oil prices would likely

stimulate higher levels of offshore exploration in

the future.

Estimates for ANWR

Although much is said and written about the

resource potential of ANWR, it is still a virtually

unknown area, and a wide range of resources is

possible in ANWR’S coastal plain. Much

depends, for instance, on the existence and

thickness of Ellesmerian sequence rocks in the

ANWR area, and State and Federal geologists differ in their assessment of these rocks. Both the

State of Alaska and the U.S. Department of the

Interior (DOI) have used play analysis to estimate

the in-place resource potential of ANWR. The

State used a model known as the Resource Appraisal Simulation for Petroleum (RASP) to estimate undiscovered resources there. DOI used

a modified version of the play analysis technique

developed by the Geological Survey of Canada

to estimate ANWR’S potential in its mandated

report to Congress. The DOI assessment is

driven by an efficient computer program known

as the Fast Appraisal System for Petroleum

(FASP) (see Appendix B for a discussion of these

models). Both models use information gained

through seismic work and through studies of

ANWR’S surface geology; both models depend

for much of their input on the opinions of

geologists familiar with the area; and both

models report their results as probability distributions rather than as single point estimates.

The State reports that there is a mean of 7.22

billion barrels of in-place oil in ANWR while DOl
98 ● ANWR

reports a mean of 13.8 billion barrels. Given the

lack of information about ANWR’S subsurface

geology, it is not surprising that DOI and State of

Alaska estimates differ at all probability levels

(Table 3-9). 47 Although the results differ, both

studies conclude: a) that the key elements for

petroleum accumulations are present beneath

the coastal plain of ANWR, b) that there is only a

smail possibility that unusuaily large petroleum

resources are present, and c) that there is a

greater likelihood that resources more moderate

in size are present.48

One thing is important – much of the difference

between the two estimates is due mainly to subjective factors. For instance, DOI and Aiaska

geologists identified different geological plays for

anaiysis (not unusual given the limited geoiogic

data available), had quite different opinions about

the quantity of potentially oil-bearing Ellesmerian

sequence rocks in the area, and disagreed about

the contribution of pre-Mississippian rocks for oil 49 Had the same subjective inforaccumulation.

mation been used in each study, the DOI and

State estimates using FASP and RASP wouid

have been about the same, but the estimates

would not necessarily have been more accurate,

Subjective factors necessarily introduce a conTable 3-9.—Comparison of Estimates for

Undiscovered In-place Oil in ANWR

Probability y State of Alaska Department of Interior

greater 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 of

undiscovered resources. Drilling data is not

available for ANWR’s coastal plain.

The Department of the Interior estimated

economically recoverable resources using the

PRESTO (Probabilistic Resource Estimates-Offshore) model. With PRESTO, DOI estimated that

if at least one field with commercially recoverable

quantities of oil is present in ANWR, then there is

Iikely to be a mean of at least 3.23 billion barrels

of recoverable oil, a 5 percent probability of at

least 9.24 billion barreis, and a 95 percent probability of at least 590 million barrels. Note that

these estimates are very sensitive to DOI’s minimum areawide economic field size, which in turn

is dependent on the assumed price of oil (in this

case, world oil prices at $35 in the year 2000 in

1984 doilars, with North Slope oil $33 because of

market conditions).

The Energy Information Administration (EiA)

also estimated the undiscovered, economically

recoverable resources of ANWR. EIA assumed

that 25 percent of the in-place resources estimated in the DOI study would be recoverable,

basing its assumed recovery factor on the approximately 26 percent area-wide recovery factor 50 This assumption for known North Slope fields.

resuits in a base case estimate of 3.45 billion barreis of recoverable oil. If EIA had applied the

same recovery factor to the State’s in-place estimate, the comparable undiscovered, economically recoverable estimate would be 1.8 billion

barrels. OTA has no basis for concluding that

one estimate is more accurate than the other, i.e.,

for using DOI’s mean oil in-place figure versus

using Alaska’s figure.

Note that the EIA and DOI estimates are not as

similar as they appear. The DOI estimate depends

on the existence of at least one commercial field,

and, according to DOI, there is a 19 percent chance

that such a field exists in ANWR. The EIA estimate

assumes the probability of finding economically

recoverable oil is nearly 100 percent (uncondition47. J,J. Hanson and R.W. Kornbrath, “AComparison of State and Federal Appraisals of the ktic National Wildlife Refuge Coastal

Plain,” 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 are

present, that traps exist other than those used by

DOI in its PRESTO analysis, and that oil accumulations smaller than 440 million barrels can be

economically recovered.

Various groups support DOI’s risked mean estimate of approximately 600 million barrels–that

is, 3.23 billion barrels multiplied by the probability

of finding economically recoverable oil (19 percent), –as the appropriate measure of ANWR’s

resource potential. In OTA’s view, the more appropriate interpretation of the DOI analysis is that

there is an 81 percent chance that no economically recoverable resources will be discovered in

ANWR, but if there are any economically

recoverable resources at all, there will be a mean

of at least 3.23 billion barrels.

On the other hand, if approximately 3.5 billion

barrels of recoverable oil are found in ANWR,

OTA considers peak production of about 800,000

barrels per day from two producing fields to be

reasonable (see OTA scenario – Table 2-4– in

Chapter 2). Production that started in 2002 might

peak by 2008 and then decline at a rate of about

12 percent per year.
100 ● ANWR

OIL INDUSTRY COST-CUTTING AND THE

EFFECT ON OILFIELD DEVELOPMENT

Oilfield costs during the past 15 years have

been linked to oil prices. When prices were

rising, costs also tended to rise after a short time

lag. One reason was that the sellers of equipment and services were able to raise their prices

and increase their profit margins when rising

prices spurred oilfield activity levels and when the

demand for services and equipment outran the

supply. Another reason was that rising oil prices

tended to dull the incentive for innovative, costcutting design and operation. When oil prices

began to fall, beginning in 1981, oilfield activity

levels dropped, and prices for drilling and other

services fell substantially. When oil prices

nosedived in late 1985, prices for equipment and

sewices fell along with them. In many areas, for

example, day rates for rigs fell more than 50 percent. At the same time, extensive cost-cutting in

the industry streamlined oilfield activities so that

the actual number of mandays and equipmentdays required to complete projects was dramatically down.

For example, the industry drilled about 92,000

wells in 1981 with nearly 4,000 rotafy rigs active;

84,000 wells in 1982 with 3,100 ri s active; and

85,000 wells in 1984 with 2,400 rigs.5 1This improvement in “rig efficiency” is a complex function of actual efficiency improvements and other factors,

such as changing geographical drilling patterns,

shifts in the balance of oil and gas targets, and lower

levels of exploration. Unfortunately, it is difficult, if

not impossible, to separate out the roles of the

various causal factors in the chan es in this and

other measures of oitfield efficiency. Thus, it is not

possible to predict reliably what portion of this increased efficiency would remain if oil prices

rebound or other oilfield conditions improve.

Nevertheless, OTA believes that there is sufficient

evidence to conclude that a significant portion of the

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

Anecdotal evidence implies that the North

Slope has seen considerable cost-cutting success. For example, Standard Alaska Production

Company claims to be drilling development wells

at Endicott for 40 percent of the originally

projected cost–with no reduction in time rates

for rigs–and the overall cost for developing the

field was about one-third of original projections

($1.3 billion final cost, $3.8 billion conceptual estimate =

). The majority of the savings came from

a combination of additional knowledge of the

resource that dictated less expensive requirements and lower material and labor costs because of the general slowdown in oilfield

activity– cost reductions that are not likely to be

repeatable. A substantial part of the savings,

however, resulted from Standard’s conscious

decision to scale-back and redesign the project.

Cost-saving measures included:

using fewer but larger production

modules;

using self-propelled, cantilevered drilling

rigs to allow smaller spacing for wells and

to reduce time for well-to-well moves;

changing the design from one island to

two, reducing drilling costs;

building a gravel causeway rather than undersea pipelines; and

using a single, rathe~~han a redundant, oilprocessing system---

None of these changes are dramatic technological breakthroughs, and all could well have

been implemented without the decline in oil

prices that began in 1981. However, it seems

likely that the price drops were the proximate

cause 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

Endicott Field, August 1987. Careful redesign allowed substantial cost savings at this field,

The result of these and other cost-cutting successes is that, as oil prices have declined, the

“breakeven” oil prices for project development

have declined as well. Consequently, projections

of reduced activity levels (because of low oil

prices) that relied strictly on previous estimates

of project costs should be viewed as overly pessimistic. Also, if oil prices rise back to previous

levels, much of the “benefit” associated with the

period of low prices would remain. For example,

the rates for services probably would rise also,

but not to previous levels. Higher efficiency

reached during the period of low oil prices would

probably remain, except for temporary losses

that might occur if the demand for oilfield services and equipment outstripped the capacity of

the providers. The net result would be that a

return to previous oil price levels might find the

industry capable of doing more project development than was economic at the time of the previous price peaks,

The oil industry’s ability to cut costs in the face

of low oil prices implies that projections based on

previous cost estimates should be viewed somewhat skeptically. This view applies to production

projections for the entire North Slope as well as

to estimates of the oil price necessary to develop

a 500-million-barrel oilfield in the Arctic National

Wildlife Refuge. For the North Slope, the ability

of the industry to complete projects at lower

costs makes it likely that the more optimistic of

the available production projections–forecasting a 25 percent decline in production by 2000–
is the more realistic of the two presented pre- Mlnimum Economic Field Size (MEFS) is Ss–that a $35/bbl oil Price viousl y. However, basic resource constraints probably too large

and the unavailability of any “breakthrough” en- (1984 dollars) would allow the development of a

hanced oil recovery technologies implies that still field smaller than DOI’s MEFS of 440 million barhigher production levels are unlikely. For ANWR, rels of economically recoverable oil, or else that a

OTA tends to agree with the Energy Information 440-million-barrel field could be developed at a

Administration’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, revised

edition, WViNGD/87+1, ootober 19S7.
BOX 3-B

HOW MUCH OIL IS IN THE ANWR COASTAL PLAIN?

The decision to allow or block leasing of the ANWR coastal plain depends on balancing the potential damage that expiration and development may cause the wilderness, wildlife, subsistence, and

other values with the value of the potential oil resources, Resource estimates for undrilied regions

are notoriously subjective and inaccurate, however, and Congress should view the Department of

Interior’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 an

evaluation 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 the

assessment. In our view, the assessment is more likely to have produced results that are conservative, that is, resuits that are more pessimistic about the likely recoverable oil than the evidence

suggests. OTA did not review DOI’s geologic assessment that produced estimates of total in-place

oil, but we note that this assessment is substantially more optimistic than the assessment produced

by the State of Alaska. Because the estimate of total recoverable resources reflects both the

geologic assessment of in-place resources and the economic assessment of recoverability, OTA is

reluctant to conclude that DOI’s estimate of total recoverable oil resources in the ANWR coastal

plain is either conservative or optimistic. On the other hand, we conclude that DOI’s estimate of the

likelihood that economically recoverable quantities of oil will be found in ANWR –19 percent at

world 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 optimistic because DOI assumed unrealistically high world oil prices –$35/bbi (1984 dollars) refinery

acquisition costs by the year 2000 with a continued growth in “real’ prices beyond 2000 of 1 percent per year. ’f Because the size of the “minimum economic field” –the smallest oilfield that could

support the pipeline and other facilities needed to produce and transport ANWR oil – is inversely dependent on oil prices, lowering the assumed prices would tend to increase the minimum field size

and thus reduce the estimated probability of finding commercial quantities of oil in ANWR. Lowering the assumed oil price would also affect the estimated volume of recoverable oil. However, the

effect appears somewhat pewerse because the estimated “mean” voiume of oil, assuming that

economic amounts are found, actuaily increases if assumed oil prices are lowered. This counterintuitive effect occurs because reducing the minimum field size adds a number of lower-resource

possibilities to the universe of resource possibilities sampled by DOJ’s probabilistic model, In

reality, of course, if economic quantities of oil exist In ANWR, a lower oil price would tend to

decrease the volume of oil recovered.

The assumed oil price is only one of several factors that may affect the reliability of the economic

assessment. 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 that

must be balancecf by the economic value of the oil found. Assuming that a company purchases 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 with

commercialization. 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 Minimum

Economic 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 possibility.

2. Including or excluding the possibility of 6ciu$ters* of small fields. The AKFS is calculated

on the bw% of its stand-alone prospects. {n other words, each prospect is evetuated on the

bask of its ability to pay for afi of the infrastructure necessary to develop the field, including

the main p]pethe to TAPS Pump Statian #l in the Prudhoe Bay area. tn reality, two or more

fields can share the costs of production faciilties, the main pipeline, and other infrastructure

costs. Aiso, offshore development In the Beaufort Sea could share infrastructure costs with

onshore fieids.3 Consequently, there Isa realistic possibility-Ignored by the DOI quantitative

anaiysis–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 fielddeveloper

we calculated using the terms of the taxsystempriorto the 1986 changes in the taxkw. These

terms inciude aliowance of investment tax credits, 80 percent expensing of intangible drilling

costs, ACRS depreciation for 5~year property for tangibie drilling costs, and a 46 percent

Federal income tax rate. The indust~ has ciaimed that the resuit of the 1986 changes, on

balance, has been to reduce the incentive to find and develop rwwfie[ds. Thus, using current

tax 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 necessary construction and operations are based on the 1981 National Petroieum Cotincii report on

Arctic oil and gas,4 supplemented with other data. According to industry reports, experience

of the past few years–especially foilowing the severe oil price drop of 1985/86-has

demonstrated that the costs of Arctic operations can be reduced significantly, For example,

both ARCO and the Standard Alaska Production Company ciaim to have reduced development

driliing costs sharply by Increasing drilling efficiency. Thus, there is a strong possibility that

the DOI cost data overstates the likely costs for ANWR fieid development and depresses the

estimated oii potentiai.

5. Assumed oil ptice$. in its base case, DOi assumed that worid oii prices would rise to $35/bbi

in 1984 doliars by 2000 and wouid then rise in real terms by 1 percent per year thereafter. i301’s

anaiysis 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 of

ANWR, MEFS is 425 rniilion bbi at a $35/bbi oil price and 1.39 biilion bbl for a $22/bbl oii prices

Although DOI’S price assumptions have been severely criticized, OTA beiieves that oii prices

couid attain this ievei if current forecasts of future world oli demand and supply trends prove

to be correct. There are, however, piausibie circumstances that wouid maintain prices significantly 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 is

restricted to the 26 largest structural prospects identified by the im?ial geophysical suiveys of

the area. As noted in DOi’s ANWR Resource Assessment,6 additional amounts of economically 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 additional

prospects should increase the estimated values of both the probability of finding economically 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; the

third tends to overstate it; and the fifth gives no clear direction. Overall, OTA believes that i)O1’s

economic evaluation of ANWR oil potential is likely to be too pessimistic, especiaMy with

regard 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 assessments, however. The geologic assessment prepared by the State of Alaska is more pessimistic 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 at

least 3.77 billion barreis of in-place resources) versus DOI’s estimate of 11.9 billion. The primary

factors causing the disagreement are sharply differing views of the likelihood of finding large

volumes of oil-bearing Ellesmerian rocks in the coastal plain (the State largely discounts the role of

the Ellesmerian) and differing estimates of success rates for indhddual wells (the State expects

tower success rates than does DOI). Given the judgmental character of the estimates and the lack

of drilling data, this level of disagreement is not at all unusual. However, the State’s estimates

would imply a much lower resource value for the ANWR coastal plain than the value assigned by

DOI.

The Energy Information Administration (EIA) also has examined the DOI assessment of economically recoverable oil in the coastal plain. EIA concfuded that 1)01’s assessment of in-place resources was reasonable, but it disagreed strongly with 001’s evaluation of the risk of finding

economically recoverable oil and also disagreed with DOI’S assessment of the likely magnitude of

any recoverable resources. In particular, EIA rejected DOI’s estimate that there is only a iS percent probability of finding oil in economically recoverable quantities; instead, EIA concluded

that the probability of finding economically recoverable oil in ANWR is very high. EIA projects

the likely economically recoverable oil in ANWR (at DOI’s assumed oil prices) to be 3.4 billion

barrels, with little likelihood (compared to DOI's 81 percent likelihood) that nothing will be

recovered. 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 resources

is unsophisticated, relying on a simple extrapolation of the recovery rates of known North Slope

fields. On the other hand, given the limited data on ANWR, ElA’s slmple approach may prove just

as accurate as the more detailed approach of DOI.

7. Energy Mformation Administration, Potential Oil Production from the Coastal Plain of the Arctic National Wildlife ~fi9et

revised edition, SwRNGD/87-01, In its re rt, EIA arrived at essentially the same qualitative conclusions about the details of

DO1’s eoonomic analylis as OTAdid and as rdiscussed them in more detail.
Appendixes
Appendix A

Methods of Estimating Discovered In-Place

Resources and Reserves

An estimate is only as good as the quality and

quantity of the data available at the time it is

made. Estimating either in-place resources,

recoverable resources, or reserves is inherently

difficult because petroleum engineers cannot see

the reservoir. Typically they must rely on indirect

measurements (e. g., from well logs and cores,

seismic work, regional geology, etc. ) that supply

them with only a partial picture about the shape

and characteristics of the reservoir. As more

data become available through exploratory drilling, development drilling, and production, early

estimates can be refined, Reserve estimates

often grow with time. For instance, accumulated

initial domestic reserve estimates have averaged

about 50 percent of final estimates. Also, there is

a tendency to overestimate small discoveries and

to underestimate large ones’ (estimates of Prudhoe Bay’s reserves have indeed grown over time,

but estimates of original reserves (i.e., of ultimate

recovery) appear to be converging on 12 billion

barrels).

Several methods are available for estimating inplace resources. The volumetric method, for instance, is one of the simplest ways of calculating

in-place resources and is useful when not much

data are available. In the volumetric method,

seismic and drilling information are used to determine the structure, areal extent, and thickness of

potential reservoir rocks. A rough estimate of the

bulk rock volume of the resewoir can then be

made. In addition, estimates are made of the

average porosity and water saturation of the

reservoir and of oil and gas volume factors related to the reservoir’s pressure and temperature.

Knowledge of the porosity–a measure of the

amount of void or pore space in a rock– enables

the reservoir engineer to estimate the amount of

fluids the reservoir is capable of holding.

Knowledge of average water saturation within the

pore spaces allows engineers to determine how

much of the pore space is not occupied by water

and could contain oil and/or gas. Once estimates of bulk volume, average porosity, water

saturation, and oil/gas volume factors have been

obtained, a calculation of the in-place resource

can be made.

Estimates made using the volumetric method

may vary widely depending on the amount of information available. If data are derived from only

a few wells or from the results of pre-driiling surveys, the best one can do is assume uniform

thickness, porosity, and water saturation for

various segments of a reservoir. In reality, reservoirs are usually complex: for example, thickness, porosity, and water saturation may all vary

considerably; faulting introduces barriers to flow,

as do low permeability zones; and oil and gas

within the gross reservoir may be in unconnected

compartments. Hence, if the geological interpretation is not correct or not sufficiently precise,

the result of gross volumetric calculations will be

wrong.

A second technique sometimes used to obtain

estimates of in-place resources (and reserves as

well) is the material balance method. A material

balance calculation relies on the assumption that

a petroleum reservoir can function as a large

closed tank containing oil, gas, and water. By

measuring the change in pressure after various

known increments of production, it is possible to

calculate the original in-place amounts of oil, gas,

and water.2 A principal weakness of this method

is that reservoirs are treated as a single unit

under constant pressure. Typically, however,

pressure will vary considerably throughout a

reservoir. Treating the reservoir as an undifferentiated unit, therefore, may not adequately model

the reservoir.

1, Rival op. cit., p, 126.

2. Riva, op. cit., p. 125,

109
110 ● ANWR

Several techniques are also used for estimating

recoverable oil and gas. A rough estimate of

recovery can be made using the analogy method.

For this technique, one can simply apply a

recovery factor to in-place resources. A recovery

factor is the percentage of in-place resources

that are expected to be recoverable in a reservoir, and the factor used to estimate recoverable

volumes from a given reservoir is one associated

with another reservoir having a recovery factor

known from production history and characteristics similar to the one being investigated.

A second recoverable resource estimation

technique is decline curve analysis. Peak

production must already have taken place to

properly use this technique. From a study of the

production trend over time, a mathematical

relationship can be established. Using this

relationship, one can then project production into

the future to the point where further production

would no longer be economically feasible. The

total production over time constitutes the ultimately recoverable oil and gas. A weakness in

the decline curve method is that it is only indicative if wells are allowed to produce at their maximum (unrestricted) rate. If the flow rate is

restricted, either by company policy or State or

Federal regulations, the decline curve will show a

downward trend in time that will not truly reflect

recoverable oil and gas.3

The most sophisticated technique used to estimate recoverable oil and gas is reservoir simulation. In setting up a simulator, all available

information on reservoir and fluid characteristics

is used. Unlike the material balance method in

which the reservoir is considered to function as a

single tank, reservoir simulation more systematically considers the reservoir as an aggregate of

many cells, each with its own parametric values,

such as fluid saturations, permeabilities, pressures, etc. Using all the data, flow equations are

developed for a reservoir which match the

reservoir’s history. These equations are then

solved, using computer processing, to estimate

recoverable resources. Typically, reservoir

simulators are quite expensive to develop and

are developed only for the largest fields. The

Prudhoe Bay field, the country’s largest, has

been simulated using the best available methods.

All estimation techniques have their shortcomings. Specifically, one must always keep in mind

that 1 ) although estimates may make use of the

best available data, the availability and quality of

data for oil and gas estimates are often limited,

and 2) the estimate is usually based on a number

of simplifying assumptions about the reservoir

characteristics and/or future trends in price and

technology development.

In addition to the inherent difficulty of making

accurate resource and reserve estimates, data

access problems hamper the accuracy, or at

least the credibility, of published estimates.

Published reserve estimates made by such agencies as the Alaska Oil and Gas Conservation

Commission; the Alaska Department of Natural

Resources, Division of Oil and Gas; and the U.S.

Department of Energy’s Energy Information Administration all ultimately rely on data supplied by

the oil and gas industry. Although some oil company data must by law be released to these and

other State and Federal agencies which make estimates and regulate the oil industry, much industry data is proprietary. Estimates that the oil

companies themselves make are generally not

publicly available. Moreover, oil companies

usually are not willing to be too precise about estimates they do release. Typically, a company

will confirm that recoverable resources, for example, are likely within a specified range, but

they are reluctant to go further. Hence, public

estimates, even if in the same range as the

industry’s estimates, are usually not based on all

the information to which the oil companies have

access.

The oil and gas business is competitive, and

proprietary knowledge represents an advantage.

Among the reasons for industry’s desire to keep

information proprietary are that: 1 ) a competitor

with precise knowledge of a company’s reserves

estimate could gain an advantage in future lease

sales in the area; 2) estimates, even by the companies themselves, are at best only approximate;

hence, publication of a resewe estimate that later

turned 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 investors; and 3) a company’s oil and gas resetves

can be the object of hostile takeover attempts.

An additional caveat in comparing estimates

made by different groups (particularly of reserves

or recoverable resources) is that the assumptions on which each estimate is based may not

be–in fact, usually are not– made explicit. Such

assumptions usually include the projected price

of oil, the amount of capital investment planned

for the field, and the type of secondary or enhanced oil recovery techniques expected to be

used. Also, it is sometimes difficult to determine

which portion of a reported resewes estimate is

proved and which is only inferred or potential

(some North Slope estimates include both

proved and potential reserves). This greatly

complicates attempts to compare alternative estimates of reserves. Also, unless all reserve estimates are accounted to the same time for a

specific field or group of fields, estimate comparisons will not be valid.
Appendix B

Estimation Methods for

Undiscovered Resources

The purpose of any resource estimate is to

produce the best possible guess about the extent

of resources in the absence of data which would

allow one to calculate a more precise figure.

Reasonably accurate data about oil and gas

resources can only be generated through extensive drilling; however, geological and geophysical information prior to extensive drilling and

preliminary exploratory drilling at a later stage

does provide information which can be used for

gaining some insight into the amount of resources in an area. This information can be used to

estimate resources. Methods have been developed to estimate both undiscovered, in-place

resources and economically recoverable resources. Geological factors are the main consideration in estimating in-place resources;

estimates of economically recoverable oil and

gas must take into account various economic

and technological factors and regulatory policy

as well.

Although methods for estimating resources

have become sophisticated, estimates are only

as good as the data used to produce them. An

estimate may represent the best appraisal that

can be made at the time, but only by the greatest

of luck will the amount of resources eventually

found in an area be similar to the amount originally estimated. As relevant today as in 1934 is J.T.

Hayward’s remark, “... we must not fall into the

error of believing that because we have attached

a number to a chance that we have thereby made

a successful issue more sure, or have in any way

altered its probability. Further, we must be ever

on the watch for that most insidious and

widespread superstition that assumes that mathematical manipulation, if sufficiently accurate, involved, and prolonged can transmute doubtful

data into positive scientific fact.”l

In a recent study of hydrocarbon estimation

techniques the National Research Council

pointed out that the quality of an estimate of undiscovered resources is highly dependent upon:

1 ) the quantity and quality of the geologic information available; 2) the knowledge, experience,

and awareness of the group making the estimate;

3) the appropriateness of the estimation

methodology; and 4) (for estimates of economically recoverable resources), the economic assumptions used. Moreover, they noted that

users of any resource estimate must recognize

its probabilistic nature and resulting inherent uncentainty. 2

The variability between estimates made by different people using the same method (as well as

between estimates made using different techniques) can also be wide. This is so because each

model calls for a number of subjective inputs.

For example, many models depend in one way or

another on the use of geologic analogy. Differences of opinion easily can exist over what

geologic analogy is most appropriate. When little information is available, structural geology

and stratigraphy can and are interpreted differently. For example, in evaluating the resource

potential of the Arctic National Wildlife Refuge,

geologists from the State of Alaska and from the

Department of the Interior used similar play

analysis methods; however, they identified the

plays differently.

A number of methodologies have been devised

to help estimate, with limited data, the expected

amount of resources in an area. Some of the

methods are fairly crude; others are quite sophisticated, although again it must be stressed that

even the most sophisticated methods produce

only estimates, and many of these estimates require numerous assumptions and much subjec1. 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 assessment

methods are currently in use. These include:

1.

2,

3.

4.

5.

The

Areal and volumetric yield methods in combination with geologic analogy. These

techniques range from worldwide average

yields applied uniformly over a sedimenta~

basin to more sophisticated analyses in

which the yields from a geologically

analogous basin are used to provide a basis

of comparison.

Delphi or subjective consensus methods.

In this approach, the estimation of

petroleum resources is the consensus of a

team of experts who review all the geologic

information available in an area or basin.

Historical performance or behavioristic

methods. These methods are based on extrapolating historical data, such as discovery rates, drilling rates, productivity

rates, and known field size distributions.

Geochemical material balance methods.

These methods are used to estimate how

much oil or gas was generated in source

rocks of a given area, how much was involved in migration, probable losses during

migration, and the quantity that accumulated in deposits.

Integrated methods. These methods use a

combination of some or all of the above and

incorporate geological and statistical

models. 3

integrated methods, such as play and

prospect analyses, are the most sophisticated.

Play analysis methods have become popular in

recent years for assessing conventional

petroleum resources in identified or conceptual

exploration plays in a basin or province.4 These

methods produce a range of estimates related to

the probability of occurrence of certain amounts

of oil rather than a single estimate of resources

expected in one or more plays. Since much effort has been expended by State and Federal

resource agencies applying these methods to estimating the resources of both the National

Petroleum Reserve in Alaska and the Arctic National Wildlife Refuge, these methods and the assumptions that go into them will be described in

greater detail.

In-Place Resource Models:

RASP and FASP

In-place oil and gas resources include all categories of resources still in the ground, that is,

those that are considered to be economically

recoverable, those that are technically but not

economically recoverable, and those that cannot

yet be technically or economically recovered. lnplace resources, usually expressed in terms of

original in-place volumes, constitute the resource

base. Roughly 10 percent to at most 50 percent

of in-place oil resources in any given resource

area can typically be economically recovered

using currently available technology and techniques. Estimates of in-place resources depend

upon the interpretation of the geology, economic

factors being irrevelant.

Play and prospect analysis models for assessing in-place resources include the Resource Appraisal Simulation for Petroleum (RASP) and the

Fast Appraisal System for Petroleum (FASP).

RASP has been used by the U.S. Geological Survey to assess resources in both the National

Petroleum 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 More

recently (1986) the State of Alaska used the

RASP methodology to estimate resources in

ANWR. 6 And the newer FASP method, which is

more efficient but produces similar estimates,

was used by the Department of the Interior in

1986 to estimate in-place resources in ANWR.7

Both methods are based upon the same

geologic model and employ the same probability

assumptions. 8 However, RASP employs a Monte

Carlo simulation technique which typically requires 3000 to 5000 repetitions while FASP is an

analytic method which uses statistical techniques

and probability theory rather than simulation and

thereby greatly speeds up and reduces the cost

of the estimation process.

Both methods make extensive use of the judgment of geologists familiar with the geology of

the area. In undrilled areas, geologists must

depend on surface geology and geophysical

data and consider possible geologic analogies

with other areas when they make their appraisals.

For each identified play (group of geologically related prospects with similar hydrocarbon sources, reservoirs, and traps) within an assessment

area, RASP and FASP require that geologists

judge the probability that a hydrocarbon source

exists, that the timing of oil formation has been

favorable, that oil migration from source to traps

has been successful, and that the trap contains

reservoir grade rock. The product of these four

regional geological characteristics (assuming the

probability of each occurring is independent of

the others’ occurrence) jointly determines the

marginal probability– the probability that the play

contains hydrocarbon accumulations.

Expert judgment is likewise called for at the

level of individual prospects, the untested

geologic features having the potential for trapping and accumulating hydrocarbons. The

prospect attributes are the geologic characteristics common to the individual prospects within a

play. Geologists must assess the probability of

the existence of a trapping mechanism for the

prospects, the likelihood that effective porosity

exceeds a certain amount, and the probability

that oil and gas exist in at least 1 percent of a

trap, The product of these probabilities (again

assuming independence) is the probability that a

prospect is a deposit, but it is conditional upon

the favorability of the play. Together the marginal

play probability and the conditional deposit probability are the risk factors. If all attributes comprising these risk factors are favorable, it is likely

that there will be hydrocarbons in at least some

of the prospects within the play.

A third set of judgments is needed to determine

how much oil may be contained in each

prospect. Geologists are asked to estimate the

range of possible values for each of five volume

attributes (area of closure, reservoir thickness, effective porosity, trap fill, and reservoir depth) and

to assign the probability of a given value to one of

seven categories. For example, a geologist may

estimate that there is a 100 percent probability

that the reservoir thickness of a deposit is greater

than or equal to 50 feet, a 75 percent probability

that the thickness is greater than 80 feet, and a 25

percent probability that the thickness is greater

than 100 feet. From these estimates, a probability distribution for each of the volume attributes can be made. A range of values is also

estimated for the number of drillable prospects in

each play, And finally, geologists are asked to as5. Kenneth J. Bird, “A Comparison of the Play Analysis Technique as Applied in Hydrocarbon Resource Assessments of the

National 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 Oil

and 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 in

Play 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 marginal

play 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 hydrocarbon

volume attributes

i

I Calculate resources I

+ +

i

Last prospect? No

1

i

Yes

I 1

I

i

Last pass? No

I

i

Yes

r ,

Form play

distributions

t

Last play? No

1 Yes

Robert A CrovellI, “A Comparison of Analyhc and Simulation Methods for Petroleum Play Analysls and Aggregation “ U S

Gaologlcal Survey Open-File Reporf 86-97 1985
* Pendix B ● 117

sess the likely reservoir characteristics and

hydrocarbon mix.

If RASP is used, a simulation is run using the

probabilities estimated in the geologic model

(figure B-l). First, the marginal play probability is

sampled. If the sampled play is “dry,” zero

resources are assigned to that play on that pass.

If the play is not dry, the number of prospects in

the play are sampled. Then each of the

prospects in the play are examined in turn. Sampling the conditional deposit probability for each

prospect determines whether the prospect is dry

or contains oil and/or gas. If hydrocarbons are

simulated as present, each of the hydrocarbon

volume attributes are sampled, and the resources

within the prospect are calculated using standard

reservoir engineering equations. After the last

prospect within the play is sampled, the resources are totaled for that play, and the simulation

proceeds to the next play. The process is

repeated until all the plays have been examined.

The resource estimates for all the plays are

summed to obtain the total amount of simulated

oil in the assessment area. The simulation is then

rerun as many as 5,000 times. Probability distributions can then be derived by ranking results

for each ass and dividing the rank ordering into

fractiles.8

The simulation method is easier to understand

than the analytic method, but the outcomes are

much the same. In the FASP analytic method,

the simulation is replaced by a statistical procedure which calculates means and variances of

the same geologic variables to derive an estimate

for one play (figure B-2). Results for individual

plays are then aggregated using the aggregation

model FASPA. Comparisons of RASP and FASP

have been made, and results show excellent

10 The analytic method, however, ‘as agreement.

some advantages. A principle one is that it is

thousands of times faster. The cost to run the

program is therefore negligible and FASP can be

rerun frequently, incorporating new data as available. The analytic method is also potentially

more useful because it produces mathematical

equations of probabilistic relationships involving

petroleum resources.

Estimating Economically

Recoverable Undiscovered

Resources: PRESTO

Models have also been developed to estimate

the amount of undiscovered but economically recoverable resources in a given area. In particular, the Minerals Management Service’s

PRESTO (Probabilistic Resource Estimates-Offshore) model (now in its third version) has been

used to estimate undiscovered, economically

recoverable resources in arctic offshore areas

and, recently, in the Arctic National Wildlife

Refuge. Conceptually, the model has much in

common with RASP, in that it incorporates Monte

Carlo simulation, ranges of values for volumetric

input parameters, and risk analysis.l 1 The most

important unit of analysis used to derive PRESTO

estimates is the prospect, or individual potential

oil or gas field. As in RASP, marginal and conditional risks are determined. The marginal basin

risk is the probability that no prospect within a

given basin contains hydrocarbons; the conditional prospect risk is the probability that an individual prospect modelled is “dry,” conditional

upon the basin containing at least some

economically recoverable hydrocarbons. These

risks are determined by geologists using all available geological and geophysical data. Needless

to say, in undrilled and largely unexplored areas,

the data are usually scanty. Moreover, PRESTO,

like other resource estimation models, uses the

judgment of experts when “hard” data are unavailable. Identification and characterization of

prospects, for instance, calls for significant subjective 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 and

Kornbrath, “Resource Appraisal Simulation for Petroleum...”; and L,P. White, “A Play Approach to Hy 2rocarbon Resource Assessment

and 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. Geological

Survey Open-File Report 8&97, 1986.

11. L.W. Cooke, “Estimates of Undiscovered, Economically Recoverable Oil and Gas Resources for the Outer Continental Shelf As

Of 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 volume

attributes

L J 1

I

b

+

I I 1 1

I I

4
Using risk factors and Monte Carlo simulation,

PRESTO simulates an exploratory drilling

program. For each PRESTO trial, every prospect

in the basin is “drilled, ” and discovered resources

are summed to determine an area total. The

simulation is repeated as many as 5000 times,

and results are sorted, ranked, and divided into

percentiles. Output includes the conditional 95

percent, 5 percent, and mean resource estimates

for oil and gas and the corresponding probability

of economically recoverable hydrocarbons after

accounting for the possibility that there may be

no hydrocarbons in the area (the ‘(risked” estimates).

The major difference between RASP and PRESTO is that PRESTO incorporates economic factors into the model. Thus, not only does PRESTO

determine the amount of resources in each

prospect, it determines whether the resources

within each prospect are large enough to warrant

development. To accomplish this, PRESTO uses

a single point estimate of the minimum economic

field size (MEFS) required for development in the

area. The MEFS is derived from MONTCAR, a

discounted cash flow analysis program. An important consideration in determining MEFS is the

assumed price of oil – as the price of oil

decreases, the MEFS increases. Other important

considerations include development and operating costs, and distance from markets,

Significantly, the prospect’s resources are

added to the total for the area only if the MEFS is

exceeded for the prospect being “drilled. ” But if

the MEFS is not exceeded, the prospect’s resources are set to zero. Hence, PRESTO estimates of

undiscovered, economically recoverable resources may be conservative. For example, a

prospect that, in isolation, is not estimated to

contain enough resources to be developed may

nevertheless be developed if there are other

prospects in the area that are large enough to

develop, or even if a number of fields, all below

the MEFS, are found in close proximity and can

share infrastructure costs. The Lisburne, Endicott, and Milne Point fields, for instance, would

never have been developed were it not for their

proximity to Prudhoe Bay and the TAPS pipeline.

PRESTO would have modeled these fields as

having zero resources, but they are currently

contributing to TAPS throughput, if only about 5

to 10 percent. Likewise, some geologists believe

that PRESTO estimates of economically

recoverable resources in ANWR are conservative. 12 The MEFS for ANWR as a whole has been

determined 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 declining

development costs, the high probability that

more prospects than were evaluated in DOI’s

ANWR analysis will subsequently be identified,

and other factors, the estimate of economically

recoverable resources do appear too conservative. 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 C

Glossary

API gravity: The standard American Petroleum institute method for specifying the density of

crude petroleum. The density in degrees of

API equals (141.5 ”P)-131 .5, where P is the

specific gravity of the oil measured at 60° F.

barrel: A common unit of measurement of liquids

in the petroleum industry; it equals 42 U.S.

standard gallons.

chemical flooding: An enhanced oil recovery

technique based upon adding various chemicals to the water used in waterflooding in

order to increase waterflood efficiencies.

conditional mean resources: The average

amount of oil and/or gas expected to exist if

at least one of the prospects in an area contained economically recoverable accumulations of hydrocarbons and if all of the

prospects modelled were drilled.

directional drilling: Drilling that has been

deliberately angled away from the vertical.

drilling mud: A special mixture of clay, water, or

oil and chemical additives pumped through

the drill pipe and drill bit. The mud cools the

rapidly rotating bit; lubricates the drill pipe as

it turns in the well bore; carries rock cuttings

to the surface; serves as a plaster to prevent

the wall of the bore hole from crumbling or collapsing; and provides the weight or hydrostatic head to prevent formation fluids from

entering the well bore and to control

downhole pressures,

economically recoverable resource estimate:

An assessment of the hydrocarbon potential

of a field that takes into account physical and

technological constraints on production and

the relation of costs and market price.

enhanced oil recovery: See tertiary recovery.

fault: A fracture along which the rocks on one side

are displaced relatively to those on the other.

field: Composed of a single pool or multiple pools

that are grouped on or related to a single

structural and/or stratigraphic feature. “Pool”

is a term meaning a body of reservoir rock

containing recoverable oil and/or gas.

formation: A rock mass composed of individual

beds or units with similar physical characteristics or origin.

gas lift: The effect of either naturally or artificially

induced gas pressure in an oil well t hat causes

the oil to flow from the well.

gas/oil ratio: The proportion of gas produced

relative to oil produced from a reservoir(s) or

field(s), usually expressed as cubic feet per

barrel of oil.

gas injection: The process of injecting (or reinfecting) gas into a reservoir to maintain the

producing pressure.

infill drilling: Drilling at a smaller spacing than

called for in the original development plan,

designed to speed up production and/or increase ultimate recovery.

in-place resources: The total amount of oil in a

field, only a portion of which will ultimately be

recoverable.

inferred, potential reserves: Those resources

that should eventually be added to proved

reserves through extensions of known fields,

revisions of earlier reserves estimates resulting from new subsurface and production information, and production from new

producing zones in known fields.

log, well log: Measurements of the physical

properties of the drilled section, generally

taken while raising measurement devices up

the wellbore on an electrical cable.

marginal probability: The probability that

economically recoverable oil and gas resources exist in an area under study.

121
migration: The movement of oil, gas, or water

through porous and permeable rock.

miscible flooding: A technique based upon using

some gas – such as enriched reservoir gas or

C02–to miscibly displace some oils, thereby

permitting the recovery of most of the in-place

oil contacted.

outer continental shelf: The part of the continental shelf beyond the line that marks State

ownership; that part of the offshore area

under Federal jurisdiction.

pay: A rock stratum or zone that yields oil or gas.

permafrost: Any soil, subsoil, or other surficial

deposit occurring in arctic, subarctic, and alpine regions at a variable depth beneath the

Earth’s surface in which a temperature below

freezing has existed continuously for a long

time.

permeability: The degree to which a rock will

allow liquid or gas to pass through it.

play: A rock formation or group of formations

within a sedimentary basin with geological

characteristics similar to those that have been

proven productive. A play serves as a planning unit around which an exploration

program can be constructed.

pool: A subsurface accumulation of oil and/or gas

in porous and permeable rock, having its own

isolated pressure system, Theoretically, a

single well could drain a pool. Also known as

a resemoir.

porosity: The proportion of a rock’s total volume

occupied by the voids between the mineral

grains.

pressure cycling: A technique of injecting natural

gas or CO2 into a producing formation and alternating high and low pressures to induce

mixing with the crude and thus stimulating the

flow.

primary recovery: The fraction of original oil

and/or gas in-place that will flow unaided or

can be pumped from the reservoir rock matrix

to the surface.

production: Activities that take place after the

successful establishment of means for the

removal of oil and/or gas, including such

removal, field operations, operation monitoring, maintenance, and workover driiiing.

proprietary information: Scientific, engineering,

and financial data, information, and derivatives thereof that are not released to the public

for a specified term. Federal laws, regulations, statutes, or contractual requirements

affect the terms,

prospect: An area that is a potential site of

economically recoverable petroleum accumulation based on preliminary exploration.

A play is composed of one or more prospects.

recoverable oil: The sum of proved and potential

reserves. May also inciude estimated undiscovered recoverable oil.

reserves, proved reserves (oil): The portion of

an oil field’s resource base that has been identified by drilling and estimated directly by engineering measurements, and that is

recoverable at current prices and technology.

reservoir pressure: The pressure existing at the

level of the oil and/or gas productive zone in

a well.

reservoir rock: A porous and permeable rock,

e.g., sandstone or limestone, which contains

oil and/or gas that can be produced.

resources: The total amount of oil or gas that

remains to be produced in the future.

Generally does not include oil or gas in such

small deposits or under such difficult conditions that it is not expected to be produced at

any foreseeable price/technology combination.

risked mean resources: The product obtained by

multiplying the conditional mean value by the

marginal probability that economically

recoverable hydrocarbon resources exist in

the area under study.

secondary recovery: Oil and gas obtained by the

augmentation of resetvoir energy, often by

the injection of gas or water into a producing

reservoir.
pendix C – Glossary ● 123

show: An indication of the presence of oil or gas

in the formations penetrated during drilling.

shut-in: Shutoff, so there is no flow; refers to a

well, plant, pump, etc., when valves are

closed. A shut-in well can be returned to

production, often with some downhole

cleanup work.

source rock: Sedimentary rock in which organic

material under pressure, heat, and time was

transformed to liquid or gaseous hydrocarbons. Source rock is usually shale or limestone.

stratigraphic trap: A trap for oil and/or gas, resulting from changes in rock type, porosity, or

permeability, that occurs as a result of

sedimentation and diagenetic processes

rather than from structural deformation.

structural trap: A trap for oil or gas resulting from

folding, faulting, or other rock deformation.

tertiary recovery: Oil recovered using advanced

techniques beyond secondary recovery techniques. Techniques include injection of steam

or of other injected substances, such as rich

miscible gas, carbon dioxide, polymers, solvents, surfactants, micellar fluids, or even

microorganisms.

thermal recovery/stimulation: A petroleum recovery process that utilizes heat (in the form

of steam or hot gas) to thin viscous oil in an

underground reservoir and allow it to flow

more readily toward wells through which it

can be brought to the surface.

trap: Any barrier to the upward movement of oil

or gas that allows either or both to accumulate. A trap includes reservoir rock and overlying impermeable cap rock.

viscosity: That prope~y of a fluid which determines its rate of flow. As the temperature of

a fluid is increased, its viscosity decreases,

and it therefore flows more readily.

waterflood: A secondary-recovery operation for

oilfields in which water is injected into a

petroleum reservoir to force more oil to the

producing wells.

work-over: A term applied to any remedial operation performed on a well after completion.

undiscovered, economica Ily recoverable

resources: Quantities of economically

recoverable oil and gas estimated to exist outside known fields.

undiscovered, in-place resources: Quantities of

oil and gas estimated to exist outside known

fields, without reference to technological or

economic factors.

wellhead: The equipment used to maintain surface control of a well. It is formed of the

casing head, tubing head, and Christmas tree

(assemblage of valves, gages, fittings, etc.).

Also refers to various parameters as they exist

at the wellhead: wellhead pressure, wellhead

price of oil, etc.